SR/OIAF/2000-03

The Northeast Heating Fuel Market:

Assessment and Options

May 2000

Energy Information Administration

Office of Integrated Analysis and Forecasting

U.S. Department of Energy

Washington, DC 20585

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 be attributed to the Energy

Information Administration and should not be construed as advocating or reflecting any policy position of the

Department of Energy or of any other organization. Service Reports are prepared by the Energy Information

Administration upon special request and are based on assumptions specified by the requester.
Contacts

The analysis in this report was undertaken at the request

of the Secretary of Energy, Bill Richardson. The principal

purpose of this study is to examine the feasibility and

impacts of converting factories and other major users of

heating oil to different fuels, and to discuss other options

that may mitigate future heating oil supply problems in

the Northeast.

This report was prepared by staff from the Office of

Integrated Analysis and Forecasting and the Office of

Oil and Gas, in the Energy Information Administration

(EIA). General questions concerning the report may be

directed to Andy S. Kydes (akydes@eia.doe.gov, 202/

586-2222), Senior Advisor and Project Leader; Mary J.

Hutzler (202/586-2222), Director, Office of Integrated

Analysis and Forecasting; James M. Kendell (202/

586-9646), Director, Oil and Gas Division; or Joan

Heinkel (202/586-4650), Director, Natural Gas Division.

Specific questions about the analysis may be directed to

the following EIA staff:

Natural Gas Supply and Infrastructure . . . William Trapmann (wtrapman@eia.doe.gov, 202/586-6408)

Natural Gas Infrastructure. . . . . . . . . . . . . . Joseph Benneche (jbennech@eia.doe.gov, 202/586-6132)

Oil Supply. . . . . . . . . . . . . . . . . . . . . . . . . . . . Stacy MacIntyre (smacinty@eia.doe.gov, 202/586-9795)

Oil Distribution . . . . . . . . . . . . . . . . . . . . . . . Bruce Bawks (bbawks@eia.doe.gov, 202/586-6579)

Residential Markets. . . . . . . . . . . . . . . . . . . . John Cymbalsky (jcymbals@eia.doe.gov, 202/586-4815)

Commercial Markets. . . . . . . . . . . . . . . . . . . Erin Boedecker (eboedeck@eia.doe.gov, 202/586-4791)

Industrial Markets . . . . . . . . . . . . . . . . . . . . . Crawford Honeycutt (choneycu@eia.doe.gov, 202/586-1420)

Electricity Generation . . . . . . . . . . . . . . . . . . J. Alan Beamon (jbeamon@eia.doe.gov, 202/586-2025)

In addition, Robert Latta and Alan Swenson of the Office of Energy Markets and End Use provided assistance with

residential and commercial sector data.

ii Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options
Contents

Page

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

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

Purpose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Review of the Oil Market Situation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2. What Happened to Heating Fuel Prices in the Winter of 1999-2000? . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Distillate Market Factors Leading to the Price Spike . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Crude Oil and Product Stocks Declined in 1999. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

U.S. Distillate Stocks Fell Below Normal in December 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Natural Gas Market Factors Contributing to Distillate Fuel Oil Price Increases . . . . . . . . . . . . . . . . . . . 7

The January/February 2000 Price Spike . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Northeast Heating Oil and Natural Gas Spot Prices Spiked as Low Stocks Fell Further. . . . . . . . . . . . . 9

Weather Conditions Drove January Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

The Supply Situation Deteriorated While Demand Grew . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

A Number of Events Eventually Corrected the Imbalance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

What Will the Future Bring? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

3. Consumer Markets: History, Patterns, and Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Residential Sector Heating Fuel Choice. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Highlights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Recent Trends and Current Use of Distillate Fuel Oil in the Residential Sector . . . . . . . . . . . . . . . . . 16

Projections to 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Historical Heating Costs: An Illustration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Conservation Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Commercial Sector Fuel Choice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Highlights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Recent Trends and Current Use of Distillate Fuel Oil in the Commercial Sector . . . . . . . . . . . . . . . . . 20

Projections to 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Conservation Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Industrial Sector Fuel Choice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Highlights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Recent Trends in Industrial Distillate Fuel Oil Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Projections to 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Conservation Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Other Options Cutting Across All Sectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Electricity Generation Sector Fuel Choice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Highlights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Recent Trends in Oil Use for Electricity Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Projections to 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Fuel Supply Options for Electricity Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Northeast Distillate Fuel Oil Market Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Fuel-Switching Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Conversion of Distillate Fuel Oil Use to Other Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options iii
Contents (Continued) Page

4. Natural Gas Supply, Infrastructure, and Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Current Status of the Natural Gas Industry in the Northeast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Supply. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Storage and Local Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Sales and Service Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Evaluating the Effects of Changes in Natural Gas Consumption Patterns . . . . . . . . . . . . . . . . . . . . . . . 43

Pipeline Capacity Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Natural Gas Storage Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Economic and Institutional Obstacles to Gas Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

5. Distillate Fuel Oil Supply, Infrastructure, and Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Market Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Sources of Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Receipts from the U.S. Gulf Coast. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Supplies from Area Refineries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Regional Distribution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Stocks and Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Pricing and Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

Market Implications of Reducing Reliance on Distillate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Appendixes

A. Request for Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

B. Historical Data on Fuel Consumption and Prices for the Residential Sector in the Northeast Region . . . . . . . 65

C. Historical Distillate Price Spikes: December 1989-January 1990, January-February 1994,

and January-February 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

D. Electricity Generation and Fuel Consumption Data, 1980-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Tables

ES1. Estimated Distillate Fuel Oil Switching and Conversion Potential in the Northeast by Sector . . . . . . . . . . . xi

1. U.S. Distillate Fuel Oil Balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

2. Residential Home Heating Case Illustration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

3. Commercial Buildings Fuel Oil Consumption, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

4. Industrial Distillate Fuel Oil Consumption, 1994-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

5. U.S. Manufacturing Energy Consumption, 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

6. Northeast Manufacturing Energy Consumption, 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

7. Northeast Estimated Switchable and Conversion Potential. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

8. Gas Storage Capacity and Deliverability in the Northeast, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

9. Average Daily Consumption of Natural Gas in the Peak Month Before and After Switching from

Distillate to Natural Gas in the Northeast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

10. Projected Pipeline Capacity Requirements Entering the Northeast Region If Large-Volume

Distillate Consumers Switch to Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

11. Proposed Pipeline and Capacity Expansion Projects into the Middle Atlantic Region . . . . . . . . . . . . . . . 47

12. Distillate Fuel Imports to New England Originating In Venezuela, 1998-2000 . . . . . . . . . . . . . . . . . . . 55

13. Pricing Programs Offered to Consumers by Heating Oil Retailers in Northeast States, 1999 . . . . . . . . . . . 58

B1. National Summary: Space Heating Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

B2. Northeast Summary: Space Heating Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

B3. New England Summary: Space Heating Equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

B4. Mid-Atlantic Summary: Space Heating Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

B5. Midwest Summary: Space Heating Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

iv Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options
Tables (Continued) Page

B6. Regional Fuel Consumption for Residential Space Heating. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

B7. Regional Fuel Expenditures for Residential Space Heating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

B8. Regional Fuel Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

B9. Regional Fuel Consumption for Residential Space Heating If All Households With Oil Heat

and Gas Service Switched to Gas Heat. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

B10. Regional Fuel Expenditures for Residential Space Heating If All Households With Oil Heat

and Gas Service Switched to Gas Heat. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

D1. Electricity Generation by Fuel, 1980-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

D2. Nonutility Diesel, Distillate Fuel Oil, and Residual Fuel Oil Consumption, 1991-1998 . . . . . . . . . . . . . . . 82

D3. Distillate Fuel Oil Consumption for Electricity Generation by Month, 1980-1999. . . . . . . . . . . . . . . . . . 83

D4. Electricity Generation by Fuel, Census Division 1, 1980-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84

D5. Electricity Generation by Fuel, Census Division 2, 1980-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

D6. Electricity Generation by Fuel, Census Division 3, 1980-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

Figures

1. OECD Petroleum Inventories, 1993-2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

2. U.S. Distillate Product Supplied by Month, 1994-2000. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

3. U.S. Distillate Production by Month, 1994-2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

4. Stocks of High-Sulfur Distillate Fuel Oil (Heating Oil) in New England (PADD 1a), 1994-2000 . . . . . . . . . . 6

5. Stocks of High-Sulfur Distillate Fuel Oil (Heating Oil) in the Central Atlantic (PADD 1b), 1994-2000 . . . . . . 6

6. Spot Prices for Heating Oil and Natural Gas, August 1999 - March 2000. . . . . . . . . . . . . . . . . . . . . . . 8

7. Natural Gas Pipeline Capacity Feeding into the Northeast, with Mileage from Major Supply Sources

to Regional Distribution Centers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

8. Natural Gas Storage Sites in the Northeast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

9. Retail Residential Heating Oil Prices, Winter 1999/2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

10. Retail On-Highway Diesel Prices, Winter 1999/2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

11. U.S. Distillate Fuel Oil Consumption, 1980-2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

12. U.S. Distillate Fuel Oil Consumption, Excluding Transportation, 1980-2005 . . . . . . . . . . . . . . . . . . . . 16

13. Northeast Consumption of Distillate Fuel Oil, Excluding Transportation, 1980-2005 . . . . . . . . . . . . . . . 16

14. Distillate Fuel Oil Use in the Residential Sector, 1980-2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

15. Residential Heating Fuel Shares in the Northeast Census Region, 1980 and 1997 . . . . . . . . . . . . . . . . . . 17

16. Residential Fuel Prices in the Northeast Census Region, 1980-2005 . . . . . . . . . . . . . . . . . . . . . . . . . 17

17. Commercial Delivered Energy Consumption in the Northeast Census Region by Fuel, 1997 . . . . . . . . . . . 20

18. Distillate Fuel Oil Share of Commercial Fuel Use, 1980-2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

19. Commercial Sector Distillate Fuel Oil Consumption in the Northeast by End Use, 1995 . . . . . . . . . . . . . . 21

20. Natural Gas and Distillate Fuel Oil Use in Commercial Buildings in the Northeast

and Maximum Fuel-Switching Potential, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

21. Ratio of Distillate Fuel Oil Price to Natural Gas Price in the Northeast Commercial Sector, 1980-2005 . . . . . . 23

22. Projected Distillate Fuel Oil Use in the Northeast Commercial Sector:

Percent Change from Reference Case in Low and High World Oil Price Cases, 1999-2005 . . . . . . . . . . . . . 23

23. Total and Industrial Distillate Fuel Oil Consumption in the United States, 1980-2005 . . . . . . . . . . . . . . . 24

24. Distillate Fuel Oil Share of Industrial Delivered Energy Consumption in the United States

and the Northeast, 1980-1997. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

25. Potential Switching Capability from Distillate Fuel Oil Use in the Northeast Manufacturing Segment, 1994 . . 26

26. Maximum Potential for Industrial Sector Switching From Distillate Fuel Oil Use in the Northeast

and Projected Switching Under High World Oil Price Assumptions, 2000-2005 . . . . . . . . . . . . . . . . . . 27

27. Electricity Generation by Fuel in the Northeast, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

28. U.S. Electricity Generation by Fuel, 1950-2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

29. Electricity Generation from Oil and from All Other Fuels by Census Division, 1998 . . . . . . . . . . . . . . . . 30

30. Utility and Nonutility Generator Oil Consumption by Census Division, 1998 . . . . . . . . . . . . . . . . . . . 30

31. Electric Utility Generation from Distillate Fuel Oil by Census Division and Month, 1989 . . . . . . . . . . . . . 31

32. Projected Oil Shares of Electricity Generation in the Northeast, 2000-2005 . . . . . . . . . . . . . . . . . . . . . 32

33. Electric Utility Consumption of Distillate Fuel Oil, Residual Fuel Oil, and Natural Gas

in the Northeast by Month, 1989 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

34. Average Monthly Natural Gas Consumption in the Northeast by Sector, 1989-1998 . . . . . . . . . . . . . . . . 37

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options v
Figures (Continued) Page

35. U.S. Pipeline Development Projects Completed in 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

36. Proposed U.S. Gas Pipeline Expansions, 2000-2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

37. Average Costs for New Pipeline Capacity in the Northeast, 1996-2000 . . . . . . . . . . . . . . . . . . . . . . . 46

38. Regional Daily Deliverability from Underground and Liquefied Natural Gas Storage in the Northeast, 1998. . 48

39. Northeast Distillate Fuel Oil Supply Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

40. Distillate Fuel Oil Supply on the East Coast by Source, 1995-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . 53

41. Average Monthly Distillate Fuel Oil Supply on the East Coast by Source, 1995-1999 . . . . . . . . . . . . . . . . 54

42. Distillate Fuel Oil Supplied to the East Coast from the U.S. Gulf Coast by Mode of Transport, 1995-1999 . . . . 54

43. Quarterly Imports of Low-Sulfur and High-Sulfur Distillate Fuel Oil into the Northeast Region, 1995-1999. . . 56

C1. New York Harbor No. 2 Heating Oil Spot Prices Minus West Texas Intermediate Crude Oil Spot Prices,

1989-1999. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

C2. Winter 1989-1990 East Coast Stock Variations from Average and Distillate Spreads . . . . . . . . . . . . . . . . 76

C3. Winter 1993-1994 East Coast Stock Variations from Average and Distillate Spreads . . . . . . . . . . . . . . . . 77

C4. Winter 1999-2000 East Coast Stock Variations from Average and Distillate Spreads . . . . . . . . . . . . . . . . 77

vi Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options
Executive Summary

In January 2000, prices for heating oil, the oil consumers

use to heat their homes, increased dramatically in the

Northeastern United States. As a result, many consumers were faced with unexpectedly high heating bills as

the weather turned colder. The level and duration of the

price increase prompted the President to ask Secretary

of Energy Bill Richardson to examine opportunities for

converting factories and major users from oil to other

fuels, which will help to free up future oil supplies for

use in heating homes.

In response to the President’s request, this study examines how the distillate fuel oil market (and related

energy markets) in the Northeast behaved in the winter

of 1999-2000, explains the role played by residential,

commercial, industrial, and electricity generation sector

consumers in distillate fuel oil markets and describes

how that role is influenced by the structure of the energy

markets in the Northeast. In addition, this report

explores the potential for nonresidential users to move

away from distillate fuel oil and how this might impact

future prices, and discusses conversion of distillate fuel

oil users to other fuels over the next 5 years. Because the

President’s and Secretary’s request focused on converting factories and other large-volume users of mostly

high-sulfur distillate fuel oil to other fuels,1 transportation sector use of low-sulfur distillate fuel oil is not

examined here.

Fuel switching and conversion from distillate fuel oil to

a different fuel can occur in either of two ways, depending on the time frame available. In the short term, existing equipment that has dual-fuel (e.g., distillate and

natural gas) switching capability can be used. In the longer term, other equipment may be amenable to retrofits

or replacements.2

The Distillate Fuel Oil Market

in the Winter of 1999-2000

In mid-January 2000, prices for distillate fuel oil3 and

natural gas rose dramatically in the Northeast. For

example, between January 14 and February 4, 2000, New

York Harbor spot prices for home heating oil (generally,

high-sulfur Number 2 distillate fuel oil) rose from $0.76

to $1.77 per gallon, a 133-percent increase. Over a similar

period, from January 11 to January 21, 2000, the New

York spot prices for natural gas rose from $2.65 to $11.75

per million Btu, an increase of more than 340 percent.

Retail prices for distillate fuel oil—the prices faced by

consumers—rose less dramatically but still showed

strong increases. For example, between January 17 and

February 7, 2000, the average price of home heating oil

for residential customers in New England rose from

$1.18 to $1.96 per gallon, a 66-percent increase. For the

typical household with a 275-gallon tank that was filled

up at the peak price, the increase amounted to approximately $140 for an average fill-up (two-thirds of a tank).

During the same period, the New England retail price

of diesel fuel (low-sulfur distillate used for transportation) rose from $1.44 to $2.12 per gallon, a 47-percent

increase.4 In February, the return to warmer weather

and the arrival of new distillate supplies, mainly in the

form of imports, relieved the market imbalance and

prices fell.

In the markets for distillate fuel oil, as in all competitive

markets, the balancing of supply and demand sets

prices. Any factor that leads to a significant imbalance—insufficient supply to meet demand or, vice

versa, supply that exceeds demand—can cause sharp

price changes. The key factors that influence prices in

distillate fuel oil markets include supply and demand in

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options vii

1In New Jersey, environmental regulations limit consumption of high-sulfur distillate fuel oil by large-volume distillate users.

2Furnace tuneups, insulation, and other efficiency measures may also reduce distillate consumption; however, they are unlikely to have

a significant impact and are not included in this study.

3Throughout this report, the term “home heating oil” is used to indicate Number 2 high-sulfur distillate fuel oil. There are exceptions to

this definition which, for the sake of improved communication to a broader audience, are often simplified—for example, Number 1 distillate

oil and low-sulfur Number 2 distillate can also be easily used for home heating if necessary and available. Price usually precludes their use

for heating.

4Diesel fuel oil and home heating oil are both distillate fuel oils. The primary difference is that on-road diesel fuel has a lower maximum

sulfur content and is subject to Federal and State motor fuels taxes. Diesel has slightly higher cost, excluding taxes, than high-sulfur distillate

or home heating oil.
the world crude oil market, supply and demand in the

markets for competing fuels (such as natural gas), the

status of distillate fuel oil refining and delivery capacity,

the level of stocks held by wholesalers and retailers, and

weather-induced fluctuations in demand. The last factor, weather, is especially important in the market for

home heating oil, because its chief uses are for heating

homes in the Northeast and meeting the marginal fuel

requirements of some industrial plants and power

plants when demand is high and other fuels are not

available.

Sharp movements in any combination of the factors

mentioned above can cause, and historically have

caused, significant swings in distillate fuel oil prices. In

the winter of 1999-2000, several factors appear to have

played key roles in the price increases seen in the Northeast: rapidly rising world oil prices, lower than normal

inventories of distillate fuel oil, adverse weather conditions, constraints on natural gas pipeline capacity in

some areas of the Northeast, and delivery and production problems for distillate fuel oil. These factors taken

together led to the sharp increases in distillate fuel oil

and natural gas prices seen in the Northeast in

mid-January 2000.

When the colder weather hit in January, consumers

increased their demand for both home heating oil and

natural gas, and prices rose. Because distillate fuel oil

stocks were below normal levels, quickly available supplies were limited and prices responded sharply to the

increase in demand. At the same time, the demand for

natural gas in the region stretched the capacity of some

pipelines, and natural gas customers on interruptible

contracts, mainly distillate-switchable large industrial

and power plants,5 were asked to switch to their alternative fuel—primarily, distillate fuel oil. When customers

seeking to avoid high natural gas prices and interruptible natural gas customers entered the distillate fuel oil

market, the upward pressure on distillate oil prices

increased still further.

Coming into the winter of 1999-2000, world oil prices

rose dramatically. After several years of low prices, the

price of crude oil rose from approximately $12 per

barrel6 in February 1999 to about $34 per barrel in early

March 2000—still much lower than the record high

world oil price of $70 per barrel (in 1999 dollars) seen

in 1981. Members of the Organization of Petroleum

Exporting Countries (OPEC) and key non-OPEC countries, notably, Mexico and Norway, had reduced their

production in response to the low crude oil prices in

1997 and 1998. The production decline, in combination

with increased consumption in industrialized countries

and Southeast Asia, led to an imbalance in world crude

oil supply and demand: more was being consumed than

produced. This, in turn, led to a drawdown of world

crude oil inventories.

A related drawdown occurred in distillate fuel oil inventories. With crude oil prices rising faster than product

prices in 1999, refiners saw their operating margins

shrinking. In response, they reduced their purchases of

expensive crude oil and their production of refined

products, including distillate fuel oil. The production

cutbacks contributed to a nationwide drawdown of distillate fuel oil inventories toward the end of 1999. Given

the normal stocks and the relatively warm weather in

early December, the drawdown in December was stronger than expected, particularly in the Northeast.7 For

example, in New England stocks of high-sulfur distillate

fuel oil fell by 35 percent, from 11.6 million barrels in

early December to 7.5 million barrels in early January.

Similarly, in the Central Atlantic,8 high-sulfur distillate

fuel oil stocks fell by 24 percent, from 24.5 million barrels

in early December to 18.6 million barrels in early February. Although heating oil inventories often decline in

December, the magnitude of the stock draw was greater

than expected from historic patterns.

When cold weather hit in January, low stocks could provide little supply, and prices reacted strongly. During

the week of January 22, 2000, temperatures in the New

England and Middle Atlantic areas shifted from being

15 to 17 percent warmer than normal, respectively, to 24

and 22 percent colder than normal. The change

increased weekly heating requirements by about 40 percent. As a result, the demand for distillate fuel oil

increased in all segments of the market. Residential and

commercial consumers increased their use of distillate

fuel oil to heat their homes and businesses, power companies increased their use to meet the demand for electricity (in some cases by switching from natural gas),

and industrial customers with dual-fired facilities

increased their use of distillate fuel oil by switching from

natural gas, either as required by their gas supply contracts or to avoid the higher price of natural gas. The

problem of unexpected rapid increases in demand for

viii Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

5Interruptible contracts, as an industry practice, equate “quality of service with cut-off temperatures”—the lower the cutoff temperature,

the higher the quality of service and the higher the transportation rate charged. When temperatures fall below specified cutoff temperatures,

the gas transporter/marketer may provide notice of up to 24 hours, after which the customer is to stop consuming gas. Notice to cut off

usage is not necessarily automatic.

6West Texas Intermediate spot oil price.

7The Northeast is defined as Maine, Vermont, New Hampshire, Connecticut, Rhode Island, New York, New Jersey and Pennsylvania.

This conforms to Census region 1, composed of Census divisions 1 and 2 (New England and Middle Atlantic).

8The Central Atlantic, also known as Petroleum Administration for Defense District (PADD) 1b, consists of New York, Pennsylvania,

New Jersey, Delaware, Maryland, and the District of Columbia.
distillate fuel oil was aggravated by serious delivery

problems. For example, Coast Guard ice breakers

worked overtime to keep the Hudson River open during

the coldest weather, and high winds and rough water in

Long Island Sound made it too difficult for barges to

unload heating oil from a waiting tanker in New Haven,

Connecticut, in early February.

The pressure put on distillate fuel oil markets by the

sudden change in weather was exacerbated by relatively

high natural gas prices. In some uses like boilers or generators, natural gas and distillate fuel oil can be substitutes for one another. If the price of one rises relative to

the other, some consumers—mostly large industrial

facilities or power plants—will switch to the other fuel.

In October 1999, wellhead and spot market prices for

natural gas were 35 percent and 60 percent higher,

respectively, than in October 1998. The increase was due

in part to higher prices for competing fuels and in part to

expectations of higher natural gas consumption if normal weather patterns developed.

When the weather turned colder in the Northeast in late

December 1999, natural gas spot prices for delivery to

the New York citygate rose substantially. Early in

December natural gas prices were generally below $3.00

per million Btu, but on December 21 they rose to $4.11,

and they stayed between $3.55 and $4.87 per million Btu

through December 29. New York citygate prices fell substantially in early January 2000, before rising to $6.34 per

million Btu on January 18. Gas traded above $6.00 per

million Btu on a majority of the days between January 13

and February 13. Gas pipeline capacity into the Northeast was heavily utilized during the period. Several

pipeline companies indicated that they had reached new

peak levels for service; representatives of one company,

Transco, testified that they had no interruptible capacity

available on their system from October 20 to the date of

the testimony, February 24, 2000.

In general, the ability to bring natural gas into the Northeast is more limited than in other areas of the country.

The region receives the majority of its natural gas supplies through a single supply corridor from the Southwest through Pennsylvania and New Jersey. In addition,

the Northeast markets are separated from major natural

gas supply areas in the U.S. Southwest and western Canada by substantial distances.

Although New York citygate natural gas prices and

New York Harbor distillate fuel oil prices are about

equally volatile, retail natural gas prices to residential

customers appear to be less volatile than retail heating

oil prices. For residential natural gas customers, the distribution charges added by local distribution companies

(about $4.00 per million Btu) mute the effects of citygate

price volatility. Further, the purchasing and billing

practices of natural gas distribution companies also can

obscure short-term price fluctuations.

To address the surge in heating fuel prices, the Federal

Government responded with release of funds from

the Low Income Home Energy Assistance Program

(LIHEAP), to relieve some of the financial burden to

low-income households. The surge in distillate home

heating oil prices subsided four weeks after it started.

Distillate Fuel Oil Consumption

Among customer types in the Northeast, residential consumers are by far the largest users of distillate fuel oil,9

excluding transportation use. In 1997 they accounted

for more than two-thirds (68 percent) of the distillate

fuel consumption in the region. The entire buildings sector—residential plus commercial users—accounted for

more than 90 percent of total distillate fuel oil consumption in the region. Industrial firms and power plants

accounted for smaller shares, 8 percent and 2 percent,

respectively, on an annual basis. However, while small

on an annual basis, the role played by industrial users

and power plants can vary significantly during the

course of a year.

In the residential sector, distillate fuel oil is mostly used

for home heating, primarily in the Northeast. Nationwide, distillate fuel oil accounted for only 8 percent of

the energy delivered to the residential sector in 1997, but

73 percent of that consumption occurred in the Northeast. Homes in the Northeast rely on home heating oil

for heating because heating oil prices compare favorably

to other heating fuels in the region. Even with the occasional surge in heating oil prices, historically, heating

with distillate fuel oil in the Northeast has been less

expensive than heating with natural gas. An illustrative

example, using actual household heating bills, estimated that a house on Long Island saved $1,800 in fuel

costs (in real 1999 dollars) over the past 20 years by continuing to use heating oil rather than switching to natural gas for heating. Although natural gas heating

systems tend to be slightly more efficient than comparable oil heating systems, the study assumed for simplicity

of presentation that their efficiencies were equal. In that

sense, the analysis overestimates the fuel savings that

resulted from staying on heating oil. On the other hand,

the savings are even larger when the cost of the new gas

furnace needed to switch fuels is included.

Over the past 20 years, residential use of distillate fuel oil

in the Northeast has declined by 20 percent, and the

number of customers using it has declined by 10 percent.

Efficiency gains in building shells and furnaces,

combined with warmer winters, have contributed to

the decline. In addition, the construction of new gas

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options ix

9The consumers are residential, commercial, industrial, and electricity generators.
pipelines into the region has given more consumers the

choice between distillate fuel oil and natural gas. Since

1993, however, distillate fuel oil prices have been relatively low, allowing it to maintain a 30-percent share of

the heating market in new homes in the region. Projections from the Annual Energy Outlook 2000 (AEO2000)

show this trend continuing over the next 5 years.

Although generally small in comparison with residential use, distillate fuel oil use in other sectors in the

Northeast can have a significant impact on prices, especially when demand is strong and supplies are tight. As

in the residential sector, distillate fuel oil use in the commercial sector has declined over the past 20 years, and its

use is expected to continue to decline over the next 5

years. In the commercial sector, distillate fuel oil consumption declined from 18 percent of total commercial

energy use in the Northeast in 1980 to 12 percent in 1997.

Typically, distillate fuel oil is used in the commercial

sector for heating, water heating, cooking, and electricity generation. Using 1995 data for buildings whose

owners reported that they could switch heating fuels

without any new equipment purchases or retrofits, it is

estimated that just under a quarter (52 trillion Btu or

about 9 million barrels) of the distillate fuel oil used in

the commercial sector in the Northeast could be

switched to other fuels, such as natural gas.

In the industrial sector, distillate fuel oil is a relatively

minor fuel, accounting for only 4 percent of total U.S.

industrial fuel consumption in 1997. In the Northeast,

the 79 trillion Btu (about 13.5 million barrels) of industrial distillate fuel oil consumption in 1997 accounted for

only 3 percent of total industrial fuel consumption. The

consumption of distillate fuel oil in the industrial sector

in the Northeast is divided nearly equally between manufacturing and nonmanufacturing uses. In the nonmanufacturing segment, where distillate fuel oil is used

primarily for on-site transportation (moving things

around the plant and farm sites), it is unlikely that a significant portion of it could be easily switched to another

fuel. Within the manufacturing segment in the Northeast the key uses of distillate are as a boiler fuel (37 percent), as a process fuel (32 percent), for heating and

ventilation (12 percent), and for on-site transportation

(9.8 percent). Using 1994 data,10 it is estimated that

approximately 24 percent (9 trillion Btu or about 1.6 million barrels) of the distillate fuel oil used in the Northeast

manufacturing segment could be switched quickly to

other fuels without equipment purchases or retrofits.

Over the next 5 years, distillate fuel use in the Northeast

industrial sector is expected to increase by just over

1 percent annually, but the rate could vary depending on

oil prices.

Oil plays a small role in the electricity generation sector,

and generation from distillate fuel oil is a very small portion of that. In 1998, oil accounted for less than 3.4 percent of total U.S. electricity generation, and generation

from distillate fuel oil accounted for only 0.4 percent of

total generation. Overall, the share of generation from

oil has been declining for some time, as natural gas has

become more available and the efficiency of new natural

gas generating technologies has continued to improve.

This trend is expected to continue over the next 5 years.

Even in the early 1980s, when oil-fired generation was

more important, the share from distillate fuel oil never

exceeded 1 percent. The vast majority of the oil used for

electricity generation is residual fuel oil.

In the Northeast the power generation sector is more

dependent on oil than in other parts of the country. For

example, in New England 24 percent of generation

comes from oil. Even in these more oil-dependent

regions, however, distillate fuel oil plays a small role—

only 6 percent of total oil generation. Distillate fuel oil is

typically used in small amounts in steam plants for

flame control and in relatively inefficient combustion

turbines and internal combustion engines when the

demand for electricity is high and other fuels are

unavailable to generate electricity. If all the distillate fuel

oil use in the power generation sector in the Northeast

were switched to another fuel—most likely, natural

gas—it would amount to about 35 trillion Btu (6.1 million barrels) of distillate fuel oil. Under more severe

weather conditions, as experienced in December 1989,

the annual consumption could rise to as much as 41 trillion Btu (7.1 million barrels). It is unreasonable to

assume, however, that all of that fuel use could be

quickly switched. Some of the plants that burn distillate

fuel oil are not dual-fired and may not have easy access

to natural gas.

In summary, on an annual basis, if all the distillate fuel

oil used in the Northeast commercial, industrial, and

electric power sectors that could conceivably switch

(even with equipment purchases and retrofits) were

replaced with another fuel, total distillate fuel oil use

would be reduced by 33.6 million barrels. However, as

discussed earlier, it is unlikely that all of this distillate

fuel oil use could be switched to another fuel. Looking

only at the quantity of consumption that is estimated to

be reasonably switchable,11 the total that could be made

available for residential use is only 13.1 million barrels.

x Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

10Energy Information Administration, Manufacturing Consumption of Energy 1994, DOE/EIA-0512(94) (Washington, DC, December

1997).

11Because distillate fuel oil consumption for electricity generation in periods other than the winter heating season does not adversely

affect home heating oil prices, it is excluded from the “reasonably switchable” calculation.
We believe this to be a high estimate of the distillate fuel

switching potential in the Northeast.12 In addition, as is

explained later, the reduction in nonresidential distillate

fuel use may not lead to a permanent increase in supplies available for home heating, and the volatility in the

market may not be reduced.

Because the use of distillate fuel oil varies significantly

across the seasons, it is more important to look at the

potential for reducing nonresidential sector use during

the winter months, when the use of distillate fuel oil for

heating is greatest and rapid price increases are most

likely. Using historical information about the distribution of seasonal use of distillate fuel oil in the commercial, industrial, and electricity generation sectors, it is

estimated that the volume of their winter season switchable distillate use could be as high as 133,000 barrels per

day—about 11 percent of residential heating oil use in

the winter (Table ES1).

Because the Northeast’s residential sector is highly

dependent on home heating oil, whose prices are normally highest in the winter, colder-than-normal winter

weather will further increase the demand and prices for

heating oil. If, in addition, heating oil resupply problems

are coupled with additional distillate fuel oil demand of

100,000 to 133,000 barrels per day from interruptible

and/or fuel-switchable customers, home heating oil

prices could rise sharply, as they did in the winter of

1999-2000.

Switching or Converting

From Distillate Fuel Oil

Homeowners can be given increased access to distillate

fuel oil or, at least, protected from steep price runups

in future winters. Actions that may help include:

encouraging distillate fuel oil users outside the residential sector to use other fuels, particularly natural gas;

improving the operation of the Northeast distillate fuel

oil market (for example, with better planning tools, more

local storage capacity at the wholesale, retail, and consumer levels, and/or better delivery channels); and providing more direct assistance to consumers. Each of

these approaches has practical limits, however, and their

costs would have to be borne by consumers and

taxpayers.

Natural Gas Market Effects

Possible changes to natural gas use considered in this

report include (1) keeping large consumers with

“switchable” equipment (that can use either fuel) from

moving to distillate fuel oil when gas prices are high;

and (2) in combination with keeping switchable firms

on natural gas, moving some of the “distillate-only”

capacity13 to natural gas. In this analysis it is estimated

that, over a 3-month winter period (contiguous December, January, and February), the maximum “averageday” switchable fuel consumption14 is equivalent to

about 133,000 barrels of distillate fuel oil per day. No

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options xi

Table ES1. Estimated Distillate Fuel Oil Switching and Conversion Potential in the Northeast by Sector

Sector

Maximum Annual

Switchable Volume

(Million Barrels)

Daily Average Daily Switchable

Volumes in December-February

(Thousand Barrels per Day)

Conversion Potential If All Distillate

Use by Large Users Were

Converted to a Different Fuel

(Million Barrels)

Commercial. . . . . . . . . . . . . . . . . 8.6 86 20.0

Industrial . . . . . . . . . . . . . . . . . . . 1.6 16 6.5

Electricity Generationa . . . . . . . . 2.9b 31b 7.1

Total . . . . . . . . . . . . . . . . . . . . . 13.1 133 33.6 a

Because usually only one-third of distillate consumption for electricity generation occurs in the winter months (December, January, and February), the consumption shown is the estimated winter use portion, assuming that 40 percent of the year’s distillate use might occur in the winter of an

unusual year. b

Winter only.

Source: Tables in Chapter 3 of this report.

12The methodology used to derive the maximum distillate fuel that is switchable in the short run intentionally overestimates the actual

amount. Because actual consumption data for January and February 2000 are not available, the switchable amount was calculated by sector

(commercial, industrial, and electric generation) from available data based on normal weather and adjusted to approximate the conditions

of the winter of 1999-2000. Taken together, it is estimated that distillate consumption during an unusually cold 3-month winter period could

be as much as 42 percent higher than consumption during a normal winter.

13“Distillate-only” means that the equipment can only burn distillate fuel oil.

14Some establishments have separate gas and distillate (or residual fuel) boilers to serve the same energy needs, choosing the fuel and

equipment to be operated on the basis of relative fuel costs.
three-month winter period in the past 20 years has had

average-day switchable distillate consumption that

exceeded this average. On very cold winter days, however, switchable consumption may be higher for brief

periods.

The conversion of distillate fuel oil consumers to natural

gas by 2005 depends on the economics (end-use equipment and gas supply costs) and the effectiveness of their

implementation. Because the ultimate effectiveness of

policy initiatives cannot be known in advance, the estimates used in this report are sensitivities representing

different sizes of the market that might be moved away

from distillate fuel oil. A commitment to switch to natural gas usually means that the consumer will also have to

commit to firm contracts for supply, transportation, and

local delivery of the gas.

Conversion from distillate to natural gas would require

a natural gas supply line and gas burners in existing distillate-burning equipment, such as boilers or turbines.

Alternatively, installation of a new system that burns a

different fuel may be considered when fuel price differences are expected to be large for some time (economic

conversion) or when the original equipment fails and

needs to be replaced or repaired. The rate of equipment

failure is likely to be the primary factor affecting market

opportunities for conversions from distillate fuel oil to

other fuels.

The Northeast receives 71 percent of its current natural

gas supply15 from net inflows from other U.S. regions, 24

percent from international imports, and 2 percent in the

form of liquefied natural gas (LNG) imports. Less than 3

percent of the supply comes from production in the

Northeast region, all of which occurs in the Mid-Atlantic

Census division. New England is highly dependent on

flows from other U.S. regions, obtaining 89 percent of

its current supply from the domestic transportation

network.

Natural gas flow from the Sable Island pipeline project

began in the first week of January 2000 to serve parts of

New England and Eastern Canada. The pipeline was

first forced to shut down on January 7, 2000, due to

hydrate formation in a subsea line (essentially, ice

sludge blockage).16 The second shutdown occurred in

mid-January, when the gas processing plant developed

a gas leak and was again shut down for repair.17 Early

gas flow reached about 110 million cubic feet per day, of

which 36 million cubic feet per day entered U.S. markets.

By early March, the gas flow was about 300 million cubic

feet per day to markets in the United States. The Sable

Island project is expected to reach flows of 450 million

cubic feet per day by summer 2000, the majority of

which is expected to serve U.S. markets.

Pipeline capacity entering the entire Northeast region

was 12,519 million cubic feet per day at the beginning of

1999. If large-volume users with dual-fired capability

switched from distillate to natural gas, 839 million cubic

feet per day of additional pipeline capacity would be

needed. By 2005, the additional new capacity required,

relative to the beginning of 1999, to provide gas service

to the converted customers and to supply the baseline

increase in gas use could reach 2,241 million cubic feet

per day.

