p.1 

OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

103)IV-K-(A)-1 

Docket Number: 

A-83-27 

Printed 12/3/2008 9:15:33 AM Sheet 103 of 105 
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o ff H _ y\ ca 

IV"K-(A)-1 

ElMERGYAND ENVIRONMENTAL ANALYSIS, INC. 

1655 NORTH FORT MYER DR ARLINGTON, VIRGINIA 22209 

^ 
P.3 

PROJECTIONS OF INDUSTRIAL FUEL OIL 

AND NATURAL GAS PRICES 

Prepared for: 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 

Prepared by: 

ENERGY AND ENVIRONMENTAL ANALYSIS, INC. 

1655 North Fort Myer Drive, Suite 600 

Arlington, Virginia 22209 

October 1986 
P.4 

This report was furnished to the U.S. Environmental Protection Agency 

by Energy and Environmental Analysis, Inc., Arlington, Virginia, in fulfillment 

of Contract Number 68-02-4202. The contents of this report are reproduced 

herein as received from the contractor. 

The opinions, findings, and conclusions expressed are those of the 

author and not necessarily those of the U.S. Environmental Protection Agency. 

L 
i 5 _ 

TABLE OF CONTENTS 

Page 

1. SCOPE AND OBJECTIVES 1-1 

2. CRUDE OIL PRICES 2-1 

2.1 Overview of Methodology Used to Develop Crude Oil Prices 2-1 

2.2 Projected Crude Oil Prices 2-1 

2.3 Highlights of the Analysis of Crude Oil Prices 2-4 

3. FUEL OIL PRICES TO THE INDUSTRIAL SECTOR 3-1 

3.1 Determinants of Residual Oil Pricing 3-1 

3.2 Relationship of High Sulfur Residual Oil with Crude Oil Prices 3-1 

3.3 Differences in Residual Oil Prices by Sulfur Content 3-3 

3.4 Regional Price Differences 3-3 

3.5 Distillate Oil Prices 3-6 

3.6 Relationship Between Residual Oil and Natural Gas Prices 3-6 

4. NATURAL GAS PRICES 4-1 

4.1 The Context - Evolution of the Natural Gas Market in the 

1982-1986 Period 4-1 

4.2 Focus and Methodology for this Study 4-3 

4.3 Results for the Low Oil Price/Flexible Gas Price Scenario 4-6 

4.4 Comparisons of Gas Market Scenarios 4-10 

APPENDIX A: REGIONAL INDUSTRIAL OIL AND GAS PRICE FORECASTS FOR THE 

LOW OIL PRICE SCENARIO A-1 

APPENDIX B: REGIONAL INDUSTRIAL OIL AND GAS PRICE FORECASTS FOR THE 

HIGH OIL PRICE SCENARIO B-l 
P.6 

LIST OF TABLES 

Page 

1-1 Oil and Natural Gas Price Scenarios 1-3 

2-1 Crude Oil Price Bounding Cases 2-3 

2-2 Projected Economic Growth Rates, 1984-1995 2-5 

2-3 Energy Intensity Trends in the Low Case 2-7 

2-4 U.S. Oil Production 2-8 

2-5 U.S. Oil Demand Outlook 2-9 

2-6 World Transportation Oil Use in Low Case 2-10 

2-7 World Oil Supply/Demand in Low Case 2-11 

2-8 Market Factors in the Low Price Case 2-12 

3-1 Residual Oil Price Differentials by Sulfur Content: 

Low Oil Price Scenario 3-4 

4-1 Oil and Natural Gas Price Scenarios 4-5 

4-2 Natural Supply and Demand: Low Oil with Flexible Gas Market .. 4-7 

4-3 Projections of Gas Prices: Low Oil with Flexible Market 4-8 

4-4 Projected Trends in Natural Gas Consumption 4-12 

4-5 Projected Trends in Gas Supply and Wellhead Prices 4-14 

4-6 Projected Trends in Industrial Burnertip Prices in the 

Middle Atlantic Region 4-16 
P.7 

LIST OF FIGURES 

Page 

1. World Oil Price 2-2 

2. Federal Regions of the United States 4-9 
P.8 

1. SCOPE AND OBJECTIVES 

This report presents a set of oil and natural gas price forecasts prepared 

by EEA during the summer of 1986. The focus is on projections of delivered 

regional prices to industrial sector energy users. This report constitutes an 

update of fuel price forecasts prepared as an input for the impact analysis of 

the New Source Performance Standards for industrial boilers. The previous set 

of price forecasts, prepared in 1984, has been outdated by recent trends in oil 

prices and rapid institutional changes in the natural gas market. 