A number of recently completed pipeline expansion

projects (including the completed expansion from

Canada’s Sable Island gas fields to New England), as

well as the proposed Millennium, Independence, and

associated projects, are intended to meet the growing

demand for natural gas in the Middle Atlantic and New

England regions. Although the demand for natural gas

in the Northeast is expected to grow, all pipeline construction projects must satisfy a number of State, environmental, and regulatory requirements and gain public

acceptance before they are approved and considered

certain. Consequently, the fate of any proposed project

remains uncertain until final approval is received. The

current proposals alone represent about 2 billion cubic

feet per day of potential additional capacity, well in

excess of the additional capacity that would be needed

on a peak day (839 million cubic feet per day) to address

the new gas demand resulting from switching out of

distillate, and nearly enough for the additional 2005

potential requirements, including the baseline projected

growth in natural gas consumption. The Sable Island gas

supply project (about 400 million cubic feet per day to

New England) also appears to be more than adequate to

handle the additional capacity (340 million cubic feet per

day) needed to address New England’s portion of the

new switching to gas, leaving the need for an additional

506 million cubic feet per day to support the potential

conversions through 2005 (see Chapter 4 of this report).

Serving the switchable market with natural gas appears

to be physically feasible by fall 2002 with projects

already built or with construction of expansion projects

planned for the Northeast; however, those projects were

not intended to provide firm service to current interruptible customers. Because of the lack of sufficient commitments, the construction dates for proposed pipeline

projects to the Northeast, such as Market Link, are

uncertain. Even if the proposed projects are built, at least

250 million cubic feet per day of additional capacity

would be necessary to also serve the new potential

xii Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

15Current supply is the sum of production, imports, and net inflow from other domestic regions. It excludes storage withdrawals and

production within the region.

16NGI’s Daily Gas Price Index (January 18, 2000), p. 3.

17NGI’s Daily Gas Price Index (March 9, 2000).
conversion customers in 2005. Because the planned

pipelines were sized and targeted for specific customers

with specific operating requirements (e.g., pressures),

the system may not be capable of serving all the additional requirements of the former distillate users and,

therefore, could require even more additional capacity

than estimated. One of the major hurdles that potential

new Federal policies must overcome, however, appears

to be economic. For industrial consumers and electricity

generators with the capability to switch between natural

gas and distillate fuel oil, firm year-round contracts for

natural gas may not be economical in the Northeast. The

New Jersey Board of Public Utilities findings on pipeline

construction for interruptible customers are consistent

with this study:18

“To design and construct a gas distribution system

to serve the interruptible customer class on a yearround basis would require significant investment

and take years to install. Furthermore, on a cost of

service basis, the resultant tariff rates would

undoubtedly make it uneconomical for large customers to avail themselves of year-round service.

Therefore, absent the current interruptible service

offerings by natural gas utilities, larger customers

would burn an alternate fuel continuously and further complicate the supply situation.”

Through 2005, several potential obstacles or unintended

consequences are possible if establishments with current

dual-fuel switchable systems become firm natural gas

customers. Because any capability to meet the new load

will require pipeline and storage capacity expansion

that is sufficient to meet the new peak, the costs of the

incremental pipeline and storage capacity will have to

be recovered from new customers, as is usually the current policy of the Federal Energy Regulatory Commission (FERC). Otherwise, costs to existing firm gas

customers (usually residential and small commercial

customers) will increase. Firm transportation capacity

has proved to be too costly for fuel-switchable customers in the past.

When interruptible customers use the natural gas system, at least some of the resulting revenues are applied

to reducing transportation costs for firm customers,

including residential users, for whom the pipelines were

originally justified and built. If interruptible natural gas

customers became firm customers, unless uncommitted

capacity were available for firm service, new capacity

would have to be built. Their previous purchases of

interruptible service would no longer benefit the firm

customers on existing capacity by reducing their costs.

Further, pipeline operators would be faced with more

unused off-peak capacity to auction off, with a very

limited base of seasonal users, thereby reducing the

value of the interruptible capacity. Pipeline companies

currently gain some revenues from the sale of interruptible capacity. There could be a considerable loss of efficiency in the operation of the gas market and the

economy in general if switchable capacity were kept on

natural gas all year round.

Distillate Fuel Market Effects

While the elimination of incremental distillate fuel oil

demand from customers switching from natural gas at

peak is likely to reduce the potential for distillate fuel oil

price spikes in the short term because of the overcapacity created, it cannot eliminate their possibility in the

longer term, and it could increase the volatility of natural gas prices. Successful conversion of large-volume

customers from distillate to natural gas could also exacerbate the potential for distillate price spikes, because it

would remove a stable base of heating oil consumption.

The remaining distillate fuel oil market would be

smaller, consisting of the portion of current customers

with a stronger seasonal usage pattern. Thus, distillate

fuel oil dealers and refineries would be inclined to

reduce inventories given the smaller market, the relative

swing between seasons could be larger, and inventory

management could be more difficult and uncertain. As

the stock cushion diminished, the distillate fuel oil market could become less prepared for sudden increases in

demand or decreases in supply.

Current Market Mechanisms

Simple and relatively low-cost market mechanisms

are already provided by distillate and natural gas distributors to soften price shocks created by weather.

About 98 percent of the Northeast heating oil dealers

participating in a voluntary survey offer a budget payment plan,19 as do all gas utilities. The budget plans estimate the annual heating bill and allow customers to pay

11 equal amounts plus a 12th payment that reconciles

any discrepancy in collections. Other pricing mechanisms that can minimize the risk of price shocks include

price caps and guaranteed pricing.

About 54 percent of the Northeast oil dealers responding to a voluntary survey indicated that they provide

price cap programs on distillate fuel oil to residential

customers for a small “insurance” premium, and 55 percent offer guaranteed pricing. For a small premium pergallon charge, dealers cap the maximum price they

charge to residential customers. Others simply offer a

fixed price per gallon charge for a 12-month period.

These programs, for customers who had chosen them,

would have lessened the financial pain of the 1999-2000

surge in winter distillate prices or completely insulated

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options xiii

18State of New Jersey, Board of Public Utilities, Board of Public Utilities Heating Oil Review (February 23, 2000), p. 6, web site

www.state.nj.us/bpu/wwwroot/communication/Govrpt.PDF.

19Gray, Gray, & Gray, Oilheat Survey 1999, web site www.graymail.com.
the customers from it. The extent of participation in

these payment programs is not known; however, the

persistence of relatively low world oil prices for all but

one of the past 8 years suggests that they may not have

been widely used.

Some existing market mechanisms are already available

to mitigate future heating oil price spikes, including: (1)

for large-volume, distillate-natural gas switchable users,

maintaining adequate distillate fuel oil backup at the

start of the winter season to reduce the potential for

large intrusions into the heating oil market during very

cold periods; (2) for residential consumers who buy new

oil-heated homes, installing a larger oil tank to reduce

the number of required fill-ups during the peak period;

(3) for residential heating oil customers, adopting any

one of the fuel oil purchasing plans (budget plan, cap

price, or fixed price) that will meet their preferences for

avoiding risks; (4) for all residential heating oil consumers, adding additional conservation measures, buying

more efficient heating systems when they need to be

replaced, and, in some cases, switching to a different

fuel. As recent reports in the press have indicated, some

Northeast consumers have reacted to the recent price

spike by switching to natural gas or by purchasing

high-efficiency heating systems, or are seriously considering switching to a more predictable heating oil plan.

As a result of recent hearings by the New Jersey Board of

Public Utilities, the Board noted that it will reconsider

reimposing the requirement that interruptible gas

customers maintain adequate alternate fuel supplies:

“Given the magnitude of the [distillate volumes]

involved, it is unlikely that this would have a significant

effect on the price of heating oil. It is, however, worth

considering as part of a future, overall response plan.”20

Other market approaches that are available for the electricity generation market include the expansion of interregional transmission capability and the construction

and expanded use of nuclear, coal and renewables generation. Besides switching to other fuels for generation,

regional distillate fuel oil use could be reduced by

increasing interregional electricity transmission capacity and/or building new capacity to displace existing

capacity. Given the high cost and long lead times for

building new transmission capacity, however, displacing intermittent use of distillate fuel oil by electricity

generators may not be an economical choice.

New gas-fired plants can be brought on line in 1 to 2

years, and many are already planned. Other new capacity types—coal, wind, biomass, nuclear and solar—are

much less economical than gas and normally take longer

to bring on line. In addition, because wind and solar are

not dispatchable,21 they probably are not good substitutes for plants that use distillate fuel oil. The industrial

sector already uses the maximum available amounts of

black liquor and residues for cogeneration applications.

Other incremental cogeneration opportunities are small

in the 2000-2005 time frame without substantial financial

incentives. The situation in the residential and commercial sectors is similar.

xiv Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

20State of New Jersey, Board of Public Utilities, Board of Public Utilities Heating Oil Review (February 23, 2000), p. 6, web site

www.state.nj.us/bpu/wwwroot/communication/Govrpt.PDF.

21An electricity generator is “dispatchable” if it can provide electricity on an as-needed basis. Solar and wind plants are intermittent

generators and are therefore not dispatchable.
1. Introduction

Purpose

This study was undertaken at the request of the U.S. Secretary of Energy, Bill Richardson.1 As stated by the President, "I've asked Secretary Richardson to conduct a

60-day study on converting factories and major users

from oil to other fuels, which will help to free up future

oil supplies for use in heating homes."2 The principal

purpose of this study is to examine the feasibility and

impacts of converting factories and major users of heating oil to different fuels, and to discuss other possible

supply-related policy options that may mitigate future

heating oil supply problems in the Northeast.3 This

study examines how the market behaved in the winter

of 1999-2000, identifies the key price and demographic

factors that influence the market, compares the market

behavior in 1999-2000 with that in previous winters, and

discusses options that could encourage major users of

distillate fuel oil to convert to other fuels. Given the oil

price environment in the winter of 1999-2000, the

options considered are those that could have a meaningful impact over the next 5 years.

Throughout this report, the terms “home heating fuel

oil” and “heating oil” are used to indicate number 2

high-sulfur distillate fuel oil. There are exceptions to this

which, for the sake of improved communication to a

broader audience we often simplify—for example, number 1 distillate oil and low-sulfur number 2 distillate fuel

can also be easily used for home heating if necessary and

available. Price usually precludes their normal use for

these purposes.

Review of the Oil Market Situation

Over the past 12 months, the average daily price of West

Texas Intermediate crude oil in world markets ranged

from $12 per barrel to more than $34 per barrel in early

March (before subsiding in recent weeks), as members

of the Organization of Petroleum Exporting Countries

(OPEC) and several other exporting countries cut production and world oil demand increased. Prices were

influenced by the successful adherence to announced

cutbacks in production by OPEC and key non-OPEC

members, notably Mexico and Norway. Also influencing prices were strong growth in oil consumption in the

industrialized countries (which accounted for 60 percent

of the growth in demand in 1999) and rising demand in

Southeast Asia as the economies there began to recover

from the recession of 1997-1998.

Stocks were used to meet demand growth in many countries. At the end of March 2000, world stocks of crude oil

and refined products were below average levels. In

response, prices rose from about $12 per barrel in

mid-February 1999 and over $34 per barrel in early

March 2000 (although $34 per barrel is still less than half

the peak inflation-adjusted price of $70 per barrel—$39

per barrel in 1981 dollars—that occurred in 1981). Following the OPEC agreement on March 29, 2000, to raise

production by 1.7 million barrels per day and earlier

declarations by Mexico that it would raise its oil production, crude oil prices fell into the $25 per barrel range in

early April 2000 (see discussion in Chapter 2).

Low U.S. stocks of heating oil in January 2000 set the

stage for a price spike in the Northeast.4 Low inventories

(stocks)5 left little cushion to meet sudden increases in

demand or decreases in supply without creating

upward pressure on oil prices. The demand for distillate

and diesel fuel6 in the Northeast increased in midJanuary 2000 in response to cold weather. Delivery problems, primarily affecting tanker ships and barges,7 compounded the problem of low stocks in the region by

delaying the refill of depleted stocks (inventories). As

local supplies diminished, prices surged. New England

home heating oil prices8 peaked in January at $1.96 per

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 1

1See Appendix A for a copy of the letter requesting the study.

2The White House, Office of the Press Secretary, Press conference by the President, Feb. 16, 2000, web site www.pub.whitehouse.gov/

uri-res/I2R?urn:pdi://oma.eop.gov.us/2000/2/17/1.text.1 (Washington, DC, February 17, 2000).

3Readers should note that “heating oil” is “distillate fuel oil.”

4For purposes of this study, the Northeast is defined as New England (Maine, Vermont, New Hampshire, Massachusetts, Rhode Island,

and Connecticut) and the Mid-Atlantic Census division (New York, New Jersey, and Pennsylvania). Oil supply data are collected at a larger

level of aggregation (New England, Mid-Atlantic, Maryland, Delaware, and Washington, DC). The discussions in each case refer to the

Northeast and the reader should keep the distinction in mind.

5The terms “stocks” and “inventories” are used interchangeably in this report.

6Diesel fuel is low-sulfur distillate fuel oil used for truck and heavy freight transportation.

7Frozen waterways slowed the arrival and unloading of distillate fuel oil in New York and Boston harbors.

8Home heating oil is distillate fuel oil.
gallon (again, this price is still lower than the U.S. average heating oil price in 1981 of about $2.45 per gallon in

1999 dollars—$1.29 in 1981 dollars). In response, in early

February 2000, U.S. refineries began increasing their

output of distillate, and marketers substantially

increased their purchases of imported distillate fuel oil.

It takes several weeks for refiners to increase production

and deliver product to the Northeast, and by mid- to late

February new distillate supplies began arriving and

prices began to decrease.

Distillate fuel oil imports played a major part in controlling the stock decline and moderating distillate fuel oil

prices after the first week of February. Distillate fuel oil

imports jumped from 105,000 barrels per day during the

week of February 4 to 528,000 barrels per day during the

week of February 11 and averaged more than 550,000

barrels per day for the last three weeks of February.

The surge in home heating oil and diesel fuel prices, primarily in the Northeast United States, prompted the

President's request for a review of policy options that

might help reduce the volatility of these prices in the

future. The Secretary asked the Energy Information

Administration (EIA) and the U.S. Department of

Energy's Office of Policy to conduct an analysis of the

causes of the price increases and the potential for conversion of large-volume distillate fuel users to other

fuels by 2005. The options considered in this report are:

(1) increasing natural gas pipeline capacity for deliveries

to the Northeast, (2) removing obstacles to conversions

from distillate fuel oil, (3) improving the management of

distillate fuel oil supplies, particularly by large industrial users and electricity generators, and (4) increasing

on-site distillate fuel oil storage capacity. The framework and results of EIA's analysis are described in this

report.

Chapter 2 describes what happened in the 1999-2000

winter season and what factors contributed to the rapid

price runups for heating oil in the Northeast. Chapter 3

focuses on Northeast energy consumption, describing

the historical fuel mix in the Northeast by sector and

estimating the ability of the region's large distillate fuel

oil consumers to switch to different fuels. The chapter

also examines the economics of space heating equipment choices in the Northeast, typically distillate fuel oil

or natural gas, and provides an illustrative example for

such choices. The historical costs of heating Northeast

homes using home heating oil (distillate) and natural

gas are analyzed and compared with those in the

Midwest region and the United States as a whole. The

economics of future heating fuel choices are examined,

based on fuel price projections through 2005 from EIA's

Annual Energy Outlook 2000.

9

Chapter 4 examines the current supply, infrastructure,

and processing for natural gas and describes how the

current business environment affects supply, contracting practices, seasonal pricing, and storage. The chapter

ends by examining the feasibility, from the supply perspective, and implications of moving a portion of the

distillate fuel oil demand by large energy users to an

alternate fuel like natural gas. Chapter 5 examines the

supply, infrastructure, and processing for distillate fuel

and describes how a successful conversion of large distillate fuel oil users in the Northeast might affect the

market for distillate fuel oil.

The following definitions are provided to facilitate the

discussions that follow:

Distillate Fuel Oil: Nos. 1, 2, and 4 heating oils and diesel fuels. Most often subdivided (by EIA) into:

• High-sulfur distillate fuel oil (often called "heating

oil" but has other uses, including off-highway transportation, agricultural, and industrial)

• Low-sulfur distillate fuel oil (often called "diesel

fuel" or, more appropriately, "on-highway diesel

fuel"). Although low-sulfur distillate can also be

used for heating, and sometimes is, its higher price

normally precludes its use as a heating fuel.

Technically, the high-sulfur and low-sulfur designations

are based on product specifications, whereas the diesel

and heating designations are based on use.

New England: Census Division 1 and Petroleum

Administration for Defense District (PADD) 1a.

Includes Maine, New Hampshire, Vermont, Massachusetts, Rhode Island, and Connecticut.

Middle Atlantic: Census Division 2. Includes New

York, New Jersey, and Pennsylvania.

Lower Atlantic: PADD 1c. Includes Virginia, West

Virginia, North Carolina, South Carolina, Georgia, and

Florida.

Midwest: Census Region 2. Includes Ohio, Indiana, Illinois, Iowa, Michigan, Wisconsin, Minnesota, Missouri,

Kansas, Nebraska, North Dakota, and South Dakota.

Northeast: Census Divisions 1 and 2.

Central Atlantic: PADD 1b. Includes New York, New

Jersey, Pennsylvania, Delaware, Maryland, and the

District of Columbia.

South Atlantic: Census Region 5. Includes Maryland,

Delaware, District of Columbia, West Virginia, Virginia,

North Carolina, South Carolina, Georgia, and Florida.

2 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

9Energy Information Administration, Annual Energy Outlook 2000, DOE/EIA-0383(2000) (Washington DC, December 1999).
2. What Happened to Heating Fuel Prices

in the Winter of 1999-2000?

Introduction

In mid-January 2000, a combination of adverse weather

conditions, low heating oil inventories, natural gas

capacity and delivery constraints in some areas of the

Northeast, and distillate delivery and production problems created rapid price increases in the distillate fuel oil

(heating oil and diesel fuel oil)10 and natural gas markets

in the Northeast. When spot prices for distillate fuel oil

in the Northeast surged, retail prices for heating oil and

diesel fuel quickly rose in response.11 This is not the first

time heating oil prices have spiked in the Northeast.

There were similar spikes in December 1989 and to a

lesser degree in January 1994 (see Appendix C).

Historically, distillate fuel oil prices have risen sharply

only during the high-demand winter months. In each

case, including the experience in January and February

2000, cold weather increased demand unexpectedly and

hindered the arrival of new supply, as frozen rivers and,

in some cases, high winds slowed the docking and

unloading of barges and tankers. Stocks (inventories)

were drawn down rapidly because the demand for distillate ful oil exceeded new supply. Because space heating in the Northeast depends heavily on distillate fuel oil

from imports and from the Gulf Coast, which can take

weeks to arrive, resolution of market imbalances is not

immediate. Distillate fuel oil stocks approached very

low levels in January and February, and wholesale buyers, concerned about supply availability, rapidly bid up

the price of the new supplies that did arrive, until

warmer weather and increased new supply relieved the

market imbalance and prices fell.

Distillate fuel oil and natural gas prices are both affected

by cold weather. Both fuels are used for heating, and

increases in demand for either fuel can cause prices to

rise during the winter season. Furthermore, there

is some interplay between the use of the two fuels.

Some large industrial, commercial, and electric utility

customers with dual-fuel burning capability use distillate fuel oil as an alternate or peaking fuel (see Chapter

5). Some customers who normally use natural gas switch

to distillate fuel oil either because they have interruptible contracts that require them to stop using natural gas

under certain terms or conditions (such as low temperatures) or because they find distillate fuel oil economically more attractive.12 As a result, distillate fuel oil is an

important peak-demand fuel in the Northeast for residential as well as the other end-use sectors.

Distillate Market Factors

Leading to the Price Spike

One of the key factors setting the stage for the distillate

price spike in January and February 2000 was the very

low level of distillate stocks at the beginning of January.

With little inventory to absorb sudden demand or supply changes, the chances for a distillate price spike

increased with cold weather.

Crude Oil and Product Stocks Declined

in 1999

The low distillate stock situation at the beginning of January 2000 began with events in the crude oil market.

Crude prices have changed significantly over the past

year, rising by more than $20 per barrel13 (48 cents per

gallon) from under $12 per barrel in mid-February 1999

to peak at about $34 per barrel in early March 2000,

before falling back to around $25 per barrel in early

April 2000. This price increase was the result of a shift in

the world balance between production and demand. In

1998, world oil production exceeded demand, petroleum inventories rose to very high levels, and the price

of crude oil collapsed (Figure 1). In response to the

low price, OPEC and several other crude oil exporting

countries began cutting production. At the same time,

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 3

10Distillate fuel oil is a general classification for one of the petroleum fractions produced from crude oil. It is used primarily for space

heating, on- and off-highway diesel engine fuel, and electricity generation.

11Diesel fuel and home heating oil prices usually move together. They are essentially the same product, except for sulfur content.

On-highway diesel fuel, by statutory mandate, has a lower sulfur content than heating oil. In some regions, it is more economical for refiners

to distribute one product, and so low-sulfur diesel fuel is used for both on-highway uses, where it is required, and off-highway uses, where

it is not. High-sulfur distillate (heating oil) cannot be used on-highway, and it is dyed to distinguish it. Furthermore, on-highway diesel fuel

is taxed at both the Federal and State levels.

12Not all large customers with fuel-switching capability leave natural gas fuel to use distillate. Some power plants, especially in New

England, that use natural gas as baseload or intermediate load fuel will switch to residual fuel oil when the economics are favorable.

13West Texas Intermediate (WTI) spot price.
Asian economies continued to recover from the recession of 1997-1998, and world demand grew fairly rapidly. The result was that world oil demand exceeded

production and, consequently, crude oil and product

inventories were used to meet the demand growth.

During 1999, crude oil prices rose faster than petroleum

product prices, reducing refining margins. Higher crude

oil prices and the squeeze on product margins encouraged refiners to constrain crude oil purchases, restrict

refined product output, and draw down crude oil and

product inventories. World crude oil and product inventory levels, which had been particularly high since 1998,

sank to very low levels by December 1999. U.S. distillate

stocks were no exception to this pattern of decline.

U.S. Distillate Stocks Fell Below Normal

in December 1999

U.S. distillate fuel oil stocks began the heating season

above the midpoint of the normal range, but they were

not built as usual and ended November below the midpoint of the normal range. Demand for distillate fuel oil

in December 1999 was high, despite warmer weather

than normal: 10 percent warmer than normal nationally

and 11 percent warmer in the Northeast (Figure 2).

Distillate stocks fell rapidly in December, in part because

low refinery margins constrained refinery production to

approximately the previous year’s level (Figure 3), and

imports were at an average level.

Stocks of high-sulfur distillate fuel (home heating oil) in

the Northeast drove the U.S. distillate stock pattern.

Northeast heating oil stocks14 were high throughout

1998 and most of 1999, the remnant of the warm

1998-1999 winter. Although the seasonal stock build did

not follow the historical path, inventories were well

above the recent historical levels in New England even

into November, and in the Central Atlantic region15 they

were still solidly in the normal range (Figures 4 and 5).

However, heating oil stocks in New England fell by

more than 35 percent, from 11.6 million barrels in early

December to less than 7.5 million barrels in early January. Similarly, in the Central Atlantic region, heating oil

stocks declined by 24 percent, from 24.4 million barrels

in early December to 18.6 million barrels in early January. The pace of the drawdown through the rapid price

increases merits highlighting, particularly in New England, where stocks fell from more than 11 million barrels

in early December to less than 3 million barrels by early

February. In the Central Atlantic the level of stocks

was much higher and the pace of decline was not as

4 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

January January January January January January January January

1993 1994 1995 1996 1997 1998 1999 2000

3.3

3.4

3.5

3.6

3.7

3.8

3.9

Billion Barrels

Actual (January 1993 - January 2000) Average (1990-1995)

Figure 1. OECD Petroleum Inventories, 1993-2000

Note: OECD = Organization for Economic Cooperation and Development.

Source: Energy Information Administration, International Petroleum Monthly, DOE/EIA-0520 (Washington, DC, various issues),

Table 1.5.

14The terms “stocks” and “inventories” are used interchangeably in this report.

15The Central Atlantic region is a petroleum supply region designation that includes New York, New Jersey, Pennsylvania, Delaware,

Maryland, and Washington, DC. It is also known as Petroleum Administration for Defense District 1b (PADD 1b).
Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 5

Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun

2.0

2.2

2.4

2.6

2.8

3.0

3.2

3.4

3.6

3.8

4.0

Million Barrels per Day

1997-1998 1998-1999 1999-2000 Average (1994-1998)

Figure 2. U.S. Distillate Product Supplied by Month, 1994-2000

Note: The “Product Supplied” line in the graph provides a proxy measure of consumption.

Source: Energy Information Administration, Petroleum Supply Monthly, DOE/EIA-0109 (Washington, DC, various issues), Table

2; and Weekly Petroleum Status Report, DOE/EIA-0208(2000-12) (Washington, DC, March 24, 2000), Table 10.

Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun

2.0

2.2

2.4

2.6

2.8

3.0

3.2

3.4

3.6

3.8

4.0

Million Barrels per Day

1997-1998 1998-1999 1999-2000 Average (1994-1998)

Figure 3. U.S. Distillate Production by Month, 1994-2000

Source: Energy Information Administration, Petroleum Supply Monthly, DOE/EIA-0109 (Washington, DC, various issues), Table

2; and Weekly Petroleum Status Report, DOE/EIA-0208(2000-12) (Washington, DC, March 24, 2000), Table 10.
6 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52

Week of "Stock Season" (April-March)

0

2

4

6

8

10

12

14

16

Million Barrels

1999-2000

1998-1999

Range (1994/95-1997/98)

Apr Sep Nov Jan

Figure 4. Stocks of High-Sulfur Distillate Fuel Oil (Heating Oil) in New England (PADD 1a), 1994-2000

Note: The range represents the minimum and maximum stock levels by week between April 1994 and the end of March 1998.

Source: Energy Information Administration, Weekly Petroleum Status Report, DOE/EIA-0208 (Washington, DC, various issues),

Table 10.

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52

Week of "Stock Season" (April-March)

0

5

10

15

20

25

30

35

40

Million Barrels

1999-2000

1998-1999

Range (1994/95-1997/98)

Apr Sep Nov Jan

Figure 5. Stocks of High-Sulfur Distillate Fuel Oil (Heating Oil) in the Central Atlantic (PADD 1b), 1994-2000

Note: The range represents the minimum and maximum stock levels by week between April 1994 and the end of March 1998.

Source: Energy Information Administration, Weekly Petroleum Status Report, DOE/EIA-0208 (Washington, DC, various issues),

Table 10.
dramatic, as heating oil stocks fell from almost 30 million barrels at the beginning of November to less than 10

million barrels by early February. As at the national

level, distillate demand on the East Coast was very high

during December 1999—19 percent higher than in

December 1998 and 36 percent higher than in the previous month.

The reasons for the large increase in demand in December 1999 are not clear. Cooler weather than in December

1998—8.4 percent more heating degree days in New

England and 10.6 percent more in the Mid-Atlantic—

contributed to but did not entirely explain the large

increases in distillate fuel oil consumption in December

1999. In December, some energy analysts attributed the

large demand to year 2000 (Y2K) actions (i.e., stockpiling

for unexpected contingencies).16 EIA measures demand

by the volume of product that leaves the primary distribution system. This product is either stored at small bulk

plants (secondary storage), stored by retailers (secondary storage) or end users (tertiary storage), or consumed.

One Y2K hypothesis was that much of the surprisingly

high December volume was being shifted from primary

to secondary or tertiary stocks, which were not being

consumed. According to this hypothesis, the higherthan-expected demand in December would be countered by lower-than-expected demand in January when

the shifted stocks were consumed. This theory proved to

be incorrect, because end users did not appear to stockpile distillate fuel oil substantially. A second Y2K theory

attributed some of the unexpected increase to utilities

and other large natural gas users switching to oil in

order to be off the natural gas pipelines during the Y2K

rollover. This theory is consistent with the aggregate

data, but EIA does not have detailed data to confirm it.

Whatever the cause, the low stocks going into January

left the Northeast vulnerable to the price spike that

occurred when colder than normal weather brought rising demand and delivery problems.

Natural Gas Market Factors

Contributing to Distillate Fuel Oil

Price Increases

Going into the winter heating season of 1999-2000, both

heating oil and natural gas supplies were relatively

plentiful. Overall inventories in underground working

gas storage were 3.0 trillion cubic feet, about 1 percent

above the average for the past 5 years, although slightly

below the record levels of the previous year.17 The supply outlook for the Northeast was strong with the

expected opening of the Maritimes and Northeast Pipeline, which established a link between New England

markets and the Sable Offshore Energy Project off the

coast of Newfoundland. The pipeline began gas flow in

early 2000, but operational difficulties limited the flow

to below anticipated levels. Only 36 million cubic feet

per day was making its way into U.S. markets before an

operational problem forced a temporary shutdown.18

The pipeline was first forced to shut down on January 7,

2000, due to hydrate formation in a subsea line

(essentially, ice sludge blockage). The second shutdown

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 7

Prices and Stocks in December 1999

At first glance, it is surprising that prices did not

respond immediately to the large stock drawdown in

December that moved inventories from normal to

below normal. Typically, when distillate fuel oil stocks

drop to low levels during the winter season, the spread

between distillate fuel oil and crude oil prices

increases. This was not the case in 1999. Historically,

the spread between the New York Harbor spot price

for heating oil and the price for West Texas Intermediate crude oil has averaged about 8 cents per gallon during December. In December 1999, even with low stock

levels, the spread averaged only about 5 cents per gallon—about the same as it was in November.

Several factors may have contributed to the weak price

response. First, after the December stock draw, stock

levels did not hit the very low levels seen after similar

historical periods when cold weather resulted in large

stock draws and high prices. For example, at the end of

December 1989 when there was a large price spike,

stocks ended the month at 105.7 million barrels, well

below the 124.1 million barrels at the end of December

1999. Second, year 2000 (Y2K) issues may have moderated the price response. The market may have believed

the trade press articles that attributed much of the

unusual drawdown to stocks being shifted from the

primary level (e.g., bulk terminals and refineries) to the

secondary level (distributor and retail storage). Third,

the warm weather may also have lulled consumers into

not worrying about supply. Finally, and related to the

third point, there was no incentive for producers to buy

expensive crude oil in order to build up distillate product stocks, given that consumption and prices were

expected to decline.

16Cambridge Energy Research Associates, Inc., “Ringing in the New Year with Backwardation and Y2K,” CERA Alert (December 14,

1999).

17The American Gas Association (AGA) considers full gas storage capacity to be roughly 3.4 trillion cubic feet.

18By November 2000, the project is expected to deliver up to 400 million cubic feet per day to the Northeast—equivalent to about 70,000

barrels of heating oil or 65,000 barrels of residual fuel oil per day.
occurred in mid-January, when the gas processing plant

developed a gas leak and was again shut down for

repair. Early gas flow reached about 110 million cubic

feet per day, of which 36 million cubic feet per day

entered U.S. markets.19 By early March, the gas flow was

about 300 million cubic feet per day to markets in the

United States. The Sable Island project is expected to

reach flows of 450 million cubic feet per day by summer

2000, the majority of which is expected to serve U.S. markets.20

Although the availability of gas supplies was comparable to that of a year earlier, prices on both the spot and

futures markets21 were significantly higher, in part

because the prices of competing fuels were higher and

also because higher consumption levels were expected if

more normal weather patterns developed. In October

1999, gas wellhead and spot market prices were 35 percent and 60 percent higher, respectively, than in October

1998.

With the first wave of cold weather moving into the

Northeast area in late December, spot prices for gas

delivery at the New York citygate started to show substantial increases.22 In early December, delivered prices

were generally below $3.00 per million Btu. On December 20 and 21, the price jumped by $0.23 and $0.86,

respectively, to $4.11 per million Btu, and ranged

between $3.55 and $4.87 through December 29 (Figure

6). By December 30 the price had dropped to $3.07 per

million Btu, and trade press accounts noted that demand

pressures had been reduced as utilities and other firms

(primarily, industrial gas customers) shifted from natural gas consumption to oil for the Y2K rollover. While

spot and futures prices generally trended upward during the first two months of year 2000, the most dramatic

price swings were again seen at the New York citygate

as the most extreme weather conditions of the winter

reached the Northeast in mid-January. The New York

citygate price rose from $2.65 per million Btu on

January 11 to $6.34 on January 18. During the month

from January 13 through February 13, citygate gas

traded at prices above $6 per million Btu on 21 days.

In late 1999 and early 2000, gas pipeline capacity into the

Northeast was being used at heavy levels on segments

8 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

8/2/99 8/16/99 8/30/99 9/13/99 9/27/99 10/11/99 10/25/99 11/8/99 11/22/99 12/6/99 12/20/99 1/3/00 1/17/00 1/31/00 2/14/00 2/28/00 3/13/00

0

2

4

6

8

10

12

14

Dollars per Million Btu

No. 2 Heating OIl

New York Harbor

Natural Gas

New York Citygate

Natural Gas

Henry Hub, LA

Figure 6. Spot Prices for Heating Oil and Natural Gas, August 1999 - March 2000

Sources: Reuters Daily No. 2 Heating Oil, New York Harbor (converted to dollars per million Btu using 5.825 million Btu per barrel),

New York City Gate Natural Gas Prices, and Henry Hub Louisiana Natural Gas Prices.

19NGI’s Daily Gas Price Index (January 18, 2000), p. 3.

20NGI’s Daily Gas Price Index (March 9, 2000).

21Spot prices, also known as “cash prices,” are current market prices for immediate deliveries of the product. Futures prices, also known

as “forward prices,” are the prices of the commodity for delivery at a specified time and location in the future.

22The prices for gas traded at Transco Zone 6 are used as indicators of spot prices for the New York citygate. See Gas Daily (Arlington,

VA: Financial Times).
serving the Northeast region from New York up

through New England. Pipelines carrying Canadian

supplies to New England also experienced similar

heavy usage. Several pipeline companies indicated that

they had reached new peak levels for service. Officials

from Transco, a major pipeline into the region, testified

on February 24, 2000, that they had no interruptible

capacity available on their system from October 20 to the

date of the testimony.23 All requirements under firm service contracts were met, but some customers with interruptible service contracts did have their service

interrupted. The new Maritime and Northeast Pipeline

had been opened, but operational difficulties kept deliveries low. The limited availability of additional gas supplies above firm service volumes in the Northeast

market had a significant impact on citygate spot prices.

The Northeast region, as well as most regions in the

country, has seen dramatic increases in natural gas service over the past 10 years. But a very important operational characteristic of this regional market relative to

many other major natural-gas-consuming regions is that

the bulk of the supply arrives through a single supply

corridor, or gateway, from the Southwest through Pennsylvania and New Jersey. Additionally, the Northeast

markets are distant from the major supply areas of the

U.S. Southwest and western Canada (Figure 7). Storage

sites for natural gas are concentrated in western Pennsylvania, New York, and eastern Ohio, again requiring

the gas to move an additional substantial distance to the

market (Figure 8). Thus, the supply flexibility is more

limited than in regions such as the area around Chicago

that are both closer to the major producing regions and

have multi-directional access to storage and other pipeline supplies. Gas supply difficulties in the Northeast are

expected to abate once the Canadian Alliance Pipeline

begins to deliver an expected 1.2 billion cubic feet of

gas per year in 2001 to the Chicago area, much of which

will be transported further into New England and the

Middle Atlantic.

The January/February 2000

Price Spike

Northeast Heating Oil and Natural Gas

Spot Prices Spiked as Low Stocks Fell

Further

In mid-January, as a brief cold weather snap descended

on the Northeast, New York Harbor spot heating oil

prices soared from about 76 cents per gallon on January

14 to a peak of $1.77 on February 4 before falling back.

New York citygate natural gas prices rose from about

$2.65 per million Btu on January 11 to a peak of $11.75 on

January 21 (see Figure 6). Yet, while heating fuel oil and

natural gas prices rose rapidly in the Northeast, natural

gas prices at Henry Hub on the Gulf Coast and heating

oil prices on the Gulf Coast rose very little, indicating the

regional nature of the situation.

In response to the rise in spot and wholesale prices, residential heating oil and retail diesel fuel prices (i.e., distillate fuel oil prices) in the New England and Central

Atlantic regions24 turned sharply upward in the third

week of January (Figures 9 and 10). In the 3 weeks

between January 17 and February 7, New England residential heating oil prices rose by 79 cents per gallon (66

percent), from $1.18 to $1.97. During the same 3-week

period, New England retail diesel fuel prices rose by 68

cents per gallon (47 percent), from $1.44 to a peak of

$2.12 per gallon.

Outside the Northeast, retail price increases for residential heating oil were relatively mild. In the Midwest, for

example, residential prices rose by only 10 cents per gallon during the same 3-week period. The spike in the

Northeast occurred as demand increased suddenly well

above supply arrivals, driving already low distillate

stocks to levels so low that some terminals reported

runouts.25

Weather Conditions Drove January

Demand

During the week ending January 22, temperatures in

New England and the Middle Atlantic shifted from 15

percent and 17 percent warmer than normal, respectively, to 24 percent and 22 percent colder than normal.

The rapid change in weather patterns increased weekly

heating requirements for both distillate fuel oil and natural gas by about 40 percent.

Temperature declines during the winter affect heating

oil demand in a number of ways:

• Space heating demand increases.

• Electricity peaking demand increases, and power

generators must often turn to distillate to meet the

new peak needs when natural gas is not an alternative.

• Fuel switching from natural gas to distillate

occurs among some large customers with dual-fuel

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 9

23Testimony of Gary D. Lauderdale on behalf of Transcontinental Gas Pipeline Corporation before the Senate Committee on Energy and

Natural Resources, February 24, 2000.

24New England includes Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont. The Central Atlantic region

includes Delaware, the District of Columbia, Maryland, and the Mid-Atlantic Census Division, which is composed of New Jersey, New

York, and Pennsylvania (see map and discussion in Chapter 1).

25S. McCaffrey, “Heating Oil Companies Run Out in Some Areas,” Albany Times Union (February 8, 2000).
capabilities—some by choice if distillate is cheaper,

and some by the terms of their natural gas contracts.