Specifically the report provides delivered industrial energy price 

projections by Federal region through the year 2005 for the following alternative energy sources: 

t Distillate fuel oil 

0 Residual fuel oil 

• Natural gas. 

The need to update these price forecasts occurs in a period of unusually 

high uncertainty in oil and natural gas markets. Although oil and gas markets 

have been notoriously difficult to predict in the last 15 years, the present 

environment is unusually unstable due to: 

t The sharp drop in crude oil prices from $26-27 per barrel in 

1985 to $12-15 in early 1986. 

• The evolution of a more market-oriented institutional environment in natural gas markets combined with sharply declining prices 

during 1983-1986. 

This report addresses these uncertainties by generating alternative 

scenarios to reflect the potential impact of these issues on the range of 

future oil and gas prices. With respect to oil prices the scenarios reflect: 

• High and low scenarios for world crude oil prices 

t That no attempt was made to prepare a "best guess" scenario due to 

current uncertainty 

t That an attempt was made to generate "plausible" (but not extreme) 

scenarios with the high and low forecasts expected to bracket future 

outcomes. 

With respect to delivered natural gas prices to the industrial sector, 

1-1 
P.9 

t,he scenarios reflect: 

• Alternative outcomes of the institutional evolution of the market 

• Within an "institutional" scenario, price for gas sold in 

traditional markets and a different price reflecting sales in 

the new transport (or carriage) market. 

Table 1-1 summarizes the description of the scenarios reflecting: 

• Two fuel oil price forecasts, reflecting high versus low crude 

oil trends 

• Six distinct forecast price trajectories for natural gas to represent: 

- high and low oil prices 

- a flexible versus rigid institutional environment under the 

lower crude oil prices 

- traditional as well as transport market prices for each of 

the three scenarios of natural gas prices 

This report is organized into three sections. Section 2 presents the 

forecasts of crude oil prices. Section 3 explains the development of fuel oil 

prices in relation to the crude oil prices. Section 4 contains the discussion 

of natural gas prices. Two appendices contain the detailed regional price 

projections. Appendix A contains projections for all fuel prices under the 

low crude oil price scenarios while Appendix B has all projections which were 

based on the high crude oil price scenario. 

1-2 
P.10 

TABLE 1-1. OIL AND NATURAL GAS PRICE SCENARIOS 

Low oil 

• Fuel oil product prices 

• Natural gas 

- Presents prices for two market segments 

-- Carriage 

-- Non-carriage or local distribution company (LDC) sales 

- Two alternative scenarios of natural gas prices depending on 

market evolution 

-- Flexible market - maximizes ability to retain gas sales 

-- More rigid market - institutional and behavioral constraints 

limit ability to lower burnertip natural gas prices and retain 

natural gas sales 

High oil 

• Fuel oil product prices 

• Natural gas 

- Presents prices for two market segments 

-- Carriage 

-- Non-carriage or LDC sales 

1-3 
P.11 

2. CRUDE OIL PRICES 

2.1 OVERVIEW OF METHODOLOGY USED TO DEVELOP CRUDE OIL PRICES 

EEA utilized a model of world oil markets as the framework to develop the 

crude oil price scenarios. This model (WOIL), developed by EEA and DOE, is 

the framework used in DOE's National Energy Policy Plan (NEPP) projections. 

In this model, demand and supply balances are represented for five country 

groups: the United States, the rest of the OECD countries, the developing 

countries, Mexico and the producer members of OPEC. It is a systems dynamics 

framework with structural representations of demand forces (reflecting efficiency gains and fuel switching) and explicit tracking of resource discovery, 

development and production in the supply sectors. For each world region WOIL 

projects primary energy supplied in terms of oil, gas, coal, nuclear and 

renewables (including production, net trade, and stock changes). Energy 

consumption is estimated based on economic activity and equipment efficiency 

assumptions and is projected by fuel type (including electricity) and by 

sector (residential, commercial, industrial, electric utility and transportation). Energy prices are calculated from supply/demand balances for 

resource costs (for example, minemouth coal) plus taxes, delivery charges, and 

other markups to determine delivered energy prices. 

The WOIL model treats the OPEC countries as the marginal supplier of oil 

in world markets, with some degree of control on excess production capacity. 

Prices are determined by demand and supply forces, with OPEC exerting market 

power in tight markets. 

2.2 PROJECTED CRUDE OIL PRICES 

Figure 1 shows the High and Low Price Scenarios generated in this study. 