U.S. demand for distillate fuel oil for all sectors

increased by 22 percent in the second half of January

2000 relative to the first half of the month. Although

regional demand data are not available on a weekly

basis, East Coast demand would have been a substantial

contributor to the increase, because it represents the

majority of the U.S. heating oil market (see Chapter 3).

East Coast distillate stock draw during these two weeks

accounted for more than three-fourths of the Nation’s

stock draw. Yet the total January demand for distillate

fuel oil was not unusually high, because the first half of

the month had been relatively warm. As a result, the

imbalance between supply and demand at the end of the

month is obscured in the aggregated monthly data.

The extreme cold weather, coupled with rising natural

gas spot prices in the Northeast during January and February indicated that natural gas customers with

non-firm contracts probably were either switching voluntarily or being switched contractually from gas to oil

to assure adequate gas supplies to firm contract customers, such as the residential market. The trade press

reported that utilities, along with industrial and commercial users, were buying distillate for both peaking

power and to substitute for natural gas supplies, as is

frequently the case during high demand periods.26

Although EIA has not independently confirmed it, two

10 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Western Canadian

Sedimentary Basin Sable

Island

Gulf Coast

1,900

Miles

250

Miles

400

Miles

950

Miles

1,600

Miles

1,900

Miles

1990

1995

2000

2005

200

Miles

750

Miles

1,200

Miles

2,200

Miles

4,000

0

2,000

6,000

8,000

10,000

2,200

Miles

Million Cubic Feet per Day

Figure 7. Natural Gas Pipeline Capacity Feeding into the Northeast, with Mileage from Major Supply

Sources to Regional Distribution Centers

Note: The 2005 values reflect additions that were deemed likely to occur based on ongoing and announced projects.

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

26J.P. Hamilton and M. Pittman, “Utility Contracts Exacerbate N.Y. Heating Oil Shortage,” Bloomberg Newsroom (January 26, 2000).
Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 11

Underground Natural Gas Storage Facilities

LNG Facilities

Northeast

(New England and Middle Atlantic)

Midwest

(East North Central)

43 LNG Facilities

82 Underground Storage Facilities

9 LNG Facilities

127 Underground Storage Facilities

Figure 8. Natural Gas Storage Sites in the Northeast

Note: See Chapter 4 of this report for more information on LNG storage.

Source: See Table 8 of this report.

10/4 11/1 11/29 12/27 1/24 2/21 3/20

0.75

1.00

1.25

1.50

1.75

2.00

2.25 Dollars per Gallon

New England

Central Atlantic

Lower Atlantic

Midwest

Figure 9. Retail Residential Heating Oil Prices,

Winter 1999/2000

Source: Energy Information Administration, Weekly Petroleum Status Report, DOE/EIA-0208(2000-12) (Washington,

DC, March 24, 2000), Table C3, based on data collected by

State energy offices.

10/4 11/1 11/29 12/27 1/24 2/21 3/20

0.75

1.00

1.25

1.50

1.75

2.00

2.25 Dollars per Gallon

New England

Central Atlantic

East Coast

United States

Figure 10. Retail On-Highway Diesel Prices, Winter

1999/2000

Source: Energy Information Administration, Weekly Petroleum Status Report, DOE/EIA-0208(2000-12) (Washington,

DC, March 24, 2000), Table 18.
sources in the trade press indicated that perhaps as

much as 100,000 barrels per day may have been added to

distillate fuel oil demand during the second half of January through early February as a result of fuel switching.27 This represents about 10 percent of the January

1999 demand for high-sulfur distillate oil on the East

Coast (992,000 barrels per day)

The Supply Situation Deteriorated

While Demand Grew

During the winter months, the Northeast depends on

distillate fuel oil supply from nearby East Coast refineries and from distant sources such as the Gulf Coast and

imports from other countries. It also depends on

regional inventories (stocks), which are the closest

source of supply to the end-use market and the first

source of supply used when demand exceeds ongoing

supply arrivals (see Chapter 5). If inventories are low

and dropping when demand exceeds new supplies,

prices usually rise rapidly. The high prices stimulate an

increase in new supply, but because of the region’s

dependence on distant supply sources, increases in new

supply can take several weeks or more to arrive, leaving

prices elevated in the interim.

As noted above, low stocks of distillate fuel oil set the

stage for the January/February 2000 price spike in the

Northeast spot market for distillate fuel oil. Weekly data

indicate that in the 4-week period ending February 4,

2000, East Coast distillate stocks fell by almost 20 million

barrels (41 percent), and outages occurred at some

terminals. During the 4-week period, almost 700,000

barrels per day of demand was met with stocks (inventories). At the same time, the cold weather not only

increased demand but also caused distillate fuel oil

delivery problems, with frozen rivers and high winds

along the New York, Connecticut, and Massachusetts

coastlines hindering the arrival of new supplies by water

into New York and Boston harbors.

Finally, refinery outages at the end of the week of January 21 resulted in a temporary loss of new supply and

sent even more buyers into the distillate market, which

added upward pressure on market prices. When refiners cannot produce distillate fuel oil to meet their contracts, they enter the spot market to purchase the

product from others. EIA data do not indicate the volumes involved, but during such tight market conditions

any increase in buying volume would lead to higher

prices. With the arrival of new supply falling behind

demand, stocks dropping to very low levels, and buyers

knowing that any substantial new supply must come

from distant sources, prices were bid up quickly.

A Number of Events Eventually Corrected

the Imbalance

The imbalance between distillate oil supply and demand

was resolved in February 2000 with the arrival of new

supply and a return to warmer weather, which moderated demand and lowered the volume of interruptions

in gas service. New supply can come from East Coast

refineries, Gulf Coast refineries, and imports. Ultimately, the largest increases in new supply came from

imports attracted by the high prices.

EIA data on the U.S. heating oil and diesel transportation fuel markets (Table 1) illustrate the dynamics of the

recovery. On a regional basis, EIA’s weekly distillate

data are limited to production and stocks; however, the

weekly U.S. data reflect much of what was occurring in

the Northeast. Virtually all U.S. imports during the

period of interest were delivered to the Northeast, and

the changes in U.S. distillate fuel oil stocks mainly reflect

changes in East Coast stocks.

During the three weeks ending February 25, distillate

fuel oil imports averaged 566,000 barrels per day. During the preceding four weeks, imports averaged only

162,000 barrels per day. Refinery production on the East

Coast also increased. For the three weeks ending February 25, East Coast distillate production averaged 478,000

barrels per day, which was an increase of about 91,000

barrels per day (24 percent) over the preceding four

weeks (although national distillate production rose by

only 7 percent). U.S. distillate stocks, which had fallen

from 124.1 million barrels at the end of December 1999 to

106.7 million barrels at the end of January 2000, finally

leveled off by February 18 at 99.3 million barrels and

increased slightly through the remainder of February as

the increased imports and refinery production balanced

out the now lower demand. Prices receded both in the

spot markets and at the retail level, although high crude

oil prices in March 2000 continued to keep home heating

oil and diesel fuel prices high relative to the previous

year.

What Will the Future Bring?

The distillate price spike that began in January 2000 was

the result of both demand and supply factors: cold

weather creating a surge in demand, and logistics problems that coincided with low stocks in the regional market. Such tight market situations with accompanying

price spikes are not uncommon in commodity markets,

but for distillate fuel, such price spikes have not

happened often. December 1989 and January/February

12 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

27Information provided to EIA by several State offices (discussed in more detail in Chapter 4); and Petroleum Industry Research Foundation, What Happened to Heating Oil (New York, NY, 2000), p. 6.
1994 are the only other instances in recent years.

Although such spikes are short-lived, some residential

users may be faced with financial hardships and even

the fear of not being able to pay for fuel. Programs such

as the Low Income Home Energy Assistance Program

(LIHEAP) help low-income consumers of heating fuels

during these infrequent and brief upheavals. If the market is left to function on its own, such spikes will likely

occur in the future.

The remainder of this report focuses on the question of

whether removing large customers from the distillate

market will prevent or diminish the magnitude of price

surges in the future. Large industrial, utility, and commercial customers represent incremental demand that

can exacerbate price spikes. Two potential options are

analyzed here: removing large fuel-switchable customers from the distillate fuel oil market completely during

the winter heating season and moving some additional

large-volume users of distillate fuel who currently do

not have the capability to burn other fuels. To lay the

groundwork for the discussion, the following chapters

provide some background on how large customers in

the Northeast use energy, why they choose one fuel over

another, and how the energy infrastructure works to

supply energy to large customers.

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 13

Table 1. U.S. Distillate Fuel Oil Balance

(Thousand Barrels Per Day)

Week Ending

Product

Supplied

(Thousand

Barrels per Day)

Production

(Thousand

Barrels per Day)

Imports

(Thousand

Barrels per Day)

Exports

(Thousand

Barrels per Day)

Stock Build

(Draw)

(Thousand

Barrels per Day)

Stock Level

(Thousand

Barrels)

01/07/2000 . . . . . . . . 3,007 3,341 252 157 429 122,700

01/14/2000 . . . . . . . . 3,766 3,138 231 160 (557) 118,800

01/21/2000 . . . . . . . . 4,364 3,198 152 157 (1,171) 110,600

01/28/2000 . . . . . . . . 3,866 3,267 160 147 (586) 106,500

02/04/2000 . . . . . . . . 4,192 3,259 105 158 (986) 99,600

02/11/2000 . . . . . . . . 3,866 3,471 528 147 (14) 99,500

02/18/2000 . . . . . . . . 3,716 3,392 452 157 (29) 99,300

02/25/2000 . . . . . . . . 3,761 3,445 718 159 243 101,000

03/03/2000 . . . . . . . . 3,386 3,577 200 148 243 102,700

Source: Energy Information Administration, Weekly Petroleum Status Report, DOE/EIA-0208 (Washington, DC, various issues), Table 10.
3. Consumer Markets: History, Patterns, and Outlook

Introduction

This chapter provides the historical background of

energy use trends and energy mix in the Northeast. The

purpose of the analysis is to estimate the size of the distillate fuel oil market in the residential, commercial,

industrial, and electricity generation energy sectors; to

estimate how much of that might be switchable to different fuels; and to estimate what the absolute size of conversions might be if all large-volume nonresidential

customers currently using distillate fuel oil switched to

other fuels.

Until about 50 years ago, the mix of fuels in the residential and commercial sectors included a much larger proportion of coal than it does today. The coal share of

energy use in those sectors has declined as the electricity

and natural gas shares have increased. In the Northeast,

the oil share of energy use relative to the natural gas

share in all sectors is higher than in the rest of the Nation,

primarily because petroleum products are more competitively priced and natural gas pipeline capacity to the

Northeast is smaller than capacity for other urban centers, such as Chicago (in the Midwest Census region).28

Several factors have contributed to that condition. First,

the cost of adding new pipeline capacity to the Northeast is relatively high, because the region is distant from

U.S. gas supply sources. Second, natural gas has historically been considered a scarce and premium fuel that

should be reserved for nonindustrial and non-electricity

generation uses, reducing financial incentives to build

new pipelines for those users. Third, the Northeast is

readily accessible to ships carrying distillate and cheap

residual fuel oil. Because residual fuel oil is relatively

cheap—often between 70 and 90 percent of the crude oil

price—and readily accessible to the electricity generation market, most of the switchable oil-steam units in the

Northeast use residual fuel oil when they cannot have

natural gas, or when natural gas is too expensive.

The Northeast is heavily dependent on distillate fuel oil,

but the dependence is masked by the quantity of distillate fuel oil used for transportation (Figure 11). When

transportation uses are removed, the dependence

becomes more obvious (Figure 12). In the Northeast, residential use of distillate fuel oil dominates all other stationary uses (Figure 13). In 1997 (the most recent year for

which historical data are available), residential use of

distillate fuel oil represented about 68 percent of all stationary distillate fuel oil use in the region.

Residential Sector

Heating Fuel Choice

Highlights

• Residential distillate fuel oil use in the Northeast has

declined by about 20 percent since 1980, as natural

gas availability, energy efficiency, and warmerthan-average winter temperatures have decreased

the amount of heating oil consumed in the region.

• Since 1992, heating oil prices in the Northeast have

been lower on average than natural gas prices,

allowing heating oil to retain market share in the

region, although natural gas provides heat for 65

percent of all new single-family homes built in the

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 15

1980 1985 1990 1995 2000 2005

0

2

4

6

8

10 Quadrillion Btu

Northeast

Rest of the United States

History Projections

Figure 11. U.S. Distillate Fuel Oil Consumption,

1980-2005

Note: One quadrillion Btu is equivalent to about 172 million

barrels of distillate fuel oil.

Sources: History: Energy Information Administration, State

Energy Data Report 1997, DOE/EIA-0214(97) (Washington,

DC, September 1999). Projections: Energy Information

Administration, Annual Energy Outlook 2000, DOE/EIA0383(2000) (Washington, DC, December 1999).

28The Midwest Census region is composed of Ohio, Indiana, Illinois, Iowa, Michigan, Wisconsin, Minnesota, Missouri, Kansas,

Nebraska, North Dakota, and South Dakota.
region, and thousands of residential customers

switch from distillate fuel oil to natural gas each

year.

• EIA’s Annual Energy Outlook 2000 (AEO2000) projects that average distillate fuel oil prices in the

Northeast will remain below average natural gas

prices through 2005, even in the high world oil price

case.

• An illustrative example, using actual residential billing data for heating oil and natural gas in Long

Island, NY, indicates that total heating fuel costs

over the past 20 years were nearly $1,800 lower for

this household heating with oil and using a

550-gallon underground storage tank than if it had

heated with natural gas.

Recent Trends and Current Use of

Distillate Fuel Oil in the Residential Sector

Heating oil accounted for about 8 percent of all energy

delivered to the U.S. residential sector in 1997, and

73 percent of the total home heating oil was consumed

in the Northeast Census region.29 While the total heating loads served by distillate fuel oil and natural gas

are comparable between the Midwest and Northeast

regions, the shares of the two fuels were radically

different in 1997: distillate fuel oil use for heating in the

Midwest region was about 15 percent of that in the

Northeast, and natural gas use for heating in the Midwest region was about 124 percent higher than in the

Northeast. Households in the Northeast traditionally

have relied on oil for heating because of the lower availability of natural gas and the competitive price of heating oil.30

Over the past 20 years residential oil use in the Northeast

has declined as natural gas pipelines have been built,

allowing newly constructed and existing homes to

choose natural gas instead of heating oil. Figure 14 summarizes residential-sector distillate fuel oil consumption

in the Northeast, the Midwest, and the rest of the United

States over the past 20 years and its projected use

through 2005. The effects of record warmth in the Northeast during the winters of 1990 and 1998, as well as a

more “normal” winter in 1993, are easily discernible.

Residential consumption of distillate fuel oil in the

Northeast has decreased by about 20 percent since 1980,

and the number of heating oil customers has fallen by

more than 10 percent.31 Gains in furnace and building

shell efficiency and generally warmer winters have

16 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

1980 1985 1990 1995 2000 2005

0

1

2

3

4

5

Quadrillion Btu

Northeast

Rest of the United States

History Projections

Figure 12. U.S. Distillate Fuel Oil Consumption,

Excluding Transportation, 1980-2005

Note: One quadrillion Btu is equivalent to about 172 million

barrels of distillate fuel oil.

Sources: History: Energy Information Administration, State

Energy Data Report 1997, DOE/EIA-0214(97) (Washington,

DC, September 1999). Projections: Energy Information

Administration, Annual Energy Outlook 2000, DOE/EIA0383(2000) (Washington, DC, December 1999).

1980 1985 1990 1995 2000 2005

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4 Quadrillion Btu

Residential Commercial

Industrial Electric Utilities

History Projections

Figure 13. Northeast Consumption of Distillate

Fuel Oil, Excluding Transportation,

1980-2005

Sources: History: Energy Information Administration, State

Energy Data Report 1997, DOE/EIA-0214(97) (Washington,

DC, September 1999). Projections: Energy Information

Administration, Annual Energy Outlook 2000, DOE/EIA0383(2000) (Washington, DC, December 1999).

29Energy Information Administration, State Energy Data Report 1997, DOE/EIA-0214(97) (Washington, DC, September 1999).

30Energy Information Administration, A Look at Residential Energy Consumption in 1997, DOE/EIA-0632(97) (Washington, DC, November 1999).

31Energy Information Administration, Residential Energy Consumption Survey (RECS) data for 1980 and 1997.
combined to decrease residential distillate fuel oil consumption relative to its 1980 level. Since 1993, however,

the number of heating oil customers in the Northeast has

remained relatively constant, and oil has maintained a

30-percent share in the heating market for new single-family homes,32 offsetting the number of customers

switching to gas over the same period. From 1982 to

1998, more than 1.6 million oil customers switched to

natural gas nationwide. In 1998, it was reported that

13,255 oil customers (0.2 percent) in the Northeast

switched to gas, nearly 82 percent less than the number

of oil customers that switched to natural gas in 1992.33

Figure 15 shows the changes in heating fuel shares

between 1980 and 1997.

Projections to 2005

Many factors contribute to heating fuel choice, including

fuel availability, but fuel costs tend to be more important

in times of price volatility. Perceived reliability of supply can also become an important criterion for fuel

equipment choices, as was illustrated by the gas curtailments in the 1970s. Figure 16 shows heating oil and natural gas prices for the Northeast Census region from 1980

to 2005. Although the prices for the two fuels are competitive over most of the period, it is clear that oil prices

have been lower since 1992, and they are projected to

remain slightly lower through 2005.

If higher world oil prices were expected through 2005, as

in the AEO2000 high world oil price case, heating oil

prices would still be projected to remain below gas

prices in the Northeast. With world oil prices reaching

$24.48 per barrel (1999 dollars) by 2005 in the high world

oil price case ($20.75 in the reference case), residential

heating oil prices in the Northeast would reach $8.37 per

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 17

1980 1985 1990 1995 2000 2005

0.0

0.2

0.4

0.6

0.8

1.0 Quadrillion Btu

Northeast Midwest Rest of the United States

History Projections

Figure 14. Distillate Fuel Oil Use in the Residential

Sector, 1980-2005

Note: One quadrillion Btu is equivalent to about 172 million

barrels of distillate fuel oil.

Sources: History: Energy Information Administration, State

Energy Data Report 1997, DOE/EIA-0214(97) (Washington,

DC, September 1999). Projections: Energy Information

Administration, Annual Energy Outlook 2000, DOE/EIA0383(2000) (Washington, DC, December 1999).

Natural Gas

37.3%

Heating Oil

45.2%

Electricity

9.0%

Other

8.5%

Natural Gas

46.7%

Heating Oil

36.0%

Electricity

11.7%

Other

5.6%

1980 1997

Figure 15. Residential Heating Fuel Shares in the

Northeast Census Region, 1980 and

1997

Note: The “Other” category includes kerosene, liquefied

petroleum gas (LPG), renewables, and a small amount of coal.

Source: Energy Information Administration, Residential

Energy Consumption Survey, DOE/EIA-0632(97) (Washington, DC, 1980 and 1999).

1980 1985 1990 1995 2000 2005

0

2

4

6

8

10

12

14

16 1999 Dollars per Million Btu

History Projections

Natural Gas

Heating OIl

Figure 16. Residential Fuel Prices in the Northeast

Census Region, 1980-2005

Sources: History: Energy Information Administration, State

Energy Price and Expenditure Report 1995, DOE/EIA0376(95) (Washington, DC, August 1998). Projections:

Energy Information Administration, Annual Energy Outlook

2000, DOE/EIA-0383(2000) (Washington, DC, December

1999).

32U.S. Census Bureau, Current Construction Reports—Characteristics of New Housing: 1998, C25/98-A (Washington, DC, July 1999).

33American Gas Association, Residential Natural Gas Market Survey 1998 (Washington, DC, December 1999).
million Btu ($7.65 per million Btu in the reference case),

while natural gas prices would reach $8.48 ($8.24 in the

reference case). The price gap in 2005 between heating

oil and natural gas narrows in the high world oil price

case; however, the residential heating oil price still is

projected to remain below the natural gas price.

Historical Heating Costs: An Illustration

About 7.1 million households heat with oil in the Northeast Census region, which accounts for 75 percent of distillate-heated households in the United States.34

Although retail heating oil is more susceptible to price

volatility than natural gas, it has remained costcompetitive with natural gas over the past 20 years. During periods of high oil prices, however, a question arises

as to why households in the Northeast choose not to convert from oil for space heating, especially in cases where

gas is available to the households and is used for other

applications, such as water heating and cooking. Of the

7.1 million homes that heat with oil in the Northeast, 2.4

million (34 percent) have gas service.35 Additional customers in the Northeast with no gas service into their

homes are sufficiently close to gas distribution lines to

have gas service installed at little or no cost but choose to

heat with oil and cook with electricity instead. To examine the question, an analysis of energy bills for a house

located in Long Island, NY, is provided below.36

The primary motivation for heating with oil rather than

natural gas is economic, although perceptions of safety

and reliability also play a role. Furnaces can last for 30

years or more, limiting the opportunity to switch fuels,

especially since few homeowners retire heating equipment before it needs to be replaced. Even if gas service is

already available in a home, a new furnace with installation can cost well over $2,000—a significant economic

barrier to conversion. Leaving that consideration aside,

this case deals only with fuel costs, based on oil and gas

bills collected from the homeowner.37

The study house uses oil for heating, with a 550-gallon

below-ground storage tank. A tank of this size allows for

oil purchases at lower prices during the summer

months. The homeowner provided monthly oil usage

readings, measured on the last day of each month, which

were cross-referenced with documented oil deliveries

for verification. The oil price in a given period was taken

as the price per gallon that was paid for a delivery of oil

until the full amount of the delivery was used, as

determined from the usage readings and confirmed subsequent to the oil deliveries. The oil price and consumption data were converted to energy (Btu) equivalents to

facilitate a comparison with a natural gas furnace of similar efficiency characteristics. Gas bills were provided for

each 2-month billing cycle over the entire 20-year

period. Given that the home was billed on a water heating schedule with low gas consumption, and because

data for a comparable gas-heated home were not available for the entire period, the analysis assumed that the

gas price would be discounted by 35 percent at higher

usage rates (a declining tail block rate structure), which

was estimated from partial billing data for a home in the

same service territory with natural gas heat. Table 2

shows oil and gas prices as well as heating costs for the

study household over the past 20 years.

Oil prices in the Northeast have generally been lower

than gas prices, particularly over the past decade. The

latest oil delivery, priced at $1.40 per gallon ($10.09 per

million Btu) on January 21, 2000, during the peak of the

recent oil price spike, was only 5 percent more expensive

than the estimated price for natural gas over the same

period ($9.63 per million Btu). Assuming the same efficiency for oil and gas heating, over the past 20 years

(through March 28, 2000), nearly $1,800 (1999 dollars) in

heating costs have been saved by the homeowner. For

the 1999-2000 heating season (October 1, 1999, through

March 28, 2000), heating costs for oil were $349, as compared with an estimate of $563 if the home had been

heated with natural gas.

Even if oil and gas prices remain at their respective January 21, 2000, levels through 2005, annual heating costs

for the study household would be $773 using oil and

$737 using natural gas. Over the 6-year period

(2000-2005), a total of $216 in fuel costs would be saved

by heating with gas. At a cost of $2,000 for a new gas furnace, the simple payback period would exceed 50 years,

much too long for such an investment to be made. Moreover, it is unlikely that such winter fuel price differentials would be sustained through 2005.

Whereas it is not feasible for residential customers to

purchase natural gas in the summer months when prices

are low and store it for later use, distillate fuel oil can be

purchased and stored in oil tanks until needed. (On the

other hand, degree-days and/or actual fuel levels must

be accurately monitored to avoid running out of oil during cold winter months, whereas natural gas needs no

18 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

34Energy Information Administration, A Look at Residential Energy Consumption in 1997, DOE/EIA-0632(97) (Washington, DC, November 1999).

35Energy Information Administration, A Look at Residential Energy Consumption in 1997, DOE/EIA-0632(97) (Washington, DC, November 1999).

36Tables B1-B10 in Appendix B provide a historical comparison of residential equipment, fuel use, and expenditures for a variety of categories.

37Oil and gas bills were provided to EIA for the period from October 1978 through March 2000 for a customer of Long Island Power

Authority.
such monitoring.) For a residential fuel oil customer,

concerns about oil supply and relatively high prices can

be mitigated by well-timed fuel oil purchases, installation of a large fuel oil storage tank, and “cap” pricing

contracts that place an upper limit on fuel oil prices for a

small premium.38 For residential users, above-ground

275-gallon tanks cost about $500, and 550-gallon tanks

(which must be buried) cost about $2,000.

Transparent and timely data and information to home

heating fuel consumers facilitate good planning and

decisionmaking and improve market responses to

potential price surges in the heating fuel market. The

operational efficiency of the energy market is also likely

to be enhanced by such market transparency.

Conservation Options

There is limited additional conservation potential in the

Northeast residential sector with respect to distillate fuel

oil consumption. Since 1980, distillate fuel oil consumption per household using oil has declined by more than

10 percent, reflecting efficiency gains in both equipment

and building shell characteristics. Because most distillate fuel oil use is for space heating, fuel conservation

can be achieved by adjusting thermostats down during

the winter months or by installing setback thermostats,

which automatically alter the thermostat setting either

for times when the house is unoccupied or when higher

settings are not needed. More expensive efficiency

options, such as newer furnaces, better insulation, and

multi-paned windows, can also help mitigate the perunit consumption of distillate fuel oil.

There is little, if any, opportunity for renewable energy

sources to replace distillate use in the residential sector.

The use of ground-source or water-source heat pumps

can be considered renewable resources; however, electricity is needed to power the equipment, ventilation

system, and pump, where appropriate. Solar energy can

provide heat for part of the household load, but low

insolation values39 and high costs restrict widespread

use of this technology in the Northeast.

Commercial Sector Fuel Choice

Highlights

• In the Northeast, consumption of distillate fuel oil in

the commercial sector has declined from 18 percent

of commercial fuel use (257 trillion Btu or about 44

million barrels of distillate fuel oil) in 1980 to 12 percent (219 trillion Btu or about 38 million barrels) in

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 19

Table 2. Residential Home Heating Case Illustration

Year

Distillate Fuel Oil Price

(1999 Dollars

per Million Btu)

Natural Gas Price

(1999 Dollars

per Million Btu)

Household Heating Cost

with Natural Gas

(1999 Dollars

per Household)

Household Heating Cost

with Distillate Fuel Oil

(1999 Dollars

per Household)

1980 . . . . . . . . . 11.39 7.30 366.55 571.84

1981 . . . . . . . . . 11.52 6.62 330.38 575.36

1982 . . . . . . . . . 12.17 7.15 361.16 614.14

1983 . . . . . . . . . 12.37 8.11 480.31 732.62

1984 . . . . . . . . . 9.57 7.82 454.32 556.25

1985 . . . . . . . . . 8.62 7.78 469.10 520.27

1986 . . . . . . . . . 7.65 7.60 496.63 499.58

1987 . . . . . . . . . 4.87 7.40 477.54 313.85

1988 . . . . . . . . . 5.85 7.46 521.24 409.07

1989 . . . . . . . . . 5.44 7.25 466.39 350.21

1990 . . . . . . . . . 6.08 7.33 408.94 338.97

1991 . . . . . . . . . 8.04 7.08 429.39 487.59

1992 . . . . . . . . . 6.09 7.75 578.05 454.77

1993 . . . . . . . . . 5.98 8.34 643.09 460.84

1994 . . . . . . . . . 5.46 9.84 747.90 414.85

1995 . . . . . . . . . 4.45 10.24 751.01 326.63

1996 . . . . . . . . . 4.95 10.77 815.45 374.59

1997 . . . . . . . . . 6.15 10.39 674.47 399.21

1998 . . . . . . . . . 5.77 9.86 614.14 359.26

1999 . . . . . . . . . 4.01 9.99 615.05 247.08

Source: Oil and gas billing records provided to EIA by the homeowner.

38Chapter 5 describes pricing options for distillate fuel oil at the wholesale and retail level in greater detail.

39Insolation is the rate of delivery of direct solar energy per square unit of horizontal surface area, often expressed in annual number of

kilowatthours per square foot. Insolation values determine the viability of photovoltaics for a particular location.
1997. In 1997, the commercial sector consumed about

22 percent of all nontransportation distillate fuel oil

used in the Northeast.

• AEO2000 projects that the declining trend in commercial distillate fuel oil use will continue through

2005, even in the low world oil price case.

• The maximum potential for Northeast commercial

distillate fuel oil use that could be switched to

another fuel in one week or less, without new equipment or retrofits, is about 50 trillion Btu (about 8.6

million barrels)—23 percent of the region’s commercial distillate fuel oil use and 3 percent of its total distillate fuel oil use, based on 1997 consumption data.

Recent Trends and Current Use of

Distillate Fuel Oil in the Commercial Sector

Distillate fuel oil use by commercial establishments in

the Northeast is relatively small and declining. Northeast distillate fuel oil use in 1997 for all purposes totaled

more than 1.5 quadrillion Btu (about 260 million barrels). Commercial distillate fuel oil consumption in the

region has declined from 18 percent (257 trillion Btu or

44 million barrels of distillate fuel oil) of total commercial energy consumption in 1980 to 12 percent (219 trillion Btu or 38 million barrels) in 1997. In 1997, the

commercial sector in the Northeast consumed about 1.8

quadrillion Btu of energy, or 12 percent of the region’s

total fuel use. Electricity and natural gas currently dominate Northeast commercial fuel use, followed by distillate fuel oil with a 12-percent share of energy delivered

to the commercial sector (Figure 17).

Although distillate fuel oil represents only a relatively

small proportion of total commercial sector energy use

in the Northeast region, commercial use of distillate fuel

oil in the region represents nearly half (49 percent) of

U.S. commercial distillate fuel oil use. Nationally, distillate fuel oil’s share of commercial sector energy consumption has declined steadily from 11 percent in 1983

to about 6 percent in 1997. The commercial fuel oil share

in the Northeast has been more volatile than the national

commercial consumption share, but overall it has

decreased at nearly the same rate as the national share,

from 18.5 percent in 1983 to 12.1 percent in 1997 (Figure

18). The factors that contributed to the declining trend in

fuel oil use in the commercial sector, both nationally and

in the Northeast, include increased natural gas infrastructure (pipelines and distribution systems), increased

gas supplies to all markets, increasingly competitive natural gas prices, and improving equipment efficiencies.

To estimate the potential for reducing commercial sector

distillate fuel oil use in the Northeast, it is necessary to

understand how commercial consumers use distillate

fuel oil. The latest available survey of commercial building end-use consumption is EIA’s 1995 Commercial

20 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Natural Gas

46%

Distillate Fuel Oil

12%

Electricity

33%

Other fuels

9%

Figure 17. Commercial Delivered Energy

Consumption in the Northeast Census

Region by Fuel, 1997

Note: Other fuels include liquefied petroleum gas (LPG),

residual fuel oil, kerosene, motor gasoline, coal, and

renewables.

Source: Energy Information Administration, State Energy

Data Report 1997, DOE/EIA-0214(97) (Washington, DC, September 1999).

1980 1985 1990 1995 2000 2005

0

5

10

15

20

Percent

Northeast

United States

History Projections

Figure 18. Distillate Fuel Oil Share of Commercial

Fuel Use, 1980-2005

Sources: History: Energy Information Administration, State

Energy Data Report 1997, DOE/EIA-0214(97) (Washington,

DC, September 1999). Projections: Energy Information

Administration, Annual Energy Outlook 2000, DOE/EIA0383(2000) (Washington, DC, December 1999).
Buildings Energy Consumption Survey (CBECS95).40

The survey covers only energy use in buildings; any

non-building energy uses, such as water treatment and

sewer services, are not included. For this reason, the

CBECS95 estimate of fuel oil use in commercial buildings in the Northeast is about 25 percent lower than the

commercial distillate fuel oil use reported for the region

in EIA’s State Energy Data Report.

41

The CBECS95 estimates of 1995 fuel oil use in commercial buildings totaled approximately 235 trillion Btu

(about 41 million barrels) for the United States and 168

trillion Btu (about 29 million barrels) for the Northeast.42

CBECS95 estimates for fuel oil use in commercial buildings in the Midwest Census region are very low by comparison, totaling 16 trillion Btu (about 2.8 million

barrels). Fuel oil accounted for 16 percent of total fuel

use in commercial buildings in the Northeast in 1995, a

decline from 20 percent of total fuel use in 1983 (according to CBECS83). According to the CBECS95 estimates,

116 trillion Btu of fuel oil (about 20 million barrels) was

used in 1995 to heat commercial buildings in the Northeast. The remainder was used for a variety of other

building uses, such as water heating, cooking, and electricity generation (Figure 19).

The switchable portion of the market is the portion that

can easily change fuels to serve demand (e.g., for space

heating) and, potentially, have an immediate effect on

fuel prices without installing new equipment or retrofits. In a well-functioning market, the ability to switch

fuels should act to reduce the gap between retail oil and

gas prices. Assuming that customers who can switch

heating fuels can also switch fuel sources for other end

uses,43 a total of 116 trillion Btu (20 million barrels distillate fuel oil equivalent) of energy use in commercial

buildings in 1995 could have been provided either by oil

or by natural gas (Figure 20). In 1995, more than half of

that total (64 trillion Btu) was provided by natural gas,

representing the maximum potential natural gas consumption in commercial buildings in the Northeast that

could have been switched to distillate fuel oil use without new equipment or retrofits.

Fuel switching among commercial establishments that

have identified themselves as dual-fuel capable usually

does not occur except under special circumstances.

Many use the alternate fuel capability as a backup and as

a means to negotiate better primary fuel prices. However, large and prolonged price differences between distillate fuel oil and natural gas can also cause fuel

switching and conversions, as shown during several episodes in the 1980s. Conversions occur most often when

equipment fails and new equipment is required.

The CBECS95 survey provides an estimate of total fuel

oil consumption in buildings that use fuel oil for their

main heating fuel. Fuel oil use is also estimated for

buildings that can switch their main heating fuel source

within a week’s time, the CBECS survey criterion (Table

3). No information is available about the ability to switch

fuel sources for other end-use services; however, assuming that commercial consumers who can switch their

main heating fuel can also switch fuel sources for other

end-use services (e.g., water heating), the maximum

switchable distillate fuel oil use in 1995 for the Nation as

a whole was 12 percent of total commercial distillate fuel

oil consumption, or 9.8 million barrels. The maximum

switchable percentage in the Northeast commercial sector was 23 percent (about 8.9 million barrels), reflecting

the relatively high level of distillate fuel oil use in the

region. In 1997, commercial distillate fuel oil use in the

Northeast was 219 trillion Btu, of which about 50 trillion

Btu would have been switchable to natural gas (based on

the 1995 data and the above assumptions). A key question is whether switching from distillate fuel oil to

another fuel would make sense, in terms of either

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 21

Non-Building Uses

25%

Space Heating

52%

Other Building Uses

23%

Total = 225 Trillion Btu

Figure 19. Commercial Sector Distillate Fuel Oil

Consumption in the Northeast

by End Use, 1995

Source: Energy Information Administration, 1995 Commercial Buildings Energy Consumption Survey, Public Use Data,

web site www.eia.doe.gov/emeu/cbecs/.

40As with any sample survey, the results of CBECS95 contain a certain measure of error associated with individual data points. Point

estimates are presented here for discussion purposes; however, for use in an analysis, survey results should be presented as a range of values with an associated probability.

41Energy Information Administration, State Energy Data Report 1997, DOE/EIA-0214(97) (Washington, DC, September 1999).

42Fuel oil estimates from CBECS95 consist primarily of distillate fuel oil but may include small amounts of residual fuel oil and kerosene.

43As such, this is an optimistic estimate of fuel-switching potential. The fuel-switching potential would be 35 to 40 percent lower if

switching were limited to fuel use to provide heating.
economic or reliability considerations, for commercial

consumers.

Projections to 2005

In the AEO2000 reference case, the projected prices for

distillate fuel oil to commercial consumers in the Northeast are about the same as those projected for natural gas

from 2000 through 2005 (Figure 21), reaching $5.66 and

$5.72 (1998 dollars) per million Btu, respectively, in 2005.

This assumes, of course, that the world oil market will

work freely, without the coordinated production limits

that have occurred in 1999 and early 2000. Northeast

commercial distillate fuel oil demand in the reference

case is projected to decline by 2.4 percent per year from

1997 to 2005, dropping to 184 trillion Btu by 2005, with a

corresponding decline in fuel share to 10 percent of commercial fuel use. Higher fuel oil prices could accelerate

that decline. Natural gas use in the Northeast is projected to increase by 0.2 percent per year in the reference

case.

Two alternative oil price cases in AEO2000 illustrate the

changes that might accompany higher or lower world

oil prices. High world oil price assumptions (relative to

the reference case) yield projected distillate fuel oil

prices that are higher than commercial natural gas price

projections in the Northeast through 2005. The opposite

is projected under low world oil price assumptions (Figure 21). Varying world oil price assumptions result in

corresponding differences in commercial distillate fuel

oil use compared to the reference case (Figure 22).

Although low oil prices yield 9 percent more Northeast

commercial distillate fuel oil use in 2005 relative to the

reference case, consumption is still projected to decline

at a rate of 1.8 percent per year from 1997 through 2005.

Commercial distillate fuel oil consumption is projected

to be 6 percent lower than in the reference case in 2005

under the high world oil price assumptions, declining

by 3.1 percent per year. Neither of these cases indicates

how rapidly the market might actually change in the

event of more frequent price surges for either fuel oil or

natural gas.

Conservation Options

Conservation measures provide another method for

reducing distillate fuel oil use in the commercial sector.

The potential for additional conservation in distillate

fuel oil use in the commercial sector includes both

22 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

99

116

172

61

17

52

64

Natural gas in buildings with

gas as main heating fuel

that cannot switch to fuel oil

Natural gas in buildings

with main heating fuel

other than gas

Fuel oil in buildings

with main heating fuel

other than fuel oil Fuel oil in buildings with

fuel oil as main heating fuel

that cannot switch to other fuel

Fuel oil in buildings with

fuel oil as main heating fuel

that can switch to other fuel

Natural gas in buildings with

gas as main heating fuel

that can switch to fuel oil

Maximum

fuel-switching

potential

Figure 20. Natural Gas and Distillate Fuel Oil Use in Commercial Buildings in the Northeast

and Maximum Fuel-Switching Potential, 1995 (Trillion Btu)

Source: Energy Information Administration, 1995 Commercial Buildings Energy Consumption Survey, Public Use Data, web site

www.eia.doe.gov/emeu/cbecs/.

Table 3. Commercial Buildings Fuel Oil Consumption, 1995

(Trillion Btu)

Fuel Oil Consumed for All Purposes United States Northeast

Commercial sector, including non-building uses. . . . . . . . . . . . . . . . . . . . . . . . . 460 225

Buildings using fuel oil for any purpose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 235 168

Buildings using fuel oil as main heating fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196 151

Buildings using fuel oil as main heating fuel that can switch fuel . . . . . . . . . . . . 57 52

Sources: Energy Information Administration, State Energy Data Report 1997, DOE/EIA-0214(97)(Washington, DC, September 1999) and Energy

Information Administration, 1995 Commercial Buildings Energy Consumption Survey, Public Use Data, http://www.eia.doe.gov/ emeu/cbecs/.
short-term and long-term options. Immediate avenues

for conservation are limited to actions related to energy

management, such as reductions in heating during

off-hours and reductions in hot water use. Permanent

efficiency improvements provide opportunities for conservation over time, lessening the impact of any future

fuel price volatility on the business that implements the

improvements. Efficiency options include the purchase

of new, efficient equipment and the installation of

improved building shell measures, such as higher levels

of insulation and windows that minimize heat loss. Conservation measures already employed by commercial

businesses contributed to the significant decline in distillate fuel oil use observed since 1980. The potential for

additional conservation is limited to the implementation

of additional energy management practices and efficiency measures beyond those already in place.

Limited opportunities exist in the commercial sector to

displace distillate fuel use with renewable energy

sources. Solar energy systems are currently more expensive than systems fueled by electricity or fossil fuels,

even with net metering available to photovoltaic systems in many Northeastern States. Also, solar systems

generally offset part of a commercial building’s energy

needs, with systems that run on electricity or fossil fuels

required to meet the remaining load. Ground-source

heat pumps provide another avenue for renewable

energy to displace some distillate use, although some of

the reduced distillate use would be offset with electricity

requirements for heat pump operation. Unless solar and

ground-source heat pump technologies are already in

place, they would not be considered as cost-effective

short-term fuel-switching options.

Industrial Sector Fuel Choice

Highlights

• Industrial distillate fuel oil consumption is a small

part (5 percent) of the total Northeast distillate fuel

oil market.

• More than half of industrial distillate fuel oil consumption in the Northeast is off-road diesel (41 trillion Btu of 79 trillion Btu).

• The maximum fuel-switching capability for industrial distillate fuel oil users in the Northeast without

new equipment or retrofits is 9 trillion Btu (or 1.6

million barrels of distillate fuel oil), less than 1 percent of the region’s total distillate fuel oil consumption.

• Based on the AEO2000 high world oil price case, a

10-percent increase in distillate fuel oil prices would

reduce industrial distillate fuel oil consumption in

the Northeast by 2 trillion Btu (about 2.3 percent or

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 23

1980 1985 1990 1995 2000 2005

0.0

0.5

1.0

1.5

2.0

Ratio

Reference

Low World Oil Price

High World Oil Price

History Projections

Figure 21. Ratio of Distillate Fuel Oil Price to

Natural Gas Price in the Northeast

Commercial Sector, 1980-2005

Sources: History: Energy Information Administration, State

Energy Price and Expenditure Report 1995, DOE/EIA0376(95) (Washington, DC, August 1998). Projections:

Energy Information Administration, Annual Energy Outlook

2000, DOE/EIA-0383(2000) (Washington, DC, December

1999).

1999 2000 2001 2002 2003 2004 2005

0

2

4

6

8

10

-2

-4

-6

-8

-10

Percent

Low World Oil Price

High World Oil Price

Figure 22. Projected Distillate Fuel Oil Use in the

Northeast Commercial Sector: Percent

Change from Reference Case in Low

and High World Oil Price Cases,

1999-2005

Note: One quadrillion Btu is equivalent to about 172 million

barrels of distillate fuel oil. Six quadrillion Btu is equivalent to

about 1 billion barrels of distillate fuel oil.

Source: Energy Information Administration, Annual Energy

Outlook 2000, DOE/EIA-0383(2000) (Washington, DC,

December 1999).
about 345,000 barrels) in 2005 relative to the reference case projection.

Recent Trends in Industrial Distillate Fuel

Oil Consumption

The industrial sector includes manufacturing, agriculture, mining, and construction. The industrial share of

U.S. distillate fuel oil consumption has fallen since the

mid-1980s, to about 16 percent in 1997 from about 22

percent in 1985,44 although the actual quantity consumed has been relatively stable at about 1.1 quadrillion

Btu. Total U.S. distillate fuel oil consumption has risen

from about 6 quadrillion Btu in 1980 to about 7.2 quadrillion Btu in 1997 (Figure 23). Distillate fuel oil is a minor

fuel in the industrial sector, representing only 4 percent

of total energy consumption in 1997 (Figure 24).

In the Northeast, industrial distillate fuel oil consumption is a small part (5 percent) of the total regional market for distillate fuel oil. The 79 trillion Btu (about 14

million barrels) of industrial distillate fuel oil use in the

Northeast during 1997 amounted to only 3 percent of

industrial delivered energy in that region. The fraction

of total Northeast distillate fuel oil consumption represented by the region’s industrial distillate fuel oil consumption mirrors the national relationship, although

the industrial share of total Northeast distillate fuel oil

consumption (5 percent in 1997) is substantially less

than the industrial share of U.S. total distillate fuel oil

consumption (16 percent) because of the relatively large

share of residential distillate use in the Northeast.

Manufacturing and Nonmanufacturing

Distillate Fuel Oil Consumption

Further disaggregation of industrial distillate fuel oil

consumption is required to assess the prospects for

reducing distillate fuel oil consumption by increasing

consumption of substitute fuels. Within the manufacturing component of the industrial sector, there is some

ability to switch boiler fuels, whereas in the nonmanufacturing component (agriculture, mining, and

construction) the substitution possibilities are limited. In

the latter components, distillate fuel oil is primarily used

in farm equipment and other off-road vehicles rather

than as a heating source.

Nonmanufacturing distillate fuel oil consumption (primarily diesel fuel) has accounted for about two-thirds

(747 trillion Btu in 1997) of nationwide industrial distillate fuel oil consumption in recent years (Table 4). In the

Northeast, however, consumption is almost evenly split

between the two components, with 41 trillion Btu (about

7.1 million barrels) in the nonmanufacturing segment

and 38 trillion Btu (about 6.6 million barrels) in

24 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

1980 1985 1990 1995 2000 2005

0

2

4

6

8

10 Quadrillion Btu

History Projections

Industrial

Total

Figure 23. Total and Industrial Distillate Fuel Oil

Consumption in the United States,

1980-2005

Note: One quadrillion Btu is equivalent to about 172 million

barrels of distillate fuel oil. Six quadrillion Btu is equivalent to

about 1 billion barrels of distillate fuel oil.

Sources: History: Energy Information Administration, State

Energy Data Report 1997, DOE/EIA-0214(97) (Washington,

DC, September 1999). Projections: Energy Information

Administration, Annual Energy Outlook 2000, DOE/EIA0383(2000) (Washington, DC, December 1999)

1980 1985 1990 1995 1997

0

2

4

6

8

Percent

United States Northeast

Figure 24. Distillate Fuel Oil Share of Industrial

Delivered Energy Consumption in the

United States and the Northeast,

1980-1997

Source: Energy Information Administration, State Energy

Data Report 1997, DOE/EIA-0214(97) (Washington, DC, September 1999).

44Energy Information Administration, Fuel Oil and Kerosene Sales 1998, DOE/EIA-0535(98) (Washington, DC, August 1999), and earlier

issues.
the manufacturing segment. Consequently, potentially

switchable industrial distillate fuel oil consumption in

the Northeast in 1997 was 38 trillion Btu or 6.6 million

barrels, or 2.5 percent of the region’s total distillate fuel

oil consumption. Of that amount, however, only 24 percent was actually switchable (i.e., the consumption was

by industrial concerns that either had equipment with

dual-fuel capability or had second boilers that could

actually be fired up to operate in place of the other fuel).

Industrial Distillate Fuel Oil Switching

Potential

Data on fuel switching in the manufacturing sector for

1994 are available from EIA’s 1994 Manufacturing

Energy Consumption Survey (MECS94). MECS94

shows total U.S. manufacturing distillate fuel oil consumption of 152 trillion Btu (Table 5), including 42 trillion Btu for boiler fuel and 51 trillion Btu for direct

process energy. Onsite transportation accounted for 35

trillion Btu, and facility heating, ventilation and air conditioning (HVAC) accounted for another 7 trillion Btu.

(On-site transportation involves movement of materials

within a plant site, not transportation among different

sites.)

The pattern for the Northeast is similar (Table 6), except

for facility heating. In the Northeast, MECS reported 41

trillion Btu of distillate fuel oil consumed for all purposes. Boiler fuel accounted for 15 trillion Btu. The

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 25

Table 4. Industrial Distillate Fuel Oil

Consumption, 1994-1998

(Trillion Btu)

1994 1995 1996 1997

United States

Manufacturing . . . . . . 388 358 379 388

Nonmanufacturing. . . 720 717 749 747

Total . . . . . . . . . . . . 1,107 1,075 1,128 1,135

Northeast

Manufacturing . . . . . . 45 40 40 38

Nonmanufacturing. . . 41 38 42 41

Total . . . . . . . . . . . . 86 78 82 79

Source: Energy Information Administration, Fuel Oil and Kerosene

Report 1998, DOE/EIA-0535(98) (Washington, DC, August 1999),

and earlier issues.

Table 5. U.S. Manufacturing Energy Consumption, 1994

(Trillion Btu)

End Use Total Electricity

Residual

Fuel Oil

Distillate

Fuel Oil

Natural

Gas

Liquefied

Petroleum

Gas Coal Other

Boiler Fuel . . . . . . . . . . . . . . 3,669 28 313 42 2,396 15 875 —

Process Fuel . . . . . . . . . . . . 5,460 2,075 106 51 2,872 54 302 —

Nonprocess Uses

Facility HVAC. . . . . . . . . . . 588 217 5 7 351 5 3 —

Onsite Transportation . . . . 59 4 — 35 1 19 — —

Generation . . . . . . . . . . . . . 351 — 5 4 335 1 6 —

Other . . . . . . . . . . . . . . . . . 281 236 4 3 39 0 0 0

Not Allocated. . . . . . . . . . . . 6,107 96 9 9 148 4 13 5,828

Total Inputs. . . . . . . . . . . . . 16,515 2,656 441 152 6,141 99 1,198 5,828

Source: Energy Information Administration, Manufacturing Consumption of Energy 1994, DOE/EIA-0512(94) (Washington, DC, December 1997),

ftp://ftp.eia.doe.gov/pub/consumption/industry/m94_11b.wk1.

Table 6. Northeast Manufacturing Energy Consumption, 1994

(Trillion Btu)

End Use Total Electricity

Residual

Fuel Oil

Distillate

Fuel Oil

Natural

Gas

Liquefied

Petroleum

Gas Coal Other

Boiler Fuel . . . . . . . . . . . . . . 407 2 119 15 174 2 95 —

Process Fuel . . . . . . . . . . . . 566 236 25 13 250 11 31 —

Nonprocess Uses

Facility HVAC. . . . . . . . . . . 97 31 3 5 57 1 * —

Onsite Transportation . . . . 8 1 — 4 * 3 — —

Generation . . . . . . . . . . . . . 13 — W 1 12 W * —

Other . . . . . . . . . . . . . . . . . 47 37 4 1 5 0 0—

Not Allocated. . . . . . . . . . . . 487 14 2 3 18 1 3 446

Total Inputs. . . . . . . . . . . . . 1,626 321 153 41 517 18 130 446

*Less than 0.5 trillion Btu.

W = Withheld to avoid disclosure of individual establishment data.

Source: Energy Information Administration, Manufacturing Consumption of Energy 1994, DOE/EIA-0512(94)(Washington, DC, December 1997),

ftp://ftp.eia.doe.gov/pub/consumption/industry/m94_11b.wk1.
Northeast, with 5 trillion Btu of distillate fuel oil used for

facility HVAC, accounted for 70 percent of the distillate

fuel oil consumed for this purpose at all U.S. manufacturing sites.

Some portion of the distillate fuel oil consumed in

the manufacturing sector—primarily, the boiler fuel

usage—can be switched to other fuels, such as natural

gas. Switching may involve the use of dual-fired boilers,

changes in utilization rates, or the activation of standby

boilers. In 1994, 27 trillion Btu of the total 152 trillion Btu

of U.S. manufacturing use of distillate fuel oil (18 percent) could be switched within 30 days to other fuels,

including 20 trillion Btu that could be switched to natural gas,45 and the remainder to other fuels like coal, electricity or residual fuel oil. In the Northeast, 10 trillion Btu

of the total 41 trillion Btu of manufacturing distillate fuel

oil use (24 percent) could be switched to other fuels,

including 8 trillion Btu that could be switched to natural

gas (Figure 25). Except for planned seasonal variation,

there is little economic reason to switch to distillate

fuel oil, because its price tends to be significantly higher

than the price of natural gas. The gas price tends to be

lower because the dual-fuel switchable candidates in

the industrial sector use interruptible gas contracts or

purchase delivered gas during off-peak periods. Residential customers must pay undiscounted rates. In the

Northeast, distillate fuel oil averaged $5.44 per million

Btu and natural gas averaged $4.09 per million Btu in

1997.46

From the manufacturing share of total industrial distillate fuel oil consumption and the percentage of manufacturing distillate fuel oil that is switchable, the

potential maximum amount of distillate fuel oil that

could be switched can be calculated. The manufacturing

share of total U.S. industrial distillate fuel oil use in 1994

was 35 percent (Table 4), and the switchable fraction was

18 percent. This implies that the maximum switchable

fraction of U.S. industrial distillate fuel oil consumption

was 6 percent.

In the Northeast, the manufacturing share of industrial

distillate fuel oil consumption in 1994 was higher, at

48 percent (Table 4), as was the switchable fraction, at

24 percent. Those numbers imply that the maximum

switchable fraction of total industrial distillate fuel oil

use in the Northeast was 12 percent in 1994. In 1997,

industrial distillate fuel oil consumption in the

Northeast was 79 trillion Btu (13.6 million barrels).

Consequently, the maximum switchable amount of distillate was approximately 9 trillion Btu or about 1.6 million barrels. In comparison, overall distillate fuel oil

consumption in the Northeast was 1,540 trillion Btu in

1997. Therefore, at most 0.5 percent of distillate fuel oil

consumption in the Northeast could be freed up if the

switchable industrial fuel market did not use any distillate fuel oil. If all of that potential reduction occurred

during the coldest 2-week period of the winter—an

unlikely event—then the increased supply of distillate

fuel oil might have a moderating effect on distillate fuel

oil prices. In a period of increasing differences between

distillate fuel oil and natural gas prices, the industrial

sector is likely to react by switching fuels to the extent

possible; however, contractual arrangements that limit

natural gas consumption in some situations (e.g., service

that may be interrupted or curtailed at preset temperature cutoffs in exchange for lower service costs) would

reduce the actual switching potential to something less

than the maximum switching capability.

Projections to 2005

The AEO2000 projections can be used to assess the sensitivity of industrial demand to alternative energy prices.

In the reference case, industrial distillate fuel oil consumption in the Northeast is projected to increase by 1.1

percent per year from 1997 to 2005. In the high world oil

price case, industrial distillate fuel oil prices are about 10

percent higher than in the reference case, and in the low

26 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Not Switchable

31

Other

2

Natural Gas

8

Trillion Btu

Figure 25. Potential Switching Capability from

Distillate Fuel Oil Use in the Northeast

Manufacturing Segment, 1994

Source: Energy Information Administration, Manufacturing

Consumption of Energy 1994, DOE/EIA-0512(94) (Washington, DC December 1997).

45The MECS94 fuel-switching tables give the maximum amount of distillate fuel oil that could be switched to a given other fuel. The sum

of the individual quantities exceeds the amount of switchable distillate fuel oil. The calculations in the text subtract the maximum amount

that could be switched to natural gas from the amount of switchable distillate fuel oil to impute the quantities for the other fuels (coal, electricity, residual fuel, etc.).

46Calculated from AEO2000 Supplement Tables 1, 2, 11, and 12. See web site www.eia.doe.gov/oiaf/aeo/supplement/index.html.
world oil price case results they are about 17 percent

lower than in the reference case. In the high world oil

price case, industrial distillate fuel oil consumption is

projected to be 2 percent (about 2 trillion Btu) less than in

the reference case. As noted earlier, the maximum

switchable percentage in the Northeast is 12 percent of

total industrial distillate fuel oil consumption. Figure 26

compares the maximum switchable amount (10 trillion

Btu or 1.7 million barrels in 2005) with the amount that is

projected to be switched as result of a 10-percent

increase in the price of distillate fuel oil (about 2 trillion

Btu or 0.34 million barrels).

Conservation Options

There is limited additional conservation potential in the

industrial sector. Industrial distillate fuel oil consumption per unit of output fell by 40 percent from 1980 to

1997.47 In 1997, industrial distillate fuel oil energy intensity was 0.28 thousand Btu per dollar of output, while

industrial total delivered energy intensity was 6.81 thousand Btu per dollar of output. In the manufacturing

component of industrial demand, distillate fuel oil is

used mainly as a boiler fuel. Little, if any, additional

boiler capacity designed primarily to consume distillate

is likely to be built. Maintenance of existing distillate

capability to facilitate seasonal fuel switching is likely to

continue; however, most industrial distillate consumption is in the nonmanufacturing segment, where it is

used as motor fuel in farm and construction equipment.

This equipment becomes more fuel efficient over time,

but fuel consumption is strongly related to the precise

type of agricultural or construction activity being undertaken. Further, because peak agriculture and construction activities do not occur in the winter, additional fuel

conservation in these activities is unlikely to make available significant additional quantities of distillate at times

of high residential demand.

In the Northeast, the pulp and paper industry consumed

54 trillion Btu of pulping liquor and 30 trillion Btu of

other biomass residues during 1994. This industry consumed 2 trillion Btu of distillate fuel oil, and its total

energy consumption was 305 trillion Btu in the region

during 1994. The lumber industry consumed 12 trillion

Btu of biomass and 1 trillion Btu of distillate, and its total

energy consumption was 22 trillion Btu in the region

during 1994. Little, if any, additional pulping liquor or

biomass residues would be available for short-term fuel

switching.

Other Options

Cutting Across All Sectors

In addition to the flexibility available through current

fuel-switching capabilities, additional flexibility can be

developed over the next 5 years through incremental

consumer investments that can further reduce dependence on home heating oil. Two kinds of investment can

be made: those that enhance the efficiency of existing

equipment and buildings, and those that replace existing capital stock (or planned additions to stock). Additional new investments over the next 5 years are

expected in the Northeast, including electricity generation investments that could result in greater use of alternate fuels and greater electricity generation efficiency,

pipeline and distribution investments that could provide greater access to natural gas for end users, and

investments in new industrial and building equipment.

The efficiency of existing stock that has not already been

upgraded can sometimes be increased through maintenance efforts, such as insulating steam pipes or installing a more efficient burner head in a boiler. Even where

the efficiency improvements are not to oil-burning

equipment, increases in the efficiency of electricity production from other fuels may reduce some of the pressure on distillate fuel oil stocks.

Cutting across all sectors is the potential for growth in

distributed energy resources, such as heat or electricity

at or near the site of consumption. Distributed energy

resources have the potential to relieve electricity transmission bottlenecks and lower the costs of electricity,

heating, and cooling services—particularly when the

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 27

2000 2001 2002 2003 2004 2005

0

2

4

6

8

10

12

14 Trillion Btu Change From Reference Case

Maximum Fuel-Switching Potential

High World Oil Price Case Projections

Figure 26. Maximum Potential for Industrial Sector

Switching From Distillate Fuel Oil Use

in the Northeast and Projected

Switching Under High World Oil

Price Assumptions, 2000-2005

Sources: Energy Information Administration, Manufacturing

Consumption of Energy 1994, DOE/EIA-0512(94) (Washington, DC December 1997), and Annual Energy Outlook 2000,

DOE/EIA-0383(2000) (Washington, DC, December 1999).

47Energy Information Administration, State Energy Data Report 1997, DOE/EIA-0214 (Washington, DC, September 1999).
load is well matched to the optimal operating conditions

of the distributed energy source. However, through

2005, distributed energy resources are limited by their

economics and operational difficulties in integrating

with the electricity grid system.

Electricity Generation Sector

Fuel Choice

Highlights

• Utility and nonutility generators in the United

States, excluding traditional cogenerators, consumed about 32.6 million barrels of distillate fuel oil

(190 trillion Btu) in 1998 for nontransportation uses,

or 2.6 percent of the Nation’s total distillate fuel oil

consumption. In the Northeast, 35 trillion Btu or

about 6 million barrels of distillate fuel oil was used

to generate about 0.5 percent of the region’s total

electricity generation. However, when weather conditions are severe, causing high demand and natural

gas delivery problems (as in December 1989) or high

natural gas prices, the impact of electricity generators on the distillate fuel market can be larger.

• Overall, a small amount of oil is used in the production of electricity today, and its use is expected to

decline further.

• Of the oil that is used, the vast majority is residual

fuel oil rather than the distillate fuel oil that can be

used by consumers to heat their homes.

• Even in the Northeast, where oil use in electricity

production is more important than in the rest of the

country, about 0.5 percent of the power generated

annually comes from distillate fuel oil.

• If distillate fuel oil were unavailable, power companies would most likely turn to natural gas as the

replacement fuel.

• Other options could include increasing imports from

outside the region, instituting demand management

programs in the winter, and improving distillate fuel

oil purchasing and storage practices to reduce the

possibility that power companies will be buying it

when consumers need it for home heating.

Recent Trends in Oil Use for Electricity

Generation

The majority of the electricity produced in the United

States is generated from coal, followed by nuclear, natural gas, and hydroelectric power. Generation from these

four fuels accounted for more than 94 percent of total

U.S. electricity generation in 199848 (52 percent coal, 19

percent nuclear, 15 percent natural gas, 9 percent hydropower) (see Appendix D). Other fuels, such as oil and

nonhydroelectric renewables, played a very small role.

The vast majority of oil used for electricity generation

was, and continues to be, residual fuel oil, not distillate.

In the Northeast, oil-based generation was somewhat

greater than hydropower (Figure 27).

In 1998, oil accounted for less than 3.4 percent of total

U.S. electricity generation. The role played by oil has

declined substantially since the mid-1970s and early

1980s (Figure 28). In the 1980s, electricity generation

from coal and nuclear (and later in the decade natural

gas) increased to meet the increasing demand for electricity and to displace oil-based generation. The move

away from oil-based generation was based on several

factors, including the changing economics and reliability of coal supply for generation, the nervousness created in the market by the oil shocks of the 1970s,

improvements in the national gas supply infrastructure,

and the increasing economic competitiveness and perceived reliability of gas supply and generation technologies. In 1980 the share of total electricity generation

produced from oil was just under 11 percent, but it has

dropped almost continuously since then. The share of

generation coming from oil for utility and nonutility

generators differs only slightly. In 1998, oil accounted

for only 2.6 percent of utility generation and 4.1 percent

of nonutility generation.

The share of U.S. electricity generation coming from distillate fuel oil49—the type of oil used by consumers to

28 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Coal 34.0%

Natural

Gas

17.9%

Nuclear 28.4%

Hydropower

7.6%

Other

3.0%

Residual

8.6%

Distillate

0.5%

Oil 9.1%

Figure 27. Electricity Generation by Fuel in the

Northeast, 1998

Sources: Energy Information Administration, Form EIA-759,

“Monthly Power Plant Report”; Form EIA-860B, “Annual Electric Generator Report—Nonutility”; and Form EIA-867, “Annual

Nonutility Power Producer Report.”

481998 is the last year for which both utility and nonutility generator data are finalized.

49Distillate fuel oil used for electricity generation is also referred to as “light oil.”
heat their homes—is much smaller. The vast majority of

the oil used by power plants is residual fuel oil. For utilities, only 0.3 percent of total generation came from distillate fuel oil in 1998 and 1999, down from 0.6 percent in

1980. The trend for nonutility generators is similar.

Nonutility generators do not report their distillate fuel

oil generation directly, but their fuel consumption data

for 1998 show that only 20 percent of the oil they consumed was distillate fuel oil (see Appendix D). As a

result, their generation from distillate fuel oil is approximately 0.6 percent of their total generation.

Distillate fuel oil is not economically competitive with

other available generation fuels. Typically, it is used in

small amounts in steam plants for flame control and in

relatively inefficient combustion turbines and internal

combustion engines when the demand for electricity is

high and other fuels are unavailable to generate it. Such

plants tend to be run intermittently and are not good

investment opportunities for natural gas suppliers or

pipeline developers. Distillate fuel oil can be used in

many of the new turbines and combined-cycle plants in

the construction pipeline, but the relative price and environmental advantages of gas are expected to make natural gas the fuel of choice in almost all cases. For example,

in 1998, with very low overall oil prices, distillate fuel oil

delivered to power plants cost $3.19 per million Btu, but

natural gas was much less expensive at $2.34 per million

Btu. Over the next 5 years, the price gap is expected to

persist and could widen.

Total U.S. utility consumption of distillate fuel oil in

1998 was just over 22.0 million barrels (128 trillion Btu)

(see Appendix D), or 1.6 percent of total distillate fuel oil

consumption. For nonutility generators, distillate fuel

oil consumption totaled 10.5 million barrels (61 trillion

Btu) in 1998 (1998 is the last year for which nonutility

generator data are available).50 Utility and nonutility

generators together consumed 32.6 million barrels (190

trillion Btu) of distillate fuel oil in 1998, or 2.6 percent of

total distillate fuel oil consumption.

The use of oil in the electricity generation sector varies

by region of the country (Figure 29 and Appendix D).

The largest quantity of oil is used in Census division 5,

the South Atlantic.51 In terms of the share of generation,

however, Census division 1, New England, is by far the

highest with a 24-percent share in 1998. Other than Census division 1, only divisions 5 and 2 produced more

than 5 percent of their generation from oil. Each of these

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 29

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

Billion Kilowatthours

Coal

Natural Gas

Oil

Nuclear

Hydropower

Other Renewables

Figure 28. U.S. Electricity Generation by Fuel, 1950-2005

Sources: History: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report”; Form EIA-860B, “Annual

Electric Generator Report—Nonutility”; and Form EIA-867, “Annual Nonutility Power Producer Report.” Projections: Energy Information Administration, Annual Energy Outlook 2000, DOE/EIA-0383(2000) (Washington, DC, December 1999).

50Nonutility generator consumption data include data for cogenerators, small power producers, and independent power producers.

Some of this consumption is typically reported in the industrial sector.

51Includes Delaware, Maryland, the District of Columbia, Virginia, West Virginia, North Carolina, South Carolina, Georgia, and Florida.
regions relies more heavily on older oil and gas steam

plants than do other regions. In the Midwest region

(Census division 3), the region just to the west of the

Northeast, the share of generation coming from oil was

only 0.6 percent in 1998.

In all U.S. regions, the vast majority of the oil used for

electricity generation is residual fuel oil rather than distillate fuel oil (Figure 30). In the Northeast (the combination of Census divisions 1 and 2 in this report), only 6

percent of the total generation from oil comes from distillate fuel oil. If all the distillate fuel oil used to produce

electricity in the Northeast were shifted to some other

fuel, distillate fuel oil consumption would be reduced by

6.1 million barrels (35 trillion Btu), an average daily

reduction of just 17,000 barrels per day (0.1 trillion Btu).

More important, however, is the amount of distillate

fuel oil consumed during the peak winter months of

December through February, when distillate fuel oil

pricing is an issue. For example, December 1989 saw

record distillate fuel oil consumption levels for electricity generators in the Northeast, reaching 77,000 barrels

per day. Such short-term, rapid changes in demand can

cause rapid and significant price changes.

Although the use of distillate fuel oil for electricity generation is relatively limited on an annual basis, seasonal

variations in use can influence the prices paid by heating

oil consumers. In most years, the use of distillate fuel oil

for electricity generation peaks in summer, when consumers’ need for power is greatest. In extremely cold

winters, however, distillate fuel oil use for generation

can also rise, as occurred in December 1989 (Figure 31).

In a typical year, distillate fuel oil consumption in the

electricity generation sector in the Northeast average

approximately 17,000 barrels per day; however, in

December 1989 it averaged nearly 77,000 barrels per

day. Average temperatures in December 1989 were

much colder than normal. In the North, the colderthan-normal month significantly increased the demand

for natural gas by firm service customers (primarily in

the residential and commercial markets). In the

gas-producing regions of the South, unusually cold temperatures caused some wells to freeze, reducing production during the period of critically high demand,

particularly in the Northeast. Gas prices rose sharply as

a result, and significant numbers of industrial and electricity generation customers were forced to switch fuels,

mostly to residual and distillate fuel oil.

30 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

123456789

U.S. Census Division

0

200

400

600

800

Billion Kilowatthours

Other

Oil

Figure 29. Electricity Generation from Oil and from

All Other Fuels by Census Division,

1998

Note: U.S. Census divisions: 1 = New England (CT, ME, MA,

NH, RI, VT); 2 = Middle Atlantic (NJ, NY, PA); 3 = East North

Central (IL, IN, MI, OH, WI); 4 = West North Central (IA, KS,

MN, MO, NE, ND, SD); 5 = South Atlantic (DE, DC, FL, GA,

MD, NC, SC, VA, WV); 6 = East South Central (AL, KY, MS,

TN); 7 = West South Central (AR, LA, OK, TX); 8 = Mountain

(AZ, CO, ID, MN, NV, NM, UT, WY); 9 = Pacific Contiguous

(CA, OR, WA); 10 = Pacific Noncontiguous (AK, HI).

Sources: Energy Information Administration, Form EIA-759,

“Monthly Power Plant Report”; and Form EIA-860B, “Annual

Electric Generator Report—Nonutility.”

123456789

U.S. Census Division

0

20

40

60

80

100

120

Million Barrels

Residual

Distillate

Figure 30. Utility and Nonutility Generator Oil

Consumption by Census Division, 1998

Note: U.S. Census divisions: 1 = New England (CT, ME, MA,

NH, RI, VT); 2 = Middle Atlantic (NJ, NY, PA); 3 = East North

Central (IL, IN, MI, OH, WI); 4 = West North Central (IA, KS,

MN, MO, NE, ND, SD); 5 = South Atlantic (DE, DC, FL, GA,

MD, NC, SC, VA, WV); 6 = East South Central (AL, KY, MS,

TN); 7 = West South Central (AR, LA, OK, TX); 8 = Mountain

(AZ, CO, ID, MN, NV, NM, UT, WY); 9 = Pacific Contiguous

(CA, OR, WA); 10 = Pacific Noncontiguous (AK, HI).

Sources: Energy Information Administration, Form EIA-759,

“Monthly Power Plant Report”; and Form EIA-860B, “Annual

Electric Generator Report—Nonutility.”
In 1989, at the national level, nearly 23 percent of the

annual utility use of distillate fuel oil ful oil occurred in

December. The winter increase in usage was even more

pronounced in Census division 1 (New England) where

more than 25 percent of the annual utility use occurred

in December. Still, distillate fuel oil accounted for only

0.4 percent of total utility generation nationally in 1989

and only 1.3 percent in New England. In December 1989,

distillate fuel oil accounted for 2.8 percent of total utility

generation in New England.

In terms of the overall distillate fuel oil market in the

Northeast, the electricity generation sector is a relatively

small player. On an annual basis, electricity generation

accounts for only 2 to 3 percent of the region’s total market for distillate fuel oil (excluding transportation uses).

However, when weather conditions are severe and natural gas is unavailable or expensive, the use of distillate

fuel oil for electricity generation can be more important.

In 1989, with a very cold winter, the electricity generation share of annual distillate use in the Northeast was

nearly 5 percent, and in December 1989, 24 percent of

electric utility generation was from distillate fuel oil. As

mentioned above, electric utility consumption of distillate fuel oil in December 1989 averaged 77,000 barrels

per day, much higher than the typical yearly average of

17,000 barrels per day.52

In the future, oil is expected to play a comparatively

minor and decreasing role in the U.S. electricity generation sector. In AEO2000, generation from oil is projected

to account for less than 2 percent of total generation by

2005 and less than 1 percent by 2020. Existing oil-fired

generators are expected to be used less, and some are

expected to be retired. In addition, new natural-gasfired combustion turbines and combined-cycle plants

are expected to account for more than 90 percent of new

capacity additions. As the new plants are built, they will

be used not only to meet growing demand but also to

displace the generation from older oil-fired plants—particularly in regions like the Northeast that currently use

relatively large amounts of oil for electricity generation.

If oil prices were much lower than expected, as in the

AEO2000 low world oil price case ($14.90 per barrel in

2020), the share of generation from oil could stay near

the current level of 3 to 4 percent of total generation.

Although no new oil-fired plants would be built, existing oil plants would continue to be used. Still, however,

the vast majority of the oil used would be residual fuel

oil (heavy oil) rather than distillate fuel oil (light oil).

Projections to 2005

Over the next few years the use of oil for electricity generation is expected to continue to fall. New oil plants are

simply not economically competitive with other

options, and the utilization of existing plants is expected

to decline as new gas-fired plants are added to meet

demand growth. The older oil and gas steam plants in

the Northeast are expected to be prime candidates for

retirement as new, more efficient plants are brought on

line. In the AEO2000 reference case, approximately 20

percent (4 gigawatts) of the existing oil and gas steam

capacity in the Northeast (here defined as the combination of the New York and New England power pools) is

expected to be retired by 2005. As a result, the share of

generation from oil declines from just over 2.4 percent in

2000 to 1.7 percent by 2005 at the national level and from

13.2 percent to 10.8 percent in the more oil-intensive

Northeast (Figure 32). As mentioned above, the share of

generation from distillate fuel oil remains well below 1

percent in all years. As new turbine-based systems (simple combustion turbines and combined-cycle plants) are

added, it is possible that they could turn to distillate fuel

oil when gas is not available. Most of the new gas plants

are expected to be heavily utilized, making it economically attractive to develop the gas infrastructure needed

to meet their needs.

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 31

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

1

2

3

4

5

6

Billion Kilowatthours

Division 1

Division 2

Division 3

U.S. Total

Figure 31. Electric Utility Generation from Distillate

Fuel Oil by Census Division and Month,

1989

Note: U.S. Census divisions: 1 = New England (CT, ME, MA,

NH, RI, VT); 2 = Middle Atlantic (NJ, NY, PA); 3 = East North

Central (IL, IN, MI, OH, WI).

Source: Energy Information Administration, Form EIA-759,

“Monthly Power Plant Report.”

52The 1989 values are for utilities only. Monthly data for nonutility generator consumption in 1989 are not available.
Fuel Supply Options for Electricity

Generators

Electricity generators in the Northeast (both utilities and

nonutilities) using natural gas as their primary fuel have

been reluctant to commit contractually to firm (365-day)

gas service because of the high transportation costs for

such service. As an alternative, a power generator might

buy natural gas on the interruptible market and either

build a short-duration storage facility for distillate (or

residual) fuel oil or shut down the generator when gas

service is actually interrupted and either dispatch

another plant or import power from an adjacent region.

Another alternative might be to contract for a variety of

semi-firm services (for up to 365 days) but allow a local

gas distribution company the right to call on the gas for a

specified number of days. Because the winters have been

warm for most of the past 20 years, interruptible gas service has effectively turned into firm service without the

higher costs. There is little incentive under these circumstances for generators to commit to costlier firm service

options. Recent anecdotes suggest that the reliability of

natural gas supply and the added cost of carrying a full

inventory of distillate fuel oil or residual fuel oil (which

has often remained unneeded) have tempted some electricity generators not to maintain adequate inventories

of replacement fuel in storage through the winter. If so,

their need to buy oil supplies on the spot market when

gas supplies were interrupted may have contributed to

this year’s distillate fuel oil price surge.

Possibilities for reducing the use of distillate fuel oil by

electricity generators in the Northeast include increasing interregional transmission capacity and building

new generating capacity to displace existing capacity.

Given the high costs and long lead times involved in natural gas pipeline capacity expansion projects, that

option may not be economical. New natural-gas-fired

generating plants can be brought on line in 1 to 2 years,

and many are already planned. Other new capacity

options (coal, wind, biomass, and solar) are much less

economical and normally take longer to bring on line. In

addition, because wind and solar plants are not

dispatchable,53 they are not likely to be good substitutes

for plants that use distillate fuel oil.

In AEO2000, the levelized cost for new plants in 2005

averages 3.5 cents per kilowatthour for gas combined

cycle, 4.1 cents per kilowatthour for coal, 5.9 cents per

kilowatthour for wind, 7.0 cents per kilowatthour for

nuclear, and 20.2 cents per kilowatthour for solar photovoltaic. In addition, because wind and solar generating

plants are not dispatchable, they may not be good substitutes for plants that use distillate fuel oil. Although

new nuclear power plants are currently too costly to

compete with either coal or natural gas combined-cycle

plants, and nuclear construction lead times are too

lengthy to have an impact by 2005, it may be possible to

increase the utilization rates of existing nuclear units in

the winter period to reduce distillate fuel oil use during

the winter months. However, the current utilization rate

for nuclear power plants in the Northeast exceeds 80

percent, and the opportunities for significant additional

contributions appear to be minimal.

Although not likely to have a notable impact in the near

term, over the longer run renewable energy sources

could reduce some of the demand for petroleum and

other fossil fuels in New England’s electricity production. New England is moving to increase the use of

renewable sources for electric power, including biomass

(such as from wood chips), landfill gas from municipal

solid waste, solar power (both solar photovoltaics for

direct electricity production and solar thermal water

heating to reduce electricity demand), and wind. Connecticut, Maine, and Massachusetts all have enacted

renewable portfolio standard (RPS) programs requiring

increased use of renewable energy sources after 2000.

Massachusetts and Rhode Island have “green power”

programs allowing customers willing to pay a premium

to purchase electric power generated from new renewable energy sources. A leading-edge biomass gasification-to-electricity facility using wood chips is being

tested in Vermont. In addition, most New England

States offer tax incentives to encourage renewables and

allow consumers to sell unneeded power generated

32 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

2000 2001 2002 2003 2004 2005

0

5

10

15

20

Percent

Reference

High World Oil Price

Low World Oil Price

Figure 32. Projected Oil Shares of Electricity

Generation in the Northeast, 2000-2005

Source: Energy Information Administration, Annual Energy

Outlook 2000, DOE/EIA-0383(2000) (Washington, DC,

December 1999).

53An electricity generator is “dispatchable” if it can be called on to generate electricity as needed.
from renewable sources back to their utilities at the same

prices the utilities charge them for retail service (referred

to as “net metering”). Use of solar photovoltaics is especially encouraged in order to reduce electric power

demands during peak air conditioning times. To the

extent that these programs are successful, renewables

will be able to reduce New England’s dependence on

fossil fuels. Nevertheless, because New England is not

well endowed with most renewable resources, generating electricity from them is—and will remain—more

costly than using fossil fuels in most instances. Therefore, additional renewables will likely remain minor

contributors to New England electricity supply well

beyond 2005.

An alternative to reducing distillate fuel oil use, might

be to improve the purchasing and storage practices of

electricity generators, so that they would not be competing with homeowners when unexpected cold weather

strikes. Options for doing this include improving the

distillate fuel oil delivery channels to power plants and

increasing their storage capacity.

Northeast Distillate Fuel Oil

Market Summary

The estimates of fuel-switching capability in the various

end-use sectors described in this chapter are approximations derived from EIA’s MECS, CBECS, and electric

power survey data for discrete years. The data are also

aggregate in nature. Several factors contribute to the

uncertainty of the estimate of the size of the dual-fuel

market, including the use of data from a survey sample

to represent a whole set of establishments and the use of

survey data that are not designed to address the specific

questions being analyzed here (how consumers make

fuel choices, what consumer options are or what they

perceive them to be, what the specific capability to use

alternate fuels is, etc.). Further, because energy consumption is not measured at the daily or even the

weekly level for any fuel, the precise interaction of spot

prices with other factors, such as deliverability constraints, fuel consumption, and stock in storage, can only

be approximated. Special circumstances, such as the status of equipment that uses other fuels or year 2000 (Y2K)

concerns, may determine actual fuel choices in some

periods that appear to be inconsistent with cost

considerations.

The practical capability to switch year-round distillate-only consumption to different fuels depends on a

variety of factors, including the time frame, the rate

of physical retirement of equipment, interest rates,

equipment and fuel choices and their associated characteristics, and specific performance and reliability

requirements (for example, uninterrupted fuel supply

24 hours per day, 7 days per week, may be required, or

equipment shutdown may be an acceptable alternative).

Typically, large energy-using equipment (such as boilers, heating systems, and generators) is replaced only

when it breaks down. Exceptions occur when the energy

cost of production has to be brought down to remain

competitive or when environmental constraints on

effluents or emissions impose a sufficiently large

externality cost to warrant retirement.

To take advantage of episodic price differences between

fuels, large energy-using establishments usually install a

dual-fuel-switching capability, usually between natural

gas and either residual fuel oil or distillate fuel oil. If they

have not done so, it usually means that conversion from

distillate-only equipment is either not economical or not

feasible. Most of the fuel-switching capability in the

Northeast is between residual fuel oil and natural gas,

not distillate fuel oil and natural gas. Figure 33 shows

the switching by utilities that took place among natural

gas, distillate fuel oil, and residual fuel oil in 1989, when

December distillate fuel oil consumption was the highest on record, at about 2.4 million barrels.

Fuel-Switching Potential

The size of the maximum potential of 1997 distillate fuel

oil consumption that could be switched to other fuels in

a relatively short time frame can be estimated from

information in the preceding sections of this chapter.

Considering the estimated maximum potential switchable amounts from the commercial and industrial sectors, and assuming that all utility use of distillate fuel oil

in the winter is switchable, a total maximum potential of

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 33

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

20

40

60

80

100

120

140

Trillion Btu

Distillate

Natural Gas

Residual

Figure 33. Electric Utility Consumption of Distillate

Fuel Oil, Residual Fuel Oil, and Natural

Gas in the Northeast by Month, 1989

Source: Energy Information Administration, Form EIA-759,

“Monthly Power Plant Report.”
76 trillion Btu (13.1 million barrels per year), or about

5 percent of overall distillate fuel oil consumption in the

Northeast in 1997 could be switchable (Table 7). We

know, however, that not all utility demand for distillate

fuel oil is switchable; that about 1.4 million barrels per

month is distillate-only generation;54 and that for commercial and industrial applications, most of the switchable demand is likely to occur during the heating season.

The methodology used to estimate the maximum

switchable quantities was as follows:

• For the commercial sector, it was assumed that all

distillate fuel oil used in a building is switchable

(including the fuel oil used for water heating and

other uses) if distillate fuel oil was the building’s primary heating fuel but it was reported that it could be

switched to another fuel. Because applications other

than space heating can account for 30 percent or

more of a building’s distillate fuel consumption, this

component of the switchable estimate is likely to be

high.

• Second, it was assumed that 90 percent of the heating

oil requirements occur in the three contiguous

winter months (December, January, and February).

Because both November and March also contain

substantial heating degree-days, the allocation of 90

percent of the distillate consumption into 90 days

also overestimates consumption.

• Finally, because the direction was that we should

look only at large-volume users or industrial users

for conversion to a different fuel, less than 50 percent

of the commercial market would qualify, largely offsetting those natural gas customers who can switch

to distillate fuel oil.

The first three factors overestimate the switchable distillate volumes in the commercial sector. The overestimation is intended to compensate for the use of

consumption data for 1997, which was a normal year,

because we are concerned with years that are as much as

10 percent colder than normal years during the three

winter months. For example, if we assume that: (1) only

85 percent of the distillate is consumed in the three coldest months (instead of 90 percent), (2) 90 percent of the

switchable distillate use in buildings with reported

fuel-switching capability (not the 70 percent implied

earlier), (3) distillate consumption in the commercial

sector stops declining under normal weather conditions,

and (4) there is a 10 percent colder than normal winter in

the Northeast, then our estimate of commercial and

industrial sector distillate fuel consumption during the

three winter months would be overestimated by at least

5 percent, and probably more. The treatment of the

industrial sector is similar, with 90 percent of the 9 trillion Btu (1.6 million barrels) defined as switchable allocated to the three winter months.

For the electricity sector, the switchable amount was

estimated from a recent normal historical year and then

increased by slightly more than 14 percent for 2005

under normal weather conditions. Since the AEO2000

projects declining distillate usage, this overestimates

consumption under normal weather conditions. We

then applied 40 percent of the total annual consumption

to the winter period. Taken together, these adjustments

mean that in a severe winter, distillate consumption during a three-month winter period of colder than normal

weather could be about 42 percent higher than consumption during a normal winter. The normal distribution of distillate fuel oil use for electricity generation is

almost evenly divided between the three periods: summer (June, July, August), winter (December, January

and February), and the rest of the year. Under these conditions, distillate fuel oil consumption could increase by

about 133 thousand barrels per day or more in the

Northeast. The peak-day usage could actually be higher.

Whether such short-term increases cause price surges

also depends on the duration of distillate fuel oil

demand, stock levels, imports, and other production

and delivery factors. If such a sharp distillate fuel oil

34 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Table 7. Northeast Estimated Switchable and Conversion Potential

Sector

Maximum Annual

Switchable Volume

(Million Barrels)

Daily Switchable Volumes If

Consumption Were Restricted to

December-February

(Thousand Barrels per Day)

Conversion Potential If All Distillate

Use by Large Users Were

Converted to a Different Fuel

(Million Barrels)

Commercial. . . . . . . . . . . . . . . . . 8.6 86 20.0

Industrial . . . . . . . . . . . . . . . . . . . 1.6 16 6.5

Electricity Generationa . . . . . . . . 2.9b 31b 7.1

Total . . . . . . . . . . . . . . . . . . . . . 13.1 133 33.6 a

Because usually only one-third of distillate consumption for electricity generation occurs in the winter months (December, January, and February), the consumption shown is the estimated winter use portion, assuming that 40 percent of the year’s distillate use might occur in the winter of an

unusual year. b

Winter only.

Source: Tables in this chapter.

54Because natural gas prices are lowest from April through August, any distillate fuel oil consumption during those months can be

roughly attributed to increased electricity demand and the inability to burn natural gas—that is, to the use of distillate-only generators.
demand increase occurred during a very cold period

and during a severe supply-demand imbalance, the

short-term incremental demand could significantly raise

what might already be high distillate fuel oil prices to

residential customers, as occurred in the winter of

1999-2000.

Northeast distillate fuel oil consumption in the 1990s for

utility and independent power producers (see Appendix D) ranged from about 19 trillion Btu (3.3 million barrels) to about 41 trillion Btu (about 7.1 million barrels)

annually. Data for 1998, the most current year for which

regional utility and nonutility consumption data are

available, show the Northeast with about 35 trillion Btu

(about 6 million barrels) of distillate fuel oil consumption. Distillate fuel oil consumption for electricity generation could rise as high as 40 trillion Btu by 2005, or more

if large amounts of combined-cycle capacity are added

and a cold winter occurs. Peak-month distillate fuel oil

consumption was about 2.4 million barrels in December

1989 (about 77,000 barrels per day) and occurred

because of the extraordinary gas situation and extreme

weather. More normal winter weather would result in

peak-month distillate fuel oil consumption of less than

0.6 million barrels or less than 19,000 barrels per day.

The likelihood that all electricity generated from distillate fuel oil use could actually be switched to another

fuel is small. Distillate fuel oil is expected to be used by

utilities primarily when natural gas is unavailable. Some

of the units that burn distillate fuel oil are older, inefficient diesel-fired units that have no pipeline gas access

and are used only intermittently. At least 1.4 million barrels per month of such capability exists in the Northeast,

and the economics of delivering gas to these relatively

small, intermittent users may preclude the possibility of

switching them to gas. The rest of the Northeast’s distillate fuel oil use for power generation is attributed to

dual-fired turbines or combined-cycle units that can

use either distillate fuel oil or natural gas. Distillate fuel

oil consumption in the winter period averages about

33 percent of the year’s total but can rise to 40 percent

under unusual circumstances. Northeast distillate fuel

oil consumption in the three coldest winter months,

when natural gas may not be available, has the greatest

potential impact on distillate fuel oil prices. Based on

these assumptions, no more than 2.9 million barrels is

switchable during the winter months. The maximum

estimate of 50 trillion Btu (about 8.6 million barrels) for

annual switchable potential in the commercial sector is

also optimistic, because it was assumed that consumers

who can switch their heating fuel can also switch fuels

for all other uses.

Conversion of Distillate Fuel Oil Use

to Other Fuels

If all the distillate fuel oil used for manufacturing and

utility purposes in the Northeast were displaced, at most

79 trillion Btu (13.6 million barrels) of distillate fuel oil

would be freed for use by residential consumers.

Adding all the distillate fuel oil used for heating in the

commercial sector raises the total in this extreme case to

about 195 trillion Btu (33.6 million barrels) of fuel oil.

The manufacturing total includes all uses, ranging from

boiler use and direct process use to onsite transportation

and facility HVAC uses, some of which are not practical

for conversion. In addition, the total includes distillate

fuel oil use by manufacturing concerns that reported

they could not switch boiler fuels without replacing

their existing boilers, an uneconomical decision under

the range of distillate fuel oil and natural gas prices considered. The caveats raised in the previous paragraph

concerning the commercial and utility potential apply

here as well. The complete conversion of distillate fuel

oil use to other fuels, particularly to natural gas, is infeasible and probably unnecessary in view of completed or

planned natural gas pipeline construction over the next

2 years and the availability of less costly consumer management and price hedging instruments for heating oil

customers (see Chapters 4 and 5 of this report).

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 35
4. Natural Gas Supply, Infrastructure, and Pricing

Introduction

One of the goals of this study is to assess the ability of the

natural gas infrastructure in the Northeast to support a

shift by large-volume users of distillate fuel oil to natural

gas. Demand for natural gas tends to be seasonal, and

the infrastructure is designed and operated primarily to

meet the need for firm service. The additional demand

that would result from a shift of large-volume distillate

users to gas would require an increase in gas deliveries

to the Northeast.55 More importantly, the new customers would require firm service throughout peak demand

periods, to avoid the risk of adding demand to the oil

market when conditions are tight. To provide the additional service, capacity expansions would be needed

across the delivery system, with emphasis on ensuring

physical deliverability even when demand in the region

and the load on the gas infrastructure are at peak levels.

Natural gas consumption requirements in the Northeast

are met through the combined operation of the three

major components of the gas supply chain: transportation, storage, and distribution. Transportation generally

refers to long-distance shipment of natural gas, primarily in interstate commerce. Storage generally refers to

three methods of storing gas for later delivery: underground storage of large volumes of natural gas in

depleted oil and gas reservoirs, and two “peak shaving”

options for storing smaller volumes of liquefied natural

gas (LNG)56 or propane. Distribution refers to operations associated with the local delivery of gas, primarily

to end users. Distribution, provided by local distribution

companies (LDCs) within the borders of each State to

deliver gas to customers at the burnertip, falls under the

jurisdiction of State authorities. Transportation falls

under Federal jurisdiction when it involves interstate

commerce, or under State jurisdiction if the transportation service provider operates wholly within the borders

of one State.

Current Status of the Natural Gas

Industry in the Northeast

Consumption

Although natural gas can be stored in the vicinity of

major consumption markets, consumption by end users

in U.S. markets generally occurs on a “just-in-time”

basis, with most customers drawing supplies from the

system as needed. With limited capability for on-site

storage at customer locations, the system must meet customer requirements under a wide range of operating

conditions. In the Northeast, seasonal patterns of gas

consumption vary among the end-use sectors (Figure

34). For the residential and commercial sectors, average

daily volumes peak in the months of the heating season

and fall to yearly lows in the summer months. Average

daily demand in the residential sector during February

is more than 7 times the average during August. For

electric utilities the pattern is reversed, with peak

demands during the summer air-conditioning season

(when demand for electricity peaks and even the most

inefficient turbines are brought into service) and lows

during the winter heating season. In the future, as more

intermediate and base electric load is served by natural

gas, the proportion of winter usage is expected to rise,

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 37

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

1

2

3

4

5

6 Billion Cubic Feet per Day

Residential

Commercial

Industrial

Electric Utilities

Figure 34. Average Monthly Natural Gas

Consumption in the Northeast by

Sector, 1989-1998

Source: Energy Information Administration (EIA), Oil and

Gas Information Retrieval System (OGIRS) (February 2000).

55In the discussion of natural gas supply, the Northeast consists of the New England Census division (Connecticut, Massachusetts,

Maine, New Hampshire, Rhode Island, and Vermont) and the Middle Atlantic Census division (New Jersey, New York, and Pennsylvania).

56LNG is natural gas converted to a liquid state by cooling to -260o

F (-162oC). The transformation reduces volume by a factor of 600 to 1,

which makes it a useful storage option. The ability to regasify LNG rapidly makes it especially suitable as a source of gas supply to satisfy

peak demand.
although not as high as in the summer. The seasonal pattern for industrial demand is similar to that for the residential and commercial sectors, but with much smaller

shifts between the high and low points.

Supply

Sources of gas in the Northeast are production, imports,

pipeline transportation, and storage withdrawals. Production of natural gas in the Northeast is limited to relatively small volumes in States in the Middle Atlantic

region, where 1998 production was less than 4 percent of

the total volume delivered to end users in the Middle

Atlantic and less than 3 percent of the total delivered to

end users in the Northeast as a whole.57 The Northeast

received 71 percent of current supply58 in 1998 from net

inflows from other U.S. regions, 24 percent from pipeline imports, and 2 percent from LNG imports. In New

England, 89 percent of current supply was obtained

from the domestic transportation network.59 Although

LNG is a small part of total regional supply, it is significant in New England. LNG made up 11 percent of New

England supplies in 1998, and LNG volumes more than

doubled in 1999 (96 billion cubic feet, compared with 43

billion cubic feet in 1998).

The key issue for the natural gas infrastructure is the

ability of the supply system to meet gas demand requirements on winter peak days. At times of peak gas

demand, system operators rely on various methods to

manage demand and obtain suitable supplies. Demand

is managed by removing some users from the system,

usually under the terms of interruptible service contracts. To ensure delivery to customers who generally

pay higher rates for firm service, supplies from the pipeline system may be supplemented with inventories

drawn from regional underground storage facilities or

with smaller amounts of LNG or propane from storage.

As demand rises to peak levels, maintaining gas service

to firm customers requires the use of increasingly costly

measures, eventually involving LNG and propane

storage volumes. On average, net storage withdrawals

provide 20 percent or more of total U.S. natural gas consumption during the winter period; however, reliance

on storage can be much higher in some peak periods. For

example, on a typical winter day, gas from storage meets

60 to 80 percent of Ohio’s natural gas requirements.60

Transportation

Gas transportation pipelines entering the Northeast,

including domestic lines from the Southwest into the

Middle Atlantic region and cross-border lines from Canada, have a combined design capacity of 12.52 billion

cubic feet per day, or an annual equivalent of 4.57 trillion

cubic feet—well in excess of the region’s total consumption of 2.9 trillion cubic feet in 1998. Existing pipeline

capacity in many parts of the Northeast is adequate to

meet current firm-service demand, and some of the

area’s pipeline systems have unused capacity on an

annual basis. In fact, capacity utilization rates along

pipeline corridors entering the Middle Atlantic and

New England regions averaged 61 to 86 percent during

1998.61 During peak periods, however, most service providers are heavily, if not fully, utilized.

Transported gas is the major source of new gas supplies

in the Northeast, and capacity entering the region grew

by 13 percent from 1996 to the end of 1998. Expansion

continued in 1999, with the completion of nine projects

providing 1,080 million cubic feet per day, or about 0.4

trillion cubic feet per year, of additional capacity (Figure

35). More than half of the new capacity in 1999 (618 million cubic feet per day) was associated with the

Maritimes and Northeast Pipeline and Portland Gas

Transmission System projects, which will transport

Canadian gas to the New England area. Those two projects alone increased overall pipeline capacity into the

Northeast region by 5 percent.62

There are some problem areas in the Northeast. Pipeline

capacity in the New York City area appears inadequate

to meet growing market demand, as indicated by recent

price spikes in the area due to several constraint points

that have developed in recent years. The Leidy area of

north central Pennsylvania (a major hub area with

numerous interconnections among major interstate natural gas pipelines) is rapidly becoming a potential constraint for pipeline gas flowing to the East Coast, and

particularly for northern New Jersey and New York

City. Although the current pipeline capacity through the

area appears sufficient, growing demand for gas trading

and transport capacity probably will require some

38 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

57The last year of available EIA natural gas data with regional detail is 1998.

58Current supply is the sum of production, imports, and net inflow from other domestic regions. It excludes storage withdrawals.

59“Supplies from the domestic transportation network” refers to the infrastructure from which the gas enters the region. The supplies

may originate either as domestic production or as foreign production that passes through other U.S. regions.

60Public Utility Commission of Ohio, Weather Impacts on Gas Cost and Residential Winter Heating Bills, 1996-1997 (January 31, 1997), p. 6.

61Energy Information Administration, EIAGIS-NG (March 2000).

62The completion of the Maritimes & Northeast Pipeline occurred late in the year. It did not initiate flow to U.S. markets until January 4,

2000.
expansion of existing pipelines.63 In the Boston metropolitan area, demand from developers of gas-fired

power generation plants has been growing and is

expected to grow more rapidly over the next decade,

creating the potential for capacity shortfalls.

Another 23 interstate pipeline projects have been proposed for the Northeast region in 2000-2002—the largest

number for any U.S. region (Figure 36). Several major

projects were scheduled for completion by November 1,

2000, but delays in the approval process are expected to

push back the startup dates for the Millennium, Independence, and several associated projects representing

some 2 billion cubic feet per day of potential additional

capacity. Given the competing nature of some proposals

and the possibility of other alternatives to meet at least a

portion of projected demand, generally not all proposed

projects are expected to be built.64

The 23 projects proposed for the Northeast over the next

several years would add a total of 5.9 billion cubic feet

per day to the region’s pipeline transportation capacity.

The prospects are uncertain, however, for some of the

projects.65 For example, the New York portion of the

Millennium pipeline has been delayed due to regulatory

concerns about its necessity and safety, and negative

public reaction to parts of its proposed route,66 despite

the fact that other sections have been approved by the

Federal Energy Regulatory Commission (FERC) and the

project is already underway. Some of the proposed

projects involve new pipelines from the Midwest to

the East Coast that would carry transshipments from

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 39

PADD V

Western

3 Projects

319 Million

Cubic Feet per Day

Central

8 Projects

1,915 Million

Cubic Feet per Day

Southwest

3 Projects

829 Million

Cubic Feet per Day

Southeast

6 Projects

1,412 Million

Cubic Feet per Day

Midwest

5 Projects

258 Million

Cubic Feet per Day

Northeast

9 Projects

1,080 Million

Cubic Feet per Day

Figure 35. U.S. Pipeline Development Projects Completed in 1999

Note: A dot on the map indicates the location of either a compressor station expansion or the furthest delivery point along a segment of new pipeline capacity.

Source: Energy Information Administration, derived from EIAGIS-NG Geographic Information System, Natural Gas Pipeline Construction Database, as of March 2000.

63Major pipeline segments operated by the Columbia Gas Transmission Company, CNG Transmission Company, National Fuel Gas

Supply Corporation, Tennessee Gas Pipeline Company, Texas Eastern Transmission Company, and Transcontinental Gas Pipeline Company traverse the area around Leidy, Pennsylvania. The new Independence Pipeline and Transco Market-link projects both propose significant development of capacity in the area, and Tennessee Gas Pipeline and National Fuel Gas Supply Companies have also indicated

tentative plans to expand segments of their systems in the area.

64Three projects that were originally announced for development in 2000 have yet to be filed with the FERC, and another 10 projects currently scheduled for 2000 in their filings have yet to be approved by the FERC.

65This simple summation of project capacities is for illustrative purposes. Because some of the projects are complementary and some are

competing and might be mutually exclusive, the estimate of 5.9 billion cubic feet per day does not mean that these projects, if built, could satisfy additional market demand of that magnitude.

66For example, in January 2000, the New York Public Service Commission, fearing potential disruptions of electric service, asked FERC

not to award final environmental clearance to the Millennium pipeline, because they were opposed to the sharing of a transmission

right-of-way with Consolidated Edison Co. of New York as an “unacceptable risk.” See “NY Pulls in Welcome Mat for the Millennium,”

NGI’s Daily Gas Price Index (January 26, 2000).
cross-border pipeline projects bringing gas from Canada

to the Midwest region. If one or more of the new domestic pipelines were not built, unused capacity on existing

pipelines from the Midwest to the Northeast could pick

up a portion of the excess import load; however, this

would likely prove inadequate in the long term, and

even if the new projects are brought to completion, the

existing lines are likely to undergo expansion if Northeast demand continues to grow as expected.

Storage and Local Distribution

Two types of gas storage are currently in use in the

Northeast: underground sites—primarily, depleted oil

and gas reservoirs67— and above-ground LNG facilities.

LNG has a higher deliverability (or drawdown rate relative to stock levels) and is available in New England, but

it is used only for short durations, generally to satisfy

peak demand. Depleted oil and gas reservoirs take 5

months or more to fill and generally can be depleted

over a 3-month period. The difference in flow performance for the two types of storage is reflected in their

contributions to deliverability and capacity totals.

Almost 95 percent of Northeast stock storage capacity in

1998 was attributed to underground facilities in western

New York and Pennsylvania, which account for only 70

percent of maximum deliverability (Table 8). This difference affects supply availability: the LNG storage units

contain only 8 days of supply when filled, as compared

with more than 57 days of supply available on average

from the underground units when they are filled.68

A simple view of gas storage is that it allows supplies to

be acquired during periods of slow demand and delivered to end users during peak demand periods. In practice, however, storage utilization strategies tend to be

more complex and interwoven with Public Service Commission requirements to provide reliable service to firm

customers. Storage activities are managed to meet a

combination of objectives: supplying gas to satisfy peak

40 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

PADD V

Western

9 Projects

900 Million

Cubic Feet per Day

Central

10 Projects

3,100 Million

Cubic Feet per Day

Southwest

7 Projects

1,900 Million

Cubic Feet per Day

Southeast

12 Projects

3,500 Million

Cubic Feet per Day

Midwest

17 Projects

8,400 Million

Cubic Feet per Day

Northeast

23 Projects

5,900 Million

Cubic Feet per Day

Figure 36. Proposed U.S. Gas Pipeline Expansions, 2000-2002

Note: A dot on the map indicates the location of either a compressor station expansion or the furthest delivery point along a segment of new pipeline capacity.

Source: Energy Information Administration, derived from EIAGIS-NG Geographic Information System, Natural Gas Pipeline Construction Database, as of March 2000; and Federal Energy Regulatory Commission, Applications for “Certificate of Public Convenience and Necessity.”

67Salt cavern sites are becoming common in other regions of the country, but the only one in the Northeast as of December 1998 was the

N.Y. State Electric & Gas facility in Seneca county. Maximum deliverability from the site was only 80 million cubic feet per day, and it is

included with the data for other underground units. Another potential underground storage option is lined rock cavern (LRC) storage,

which is being researched currently. If commercially successful, LRC storage would be suitable for the Northeast. This option was not

included in the present analysis.

68Days of supply is measured as the ratio of working gas capacity to peak day deliverability. LNG supplies and normal underground

storage should not be combined for this calculation. The addition of LNG distorts the calculation because it has a very high deliverability for

only short durations. In practice, flows diminish as underground stocks are depleted, and actual drainage of all working gas from depleted

reservoirs would require more time.
demand, balancing pipeline loads, and financial arbitrage. For the LDCs, which generally are responsible as

the supplier of last resort, the ability to meet peak

demand throughout the entire winter is arguably the

predominant consideration, and their withdrawal strategies often reflect their concerns about being able to

meet demand surges in the event of a late season cold

snap. An unfortunate consequence of such a strategy is

that reduced reliance on natural gas from storage

restricts gas supplies to lower levels and may lead to

higher prices in the short run. This apparently is what

happened in the winter of 1996-1997, when gas was kept

in storage during an early cold snap. Warm weather followed, and at least some withheld storage volumes were

not needed later in the winter.69

Ideally, gas storage facilities in the Northeast would be

sited close to major markets on the Atlantic coast, in

order to minimize the time and expense required to

move supplies to consumers and avoid potential transportation bottlenecks when demand surges. Proximity

of storage facilities to end users would reduce the need

for construction of additional pipeline transportation

capacity to meet peak demands, allowing long-distance

transportation lines to be designed to accommodate

average flows, with some excess for responding to

demand surges. Off-peak transportation would be able

to move gas for baseload demand, storage replenishment, and incremental service to low-priority customers

not supplied during peak periods. Local distribution

networks in the Northeast already are designed to meet

very high demand surges.70 For example, the 1999 flow

capacity of transportation pipelines into New England is

only 2.7 billion cubic feet per day, but local gas utilities

managed peak deliveries of 3.4 billion cubic feet on January 17, 2000.71 The incremental sendout most likely represents a combination of storage gas and LNG imports.

There are distinct tradeoffs in performance and cost

among storage, transportation pipelines, and LDCs.

Although there are advantages to storage in managing

transportation costs, reliance on storage incurs costs

for injection (into an underground reservoir or conversion to LNG for above-ground storage), storage, and

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 41

Table 8. Gas Storage Capacity and Deliverability in the Northeast, 1998

Region and State

Working Gas Capacity

(Million Cubic Feet)

Total Capacity

(Million Cubic Feet)

Peak Day Deliverabilityb

(Million Cubic Feet per Day)

Days of Supply

at Full Capacity

Middle Atlantic

Underground

New York . . . . . . . . . . . . . . . . 84,389 187,924 1,097 76.9

Pennsylvania . . . . . . . . . . . . . 384,610 739,492 7,070 54.4

Total . . . . . . . . . . . . . . . . . . 468,999 927,417 8,167 57.4

LNG

New York . . . . . . . . . . . . . . . . 3,399 3,399 772 4.4

New Jersey . . . . . . . . . . . . . . 4,962 4,962 714 6.9

Pennsylvania . . . . . . . . . . . . . 4,253 4,253 544 7.8

Total . . . . . . . . . . . . . . . . . . 12,614 12,614 2,030 6.2

New England

LNG

Connecticut . . . . . . . . . . . . . . 2,549 2,549 127 20.1

Massachusetts. . . . . . . . . . . . 9,413 9,413 999 9.4

New Hampshire . . . . . . . . . . . 4 4 5 0.8

Rhode Island . . . . . . . . . . . . . 2,469 2,469 257 9.6

Total . . . . . . . . . . . . . . . . . . 14,435 14,435 1,388 10.4

Northeast

Underground . . . . . . . . . . . . . . 468,999 927,417 8,167 57.4

LNG . . . . . . . . . . . . . . . . . . . . . 27,049 27,049 3,418 7.9

Total . . . . . . . . . . . . . . . . . . . 496,048 954,466 11,585 —a

a

LNG totals should not be added to underground storage, because LNG is normally used to satisfy peak demand when underground storage is

also being used. b

Peak day deliverability at 11,585 million cubic feet per day is available only for about 8 days. For the remainder of the winter, without LNG, peak

day deliverability is 8,167 million cubic feet per day.

Sources: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Underground Natural Gas Storage Database

and LNG Facilities Database, as of March 2000.

69Energy Information Administration, “Natural Gas Residential Pricing Developments During the 1996-97 Winter,” Natural Gas

Monthly, DOE/EIA-0130(97/08) (Washington, DC, August 1997).

70In some areas, gas is delivered directly to consumers by interstate pipeline companies, bypassing the LDCs. This practice is not

thought to be widespread in the Northeast.

71“New England’s Natural Gas Industry Reaches New Growth Levels,” New England Gas Association Press Release (March 23, 2000),

web site biz.yahoo.com/prnews/000323/ne_gas_ass_1.html.
withdrawal (or LNG regasification) that add directly to

the unit costs of delivered gas. Further, in responding to

the needs of a growing market, the costs of incremental

storage expansion are likely to be higher than the average to date. The number of potential future underground storage sites is limited, and siting of new LNG

storage tanks tends to be problematic, encountering

local resistance that can increase costs even when it

is successfully overcome. Generally, the high deliverability and higher costs make LNG storage most suitable

as a source of supply in periods of extreme peak

demand.

Sales and Service Contracts

Because natural gas demand is seasonal and pipeline

systems generally are designed to handle expected loads

during periods of peak demand (for example, pipelines

typically are operated at as much as 120 percent of

design pressures72 to increase “line pack” during shortterm demand peaks), spare capacity usually is available

during off-peak periods, even after accounting for gas to

replenish storage inventories. The combination of fixed

pipeline capacity and variable load has led to the development of interruptible service contracts for some natural gas customers, as opposed to firm service contracts,

which guarantee uninterrupted gas supplies throughout the year. Interruptible service contracts with pipeline operators or LDCs vary in terms and conditions but,

generally, allow for service interruptions as a result of

either temperature threshold triggers or system operating conditions (for example, when line pressure is

threatened by high rates of drawdown on the system). In

addition, some contracts provide firm service only for a

limited duration, such as a month, or on a seasonal basis,

with suspensions of service permitted during the winter. Suspension of service is not considered an interruption as long as the terms of the arrangement are fully

met. Roughly 10 to 15 percent of all natural gas deliveries to U.S. consumers by interstate pipelines in 1997

were on an interruptible basis, down substantially from

roughly half of all deliveries in the late 1980s.73

Interruptible gas contracts and firm service on a temporary basis allow pipeline operators to increase utilization of their fixed assets and better manage costs of

service on average. Higher utilization overall enhances

the economic return on pipeline assets, encourages further investments in the gas delivery system, and provides opportunities for large-volume energy consumers,

such as industrial customers and electricity generators,

to obtain energy supplies at lower prices. Sales of

off-peak interruptible capacity also generate revenues

that contribute toward at least a portion of pipeline capital costs, providing benefits to firm service customers as

well.

Natural gas service may also be suspended voluntarily

by some customers with switchable or dual-fuel capability, even when delivery capacity is available. For example, there are reports that some demand shifted from

natural gas to distillate fuel oil during January and February 2000 because of the relative fuel prices, although

most information to date on this market behavior is only

anecdotal. Understanding this behavior and the motives

behind it, based on relative fuel prices, is important.

Preliminary information indicates that there were interruptions of gas service in the Northeast in January 2000

as a result of both temperature and operating conditions.74 There were no interruptions under firm service

contracts, and there were no service interruptions at all

in February. During January 2000, operational flow

orders (OFOs) were issued by three pipeline companies

serving the Northeast, alerting customers that they were

expected to manage their gas takes from the system to

conform strictly to the terms of their contracts. This was

done by the pipelines for purposes of load management,

and it does not indicate a reduction in service below

capacity levels.

Interstate transporters and LDCs go to great lengths to

avoid performance failure under firm service contracts

because of the serious implications for their customers

and others. (Although quite rare, interruptions may

occur under firm service contracts when extreme conditions diminish system capability to the point that deliveries cannot be made to meet all of the supplier’s firm

contract obligations.) The companies also try to continue

service even under interruptible contracts, subject to the

availability of capacity during peak periods and the ability to continue service without resort to high-cost measures, such as propane injection, that are not provided

for under interruptible service fees. As a result, interruptions are a regular feature of the gas industry. The movement to regulatory reform at the Federal and State levels

has not altered the basic role or impact of interruptible

gas contracts. The distinguishing characteristic of regulatory reform in the natural gas industry is a separation

of commodity sales from other services. The impact of

42 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

72A pipeline’s design capacity is defined as the maximum throughput that can be sustained throughout the year. Actual flow can exceed

the design capacity for brief periods.

73Interstate Natural Gas Association of America, Gas Transportation Through 1997, Report No. 99-01 (April 1999). The stated percentages

reflect primary capacity contract arrangements. Through capacity release transactions, at least some of the capacity held by firm contracts is

resold on an interruptible basis.

74EIA is conducting a data collection effort directed to local distribution companies in an attempt to develop independent, statistically

based estimates of gas service interruptions and their impact on distillate fuel oil markets across the Northeast. Results will be provided in a

study scheduled for release later in 2000.
and response to a failure to deliver gas are the same

whether the contract is for service only or for service and

sales of gas to the customer.

Prices

End-use prices for natural gas are determined by the

costs of the commodity (fuel) and related supply services (transportation, storage, and local distribution).

They also reflect the type of service provided (firm or

interruptible). For residential users, gas commodity

price is only about 30 percent of the delivered price, and

the remainder reflects the cost of services between the

wellhead and the burnertip on a firm service basis.

Because natural gas commodity prices are a small percentage of the delivered price, fluctuations in the gas

commodity price result in much smaller relative

changes in the delivered price to small-volume

customers.

Small-volume customers, such as residential and some

commercial and industrial consumers, generally receive

their gas from LDCs, which typically bill their customers

monthly. Monthly billing smooths out some of the daily

price volatility seen in upstream markets, but it also

introduces an information lag. Bills arrive after the billing period during which consumption decisions have

been made, and the bill is stated in terms of totals or

averages for the period. It is difficult at best for consumers to ascertain their marginal costs for timely decisions

within the consumption period. Thus, if upstream supply prices rise rapidly, small-volume customers are not

likely to be aware of the change in prevailing prices until

after the billing period.

Effective price signals to residential customers also are

limited by residential billing procedures, such as

levelized billings, that are designed to avoid unexpected

large increases in monthly gas expenditures when possible. This objective has resulted in the availability of consumer options such as budget-payment plans, in which

the consumer is charged a uniform rate for 11 months,

and discrepancies between cumulative payments and

costs are addressed in the 12th month.75 Budget-payment plans obscure not only the marginal cost of

additional gas units consumed on any day, but also the

average cost for the month or season.76

Natural gas billing methodologies can help the consumer by blunting the immediate impact of gas price

fluctuations, but they do not provide a means to avoid

paying their gas costs. In fact, residential prices and bills

can rise dramatically during the heating season. A prime

example occurred during the winter of 1996-1997.

Nationally, although gas consumption was down 5.7

percent from the prior year, monthly prices were 10 to 20

percent higher, resulting in an expenditure increase by

residential customers of 9 percent for the entire heating

season.

Large-volume customers vary in their approach to gas

acquisition, because the scale of their energy use provides opportunities that generally are unavailable to

small-volume customers. Large customers tend to purchase gas “off system” directly from a marketer or producer and contract for delivery separately, rather than

purchasing from a merchant LDC. The companies seek

the best deals for their requirements, and if energy is

particularly important to their operations they may even

utilize an energy acquisition unit that specializes in

sophisticated market trading.

Large-volume customers that cannot switch from natural gas depend on gas-on-gas competition and competition between service providers for advantages in their

deals. Those with dual-fuel or switchable capability look

for the least expensive fuel, relying on interfuel competition to yield advantageous transactions. The alternate

fuel used by consumers who have natural gas as one

option generally is distillate or residual fuel oil. The gas

commodity itself, excluding the addition of substantial

transportation, delivery, and storage charges, typically

is much less expensive than petroleum products on a Btu

basis. When natural gas delivery can be arranged at discounted rates, the combined costs result in an economic

advantage generally favoring gas use; however, discounted service usually is available only under interruptible contracts.

Evaluating the Effects of Changes in

Natural Gas Consumption Patterns

The potential for large-volume consumers of distillate to

switch to natural gas varies over the short term versus

the longer term horizon. The goal under the short-term

scenario would be to prevent large-volume dual-fuel

customers, including those with interruptible gas service contracts, from entering the distillate market to purchase distillate fuel oil during peak demand periods. In

the longer term scenario, an additional goal would be to

shift at least some large-volume consumers of distillate

fuel oil (not currently able to switch) to year-round

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 43

75Complete reconciliation may not be achieved in a single month, depending on the amount owed by the consumer. The objective of

these plans is to “smooth” the amounts owed by the customer, and in practice, ad hoc adjustments are introduced to achieve that goal. For

example, payments under a budget-payment plan may be adjusted upward, even when out of cycle, if costs have risen so much that further

delays in cost recovery are likely to result in a substantial “shock” if allowed to accumulate until the next reconciliation month. Thus, even

customers under a plan for payment smoothing will experience some impact from a sudden, large increase in upstream gas prices.

76Alternative payment plans are not particular to natural gas markets. Similar plans are offered to heating oil customers.
use of natural gas.77 In both cases, demand for natural

gas in the Northeast region would be expected to rise

above the levels already expected to result from the continuation of current market trends. The focus of this

analysis is to estimate the effect of such shifts on natural

gas infrastructure requirements.

One measure that provides insight into the potential

short-term impact is provided by estimating the incremental load that shifted from natural gas to distillate

fuel oil in the Northeast in January 2000. A comprehensive, direct estimate of the energy volumes affected is

not available. In Chapter 3 of this report, it is estimated

that the maximum switchable dual-fuel capability in the

Northeast during a colder-than-normal winter heating

season (December-February) is 133,000 barrels per day.

That analysis is extended here to estimate the implications of such a switch on the natural gas infrastructure.

A separate estimate of incremental demand for distillate

fuel oil due to gas service interruptions in the short-term

scenario was developed by EIA from in-house data and

information provided by State agencies in New York,

New Jersey, Connecticut, and Massachusetts—four of

the top distillate-consuming States in the Northeast. The

increase in distillate consumption from customers shifting out of natural gas is estimated at roughly 97,000 barrels per day.78 The impact of distillate purchases by such

customers, however, remains unclear pending results of

an EIA survey of customers whose gas service was interrupted. This volume is equivalent to incremental peak

demand of 510 million cubic feet of natural gas per day

in the Middle Atlantic region and 40 million cubic feet

per day in New England.79 The long-term impact,

through 2005, includes the projected market growth in

the Northeast in the reference case of the Annual Energy

Outlook 2000 (AEO2000), the short-term impact, and the

additional effects of shifting large-volume consumers of

distillate fuel oil to natural gas through equipment conversions and retrofits.

A number of uncertainties are involved in estimating

natural gas infrastructure requirements. EIA’s AEO2000

forecast, available monthly data, anecdotal evidence,

and a number of assumptions were used in developing

the estimates presented here. The initial focus of the

analysis was to estimate the average daily natural gas

and distillate consumption levels for a more extreme

peak month.80 In reality, peak day consumption levels

can exceed average peak month levels by consequential

amounts. However, for the purposes of this analysis it

was assumed that natural gas storage and pipeline infrastructure requirements would increase in proportion to

the increase in the estimates for the average daily consumption within the peak month. Estimates of 1999 and

2005 business-as-usual energy requirements for the

Northeast were based on annual consumption projections from the AEO2000 reference case, which shows

distillate consumption in 2005 that is 11 percent higher

than 1999 consumption in the industrial sector, 10 percent lower in the residential sector, and 39 percent lower

in the electricity generation sector.

Peak-month volumes for natural gas in a colder-thannormal winter (Table 9) were estimated on the basis of

the peak month to average annual ratios that occurred in

1994, a recent cold winter, and applied to the 1999 and

2005 reference case forecast from AEO2000. The methodology used in Chapter 3 (see Table 7) to derive estimates

of switchable distillate consumption by large-volume,

dual-fired customers in the winter season (December to

February) was applied to 1999 base levels. The estimates

were then converted to peak-month values by assuming

that 40 percent of the winter consumption occurs in the

peak month. The resulting values represent an estimate

of the amount of distillate consumption in a colderthan-normal peak month that could be switched to natural gas in the short term without conversions or retrofits

of existing equipment. These values include natural gas

consumption that would have been switched to distillate fuel due to gas service interruptions.

Over the longer term, by 2005, it was assumed that some

of the large-volume distillate users not currently

dual-fired could convert to natural gas use with equipment conversions or retrofits. For the sake of this analysis, the extreme position was taken that all such users

44 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

77Present small-volume heating oil customers, such as residential and commercial consumers, can shift to natural gas also, but the present analysis is limited to large-volume customers. In general, small-volume consumers do not have strong economic incentives to switch

from distillate.

78The EIA estimate is based on confidential data and therefore cannot be described in detail; however it is quite close to the 100,000 barrels per day estimated independently by the Petroleum Industry Research Foundation (cited in Chapter 2).

79Although not essential to the present analysis, the market impact of energy consumers shifting from natural gas to distillate depends

on market transactions, and not on changes in fuel oil consumption, which are not necessarily equivalent. They can differ due to consumer

use of on-site stocks of their alternative fuel, thus resulting in market purchases less than the daily consumption increase. On the other hand,

the purchasing practices of switchable customers might increase transactions by more than the increase in consumption: i.e., on the day of

purchase, large-volume users may buy fuel oil supplies for a number of days or longer. An analysis of the fuel oil market response also

would depend on the duration of the incremental demand, because the cumulative drawdown would affect available inventories. Because

the present analysis is concerned with the magnitude of incremental switching volumes to estimate gas capacity requirements at peak, duration is not considered to be relevant.

80Although the schedule of distillate purchases can have a significant impact on the distillate market, this analysis estimates distillate

consumption, as opposed to purchases, because the focus is to calculate the comparable level of natural gas that would be consumed if natural gas were consumed in place of distillate.
would convert to natural gas by 2005. As in Chapter 3,

the customers in this category, in combination with the

dual-fired customers, were assumed to include all the

distillate consumption in the electricity generation sector, the space heating portion of the commercial sector

(52 percent), and the manufacturing segment of the

industrial sector (48 percent). These factors were applied

to the 2005 distillate consumption levels from the

AEO2000 reference case. The reference case shows the

following increases in natural gas consumption in the

Northeast from 1999 to 2005 by sector: residential, 2.9

percent; commercial, 3.5 percent; industrial, 10.6 percent; and electricity generation, 152 percent. For the

commercial and electricity generation sectors, the process used to convert annual estimates of switchable distillate consumption to a peak month was the same as

used for the short-term analysis. For the industrial sector, it was assumed that 20 percent of the switchable distillate consumption in a year would occur in the peak

month.

Using the ratio of estimated peak-day consumption to

average day consumption, peak day natural gas requirements in the Northeast in the near term could increase

by 864 million cubic feet per day over the 1999 estimated

peak consumption levels (Table 9). In the longer term, a

scenario in which all large-volume distillate consumers

in the Northeast shifted to natural gas would increase

peak-month consumption of natural gas by up to 2,329

million cubic feet per day from the 1999 base by 2005.

This scenario could raise peak-month natural gas consumption by 15 percent in the Middle Atlantic region

and by 31 percent in New England by 2005 above the

short-term base. The associated capacity expansion

requirements could be substantial.

Pipeline Capacity Requirements

Because the Northeast relies heavily on natural gas supplies from outside the region, the interstate transportation system is a key element in satisfying demand

increases. Given the general lack of interruptible service

on the system during late January 2000, additional loads

at peak times would require expanded capacity. Estimated new pipeline capacity entering a region must

reflect the needed increase to accommodate the load that

otherwise would have shifted to or remained with distillate fuel oil, and to handle the increase in the peak day

volumes resulting from the shift to gas.

Estimated natural gas pipeline capacity entering New

England at the beginning of 1999 was 2,739 million cubic

feet per day. It is estimated that an additional 340 million

cubic feet per day of capacity into New England would

be required to support the short-term shift to gas. By

2005, the initial 1999 capacity would need to be

increased by 846 million cubic feet per day. The recently

built Maritimes and Portland pipelines (618 million

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 45

Table 9. Average Daily Consumption of Natural Gas in the Peak Month Before and After Switching from

Distillate to Natural Gas in the Northeast

Region

Short Term Longer Term (2005)

Million

Cubic Feet

Million

Barrelsa Million

Cubic Feet

Million

Barrelsa

New England

Base Natural Gas Consumption (Not Switchable). . . . . . . . . . . . . . . 2,405b 425 2,582 456

Distillate Switchable/Convertiblec . . . . . . . . . . . . . . . . . . . . . . . . . . . 298 53 566 100

Total Consumption After Switching . . . . . . . . . . . . . . . . . . . . . . . . . . 2,703 477 3,148 556

Percentage Increase From Short-Term Base Consumption

(2,405 Million Cubic Feet per Dayb

). . . . . . . . . . . . . . . . . . . . . . . . . . 12.4% 12.4% 30.9% 30.9%

Middle Atlantic

Base Natural Gas Consumption (Not Switchable). . . . . . . . . . . . . . . 10,572b 1,868 11,182 1,975

Distillate Switchable/Convertiblec . . . . . . . . . . . . . . . . . . . . . . . . . . . 566 100 976 172

Total Consumption After Switching . . . . . . . . . . . . . . . . . . . . . . . . . . 11,138 1,968 12,158 2,148

Percentage Increase From Short-Term Base Consumption

(10,572 Million Cubic Feet per Dayb

). . . . . . . . . . . . . . . . . . . . . . . . . 5.4% 5.4% 15.0% 15.0%

Northeast

Base Natural Gas Consumption (Not Switchable). . . . . . . . . . . . . . . 12,977b 2,292 13,764 2,431

Distillate Switchable/Convertiblec . . . . . . . . . . . . . . . . . . . . . . . . . . . 864 153 1,542 272

Total Consumption After Switching . . . . . . . . . . . . . . . . . . . . . . . . . . 13,841 2,445 15,306 2,704

Percentage Increase From Short-Term Base Consumption

(12,977 Million Cubic Feet per Dayb

). . . . . . . . . . . . . . . . . . . . . . . . . 6.7% 6.7% 17.9% 17.9% a

Distillate equivalent of natural gas consumption shown in the preceding column.

b

1999 base consumption, used to calculate percentage increases after switching for both the short term and longer term.

c

In the short term, this includes only customers with dual-fuel capability switchable from distillate to natural gas, using existing equipment. Also

included is natural gas consumption that would have been switched to distillate due to gas service interruptions. In the longer term, it also includes

customers choosing to convert to natural gas by retrofitting existing equipment or purchasing new equipment to burn natural gas.

Sources: Energy Information Administration, derived from Annual Energy Outlook 2000; and EIAGIS-NG Geographic Information System, Natural Gas Pipeline Database, as of March 2000.
cubic feet per day) should be sufficient for the indicated

requirements in the short term, and they probably can

meet a portion of the additional longer term requirements.81 Pipeline capacity entering the entire Northeast

region was 12,519 million cubic feet per day at the beginning of 1999. The shift from distillate to gas could

require additional pipeline capacity of 839 million cubic

feet per day in the short term and 2,241 million cubic feet

per day by 2005 (Table 10).82 The higher estimates represent a more successful conversion scenario, and the

lower estimates reflect a more conservative assumption

about the willingness and ability of large-volume consumers to shift from distillate fuel oil.

The arrival of gas into the Middle Atlantic and New England regions is the first stage of the supply process. Subsequent delivery of the gas to consumers would require

the intraregional infrastructure to handle local distribution and management of system loads to meet the new

peak load requirements. The introduction of the estimated new firm demand would require either new construction or the identification of uncommitted local

capacity and assignment of that capacity to the new customers. The likelihood of identifying spare capacity that

is properly positioned to serve the entire incremental

load is low.

The need for new or additional pipeline capacity to meet

the growing demand for natural gas in the Northeast can

be handled in several ways, each with particular physical and/or financial advantages and disadvantages.

The least expensive option, often the quickest and easiest, and usually the one with the lowest environmental

impact is to upgrade facilities on existing routes.

Typically, new pipelines, for which right-of-way land

must be purchased, new pipeline laid, and operating

facilities installed, would cost much more than expansion of existing routes. For instance, a new pipeline, such

as the proposed long-distance Alliance Pipeline system,

is expected to cost as much as $1.81 per added cubic foot

of daily capacity. In contrast, the relatively shortdistance Texas Eastern Lebanon expansion project is

expected to cost about $0.25 per added cubic foot of

daily capacity. When recently completed and proposed

projects are categorized by project type, new pipeline

projects average about $0.48 per added cubic foot, major

expansions about $0.33 per cubic foot, and small (compression-only) expansions about $0.15 per cubic foot of

capacity (Figure 37).83

46 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Table 10. Projected Pipeline Capacity Requirements Entering the Northeast Region If Large-Volume

Distillate Consumers Switch to Natural Gas

(Million Cubic Feet per Day)

Region 1999 Base Level Short Term Longer Term

New England . . . . . . . . . . . . . . . . . . . . . 2,739 3,079 3,585

Middle Atlantic . . . . . . . . . . . . . . . . . . . . 11,889 12,531 13,672

Northeast . . . . . . . . . . . . . . . . . . . . . . . . 12,519 13,358 14,760

Source: Energy Information Administration, EIA GIS-NG Geographic Information System, Natural Gas Pipeline Database, as of March 2000..

0

48

28

94

29

32

26

15

33

0 20 40 60 80 100

Cents per Cubic Foot per Day

New Pipelines

Expansions

Overall

Less Than 250 Miles

250 Miles or More

Principally Compressor Additions

All Other Expansion Projects

Figure 37. Average Costs for New Pipeline

Capacity in the Northeast, 1996-2000

Note: Data for each category were not available on all projects. For example, estimated or actual project costs or miles of

pipeline were not announced or not available until filed with the

Federal Energy Regulatory Commission. In some cases,

where profiles of projects were similar but for which one cost

was unavailable, an estimated cost was derived and assigned

to the project based on known data.

Source: Energy Information Administration (EIA), EIAGISNG Geographic Information System, Natural Gas Pipeline

Construction Database, as of August 1998.

81Although new pipeline generally is built to service an expanding market, it can also serve to relieve low pressure areas on the existing

system and to offer competitively priced gas from an alternative source to an area already served, thus displacing existing capacity. Furthermore, pipelines are built to target specific customers in a region. The resulting pipeline may not be suitably located to serve an unanticipated

emerging market, such as consumers wishing to switch from distillate to natural gas use.

82Peak day consumption is met also by storage withdrawals, and so flow capacity into the region increases by less than the rise in peak

day consumption.

83Pipeline construction cost estimates are from Energy Information Administration, Natural Gas 1998: Issues and Trends, DOE/EIA0560(98) (Washington, DC, June 1999).
The cost of a project also varies according to location.

Projects that must go through major population areas, as

in the Northeast region, on average cost more than those

developed in more sparsely populated areas. Although

many of the projects completed in the Northeast in

recent years have been expansions of existing systems,

which are less expensive overall, future development in

the region will include large new and expansion projects

that are, on average, more expensive. For instance, 13

projects were completed in the Northeast Region during

1996 and 1997 at an average cost of about $0.22 per cubic

foot of added daily capacity,84 but projects over the next

3 years are expected to average about $0.37 per cubic

foot. Based on the rough averages of $0.37 per cubic foot

of expansions and new construction in the Northeast

and $0.48 for new pipelines nationwide, the estimated

capital costs for incremental interregional capacity

would range between $829 and $1,076 million for the full

impact of policies that eliminate switching from and

promote conversion to natural gas. These estimates are

for pipelines from the border through the Northeast

region. They do not include additional capacity that

might be required to transport gas to the Northeast

border.

On average, construction and expansion projects completed in 1996 or 1997 took about 3 years from the time

they were first announced until they were placed in service. Construction itself typically was completed within

18 months following FERC approval, sometimes in as

little as 6 months. The remainder of the period was consumed with the initial open season (2 months), plan

development prior to filing (3 months), and FERC

review and reaction to FERC revisions, if any. Generally,

FERC review takes from 5 to 18 months, averaging about

15 months.85 When approval is delayed, however, the

schedule can be extended considerably. For example,

two of the four major pipeline proposals for capacity

expansion into the Northeast, the Independence and

Millennium projects, have been seeking FERC approval

for more than a year, and their possible in-service dates

now appear to be no earlier than 2001 (Table 11). The

combined cost of the two projects and associated projects exceeds $1 billion. These two projects would provide a combined 1,700 million cubic feet per day of new

pipeline capacity, which would appear sufficient to

serve most of the projected incremental demand.86

Natural Gas Storage Requirements

The short-term shift to retain all gas consumers on the

system year-round would heighten the peak day gas

demand. Severe “needle peaks” would require timely

supply responses, likely depending on volumes from

storage. Although deliverability from storage, including

LNG, is 10,197 million cubic feet per day in the Middle

Atlantic, and 1,388 million cubic feet per day in New

England, use of this gas as a frequent source of supply

during peak periods would also depend on the aggregate storage capacity. Storage in underground sites contains less than 2 months of supply at maximum working

gas capacity. Storage drawdowns from LNG facilities at

close to maximum rates would exhaust LNG supplies in

less than a week in the Middle Atlantic region and in 10

days in New England (Figure 38).

Given the more severe peaks in demand for natural gas

that can be anticipated with an aggressive shift to natural gas, storage capacity and deliverability likely would

have to be increased by more than the proportionate rise

in regional demand. However, using the demand

increase as a conservative guideline for the needed

regional storage capacity and deliverability, they would

need to be expanded by up to 15 percent in the Middle

Atlantic region and 31 percent in New England, requiring an increase of 70 billion cubic feet in underground

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 47

Table 11. Proposed Pipeline and Capacity Expansion Projects into the Middle Atlantic Region

Name

From

Region States Involved

Possible First

Year of Service Status

Incremental Capacity

(Million Cubic Feet

per Day)

Independence Pipeline . . . . . . . . Midwest IL, IN, OH, PA, NY 2001 Pending FERC Approval 1,000

Millennium Pipeline Project . . . . . Canada IL, MI, OH, NY 2001 Pending FERC Approval 714

Iroquois Gas Pipeline

Eastchester Expansion . . . . . . . . Canada NY 2002 Not yet filed 220

Note: No firm proposals to expand pipeline capacity into the New England region have been announced or filed with the FERC during the past

year. The Portland Natural Gas Transmission Company held an open season for possible expansion of its recently (1998) completed 178 million

cubic feet per day import system but has yet to announce the results of the market test. The Maritimes and Northeast Pipeline (400 million cubic feet

per day), completed in late 1999, can be expected to expand as Sable Island (Canada offshore) gas production continues to be expanded, but no

plans to do so have been officially announced.

Source: Energy Information Administration, derived from EIAGIS-NG Geographic Information System, Natural Gas Proposed Pipeline Construction Database, as of March 2000; and Federal Energy Regulatory Commission, Applications for Certificate of Public Convenience and Necessity.

84One of the reasons for this was that almost all of the projects were low-mileage or compression additions rather than long-haul new

pipelines.

85Federal Energy Regulatory Commission, Office of Pipeline Regulation, Case Tracking System.

86A complete determination of the ability of these specific projects to satisfy the projected demand would require a detailed analysis that

is beyond the scope of the present effort.
working gas capacity and 1,225 million cubic feet per

day in deliverability in the Middle Atlantic region and

an increase of 6.4 billion cubic feet in LNG working gas

capacity and 733 million cubic feet per day in

deliverability in the Northeast. The siting of new storage

units could present a formidable challenge in light of

previous experience. For example, 12 underground storage projects were proposed in New York and Pennsylvania for the 4-year period 1995-1998, with an associated

working gas capacity of 40.2 billion cubic feet. The projects included 8 salt dome or salt bed projects with 14 billion cubic feet of working capacity.87 By the end of 1998,

only the smallest of the salt projects had been built.

Based on the estimated average cost of $8.7 million per

billion cubic feet for the 12 projects, achieving 70 billion

cubic feet of additional underground capacity alone

would require an estimated $609 million.

A final option relies on propane supplies as a source of

peak shaving supplies. Propane can be stored on site

and then used to meet peak load requirements, but in

practice its use is limited for several reasons. First, storage facilities for petroleum products are not well

received in many locations for environmental reasons.

Second, propane is an expensive source of supply.

Third, increased reliance on propane, even if economically viable, would not disentangle the natural gas and

petroleum fuels markets. Its regular use in supplementing gas supplies would require operators to purchase

propane supplies to replenish depleted stocks. Given

that average propane sales for any month in the New

England and Central Atlantic regions88 only occasionally exceed 100,000 barrels per day, the redirection of

just a fraction of switchable energy demand to propane

probably would overwhelm the regional propane market, potentially causing severe price spikes.

Economic and Institutional

Obstacles to Gas Conversion

Although the natural gas industry in the Northeast

probably could accommodate the infrastructure requirements of a shift from distillate to gas by large-volume

consumers, economic and institutional obstacles may be

more problematic. The economics indicate that the shift

would be likely to involve about $1.5 billion in capital

costs for pipeline capacity into the region, additional

storage facilities, and additional investment in local distribution capacity. In addition, regulatory, environmental, and public perception issues would have to be

addressed (see box on page 49). Local resistance to projects can be fierce, despite the vested interest of communities in increased access to gas supplies. This is

especially problematic in terms of moving gas into and

through States to provide benefits on a regional basis.

For example, Transco has proposed an expansion project that will traverse New Jersey.

The conflicting goals of cost recovery and attracting new

customers through low service charges present an especially difficult problem that will affect pricing strategies.

Capital expansion and the associated expenditures

needed to retain large-volume customers that otherwise

would be subject to interruption of gas service are

unlikely to enhance service to other firm service customers. The direct association between the incremental

investment and costs with an identifiable group of customers is likely to discourage acceptance of rolled-in

(average) pricing by State Utility Commissions, and the

likelihood for success of incremental pricing is unclear.

Current large-volume customers were enticed to gas by

offers of heavily discounted rates. Higher prices may not

discourage gas use if the discounted rates were due to

gas-on-gas rather than interfuel competition, but the

nature of the competition cannot be determined beforehand. If delivered prices under the proposed policies are

higher than the delivered prices with interruptible service under the current system, the additional costs may

actually discourage gas use. Unless the conversion to

48 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

New England

Connecticut

Massachusetts

New Hampshire

Rhode Island

Middle Atlantic

New York

New Jersey

Pennsylvania

0 2 4 6 8 10 12

Billion Cubic Feet per Day

Underground LNG

Figure 38. Regional Daily Deliverability from

Underground and Liquefied Natural Gas

Storage in the Northeast, 1998

Source: Energy Information Administration, EIAGIS-NG

Geographic Information System, Underground Natural Gas

Storage Database and LNG Facilities Database, as of March

2000.

87Energy Information Administration, The Value of Underground Storage in Today’s Natural Gas Industry, DOE/EIA-0591 (Washington,

DC, March 1995).

88The Central Atlantic region includes Delaware, District of Columbia, Maryland, plus the Mid-Atlantic Census Division, which is composed of New Jersey, New York, and Pennsylvania.
gas is required, gas consumers will respond to the economics of the choice.

Another possibility is that the retention of gas customers

on the system on a year-round basis could alter pricing

in a fundamental way. The retention of large-volume

customers on the system even during peak periods

could effectively eliminate “off-peak service” and the

revenues associated with interruptible service contracts.

The economics of investments in incremental capacity

could also be affected adversely unless the pipeline system can capture a customer base without any significant

degree of demand seasonality. The lost opportunity for

revenue generation during off-peak periods probably

would diminish the value of infrastructure assets, affecting the returns to owners of existing infrastructure and

reducing the incentive to invest in the needed capacity.

This would not eliminate all capacity development, but

it would tend to discourage investment in marginal projects or ones with significant seasonal load variation,

which would make implementing the maximum gas

conversion scenario more difficult.

Investment in equipment is another significant challenge that might discourage conversions to natural gas.

Conversion from distillate-only equipment to natural

gas requires either modifying the consumption equipment to burn natural gas or replacing the equipment

entirely. The cost of modification or replacement of the

equipment could, by itself, make the conversion economically unattractive.

Finally, although the elimination of incremental

demand for distillate fuel oil from customers switching

from natural gas during peak demand periods could

mitigate the potential for distillate price spikes in the

short term, it cannot eliminate their possibility. For

example, the bulk of the demand surge in Northeast distillate markets in January 2000 seems to have been a

weather-induced increase involving the regular customer base, and it is likely that prices would have risen

sharply even without the additional demand as other

customers switched from natural gas. Indeed, the successful achievement of the maximum switching of

large-volume customers from heating oil to natural gas

could actually exacerbate the potential for price spikes in

the longer term by reducing the stable base of heating oil

consumption. The remaining heating oil market would

be smaller, consisting of the portion of current customers with a more seasonal pattern of use, and the remaining portion of the distillate market would consolidate to

match the new demand. Operators would be inclined to

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 49

Environmental Considerations for Natural Gas Pipeline Expansion Projects

The environmental impacts of natural gas pipeline construction for interstate transportation or local distribution projects depend on project size, length, and

design. A large greenfield pipeline route, built from

scratch, necessitates a good deal of environmentally

sensitive action compared with a project that only

involves the upgrading of existing facilities to expand

capacity. For instance, planning of a new route must

include an evaluation of its need to cross wetlands,

wildlife-sensitive areas, and potential archaeological

sites. Alternative routes must also be available in the

event that regulatory authorities withhold approval.

Other impacts that must be evaluated include the

effects of clearing construction routes and building

access roads, the temporary or permanent redirection

of waterways, possible discharges of oil-residues

(when converting an oil line), and discharges of hydrostatic test water when leaks are detected.

The potential environmental impacts of completed

projects must also be considered, such as emissions

and noise from compressor station operations. When

natural gas is used to fuel a compressor station, the unit

will emit approximately 50 tons of nitrogen oxide, 75

tons of carbon monoxide, and 50 tons of volatile

organic compounds per year (based on continuous

year-round operation of a unit with a 3,300 horsepower

rating). Some compressor stations use electricity rather

than natural gas for fuel; their on-site direct emission

levels are zero, although off-site emissions result from

electricity generation.

The National Environmental Policy Act of 1969

(NEPA) requires that anyone proposing to undertake a

major interstate-related project, such as construction of

a pipeline, LNG import terminal, gas storage field, or

other major project that may have a significant impact

on the environment first produce an environmental

impact study (EIS). The EIS must examine the environmentally sensitive features of the project and describe

the actions that are to be taken to mitigate potential

damage. The FERC must evaluate and approve any EIS

associated with a pipeline construction project within

its jurisdiction.

Depending on the project profile and its proposed

route, the preparation of the EIS itself can be a major

undertaking, the approval process lengthy, and the

cost of implementing remedial actions significant. Regulators often ask for additional data, and delays often

arise before environmental approval is granted. In

some instances, when only conditional environmental

approval is granted, the project’s economic viability

may be affected by unanticipated costs and schedule

delays. Although most proposed pipeline projects

encounter little or no delay as a result of environmental

review, the review can become quite lengthy when

approval has been delayed.
reduce inventories given the smaller market, the relative

swing between seasons would be larger, and inventory

management would be more uncertain. As the stock

cushion diminished, the market could become less prepared for sudden increases in demand or decreases in

supply.

50 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options
5. Distillate Fuel Oil Supply, Infrastructure, and Pricing

Introduction

Distillate fuel oil markets in the United States involve

two products: low-sulfur distillate, which is used as a

transportation fuel (diesel) for on-highway vehicles, and

high-sulfur distillate, which is used for space heating

(heating oil) in the residential and commercial sectors

and as a fuel for other stationary (nontransportation)

applications in the commercial, industrial, and electricity generation sectors. Beginning in October 1993, the

U.S. Environmental Protection Agency limited the

allowable sulfur content of distillate fuel oil used as diesel fuel for on-highway trucks, buses, and cars.

Although low-sulfur distillate can be used in any application, it is usually taxed as a highway fuel. The tax is

imposed at the point the product “breaks bulk,” or is

separated from a large shipment into smaller delivery

sizes, usually at a storage terminal. At the same time,

high-sulfur distillate for non-highway use is dyed to

identify it. Since 1993, the Energy Information Administration (EIA) has collected data separately for low-sulfur

and high-sulfur distillate fuel oil.89

The Northeast uses more high-sulfur distillate fuel oil

than any other U.S. region, accounting for more than

two-thirds of the total consumption of distillate fuel oil

in the U.S. residential and commercial sectors in 1998.

The residential and commercial sectors in the Northeast

account for more than one-half of the region’s distillate

fuel oil use (67 percent in New England and 44 percent in

the Central Atlantic), whereas in the other regions of the

country residential and commercial uses make up only 7

percent of total distillate consumption. Conversely,

on-highway use of low-sulfur distillate accounts for

only 38 percent of total distillate consumption in the

Northeast (25 percent in New England and 44 percent in

the Central Atlantic), compared with 62 percent in the

other regions.90

Market Structure

The infrastructure of the distillate fuel oil industry in the

Northeast begins with large distribution centers, which

provide supplies to smaller distribution points that, in

turn, supply thousands of retail dealers who deliver fuel

to millions of homes. The large distribution centers play

a central role in setting market prices throughout the

region. A variety of factors have combined to make New

York Harbor a product trading center for distillate fuel

oil: continuous supply from a variety of sources, available storage capacity, transportation alternatives for

bringing the product into and out of the area, and the

participation of many market players. Because it is the

physical source of much regional supply and an alternative market for companies with product to sell, including area refineries, the New York Harbor price quickly

reverberates throughout the region. Boston is a second-tier trading center in terms of the world market

because its sources of supply are fewer (imports and

resupply from the New York Harbor area), but it is a critical distribution center for New England.

Generally speaking, independent marketers provide the

gateway for distillate fuel oil supplies in the Northeast,

and especially in New England. They own and operate

oil storage terminals that receive supplies via tanker,

barge, or pipeline. They sell to retailers and to large bulk

consumers from their terminal “racks”— the superstructure of pipes, manifolds, and hoses under which trucks

are loaded. Marketers offer a host of services to their customers, including lines of credit, hedging programs,91

and bid support. The wholesale market in the Northeast

has undergone considerable consolidation in recent

years. The largest terminals, which form the core of the

region’s supply network, are still operating but are

owned by fewer companies. Moves toward efficiency, as

well as increased environmental regulations, have

resulted in closure of some smaller dealer-owned storage facilities located closer to consumers.

For more than a decade, refiners such as the major oil

companies have rationalized their operations, carefully

choosing their regional product markets and withdrawing from the markets where they did not have a strategic

position. The large refiners that have remained in the

Northeast continue to own some marketing assets, such

as terminals, but the focus of their regional operations

has shifted to transportation fuels (motor gasoline and

diesel) rather than heating oil. The independent refiners

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 51

89EIA’s petroleum supply data show supply on the basis of broad regions, Petroleum Administration for Defense Districts (PADDs). The

information to quantify supply details for regions smaller than the PADDs is not generally available, although selected data series are available on a sub-PADD basis, separating PADD 1, the East Coast, into New England, the Central Atlantic, and the South Atlantic. See Chapter 1

for definitions.

90Energy Information Administration, Fuel Oil and Kerosene Sales 1998, DOE/EIA-0535(98) (Washington, DC, August 1999).

91Hedging programs are based on the commodity futures price of heating oil.
that own capacity in Pennsylvania and New Jersey are

active in the heating oil market, but they are bigger players in the Central Atlantic than in New England.

Retail dealers generally pick up high-sulfur distillate

fuel oil from wholesale terminals in trucks. The oil is

sometimes transferred to a centrally located bulk plant

and from there dispatched in smaller trucks for home

delivery. Many retailers, however, dispatch delivery-size trucks to the wholesale terminal, which then

proceed directly to deliver the oil to homeowners and

other consumers.

The dense market infrastructure in the Northeast provided several alternatives for customers to obtain supplies of distillate fuel oil in January and February 2000.

Although the system did not work smoothly,92 it did

meet the minimal needs of almost all customers. When a

terminal in one area ran out of product because of delivery delays, there was nearly always a neighboring competing terminal that filled the gap. The “wet” terminal,

with product to sell, naturally experienced a surge in

demand for its barrels. While the barrels were available

to all comers, historical customers generally got preferential treatment, and volumes were routinely allocated

on the basis of year-earlier purchases. Furthermore, with

dealers’ trucks all queuing at one terminal instead of

two, there were inevitably delays, and in many cases the

trucks had to accept less than a full product load. The

delays and the need to return to the terminal more often

added further to the cost of delivery, and many

customers were inconvenienced and paid higher prices

than anticipated.

The delivery system in the Northeast has become tighter

and tighter as competitive pressures have required that

market participants store and deliver oil more efficiently. Decades ago, stocks probably would not have

reached such low levels, and there would have been

more inventory in smaller terminals backing up the supplies in the major terminals. Although the current system fosters lower prices in a normal market, it increases

the potential for brief periods of price spikes, as seen in

the winter of 1999-2000.

Sources of Supply

As shown in Figure 39, the Northeast gets its supplies of

distillate fuel oil from the following sources:

• Shipments from Gulf Coast refineries via pipelines

and, to a smaller extent, tankers or barges

• Shipments from Central Atlantic refineries distributed throughout the region by pipelines and barges

• Imports from offshore and foreign areas—most

notably, Canada, Venezuela, and the Virgin Islands

(considered by EIA to be imports)—which come

either to central distribution centers such as New

York Harbor and Boston, from which they are redistributed, or to smaller ports, where they meet local

needs.

52 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Gulf Coast

via Pipeline

to Linden, NJ

Refineries

Pipeline

Refinery

Refinery

Via Tanker

from Canada,

Venezuela,

Virgin Islands

Direct Imports

and Redistribution

Refineries in

Philadelphia

and New Jersey

Via Truck

from Canada

Large Ports and

Distribution Points

Other Ports of Entry

Regional Pipelines

Figure 39. Northeast Distillate Fuel Oil Supply Sources

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

92There was widespread press coverage of supply dislocations and readjustments. See, for instance, Hartford Courant,“Supply of Oil

Tightens, Weather Keeps Tanker Waiting in New Haven Harbor” (February 3, 2000), and“Dwindling Supply Adds to State’s Oil Crunch . . .”

(February 4, 2000).
These sources provide “fresh” supplies to the region.

Generally, from April to November, fresh supplies

exceed regional demand, allowing for a buildup of

regional stocks. From November through March, fresh

supplies amount to less than the market needs, and

stocks are used to make up the remainder of the

requirement.

More than half, and up to 60 percent in some years, of

the supply of low-sulfur distillate fuel oil to the East

Coast comes from the U.S. Gulf Coast (Figure 40). Supplies of high-sulfur distillate rely about evenly on shipments from other regions, such as the Virgin Islands,

and on local refineries. Imports make up a small but significant percentage of supply for both products. The line

for “Product Supplied” in Figure 40—a proxy for consumption—shows stock buildups in the years when the

bars are higher than the line and stock drawdowns when

the bars are lower than the line, as in 1999.

The monthly pattern of annual supply to the East is

shown in Figure 41. For low-sulfur distillate fuel oil,

there is little seasonal variation in supply, with only a

few percentage points difference from the lowest to the

highest month. In contrast, for high-sulfur distillate fuel

oil, the volume of product supplied in the highest

months is 2.5 times the volume in the lowest months.

Each of the supply components increases during the

peak months, and the importance of stocks is clear. On

average over the 1995-1999 period, stock drawdowns

contributed 20 percent of the supply of high-sulfur distillate fuel oil in the winter heating season.

Receipts from the U.S. Gulf Coast

The East Coast receives supplies of distillate fuel oil

from the Gulf Coast via pipeline and waterborne shipments (tankers and, more commonly, barges). Of the net

supplies from other regions shown in Figure 41 (approximately 385,000 barrels per day of low-sulfur distillate

and 230,000 barrels per day of high-sulfur distillate),

pipeline supplies make up the vast majority. Figure 42

shows “gross” shipments to the East Coast from the Gulf

Coast (i.e., without accounting for any shipments moving in the other direction). About 80 percent of the

low-sulfur supplies and more than 85 percent of the

high-sulfur supplies are shipped via pipeline. Supplies

leave the Gulf Coast on the Colonial Pipeline and the

Plantation Pipe Line. The two lines follow roughly the

same route, with the Plantation’s terminus in the Washington, DC, area and Colonial’s terminus in Linden,

New Jersey. About half of the East Coast’s on-highway

(low-sulfur) distillate fuel oil is consumed in the South

Atlantic. Hence, a considerable portion of the pipeline

supply from the Gulf Coast is delivered into PADD 1 in

the South Atlantic States, not in the Northeast.

The tanker and barge movements from the Gulf Coast to

the East Coast are now almost exclusively shipments

across the Gulf of Mexico to Florida, which has no

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 53

1995 1996 1997 1998 1999 1995 1996 1997 1998 1999

0

100

200

300

400

500

600

700

800

Thousand Barrels per Day

East Coast Refineries

Imports

From Other PADDs (Net)

Product Supplied Low-Sulfur High-Sulfur

Figure 40. Distillate Fuel Oil Supply on the East Coast by Source, 1995-1999

Sources: Energy Information Administration, Petroleum Supply Annual, DOE/EIA-0340, Volume 1 (Washington, DC, 1995-1998

issues); and Petroleum Supply Monthly, DOE/EIA-0109(2000/02) (Washington, DC, February 2000), Table 9.
interstate pipeline connections. At times in the past,

tanker and barge shipments of high-sulfur distillate to

the Northeast have briefly soared, in response to market

economics. In late 1996 and early 1997, for instance,

when heating oil stocks were quite low, tanker and

barge shipments from the Gulf Coast to the Northeast

ran at 40,000 to 50,000 barrels per day for several

months. In 1999, they were less than 5,000 barrels per

day, because the market did not require these high-cost

supply supplements. (Throughout 11 months of 1999,

heating oil stocks in the Northeast were high, not low, by

historical standards.) The East Coast also receives minor

volumes of distillate from PADD 2, the Midwest.

Supplies from Area Refineries

East Coast refineries supplied about 37 percent of the

East Coast’s high-sulfur distillate fuel oil in 1999, a significant decline from the 47-percent share in 1998. The

difference is a reflection of the overall market in 1999,

when high inventories and low margins discouraged

additional output. According to EIA’s Petroleum Supply

Annual, there were 14 operating refineries in PADD 1 as

of January 1, 1999. The 11 refineries in the Delaware to

New York City corridor accounted for 95 percent of the

capacity of 1.5 million barrels per day. Supplies from

area refineries are distributed throughout the Northeast

coast by barge and are transported to inland Pennsylvania and New York via the Buckeye Pipeline system.

54 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

100

200

300

400

500

600

700

800

900

1,000

1,100

Thousand Barrels per Day

East Coast Refineries

Imports

From Other PADDs (Net)

Stock Draw

Low-Sulfur High-Sulfur

Figure 41. Average Monthly Distillate Fuel Oil Supply on the East Coast by Source, 1995-1999

Sources: Energy Information Administration, Petroleum Supply Annual, DOE/EIA-0340, Volume 2 (Washington, DC, 1995-1998

issues), Table 5; and Petroleum Supply Monthly, DOE/EIA-0109 (Washington, DC, various issues), Table 8.

1995 1996 1997 1998 1999 1995 1996 1997 1998 1999

0

100

200

300

400

500

600

700 Thousand Barrels per Day

Pipeline

Tanker/Barge

Low-Sulfur High-Sulfur

Figure 42. Distillate Fuel Oil Supplied to the East

Coast from the U.S. Gulf Coast by Mode

of Transport, 1995-1999

Sources: Energy Information Administration, Petroleum

Supply Annual, DOE/EIA-0340, Volume 1 (Washington, DC,

1995-1998 issues), Tables 33 and 34; and Petroleum Supply

Monthly, DOE/EIA-0109 (Washington, DC, various issues),

Tables 54 and 55.
The refineries in the Northeast, like U.S. refiners in general, have their peak operations in the warmer months,

supplying gasoline and diesel for seasonal consumption

and high-sulfur distillate (heating oil) for seasonal stock

builds. Refinery production of high-sulfur distillate fuel

oil increases during the winter months, however, when

demand for home heating oil is at its annual peak. The

sudden unavailability of steady supply from area refineries was a factor in the price runup of early 2000. Low

margins encouraged refiners to undertake routine maintenance in January, and when the supply situation deteriorated, the lack of ready capacity combined with

unexpected equipment outages prevented refiners in

the Northeast from responding rapidly with production

increases.

Imports

According to EIA data, imports supply about 15 percent

of the distillate fuel oil on the East Coast. In recent years,

the major sources of distillate fuel oil imports to the

Northeast have been Canada (32 percent of the Northeast’s 1999 imports), Venezuela (23 percent), and the

Virgin Islands (37 percent).93 In 1999, the refinery in the

Virgin Islands began to be operated by a joint venture

between Amerada Hess (the plant’s original owner) and

the Venezuelan oil company, Petroleos de Venezuela. In

New England, the volume originating in the Virgin

Islands rose while the volume originating in Venezuela

fell from 1998 to 1999. Although distillate fuel imports to

New England that originated in Venezuela declined

by about 10 percent, the share of Venezuelan high-sulfur

distillate imports declined even more, from 75 percent

in 1998 to 60 percent in 1999 (Table 12). The shift to

low-sulfur distillate in January and February 2000 combined was even more pronounced, rising from 46 percent in 1999 to 74 percent in 2000. The share of

Venezuelan distillate fuel imports to the East Coast rose

slightly, from 24.5 percent in 1998 to 24.9 percent in 1999.

In the Central Atlantic, 1999 import volumes from the

Virgin Islands fell. (Venezuelan supplies of distillate

fuel oil into the Central Atlantic are very small.) Imports

into New England often show a distinct seasonal swing,

especially for high-sulfur distillate (Figure 43). The Central Atlantic, with lower imports, is also more focused on

low-sulfur supplies in most years.

A few ports dominate the import trade into the Northeast. In 1999, Boston was the largest import point in New

England, at 36,000 barrels per day, followed by New

Haven (20,000 barrels per day), Portland, Maine (15,000

barrels per day), and Portsmouth, New Hampshire

(14,000 barrels per day). Other ports in the region receiving more than 2,000 barrels per day included Providence, Rhode Island; New London, Connecticut; and

Searsport and Belfast, Maine. Barges and trucks redistribute supplies from these large terminals and distribution centers. In addition, pipelines carry product inland

from New Haven (Buckeye) and Providence (Mobil) to

the Springfield, Massachusetts, area. In the Central

Atlantic, the big ports are in the New York Harbor area.

New York and Perth Amboy, New Jersey, together

received 22,000 barrels per day of distillate fuel oil in

1999 (a significant decline from 1998 volumes, as noted

earlier).

Some of the ports and channels in New England could

be dredged and deepened to allow larger vessels to

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 55

Table 12. Distillate Fuel Imports to New England Originating In Venezuela, 1998-2000

(Thousand Barrels)

Year Month Low-Sulfur Distillate High-Sulfur Distillate Total

1998 January. . . . . . . . . . . . . . . . . 0 653 653

February . . . . . . . . . . . . . . . . 0 1,633 1,633

March . . . . . . . . . . . . . . . . . . 0 1,637 1,637

October. . . . . . . . . . . . . . . . . 923 668 1,591

November . . . . . . . . . . . . . . . 860 0 860

December . . . . . . . . . . . . . . . 899 282 1,181

Total . . . . . . . . . . . . . . . . . . 3,362 9,919 13,281

1999 January. . . . . . . . . . . . . . . . . 1,491 959 2,450

February . . . . . . . . . . . . . . . . 427 1,283 1,710

March . . . . . . . . . . . . . . . . . . 1,446 623 2,069

October. . . . . . . . . . . . . . . . . 0 444 444

November . . . . . . . . . . . . . . . 418 1,110 1,528

December . . . . . . . . . . . . . . . 45 632 677

Total . . . . . . . . . . . . . . . . . . 4,724 7,198 11,922

2000 January. . . . . . . . . . . . . . . . . 1,054 214 1,268

February . . . . . . . . . . . . . . . . 1,180 559 1,739

Source: Energy Information Administration, Form EIA-814 (data available on the EIA web site, www.eia.doe.gov).

93Although the Virgin Islands are officially part of the United States, EIA data classify petroleum shipments from the Virgin Islands as

imports.
carry distillate fuel oil, and perhaps to allow larger tankers to dock and unload. Dredging is typically expensive,

because both the ports and the channels leading to and

from them must be dredged to be effective. Larger tankers would require longer to unload, and that would partially offset some of the gains from having larger

deliveries. In the winter of 1999-2000, however, both

tankers and barges were unable to dock, and the problems were not limited to shallow-draft ports or ports

with significant channel limitations. Under less challenging weather conditions, New England ports have

reached import levels of 175,000 per day in the first quarter of 1995 and 1999 (Figure 43).

Other large coastal entry points in the Central Atlantic

include Baltimore, Maryland, and Newark, New Jersey.

In addition to the coastal imports, supplies from Canada

enter at a variety of pipeline points along the New York,

Vermont, New Hampshire, and Maine borders. In 1999,

there were 30 entry ports for distillate imports coming

into the Northeast, with the smaller volumes going to

diverse locations, where they are often critical to the

local supply picture.

Regional Distribution

The Northeast’s distillate fuel oil market has a routine

resupply chain, as described above. Among the regular

supply sources, pipeline shipments from the Gulf Coast

generally have the longest transit time, taking from 14 to

20 days for the run from Texas to New Jersey.

Waterborne imports arriving via tanker have shorter

transit times, with Venezuela and the Virgin Islands 5 to

7 days away. The shipments are carefully planned in

advance so that they arrive at regular intervals. Companies employ a variety of mechanisms to enhance their

supply flexibility, such as time exchanges.94 The transit

times illustrate, however, that when the interstate supply system is stretched, immediate incremental supplies

are available only from local inventories.

The Northeast receives its distillate fuel oil at many

points along the coast and along the border, but the largest volumes come to a few large ports and are redistributed from there. Barges move supplies from New York

Harbor to Long Island, northward up the Hudson, and

northeastward along the Connecticut coast to Rhode

56 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

1995 1996 1997 1998 1999 1995 1996 1997 1998 1999

0

25

50

75

100

125

150

175

200

Thousand Barrels per Day

Low-Sulfur

High-Sulfur New England Middle Atlantic

Figure 43. Quarterly Imports of Low-Sulfur and High-Sulfur Distillate Fuel Oil into the Northeast Region,

1995-1999

Source: Energy Information Administration, Form EIA-814 (data available on the EIA web site, www.eia.doe.gov).

94Time exchanges occur when one company provides a quantity of a product to another with an agreement that it will be repaid in kind

at a later date.
Island and on to Massachusetts. Barges based in Boston

and other oil-handling ports also move supplies along

the coast. Movements of the barges are carefully choreographed to minimize costs and maximize the use of

capacity available under the Jones Act.95

A delay in loading or unloading or in transit time is

quickly felt in the supply chain. With the barge fleet in

the Northeast generally operating close to capacity in

the peak winter periods, it is a challenge to compensate

for any delay. When movements are constrained by bad

weather, however, even extra capacity cannot provide

relief. Furthermore, the tankers that carry oil imports

directly to coastal ports are unable to come into port

safely during stormy weather with high seas and high

winds.

During the coldest period of January 2000, stormy

weather and ice-covered rivers and harbors delayed

resupply deliveries, with Coast Guard ice breakers

working at capacity to keep up. The fact that barges were

weather-bound during the third week of January was a

central factor in the price spike. Before that point, the

New York Harbor spot prices for distillate fuel oil did

not reflect a market concerned with short supply, in

spite of the very low inventory levels. The cold weather

and its attendant demand surge coincided with the

interruption in barge and tanker traffic, breaking the

critical pace of resupply. As a result, spot prices were

quickly bid up in the regions supplied by river barge,

like the Hudson River.

Stocks and Storage

The decision to store oil is a complex one. The market’s

present need for oil is reflected in the current price. High

prices indicate that the market needs more oil, and needs

it now. The forward price curve (the price of oil in the

future as compared to the price today) provides additional information. A market in which the price for

future delivery is lower than the current price discourages storage. Market participants are reluctant to hold

inventories or add to them when they are expected to

lose value in the future. As the heating oil season

approaches, typically in the summer and early autumn,

it is common to see a forward price curve that reflects

higher prices in December and January than in the following September and October. Using the futures market, a market participant can “lock in” the difference

(spread) between the current price and the New York

Mercantile Exchange (NYMEX) futures price during the

heating season, covering the cost of storage and the cost

of money for the purchase.

The unusual—even historic—stock drawdown that

took place in the Northeast in December 1999 and

January 2000 was precipitated by a variety of factors, as

described in Chapter 2 of this report. Importantly, the

forward price curve indicated that the product would be

worth less in the future. Thus, a ready buyer at the market price was welcome. With natural gas buyers making

the economic decision to switch to oil, there were many

such buyers available.

EIA collects data on “primary” inventories, the stocks

held by refiners, pipelines, and in terminals with large

capacity or with access to waterborne or pipeline supplies. In addition to primary inventories, secondary

inventories are held by retailers or distributors, and tertiary inventories are held by consumers; however, data

on secondary and tertiary inventories are not collected

by EIA

Secondary inventories of distillate fuel oil are largely

held in bulk plants, the small tanks that formerly dotted

the landscape throughout the Northeast, providing the

convenience of shorter truck runs for the dealers who

owned them. For the market as a whole, they provided

an additional cushion and flexibility for local exchanges

to smooth out delivery bumps. As the retail industry

consolidated, however, owners sought to enhance the

efficiency of their operations by closing underutilized

storage depots. The trend was clearly accelerated by

more stringent environmental rules and the increased

business risk the rules presented in the event of tank failures. With no new storage facilities being constructed,

there has been a net loss of secondary storage capacity

over the past decade. Comprehensive data for the

Northeast region are not available, but data from the

New York State Department of Environmental Conservation provide an illustration. The agency’s data on

facilities such as bulk storage plants indicate that there

has been a drop of more than 10 percent in the number of

storage facilities with 1,100 to 400,000 gallons capacity,

and in the capacity at such sites, in the past 2 years alone.

Tertiary stocks held by consumers are also an important

part of the distillate fuel oil supply system. For example,

home heating oil customers, on average, have about 30

days of supply in tank, a much higher supply relative to

consumption than the rest of the industry. For those customers not on a “will call” status, a dealer with an automatic delivery program in place uses degree-days, the

characteristics of the house, and consumption history to

calculate when a customer’s tank needs to be filled. The

dealer tries to optimize deliveries, filling the tank before

it gets too low but timing the delivery so that the tank

can take enough to support the cost of the delivery. (Frequent, small deliveries rapidly multiply the cost of servicing the account without providing any benefit.)

For a typical 275-gallon tank, 78 gallons would be the

optimum refill trigger, 182 gallons the optimum fill, and

260 gallons the effective maximum capacity. Because a

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 57

95The Jones Act requires that U.S. flagged ships transport shipments between U.S. ports after international ships are off-loaded.
typical single-family home consumes about one-eighth

gallon of oil per heating degree-day, during a normal

January in New England the homeowner would have

about 30 days between fills (after allowing for water

heating consumption). If the pattern followed the optimum, the homeowner would still have 15 days of supply remaining at the time of the refill. Because of this

fill-and-draw pattern, it is unlikely that many homeowners received more than one delivery at the January

2000 spike price.

During the January price runup, some dealers delivered

“short” (i.e., did not completely fill the tank) as a means

of allocating available supplies and preventing homeowners from receiving excessively high bills during the

price spike,96 which was hoped to be only temporary. It

would also raise the cost of delivery, but for homeowners not participating in a price cap or fixed price agreement it would have meant that the next delivery might

be at lower prices.

The inventory patterns of large-volume customers have

also played a role in recent price spikes (December 1989,

January 1994, and January/February 2000). Largevolume customers do not always carry adequate inventory to cover their needs during unusual circumstances,

such as the January/February 2000 cold snap. Some turn

to distillate fuel oil at times when their natural gas supplies have been interrupted as part of their service

agreements. Others turn from natural gas to distillate

fuel oil for economic reasons. The sudden entry of these

buyers into the market has been a contributing factor in

past price spikes.

Pricing and Contracts

Prices in distillate fuel oil markets respond quickly to

changes in supply and demand. First, spot prices reflect

the outcome of the ongoing “auction” in the marketplace. The routine bid-and-ask process between buyers

and sellers quickly reflects the need for more supply or a

supply glut. The prices at which once-only transactions

are taking place in the big product trading centers such

as New York Harbor become known quickly via electronic reporting services and bulletin boards, print

media, trade publications, and industry associations.

The price of commodity futures is a universally available indicator of the expected balance between supply

and demand.

During the price spike of January-February 2000, spot

prices for available supplies far outpaced the futures

price. At the peak, the price for “prompt” barrels was

$1.00 per gallon higher than the futures price. The

magnitude of the differential was as unexpected as it

was historic. During the supply crunch of late January,

deliveries under the February 2000 contract were still

weeks away. After the expiration of the February contract on January 31, volumes would not be deliverable

again until early March, under the March 2000 contract.

Spot prices in the New York Harbor are a good proxy for

the prices paid by large suppliers such as independent

marketers. The New York Harbor spot prices quickly

reflect increases in the prices paid on the spot market for

immediate supply or decreases in prices when supplies

exceed demand. Thus, a retail dealer who is detached

from the New York market may have to pay the current

New York Harbor spot price and pass it on to residential

consumers.

Risk management mechanisms, such as hedging and

price caps, are used routinely in distillate fuels markets,

and retail dealers offer a variety of pricing programs to

their customers. According to a voluntary survey of

full-service dealers routinely conducted by the Massachusetts-based accounting firm of Gray, Gray, & Gray

(Table 13), 98 percent of the dealers in the Northeast who

responded to the survey offer “budget payment plans”

to their customers. Such programs are also called

“levelized” plans. Typically, these plans extend from

July to May, allowing customers to make equal payments toward anticipated heating oil bills over the

months. Under- and overpayments are settled at the end

of the period.

58 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Table 13. Pricing Programs Offered to Consumers

by Heating Oil Retailers in Northeast

States, 1999

(Percent of Dealers Responding)

State

Guaranteed

Pricing Price Cap

Budget

Payment

Plan

Connecticut . . . . . . 70 45 90

Maine . . . . . . . . . . . 86 72 100

Massachusetts . . . . 59 56 94

New Hampshire . . . 86 64 93

Rhode Island . . . . . 57 72 86

Vermont . . . . . . . . . 78 56 100

Delaware . . . . . . . . 0 50 100

Maryland . . . . . . . . 38 50 100

New Jersey . . . . . . 28 28 100

New York . . . . . . . . 44 56 92

Pennsylvania . . . . . 47 45 92

Virginia . . . . . . . . . . 0 0 100

Overall. . . . . . . . . 55 54 98

Source: Gray, Gray, & Gray, Oilheat Survey 1999, web site

http://graymail.com/news/survey99.pdf. The numbers are based on

responses from nearly 500 dealers.

96Testimony of Peter D’Arco, SJ Fuel, Before the House Committee on Commerce, Subcommittee on Energy and Power, U.S. House of

Representatives (March 9, 2000).
Budget payment plans have the significant advantage of

allowing the customer to anticipate a stable bill, and

because the payments that would be due in cold months

are averaged with those for warm months, the final

accounting usually does not result in a large additional

payment. Even if an additional payment is due, the consumer has more time to arrange finances to reduce the

hardship.

More than half of the dealers in the survey also offered

guaranteed pricing and/or price cap programs, which

would have allowed their customers to avoid the spike

price altogether; however, the extent to which customers

participate in the programs is not known. In the New

England States, the lowest percentage of retailers offering guaranteed price programs is 57 percent of the

respondents in Rhode Island, compared with 86 percent

in both Maine and New Hampshire, 78 percent in Vermont, and 70 percent in Connecticut. Although there

were a few stories of dealers who did not honor

fixed-price contracts during the January 2000 price

runup, they are thought to be a small fraction.97 Dealers

who took losses because they left themselves vulnerable

to price increases in their supply acquisition strategies

are likely to make modifications in the future to cover

their own risks.

Retailers offering fixed-price sales to customers must

cover the costs of their own purchases. Just as retailers

offer programs to their customers, wholesalers often

offer risk management programs to retailers. For companies using the necessary mix of futures and options,98

wholesale prices remained capped even during the

worst of the spike. These programs represent insurance,

and as in all insurance decisions, there is a tradeoff

between the comprehensiveness of coverage (and hence

the cost) and the risk of an unanticipated cost event. The

volumes covered by such a program are thus seldom all

of the company’s supply, because the transaction cost is

prohibitively high. A retailer, for instance, might lock in

or cap the cost side only for those volumes that will subsequently be delivered under a fixed (or capped) price

contract. Thus, the high delivery volumes associated

with exceptionally cold weather are unlikely to be

covered.

Market Implications

of Reducing Reliance on Distillate

Two approaches have been suggested to reduce the

potential for future price spikes in Northeast distillate

fuel oil markets: (1) switching large-volume, year-round

users of distillate fuel to natural gas and (2) preventing

energy customers with interruptible natural gas service

from entering the distillate market during periods of

high demand. The first approach would reduce the market base, and the second would reduce peak demand

levels.

Switching large-volume users of distillate fuel oil to natural gas or another energy source would result in a

smaller overall distillate market, with declining economies of scale. Initially, there could be excess supply,

leading to a decrease in prices, which could lead to a

consolidation of the distillate industry. For example,

fewer barge-size deliveries would be needed, which

could lead to a reduction in the size of the barge fleet.

Similarly, fewer terminals and trucks would be needed,

scaling the delivery infrastructure to the size of the market. Many infrastructure costs are fixed, however, and

not easily scaled. Spread over a smaller volume, per-unit

costs are likely to increase as the market size decreases.

Removing large-volume, year-round users of highsulfur distillate from the market would also increase the

seasonal swings in demand for the product, because the

remaining market would consist primarily of consumers

who use distillate for space heating. Reducing the size of

the market would likely result in the closing down of terminals and companies. Rather than a reduction in volume handled by all terminals, the likely result of a

smaller market would be consolidation of terminals in

efforts to maintain economies of scale in their operation.

Because retail margins are often very thin, some companies probably would shut down. The result would likely

be fewer companies operating fewer terminals with

fewer barges and trucks. As a result, when another bout

of cold weather or supply disruption occurred, the consequences might be just as severe, and possibly worse,

than the situation where the large-volume customers

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 59

97For instance, officials in the office of the Attorney General of Massachusetts were quoted as saying that they had received complaints

about six companies that had imposed surcharges on fixed-price contracts (see Boston Globe, “Worcester Heating Oil Company to Repay

Customers It Surcharged” (February 26, 2000)). While the story does not cite the number of heating oil dealers active in the State, the dealer’s

trade association in Massachusetts has some 700 members. The case of the Worcester dealer cited in the article’s headline ended with the

dealer making restitution to its 6,000 fixed-price customers and donating $10,000 for low-income heating assistance; the dealer in question

has stated publicly that the surcharge was allowed by the contract. The Attorney General of Rhode Island received complaints on nine companies, all of which finally honored the fixed price (see Providence Journal,“Oil Dealers Will Honor Contracts” (February 18, 2000)).

98Companies can purchase an option contract above a futures contract strike price as a hedge that, if the price exceeds the strike price

before the option expires, they can either sell the option for a profit or ask for delivery at the lower strike price. However, if heating oil

futures fall below the strike price at the expiration of the option contract, the option expires and the option seller keeps the premium.
remained in the distillate market. Fewer companies

could also mean less competition, which could result in

higher prices.

The second approach—preventing energy customers

with interruptible natural gas service from entering the

distillate market during periods of high demand—probably would mitigate price surges in the heating oil market, because suppliers would be better able to anticipate

seasonal demand for distillate fuel in the winter months

and plan storage and deliveries accordingly. In recent

years there has been a movement toward a “just-intime” inventory and delivery system that reduces excess

storage capacity and reduces costs. In normal times, the

system works fine, but when demand rises rapidly

beyond the anticipated peak, infrastructure and supplies are stretched. The unanticipated entrance into the

market of large-volume customers, due to natural gas

supply interruptions, causes even greater strain on the

distillate supply system. Preventing those customers

from entering the market would lessen the strain on distillate supplies. However, seasonal demand surges by

the “regular” distillate customers would still be as

unpredictable as winter temperatures. Moreover, as discussed in Chapter 4 of this report, curtailing interruptible natural gas service could have severe consequences

for the region’s natural gas market.

Interruptible natural gas consumers,99 by virtue of their

interruptible status, typically receive favorable gas service rates afterthey show that they can switch to an alternate fuel.100 Gas deliveries can be interrupted under

certain circumstances, such as when temperatures fall

below a given threshold or operating conditions on the

pipeline require it. Such customers generally must either

have on-site storage capability for their alternate fuel,

maintain a nearby storage capability operated by a third

party, or be prepared to shut down operations when natural gas service is curtailed. Natural gas utilities in New

Jersey and New York, for example, require through their

tariffs that their interruptible gas customers have an

alternate fuel capability. Unfortunately, the stocks or

inventory maintained by end users (tertiary storage) are

typically not surveyed, and no definitive statement can

be made about their inventory levels during critical periods of the 1999-2000 winter. Information from the New

Jersey Board of Public Utilities suggests that at least a

few large-volume gas-distillate switchable consumers

may have gone into mid-January 2000 with distillate

inventories that were lower than normal.101 The total

volume of gas service interrupted in New Jersey in January 2000 was equivalent to a maximum of 741,000 barrels of fuel oil.

60 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

99Interruptible customers are those whose gas service can be curtailed to assure gas service to firm-service customers.

100Requirements for alternate fuel capability and minimum maintenance levels of alternate fuel supply (e.g., 10 days worth) vary from

utility to utility and normally are integrated into gas utility tariffs. Brooklyn Union’s new tariff for large-volume users, for example, requires

a minimum 10-day supply; most other New York State gas utilities specify only the requirement to maintain an alternate fuel capability. The

Public Utility Commissions or their equivalent endorse these gas utility practices or requirements through their acceptance of the gas utilities’ tariffs. Enforcement is left entirely up to the gas utilities.

101State of New Jersey, Board of Public Utilities, Board of Public Utilities Heating Oil Review (February 23, 2000), web site www.state.nj.us/

bpu/wwwroot/communication/Govrpt.PDF. At the hearings, New Jersey gas utilities noted that some of their interruptible gas customers

were given their normal interruption notice (about 8 hours) to stop using gas but chose to stay on natural gas despite agreed-upon heavy

price penalties for continued use—as much as 10 times their normal gas rates and well above the distillate fuel oil price. This suggests that at

least some of those interruptible customers had below-normal alternate fuel inventories and had to continue operating with natural gas,

even at much higher costs. Hearings have been held by the Board of Public Utilities on the cause of the distillate fuel oil price spikes, and

final recommendations are expected by the end of May 2000.
Appendix A

Request for Analysis
COPY OF LETTER PAGE 1 GOES ON THIS PAGE.

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 63
COPY OF LETTER PAGE 2 GOES ON THIS PAGE.

64 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options
Appendix B

Historical Data on Fuel Consumption and Prices

for the Residential Sector in the Northeast Region
Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 

Table B1. National Summary: Space Heating Equipment

(Million Households)

Year

Distillate Heating, No Gas Distillate Heating, With Gas Total

Distillate

Heating

Total Natural Gas Heating 

Single

Family

MultiFamily Total Distillate Single Family Multi- Family Total With Gas Single Family Multi- Family Total Gas Sin

Fam

1978 .............. 9.2 0.7 9.9 2.1 3.4 5.5 15.5 30.7 11.2 41.8 8

1979 .............. 8.2 0.4 8.6 1.9 3.0 4.9 13.5 31.1 11.3 42.4 81980 .............. 6.9 0.9 7.8 1.7 3.0 4.8 12.6 33.4 11.2 44.6 91981 .............. 5.9 1.0 6.9 1.5 2.9 4.4 11.3 35.5 10.7 46.2 81982 .............. 6.0 1.0 7.0 1.6 2.7 4.3 11.3 34.3 13.2 47.5 81984 .............. 5.3 0.7 6.1 1.7 2.9 4.6 10.7 33.8 14.1 47.8 91987 .............. 6.2 1.0 7.2 1.3 2.5 3.7 10.9 36.0 14.0 50.0 101990 .............. 6.6 0.8 7.4 1.1 1.9 3.0 10.4 38.7 13.0 51.7 131993 .............. 6.8 0.6 7.4 1.1 1.7 2.7 10.2 39.6 11.8 51.4 151997 .............. 6.2 0.6 6.8 1.0 1.7 2.7 9.5 44.6 8.9 53.5 20

Source: Energy Information Administration, using 1978-1997 RECS data.

Table B2. Northeast Summary: Space Heating Equipment

(Million Households)

Year

Distillate Heating, No Gas Distillate Heating, With Gas Total

Distillate

Heating

Natural Gas Space Heating 

Single

Family

MultiFamily Total Distillate Single Family Multi- Family Total With Gas Single Family Multi- Family Total Gas Sin

Fam

1978 . . . . . . . . . . . . . . 3.4 0.6 4.0 1.4 3.2 4.7 8.6 4.3 2.6 7.0 01979 . . . . . . . . . . . . . . 2.8 0.3 3.1 1.2 2.9 4.1 7.2 3.9 3.2 7.1 01980 . . . . . . . . . . . . . . 3.3 0.6 3.9 1.3 2.8 4.1 8.0 4.0 2.6 6.6 11981 . . . . . . . . . . . . . . 2.9 0.8 3.7 1.2 2.8 4.0 7.8 4.2 2.8 7.0 01982 . . . . . . . . . . . . . . 2.9 0.8 3.6 1.3 2.5 3.8 7.4 4.6 2.9 7.5 01984 . . . . . . . . . . . . . . 2.9 0.6 3.5 1.4 2.8 4.3 7.8 4.6 2.6 7.2 01987 . . . . . . . . . . . . . . 3.4 0.9 4.3 1.0 2.4 3.4 7.7 5.2 2.9 8.1 11990 . . . . . . . . . . . . . . 3.9 0.7 4.6 0.9 1.9 2.8 7.4 5.4 3.4 8.7 11993 . . . . . . . . . . . . . . 4.0 0.6 4.5 0.8 1.7 2.5 7.0 5.7 3.8 9.4 11997 . . . . . . . . . . . . . . 4.1 0.5 4.7 0.7 1.7 2.4 7.1 6.8 2.3 9.2 1

Source: Energy Information Administration, using 1978-1997 RECS data.
68 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Table B3. New England Summary: Space Heating Equipment

(Million Households)

Year

Distillate Heating, No Gas Distillate Heating, With Gas Total

Distillate

Heating

Total Natural Gas Heating 

Single

Family

MultiFamily Total Distillate Single Family Multi- Family Total With Gas Single Family Multi- Family Total Gas Sin

Fam

1980 . . . . . . . . . . . . . . 1.2 0.3 1.5 0.2 0.5 0.7 2.2 0.3 0.8 1.1 01981 . . . . . . . . . . . . . . 1.0 0.4 1.4 0.2 0.5 0.7 2.1 0.6 0.6 1.2 01982 . . . . . . . . . . . . . . 1.0 0.3 1.3 0.4 0.4 0.8 2.1 0.5 0.7 1.2 01984 . . . . . . . . . . . . . . 0.9 0.3 1.2 0.4 0.4 0.8 2.0 0.6 0.6 1.2 01987 . . . . . . . . . . . . . . 1.4 0.4 1.8 0.2 0.3 0.5 2.3 0.5 0.7 1.2 01990 . . . . . . . . . . . . . . 1.4 0.3 1.7 0.2 0.3 0.5 2.2 0.5 0.8 1.3 01993 . . . . . . . . . . . . . . 1.8 0.3 2.0 0.2 0.3 0.5 2.6 0.7 0.9 1.6 01997 . . . . . . . . . . . . . . 2.0 0.3 2.3 0.3 0.1 0.4 2.7 0.8 0.6 1.5 0

Source: Energy Information Administration, using 1978-1997 RECS data.

Table B4. Mid-Atlantic Summary: Space Heating Equipment

(Million Households)

Year

Distillate Heating, No Gas Distillate Heating, With Gas Total

Distillate

Heating

Total Natural Gas Heating 

Single

Family

MultiFamily Total Distillate Single Family Multi- Family Total With Gas Single Family Multi- Family Total Gas Sin

Fam

1980 . . . . . . . . . . . . . . 2.1 0.3 2.4 1.1 2.3 3.4 5.8 3.7 1.8 5.5 0

1981 . . . . . . . . . . . . . . 2.0 0.4 2.4 1.0 2.3 3.3 5.7 3.6 2.2 5.9 0

1982 . . . . . . . . . . . . . . 1.9 0.4 2.3 0.9 2.1 3.0 5.3 4.1 2.2 6.3 0

1984 . . . . . . . . . . . . . . 2.0 0.3 2.3 1.1 2.4 3.5 5.8 4.0 2.1 6.0 0

1987 . . . . . . . . . . . . . . 2.0 0.4 2.4 0.8 2.1 2.9 5.4 4.7 2.2 6.9 1

1990 . . . . . . . . . . . . . . 2.5 0.4 2.9 0.7 1.5 2.3 5.2 4.9 2.5 7.4 1

1993 . . . . . . . . . . . . . . 2.2 0.3 2.5 0.6 1.4 1.9 4.5 5.0 2.9 7.9 0

1997 . . . . . . . . . . . . . . 2.2 0.2 2.4 0.4 1.5 2.0 4.4 6.0 1.7 7.7 1

Source: Energy Information Administration, using 1978-1997 RECS data.
Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 

Table B5. Midwest Summary: Space Heating Equipment

(Million Households)

Year

Distillate Heating, No Gas Distillate Heating, With Gas Total

Distillate

Heating

Total Natural Gas Heating Tota

Single

Family

MultiFamily Total Distillate Single Family Multi- Family Total With Gas Single Family Multi- Family Total Gas Single Family 

1980 1.3 0.1 1.4 0.1 0.0 0.1 1.5 11.0 4.0 15.0 1.2 1981 1.4 0.1 1.5 0.1 0.0 0.1 1.6 11.9 3.5 15.4 0.6 1982 1.2 0.2 1.4 0.1 0.1 0.2 1.5 10.9 4.6 15.5 1.3 1984 1.0 0.1 1.0 0.1 0.0 0.1 1.1 11.0 5.4 16.4 1.0 1987 1.3 0.0 1.3 0.1 0.0 0.1 1.5 11.5 5.0 16.5 1.1 1990 1.1 0.0 1.1 0.1 0.0 0.1 1.2 12.4 4.1 16.5 1.4 1993 1.1 0.0 1.2 0.1 0.0 0.1 1.3 12.8 4.1 16.9 1.8 1997 1.0 0.0 1.0 0.0 0.0 0.0 1.0 14.9 3.0 17.9 1.5 

Source: Energy Information Administration, using 1978-1997 RECS data.

Table B6. Regional Fuel Consumption for Residential Space Heating

(Quadrillion Btu)

Year Oil Heating Gas Heating Electric He

New

England

MidAtlantic Northeast Midwes t USA New England Mid- Atlantic Northeast Midwes t USA New England Mid- Atlantic Northe

1980 . . 0.254 0.607 0.861 0.137 1.233 0.096 0.533 0.629 1.486 3.302 0.008 0.034 0.042 

1981 . . 0.204 0.532 0.736 0.155 1.032 0.117 0.611 0.728 1.746 3.782 0.013 0.043 0.056 1982 . . 0.202 0.474 0.677 0.137 0.964 0.107 0.559 0.666 1.327 3.277 0.008 0.025 0.033 1984 . . 0.215 0.512 0.726 0.105 0.948 0.110 0.528 0.638 1.563 3.472 0.009 0.029 0.038 1987 . . 0.205 0.461 0.666 0.120 0.912 0.099 0.625 0.725 1.399 3.345 0.010 0.038 0.047 1990 . . 0.213 0.415 0.629 0.109 0.828 0.098 0.614 0.712 1.421 3.339 0.011 0.030 0.041 1993 . . 0.248 0.380 0.629 0.123 0.885 0.125 0.646 0.771 1.558 3.645 0.010 0.031 0.040 1997 . . 0.271 0.372 0.642 0.100 0.834 0.121 0.618 0.738 1.650 3.579 0.012 0.031 0.042 

Source: Energy Information Administration, using 1978-1997 RECS data.
70 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Table B7. Regional Fuel Expenditures for Residential Space Heating

(1998 Dollars per Household)

Year

Oil Space Heating Natural Gas Space Heating Electric S

New

England

MidAtlantic Northeast Midwest USA New England Mid- Atlantic Northeast Midwest USA New England Mid- Atlantic No

1980. . . 1640 1511 1547 1271 1414 890 803 817 632 510 924 851 

1981. . . 1439 1369 1388 1354 1326 1118 895 933 771 602 1257 1171 

1982. . . 1261 1159 1187 1139 1109 1145 921 957 690 598 945 887 

1984. . . 1178 942 1004 997 960 1021 882 905 763 612 938 1028 

1987. . . 696 652 665 632 645 729 735 734 549 471 730 700 

1990. . . 887 756 796 822 743 666 663 663 502 422 577 676 

1993. . . 693 599 633 643 619 711 661 670 542 463 693 631 

1997. . . 716 606 648 670 637 772 693 705 549 452 571 529 

Source: Energy Information Administration, using 1978-1997 RECS data.

Table B8. Regional Fuel Prices

(1998 Dollars per Million Btu)

Year Oil Space Heating Natural Gas Space Heating Electric S

New

England

MidAtlantic Northeast Midwest USA New England Mid- Atlantic Northeast Midwest USA New England Mid- Atlantic No

1980. . . 14.5 14.4 14.4 14.2 14.4 10.2 8.3 8.6 6.4 6.9 36.6 31.1 

1981. . . 14.7 14.6 14.6 14.3 14.6 11.3 8.6 9.0 6.8 7.4 37.1 31.4 1982. . . 13.1 13.0 13.0 12.8 13.0 12.8 10.5 10.8 8.1 8.7 36.8 35.7 1984. . . 11.2 10.6 10.8 10.9 10.9 10.8 10.0 10.2 8.0 8.4 36.0 36.1 1987. . . 7.8 7.6 7.7 7.7 7.7 8.7 8.1 8.2 6.5 7.0 31.5 31.2 

1990. . . 9.4 9.4 9.4 9.1 9.3 9.1 8.0 8.1 5.8 6.5 33.8 30.8 

1993. . . 7.1 7.0 7.1 6.8 7.1 9.0 8.0 8.2 5.9 6.5 34.1 29.6 

1997. . . 7.2 7.1 7.1 6.9 7.2 9.3 8.6 8.7 6.0 6.7 31.8 29.3 

Source: Energy Information Administration, using 1978-1997 RECS data.
Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 

Table B9. Regional Fuel Consumption for Residential Space Heating If All Households With Oil Heat and Gas Service S

(Quadrillion Btu)

Year

Oil Space Heating Natural Gas Space Heati

New England Mid-Atlantic Northeast Midwest USA New England Mid-Atlantic Northeast 

1980 ....... 0.173 0.259 0.432 0.126 0.745 0.177 0.881 1.058 

1981 ....... 0.142 0.226 0.368 0.141 0.627 0.180 0.916 1.096 

1982 ....... 0.122 0.210 0.332 0.121 0.579 0.187 0.823 1.010 

1984 ....... 0.126 0.213 0.339 0.096 0.533 0.199 0.826 1.025 

1987 ....... 0.161 0.238 0.398 0.112 0.620 0.144 0.849 0.993 

1990 ....... 0.167 0.254 0.421 0.102 0.600 0.145 0.775 0.920 

1993 ....... 0.196 0.253 0.449 0.108 0.678 0.177 0.774 0.951 

1997 ....... 0.229 0.238 0.467 0.097 0.638 0.163 0.751 0.914 

Source: Energy Information Administration, using 1978-1997 RECS data.

Table B10. Regional Fuel Expenditures for Residential Space Heating If All Households With Oil Heat and Gas Service 

(1998 Dollars per Household)

Year

Oil Space Heating Natural Gas Space Heati

New England Mid-Atlantic Northeast Midwest USA New England Mid-Atlantic Northeast 

1980 ....... 1650 1561 1596 1248 1371 986 821 849 

1981 ....... 1538 1388 1443 1320 1309 1060 859 893 1982 ....... 1222 1173 1191 1136 1073 1204 922 972 1984 ....... 1147 1016 1061 1007 965 1084 877 913 

1987 . . . . . . . 684 754 724 650 672 751 700 708 1990 . . . . . . . 907 834 862 815 760 701 640 650 1993 . . . . . . . 691 715 704 627 652 754 635 656 1997 . . . . . . . 723 736 729 671 687 796 671 691 

Source: Energy Information Administration, using 1978-1997 RECS data.
Appendix C

Historical Distillate Price Spikes: December 1989-January 1990,

January-February 1994, and January-February 2000
Appendix C

Historical Distillate Price Spikes: December 1989-January 1990,

January-February 1994, and January-February 2000

The Northeast has experienced three distillate price

spikes in recent years: December 1989-January 1990, January-February 1994, and January/February 2000. In all

three cases, distillate prices suddenly soared above

crude oil prices, remaining volatile and elevated for several weeks. Figure C1 shows the spread between distillate and crude oil prices since 1989, illustrating the

magnitude of the different spikes.

In nominal terms, crude oil prices exacerbated the

impact of the spike on consumers in the January 2000

case more than in 1989 or 1994. Crude oil prices were low

during the January/February 1994 incident. During the

peak distillate price week in 1994, the crude oil price

averaged less than $15 per barrel (35 cents per gallon);

during the peak of the winter 1989/90 event, crude oil

was $21.70 per barrel (52 cents per gallon); and the latest

event had an underlying crude oil price of $28.06 per

barrel (67 cents per gallon). As a result, the total distillate

price peak was higher during the recent January/February 2000 event than during the two other price spikes.

The three incidents had many similarities, but there

were differences as well. Each involved a surge in

demand during cold weather, accompanied by supply

disruptions due to refinery outages and weather-related

delivery problems. Stocks were rapidly drawn down to

very low levels as demand exceeded the arrival of new

supply, and prices spiked. However, stock availability at

the start of the event and the severity of the weather

were different for the three situations.

Stocks have played an important role in each of the price

spikes. During a typical winter, distillate stocks are built

up during the summer and fall, peaking in November

ahead of the high winter demand months of January,

February, and March. Most of the seasonal build occurs

in the Northeast. Stocks are then used to help meet

demand during the peak winter months. In addition to

being a supply source themselves during the peak

demand months, stocks are the nearest source of supply

to the end-use markets, and they act as a supply buffer

against unexpected surges in demand or loss of other

supply, such as refinery outages. Thus, if demand is

high and stocks are low and falling, then demand

exceeds the arrival of new supply, and buyers bid prices

up as their concern over supply availability increases.

The increased price provides the incentive for added

supply from increased refinery production and

increased imports of distillate. Because the supply additions may take 2 to 3 weeks to be arranged for and delivered, stocks must cover the imbalance until the added

supply arrives.

Dynamics of Winter Distillate Markets:

Winter 1989-1990

The winter heating season of 1989-1990 began with an

extremely low level of distillate stocks. The distillate

stock build of late summer and fall was unusually small,

and as December began, stock levels for the United

States were more than 14 million barrels below average.102 The East Coast was only in a little better shape at

7 million barrels below average (Figure C2).

Refiners increased distillate production in November

and early December, which might have provided some

additional stock build had the weather cooperated. It

turned unusually cold early in the season, however,

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 75

01/06/89

01/05/90

01/04/91

01/03/92

01/01/93

12/31/93

12/30/94

12/29/95

12/27/96

12/26/97

12/25/98

12/24/99

0

5

10

15

20

25

30

35

40

45

-5

Cents per Gallon

41.25 Actual Average

24.35

32.30

Figure C1. New York Harbor No. 2 Heating Oil Spot

Prices Minus West Texas Intermediate

Crude Oil Spot Prices, 1989-1999

Source: DRI Platt’s daily prices averaged over a week.

102The average winter East Coast and total U.S. distillate stock patterns are based on data for the years 1989-1999.
averaging 36 percent colder than normal during December. In the second and third weeks of December, distillate production was at the highest levels seen at any

point during the 3 years before 1989. But on the weekend

of December 23rd, cold weather that had been plaguing

the U.S. mid-continent and Northeast hit the Gulf Coast.

The record-breaking cold front froze water pipes and

damaged valves and instruments in refineries. Many

refineries were shut down or curtailed production, and

some put customers on allocation. Distillate production

fell by almost 400,000 barrels per day in the fourth week

of December 1989. Furthermore, natural gas production

was curtailed by frozen equipment, requiring more natural gas customers to switch to distillate than might otherwise have been the case.

With stocks well below normal, distillate price spreads

(No. 2 heating oil minus West Texas Intermediate) at the

beginning of December were 15 cents per gallon and

growing. The price spiked at the end of month, and the

distillate spread grew to over 41 cents by the end of

December. In response to the high prices, imports

increased, rising from about 200,000 barrels per day for

the week ending December 8 to 616,000 barrels per day

for the week of February 2, 1990. Imports then fell back

to around 300,000 barrels per day in March. East Coast

refinery production peaked at 480,000 barrels per day

for the week of January 5 before drifting down to about

400,000 barrels per day at the beginning of February.

Dynamics of Winter Distillate Markets:

Winter 1993-1994

The winter of 1993-1994 began with East Coast distillate

stock levels above average, and they stayed about 7 million barrels above average through the beginning of January. But during the first 5 weeks of the year, East Coast

stocks fell by an astounding 31 million barrels (Figure

C3). January 1994 was 15 percent colder than normal in

the Northeast, and one week was 40 percent colder than

normal.103 The cold weather did not extend to the Gulf

Coast, and deliveries of both natural gas and petroleum

from there to the Northeast were maintained, unlike

during the December 1989-January 1990 event. Distillate

spreads during January rose by 5 cents per gallon, to 15

cents per gallon at the end of the month. Distillate prices

in New York Harbor were 9 cents per gallon higher than

in Rotterdam—more than sufficient to attract imports.

During the last week of the East Coast stock decline

(ending February 4, 1994), stocks stood at a level that

was 12 million barrels below average, and distillate

spreads peaked shortly thereafter at 28 cents per gallon

(daily). The rise to peak prices from mid-January to

mid-February resulted in increased supply. East Coast

refinery production increased by about 50,000 barrels

per day over January, and imports to the East Coast

increased by about 120,000 barrels per day. East Coast

stocks leveled out during February, although they

remained at a very low level. Because of the delivery

time lag, imports did not peak until the first week in

March, when they reached 450,000 barrels per day, compared with January levels of less than 200,000 barrels per

day.

Dynamics of Winter Distillate Markets:

Winter 1999-2000

As the heating season of 1999-2000 began, distillate

stocks were about average. But from December 17, 1999,

to January 14, 2000, stocks fell by 12 million barrels, ending at a level that was 10 million barrels below average

(Figure C4). Distillate spreads were well below seasonal

averages in December, and they strengthened only modestly in early January, remaining below average. In the

week ending January 21, the weather turned sharply

colder for several weeks. Demand rose, and frozen

rivers and high winds interfered with product deliveries. Distillate spreads rose sharply. The average weekly

76 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

11/03/89

11/24/89

12/15/89

01/05/90

01/26/90

02/16/90

03/09/90

03/30/90

0

5

10

-5

-10

-15

-20

-25

Stock Deviation (Million Barrels)

0

5

10

15

20

25

30

35

40

45

Price Spread (Cents per Gallon)

Figure C2. Winter 1989-1990 East Coast Stock

Variations from Average and Distillate

Spreads

Notes: Price spread is the weekly average New York Harbor

No. 2 heating oil price minus the West Texas Intermediate

crude oil price. Stock deviation is the week-ending stock level

minus the average week-ending level for the given week, calculated from 1989 through 1999.

Sources: Spot Prices: DRI Platt’s daily prices averaged

over a week. Week-Ending Distillate Stocks, January 1990

Forward: Energy Information Administration, Weekly Petroleum Status Report, DOE/EIA-0208 (various issues), Table 10.

Week-Ending Distillate Stocks, November and December

1989: American Petroleum Institute.

103Petroleum Industry Research Foundation, “Oil Markets During the Cold Weather: The Buck Stops Here,” Memorandum Submitted

to the Subcommittee on Energy and Power of the Energy and Commerce Committee, U.S. House of Representatives (February 18, 1994).
distillate spread increased by 14 cents per gallon over

the level of the previous week as the region waited for

new supply to relieve the imbalance.

East Coast refinery production increased by 60,000 barrels per day during the week ending February 4 and by

another 60,000 barrels per day the following week. The

rise in distillate production followed the margin rise by

nearly 3 weeks. Imports for the week ending February

11 were 528,000 barrels per day, compared with 105,000

barrels per day during the previous week. Very high levels of imports continued for 3 weeks, averaging 566,000

barrels per day. By February 4, East Coast stocks had

fallen to 20 million barrels below average before new

supply was able to stop the decline. During the rest of

February, distillate stocks on the East Coast stayed flat,

improving relative to the normal pattern, which declines

during the first quarter of the year.

Summary

Comparing the distillate stock level for the East Coast

region (PADD 1) with the average winter pattern provides a good indication of the potential for price spikes.

In each of the three events discussed here, when PADD 1

stocks fell to 10 million barrels below average, a price

spike followed. In the most severe incidents—1989-1990

and 1999-2000—stocks ultimately fell to 20 million barrels below average. There has been only one other winter season since 1989 when stocks fell to 10 million

barrels below average, and that was in February 1996.

For the week ending February 16, 1996, stocks were 10.7

million barrels below average. Weekly average distillate

spreads had increased from 11 cents per gallon to 17

cents per gallon over the preceding 2 weeks. But in the

following 2 weeks, demand moderated and was in balance with supply. Stocks stopped falling, and distillate

spreads fell back. The imbalance was of a shorter

duration.

In summary, when East Coast winter stocks levels are

below normal and there is an imbalance between supply

and demand that results in a rapid drawdown of stocks,

price pressure mounts as inventories approach 10 million barrels below average. If the level approaches 20

million barrels below average, Northeast prices are

likely to spike. The examples to date indicate that such

spikes can be severe.

Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 77

11/05/93

11/26/93

12/17/93

01/07/94

01/28/94

02/18/94

03/11/94

04/01/94

0

5

10

-5

-10

-15

-20

-25

Stock Deviation (Million Barrels)

0

5

10

15

20

25

30

35

40

45

Price Spread (Cents per Gallon)

Figure C3. Winter 1993-1994 East Coast Stock

Variations from Average and Distillate

Spreads

Notes: Price spread is the weekly average New York Harbor

No. 2 heating oil price minus the West Texas Intermediate

crude oil price. Stock deviation is the week-ending stock level

minus the average week-ending level for the given week, calculated from 1989 through 1999.

Sources: Spot Prices: DRI Platt’s daily prices averaged

over a week. Week-Ending Distillate Stocks, January 1990

Forward: Energy Information Administration, Weekly Petroleum Status Report, DOE/EIA-0208 (various issues), Table 10.

Week-Ending Distillate Stocks, November and December

1989: American Petroleum Institute.

11/05/99

11/26/99

12/17/99

1/07/00

1/28/00

2/18/00

3/10/00

0

5

10

-5

-10

-15

-20

-25

Stock Deviation (Million Barrels)

0

5

10

15

20

25

30

35

40

45

Price Spread (Cents per Gallon)

Figure C4. Winter 1999-2000 East Coast Stock

Variations from Average and Distillate

Spreads

Notes: Price spread is the weekly average New York Harbor

No. 2 heating oil price minus the West Texas Intermediate

crude oil price. Stock deviation is the week-ending stock level

minus the average week-ending level for the given week, calculated from 1989 through 1999.

Sources: Spot Prices: DRI Platt’s daily prices averaged

over a week. Week-Ending Distillate Stocks, January 1990

Forward: Energy Information Administration, Weekly Petroleum Status Report, DOE/EIA-0208 (various issues), Table 10.

Week-Ending Distillate Stocks, November and December

1989: American Petroleum Institute.
Appendix D

Electricity Generation and Fuel Consumption Data, 1980-1999
Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 

Table D1. Electricity Generation by Fuel, 1980-1999

(Megawatthours)

Electric Utility Generation

Year Coal Heavy Oila Hydro Light Oila Natural Gas Nuclear Other Total

1980.............. 1,161,562,405 232,141,939 276,021,192 13,447,470 346,239,969 251,115,612 5,911,109 2,286,4391981.............. 1,203,203,324 196,019,707 260,683,719 10,049,895 345,777,209 272,673,555 6,405,233 2,294,8121982.............. 1,192,004,270 139,030,539 309,213,090 7,392,201 305,259,814 282,773,297 5,538,667 2,241,2111983.............. 1,259,424,317 135,871,495 332,129,928 7,972,536 274,098,499 293,677,148 7,111,027 2,310,2841984.............. 1,341,680,794 111,730,557 321,150,440 7,460,401 297,393,648 327,633,552 9,255,230 2,416,3041985.............. 1,402,128,153 92,548,917 281,149,617 7,050,532 291,945,995 383,690,727 11,327,367 2,469,8411986.............. 1,385,831,473 128,780,706 290,844,314 6,961,050 248,508,475 414,038,069 12,346,127 2,487,3101987.............. 1,463,781,290 109,830,793 249,695,233 7,764,358 272,620,840 455,270,390 13,163,995 2,572,1261988.............. 1,540,652,759 138,637,645 222,939,877 9,222,815 252,800,706 526,973,056 13,023,420 2,704,2501989.............. 1,553,661,269 144,746,151 265,063,302 12,232,745 266,598,229 529,354,733 12,648,386 2,784,3041990.............. 1,559,605,707 107,935,943 279,925,918 7,546,663 264,089,401 576,861,678 12,185,699 2,808,1511991.............. 1,551,166,838 103,113,412 275,519,186 7,021,584 264,171,598 612,565,087 11,465,160 2,825,0221992.............. 1,575,895,394 81,206,269 239,559,447 5,777,272 263,871,508 618,776,263 12,132,998 2,797,2191993.............. 1,639,151,186 89,950,830 265,062,757 6,524,028 258,915,301 610,291,214 12,629,450 2,882,5241994.............. 1,635,492,971 80,860,175 243,693,113 8,036,642 291,114,905 640,439,832 11,074,441 2,910,7121995.............. 1,652,914,466 51,361,853 293,652,709 7,673,894 307,306,050 673,402,123 8,217,497 2,994,5281996.............. 1,737,453,477 57,343,476 327,969,977 8,351,904 262,729,781 674,728,546 8,864,991 3,077,4421997.............. 1,787,806,344 67,077,688 337,233,538 7,294,360 283,624,806 628,644,171 10,842,237 3,122,5231998.............. 1,807,479,829 95,048,609 304,402,562 10,391,091 309,222,404 673,702,104 11,924,192 3,212,1701999.............. 1,765,429,778 72,640,051 289,692,790 9,232,907 295,639,305 725,036,130 7,660,493 3,165,331

Nonutility Generation

Year Coal Hydro Natural Gas Nuclear Oil Other Total

%

Oil

1989.............. 30,162,928 5,871,784 96,252,075 47,186 5,542,985 43,578,989 181,455,947 3.05% 1990.............. 30,699,089 6,172,345 113,582,794 112,686 7,030,835 52,677,408 210,275,156 3.34% 1991.............. 38,772,705 6,180,457 127,767,083 77,124 7,493,951 59,981,559 240,272,878 3.12% 1992.............. 45,189,441 9,351,974 154,429,179 65,094 10,507,858 66,604,700 286,148,245 3.67% 1993.............. 50,858,685 11,395,678 169,501,795 76,041 12,814,453 69,752,400 314,399,053 4.08% 1994.............. 56,197,354 13,094,665 186,924,386 51,987 14,463,980 72,354,245 343,086,617 4.22% 1995.............. 57,261,055 14,626,063 204,804,378 0 14,415,816 72,201,112 363,308,424 3.97% 1996.............. 58,256,728 16,389,835 207,417,140 0 14,336,502 73,151,380 369,551,585 3.88% 1997.............. 56,024,858 17,675,113 213,683,643 0 14,974,500 69,560,033 371,918,149 4.03% 1998.............. 66,466,303 14,486,196 239,992,299 0 16,774,565 67,982,905 405,702,268 4.13% 

aLight oil is distillate fuel oil, and heavy oil is residual fuel oil.

Notes: EIA began collecting nonutility data in 1989 and is only final through 1998. Nonutilities do not directly report the split between light and heavy oil generSources: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report”; Form EIA-860B, “Annual Electric Generator Report—Nonutility”; a

Power Producer Report.”
82 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Table D2. Nonutility Diesel, Distillate Fuel Oil, and Residual Fuel Oil Consumption, 1991-1998

(Trillion Btu)

Fuel 1991 1992 1993 1994 1995 1996 1997 

National

Diesel ............... 0.000 1.111 0.776 2.344 1.997 1.759 3.468 

Light Oila............. 25.445 26.390 40.368 49.314 42.773 29.442 43.559 

Heavy Oila ........... 143.471 161.073 178.430 190.096 164.183 187.660 163.697 

Total .............. 168.916 188.574 219.574 241.754 208.952 218.862 210.725 

Percent Light Oila ...... 15.06% 14.58% 18.74% 21.37% 21.43% 14.26% 22.32% 

Census Division 1 - New England

Diesel ............... 0.000 0.087 0.087 0.059 0.093 0.439 0.322 

Light Oila............. 5.646 4.032 4.840 5.169 3.823 2.317 5.810 

Heavy Oila ........... 37.415 46.032 51.329 53.033 43.297 55.141 42.672 

Total .............. 43.061 50.151 56.256 58.261 47.213 57.898 48.805 

Percent Light Oila ...... 13.11% 8.21% 8.76% 8.97% 8.29% 4.76% 12.57% 

Census Division 2 - Mid-Atlantic

Diesel ............... 0.000 0.120 0.090 0.130 0.692 0.230 0.152 

Light Oila............. 2.861 3.497 14.586 14.836 13.148 6.398 8.855 

Heavy Oila ........... 28.156 25.877 25.072 29.826 19.231 20.985 17.358 

Total .............. 31.016 29.493 39.747 44.792 33.071 27.614 26.365 

Percent Light Oila ...... 9.22% 12.26% 36.92% 33.41% 41.85% 24.00% 34.16% 

Census Division 3 - East North Central

Diesel ............... 0.000 0.038 0.047 0.038 0.023 0.439 0.534 

Light Oila............. 0.434 0.613 1.069 2.405 2.027 1.881 1.162 

Heavy Oila ........... 10.082 10.207 11.483 12.142 8.235 16.785 12.747 

Total .............. 10.517 10.859 12.598 14.585 10.284 19.106 14.443 

Percent Light Oila ...... 4.13% 6.00% 8.86% 16.75% 19.93% 12.15% 11.74% 

aLight oil is distillate fuel oil, and heavy oil is residual fuel oil.

Note: EIA began collecting nonutility data in 1989 and is only final through 1998. Nonutilities do not directly report the split betwee

heavy oil generation.

Sources: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report”; Form EIA-860B, “Annual Electric 

Report—Nonutility”; and Form EIA-867, “Annual Nonutility Power Producer Report.”
Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 

Table D3. Distillate Fuel Oil Consumption for Electricity Generation by Month, 1980-1999

(Barrels)

Year January February March April May June July August September Oc

Electric Utility Consumption

1980............... 3,203,286 2,767,869 2,195,969 1,361,970 1,523,699 1,950,633 3,828,468 4,016,097 2,149,294 1,

1981............... 3,046,537 2,242,266 1,404,684 1,356,357 1,794,981 2,704,752 2,615,287 1,421,908 1,144,780 1,

1982............... 3,130,528 1,420,724 1,303,949 1,132,099 991,248 1,052,983 1,360,263 1,052,720 920,767 

1983............... 1,110,424 984,406 944,960 1,054,406 936,947 1,019,790 1,432,640 1,542,904 1,507,341 

1984............... 2,175,565 1,017,589 1,016,260 830,822 1,009,891 1,926,542 1,258,544 1,521,989 995,602 

1985............... 2,481,723 1,333,055 979,639 910,681 962,052 1,111,396 1,109,123 1,337,600 978,768 

1986............... 1,688,473 1,099,686 927,837 892,584 1,209,008 1,390,314 1,727,407 1,149,790 1,106,992 

1987............... 1,316,961 1,148,510 1,226,721 1,033,183 1,182,806 1,406,711 2,074,848 1,647,568 924,170 

1988............... 2,299,165 1,136,519 1,044,761 805,213 998,067 1,856,758 1,942,820 3,207,212 1,004,284 1,

1989............... 2,054,576 2,426,944 2,690,518 1,045,381 1,522,137 2,069,505 2,179,763 1,530,441 1,526,021 1,

1990............... 1,236,942 974,012 915,910 1,035,276 1,146,358 1,554,847 1,614,610 1,618,368 1,317,642 1,

1991............... 1,187,303 803,666 827,774 1,018,718 1,814,465 1,122,367 1,218,129 1,379,572 1,165,147 

1992............... 1,103,110 806,236 843,393 810,841 842,662 1,076,973 1,427,819 1,011,487 848,761 

1993............... 1,013,193 935,016 1,276,928 818,766 867,766 1,032,707 1,816,950 1,566,013 1,030,726 

1994............... 3,708,634 1,396,753 1,014,052 1,041,314 1,163,764 1,871,348 1,529,794 1,020,993 869,853 

1995............... 1,056,994 1,316,380 906,942 917,867 1,133,485 1,194,824 1,878,603 2,853,030 903,066 

1996............... 1,912,533 2,480,281 1,545,042 978,254 1,345,936 1,079,182 1,293,874 1,109,970 1,066,205 

1997............... 1,622,809 790,182 834,433 982,828 943,462 1,348,491 2,492,659 1,300,740 972,977 1,

1998............... 937,723 753,648 1,179,683 963,474 1,991,844 3,102,943 3,362,457 3,044,973 2,604,877 1999............... 2,250,700 826,918 1,013,812 1,517,235 1,208,081 1,856,872 4,500,679 2,845,033 1,166,132 

Nonutility Consumption

1980............... 18.659 16.123 12.792 7.933 8.876 11.362 22.301 23.394 12.520 1981............... 17.746 13.061 8.182 7.901 10.456 15.755 15.234 8.283 6.668 1982............... 18.235 8.276 7.596 6.594 5.774 6.134 7.924 6.132 5.363 1983............... 6.468 5.734 5.504 6.142 5.458 5.940 8.345 8.987 8.780 1984............... 12.673 5.927 5.920 4.840 5.883 11.222 7.331 8.866 5.799 1985............... 14.456 7.765 5.706 5.305 5.604 6.474 6.461 7.792 5.701 1986............... 9.835 6.406 5.405 5.199 7.042 8.099 10.062 6.698 6.448 1987............... 7.671 6.690 7.146 6.018 6.890 8.194 12.086 9.597 5.383 1988............... 13.393 6.620 6.086 4.690 5.814 10.816 11.317 18.682 5.850 1989............... 11.968 14.137 15.672 6.089 8.866 12.055 12.697 8.915 8.889 1990............... 7.205 5.674 5.335 6.030 6.678 9.057 9.405 9.427 7.675 1991............... 6.916 4.681 4.822 5.934 10.569 6.538 7.096 8.036 6.787 1992............... 6.426 4.696 4.913 4.723 4.909 6.273 8.317 5.892 4.944 1993............... 5.902 5.446 7.438 4.769 5.055 6.016 10.584 9.122 6.004 1994............... 21.603 8.136 5.907 6.066 6.779 10.901 8.911 5.947 5.067 1995............... 6.157 7.668 5.283 5.347 6.603 6.960 10.943 16.619 5.260 1996............... 11.141 14.448 9.000 5.698 7.840 6.286 7.537 6.466 6.211 1997............... 9.453 4.603 4.861 5.725 5.496 7.855 14.520 7.577 5.668 1998............... 5.462 4.390 6.872 5.612 11.602 18.075 19.586 17.737 15.173 1999............... 13.110 4.817 5.905 8.838 7.037 10.816 26.216 16.572 6.793 

Note: EIA began collecting nonutility data in 1989 and is only final through 1998. Nonutilities do not directly report the split between distillate fuel oil and residSources: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report”; Form EIA-860B, “Annual Electric Generator Report—Nonutility”; a

Power Producer Report.”
84 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Table D4. Electricity Generation by Fuel, Census Division 1, 1980-1999

(Megawatthours)

Electric Utility Generation

Year Coal Heavy Oila Hydro Light Oila Natural Gas Nuclear Other Total

1980.............. 4,538,654 46,698,737 3,404,694 484,627 576,169 22,450,207 48,941 78,2021981.............. 4,467,540 40,958,382 4,640,841 237,925 795,669 25,784,625 26,089 76,9111982.............. 11,199,301 33,086,247 4,397,879 310,927 1,471,006 26,496,606 43,436 77,0051983.............. 11,927,216 32,281,816 4,686,480 383,976 2,584,300 26,251,134 50,480 78,1651984.............. 14,622,781 33,251,450 4,599,830 718,752 3,575,159 23,785,862 177,586 80,7311985.............. 16,167,923 28,486,302 4,003,191 568,504 4,673,852 27,207,862 280,138 81,3871986.............. 14,149,446 36,919,358 4,808,530 823,824 1,376,579 29,387,580 84,729 87,5501987.............. 16,673,651 31,867,359 4,108,658 963,434 4,744,476 29,255,747 155,930 87,7691988.............. 16,979,148 36,670,879 3,819,144 1,139,922 1,933,230 32,498,780 341,927 93,3831989.............. 17,248,003 35,784,662 4,333,616 1,253,146 5,193,375 33,126,123 501,728 97,4401990.............. 16,583,321 27,257,610 5,603,383 477,902 6,250,712 37,403,556 515,784 94,0921991.............. 17,147,179 25,860,842 4,739,749 531,833 4,360,009 33,820,053 548,714 87,0081992.............. 16,284,393 20,969,720 3,959,435 322,847 4,108,822 38,473,922 466,194 84,5851993.............. 14,986,976 17,102,047 3,760,414 273,416 3,001,972 44,299,286 470,502 83,8941994.............. 15,495,426 14,634,520 4,124,901 374,733 4,623,652 41,169,782 510,645 80,9331995.............. 16,223,448 10,676,063 3,613,701 449,614 8,836,651 35,670,207 531,193 76,0001996.............. 17,178,120 12,632,757 5,401,061 368,772 8,648,431 30,255,125 572,390 75,0561997.............. 19,123,961 22,184,709 4,508,236 309,665 10,340,158 16,432,023 601,094 73,4991998.............. 13,164,281 21,376,314 4,359,462 382,809 4,859,433 20,686,136 572,847 65,4011999.............. 4,760,016 7,993,338 1,491,777 272,531 2,103,337 27,341,549 681,114 44,643

Nonutility Generation

Year Coal Hydro Natural Gas Nuclear Oil Other Total

%

Oil

1989.............. 363,447 2,024,297 687,780 0 1,627,685 5,841,094 10,544,303 15.41990.............. 1,808,396 2,349,897 1,571,217 0 1,541,056 6,595,839 13,866,406 11.11991.............. 2,384,479 2,241,520 6,508,509 0 1,254,397 7,215,462 19,604,366 6.41992.............. 2,248,528 2,667,431 10,726,313 0 1,459,459 8,034,104 25,135,836 5.81993.............. 2,267,749 2,500,641 12,091,148 0 1,708,635 8,637,933 27,206,106 6.21994.............. 2,417,117 2,682,306 13,504,443 0 1,876,056 8,382,485 28,862,406 6.51995.............. 2,254,075 2,535,751 13,033,773 0 1,796,956 8,668,585 28,289,140 6.31996.............. 2,142,117 3,202,504 13,122,453 0 1,721,262 8,604,372 28,792,708 5.91997.............. 2,395,707 2,946,283 13,677,824 0 1,523,053 8,403,938 28,946,805 5.21998.............. 5,608,848 3,261,759 19,481,471 0 3,902,364 7,617,508 39,871,951 9.7

aLight oil is distillate fuel oil, and heavy oil is residual fuel oil.

Note: EIA began collecting nonutility data in 1989 and is only final through 1998. Nonutilities do not directly report the split between light and heavy oil generaSources: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report”; Form EIA-860B, “Annual Electric Generator Report—Nonutility”; a

Power Producer Report.”
Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options 

Table D5. Electricity Generation by Fuel, Census Division 2, 1980-1999

(Megawatthours)

Electric Utility Generation

Year Coal Heavy Oila Hydro Light Oila Natural Gas Nuclear Other Total

1980.............. 119,530,366 54,799,580 26,689,332 2,520,929 17,867,007 38,993,730 133,105 260,5341981.............. 113,329,898 50,507,443 26,083,217 1,795,135 18,933,659 43,395,362 110,489 254,1551982.............. 116,349,135 42,764,535 26,932,565 1,372,440 19,836,038 44,949,012 169,701 252,3731983.............. 119,802,570 48,135,831 27,100,726 1,762,981 21,218,825 37,422,096 420,411 255,8631984.............. 122,568,700 41,372,191 27,783,222 1,822,821 24,099,052 48,360,207 380,262 266,3861985.............. 127,375,546 34,907,491 27,679,556 1,313,144 21,475,013 68,094,447 309,716 281,1541986.............. 119,366,734 43,423,184 30,642,328 1,580,480 15,592,728 76,675,061 382,382 287,6621987.............. 128,211,283 39,747,541 28,364,881 2,008,663 22,932,655 80,605,746 446,317 302,3171988.............. 136,162,930 49,739,679 24,383,703 2,577,385 18,499,292 85,927,934 515,129 317,8061989.............. 139,529,773 50,785,260 24,946,737 3,508,265 22,084,968 85,044,763 488,917 326,3881990.............. 133,670,746 37,441,953 27,301,259 1,388,888 25,423,894 105,180,794 419,199 330,8261991.............. 130,534,488 31,728,748 25,406,213 1,149,704 25,535,125 110,730,570 387,822 325,4721992.............. 132,529,150 19,948,841 26,670,800 655,442 23,323,852 105,882,758 418,838 309,4291993.............. 127,675,591 18,860,089 27,988,973 793,362 19,943,469 111,152,035 386,291 306,7991994.............. 119,457,273 16,062,213 26,545,193 1,343,062 22,305,985 118,567,584 442,238 304,7231995.............. 121,848,141 9,989,369 23,969,141 1,265,934 29,965,394 109,603,224 548,859 297,1901996.............. 127,128,343 11,226,123 27,494,718 1,327,034 16,435,561 114,925,730 635,350 299,1721997.............. 134,019,227 9,213,301 28,929,951 1,016,348 24,093,598 111,132,280 621,853 309,0261998.............. 135,606,564 17,188,098 28,003,634 1,287,133 23,339,326 119,595,071 634,949 325,6541999.............. 102,627,689 13,547,180 20,928,811 1,392,525 21,190,580 136,874,310 371,488 296,932

Nonutility Generation

Year Coal Hydro Natural Gas Nuclear Oil Other Total

%

Oil

1989.............. 4,593,724 734,125 5,034,383 0 1,003,274 1,759,692 13,125,197 7.61990.............. 4,970,933 959,516 6,971,914 0 1,130,902 2,743,948 16,777,214 6.71991.............. 7,357,624 868,084 10,722,609 0 1,100,758 3,902,716 23,951,791 4.61992.............. 9,278,947 1,897,010 21,839,871 0 1,150,874 5,251,611 39,418,313 2.91993.............. 10,427,744 1,706,811 27,550,666 0 1,629,765 5,662,383 46,977,369 3.41994.............. 11,556,854 1,858,441 33,171,098 0 2,134,559 5,701,588 54,422,540 3.91995.............. 14,037,534 1,568,617 43,855,830 0 1,718,721 6,068,114 67,248,816 2.51996.............. 14,749,887 2,313,414 41,789,350 0 1,378,641 6,109,904 66,341,196 2.01997.............. 13,681,606 2,143,932 42,943,210 0 1,475,078 5,901,798 66,145,624 2.21998.............. 13,878,090 1,943,842 40,673,523 0 1,160,953 6,042,125 63,698,534 1.8

aLight oil is distillate fuel oil, and heavy oil is residual fuel oil.

Note: EIA began collecting nonutility data in 1989 and is only final through 1998. Nonutilities do not directly report the split between light and heavy oil generaSources: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report”; Form EIA-860B, “Annual Electric Generator Report—Nonutility”; a

Power Producer Report.”
86 Energy Information Administration / The Northeast Heating Fuel Market: Assessment and Options

Table D6. Electricity Generation by Fuel, Census Division 3, 1980-1999

(Megawatthours)

Electric Utility Generation

Year Coal Heavy Oila Hydro Light Oila Natural Gas Nuclear Other Total

1980.............. 318,737,720 12,369,798 3,542,335 2,105,695 4,489,256 55,662,818 65,731 396,9731981.............. 314,160,401 7,870,170 3,638,526 1,522,682 3,108,490 60,675,078 71,015 391,0461982.............. 300,605,571 4,805,427 3,798,062 1,219,126 2,105,608 56,121,538 79,231 368,7341983.............. 316,788,766 3,366,904 4,081,849 1,034,882 2,206,395 58,606,609 68,166 386,1531984.............. 331,113,923 2,324,018 3,757,723 977,890 1,465,988 64,112,071 288,731 404,0401985.............. 335,639,564 1,039,246 3,888,392 1,099,962 1,086,124 65,480,464 359,616 408,5931986.............. 339,512,009 2,414,521 3,567,489 973,161 1,508,457 66,094,347 515,749 414,5851987.............. 348,953,676 1,806,007 2,504,834 916,707 940,007 83,406,568 660,942 439,1881988.............. 350,815,830 1,778,323 2,389,259 1,049,361 1,579,892 106,892,852 692,867 465,1981989.............. 355,688,019 1,515,202 2,698,089 929,653 1,524,204 119,641,214 719,114 482,7151990.............. 362,333,020 766,901 3,263,316 922,275 2,277,257 115,387,612 884,973 485,8351991.............. 365,922,735 1,120,295 3,722,686 958,609 3,404,539 124,711,513 620,891 500,4611992.............. 360,265,015 585,362 3,858,054 714,599 2,899,912 118,603,736 636,749 487,5631993.............. 376,682,351 933,539 3,728,314 931,864 2,794,372 128,373,693 336,432 513,7801994.............. 383,432,200 1,401,292 3,280,251 1,132,569 4,547,292 109,267,496 348,533 503,4091995.............. 388,842,356 954,914 3,594,239 1,006,164 6,014,150 130,666,901 626,623 531,7051996.............. 408,295,640 936,078 4,104,902 914,545 3,723,063 120,644,464 761,384 539,3801997.............. 416,284,507 697,443 3,926,264 922,217 5,995,918 92,229,327 922,559 520,9781998.............. 418,626,920 1,153,843 2,805,713 1,160,522 9,116,698 93,962,727 1,342,695 528,1691999.............. 408,764,344 1,166,331 2,007,648 1,274,409 7,793,638 123,863,436 1,092,646 545,962

Nonutility Generation

Year Coal Hydro Natural Gas Nuclear Oil Other Total

%

Oil

1989.............. 5,482,204 196,841 5,239,145 0 389,296 2,207,364 13,514,850 2.81990.............. 5,248,707 239,601 11,536,178 0 461,894 2,638,400 20,124,779 2.31991.............. 5,236,546 263,591 11,796,682 0 355,624 3,034,696 20,687,139 1.71992.............. 6,301,252 509,868 13,135,997 0 492,481 3,101,626 23,541,224 2.01993.............. 6,834,096 515,108 13,840,733 0 605,717 3,523,084 25,318,738 2.31994.............. 8,292,266 527,927 14,675,851 0 692,476 3,806,167 27,994,687 2.41995.............. 6,507,582 483,263 15,694,169 0 623,473 4,157,753 27,466,240 2.21996.............. 6,672,292 519,380 17,569,020 0 784,382 4,529,799 30,074,873 2.61997.............. 6,639,081 522,544 17,606,281 0 711,619 5,079,225 30,558,751 2.31998.............. 9,315,096 433,820 16,975,793 0 1,063,869 5,175,108 32,963,686 3.2

aLight oil is distillate fuel oil, and heavy oil is residual fuel oil.

Note: EIA began collecting nonutility data in 1989 and is only final through 1998. Nonutilities do not directly report the split between light and heavy oil generaSources: Energy Information Administration, Form EIA-759, “Monthly Power Plant Report”; Form EIA-860B, “Annual Electric Generator Report—Nonutility”; a

Power Producer Report.”