The Low Price Scenario falls to $13-14 per barrel ($1985), then rises to about 

$15 in 1990 and $20 by 1995. The High Case reflects a much more rapid recovery 

to $21 by 1988 and returns to 1984-1985 prices levels of $26-27 per barrel in 

1995. Table 2-1 presents the year-by-year prices used in Figure 1. 

Since these two scenarios are intended to provide plausible bounding 

cases for future oil price trends, the "themes" or underlying characteristics 

of the two scenarios should be highlighted. The Low Oil Price Case could be 

2-1 
P.12 

1985$/BBL 

30 

2 0 -

1 0-

F1GURE 1 

World Oil Price 

LOW PRICE CASE 

—T—•—r 

'84 '85 

~i—«—i—•—r 

•86 '87 *88 

T—•—r T i—•—r 

•89 '90 '91 '92 *93 '94 '95 

YEAR 

2-2 
P.13 

TABLE 2-1. CRUDE OIL PRICE BOUNDING CASES* 

(1985 $/bbl) 

Low Case High Case 

1985 26.76 26.76 

1988 13.34 21.16 

1990 14.47 23.87 

1995 20.08 27.02 

2000 24.61 30.61 

2005 30.79 37.42 

Average U.S. refiner acquisition cost of crude oil. 

2-3 
1 characterized as: 

T 

• Continued high OPEC crude oil production resulting from revenue 

needs and lack of agreement among key countries 

• Moderate economic growth rate reflecting poorer performance than 

historical experience 

• Minimal response of oil demand and supply elements to lower crude 

oil prices. 

In contrast, the High Oil Price Scenario could be characterized by: 

• A stronger economic growth rate 

• A greater response of supply and demand for oil to lower crude 

prices 

• A return to historic OPEC behavior patterns 

2.3 HIGHLIGHTS OF THE ANALYSIS OF CRUDE OIL PRICES 

The development of projections of crude oil prices considered a wide 

variety of factors. For this study the emphasis was placed on the following 

issues: 

Assumptions regarding economic growth 

Impact of world crude oil price on oil and gas production outside 

OPEC, especially U.S., North Sea and Canada 

Degree of fuel switching in U.S. industrial and electric utility 

sectors 

Degree of energy demand response to lower fuel prices 

Potential utilization of gas and coal in less developed countries 

Efficiency gains in the transportation sector 

Outlook for nuclear power 

The discussion which follows presents some of the assumptions and intermediate results for selected areas to illustrate the nature of the scenarios. 

The emphasis in the presentation is on the Low Oil Price Scenario since that 

case is a significant departure from recent trends. 

Table 2-2 presents the economic growth rate forecasts used in the analysis 

for both the Low and High Scenarios. For the U.S., the 2.3-2.8 percent per 

year range reflects uncertainty over the pace of economic recovery. In the Low 

Case, the growth rates for the OECD and rest of free world (the developing 

countries) are substantially below recent experience reflecting much poorer 

2-4 
P.15 

TABLE 2-2. PROJECTED ECONOMIC GROWTH RATES 

1984-1995 

(% per year in real terms) 

Low Case High Case 

U.S. 2.3 2.8 

Rest of OECD 1.8 2.3 

OPEC 2.5 3.3 

Rest of free world 2.5 3.3 

2-5 
performance by Japan and a considerable moderation of growth in less developed 

countries. Note that the lower economic growth rates are used in the Low Oil 

Case not because we believe lower oil prices will slow economic growth but 

because our Low Case is intended to reflect a scenario of poorer free world 

economic performance which contributes to a weaker energy demand (and lower 

oil prices). 

Table 2-3 shows forecast trends in energy intensity for the Low Oil Price 

Case. These trends continue to reflect improved energy efficiency but at a 

slower pace than in the past. The U.S. trend in efficiency is a 1 percent per 

year improvement in energy intensity per $ of GNP over the 1984-1995 period. 

Table 2-4 shows the U.S. oil production levels associated with both 

cases. For the Low Oil Price Case, the estimates show a range of uncertainty 

in the impacts of various components of U.S. production. Production in Alaska, 

for example, would not be significantly reduced because of high fixed costs and 

the relatively recent development of production capacity. On the other hand, 

EOR (enhanced oil recovery techniques) production could fall off very rapidly. 

Table 2-5 presents the U.S. oil demand projections by end use sector 

under the Low Oil Price Scenario. Most of the increase in industrial oil 

demand comes from fuel switching from natural gas. The lower end of the range 

of oil demand increases over the period 1984-1995 implies an increase of 

slightly below 1 percent per annum. The flat (or declining) oil demand for 

transportation uses tends to outweigh increased oil use in the industrial and 

electric utility sectors. 

Table 2-6 shows world oil demand for transportation uses declining from 

40 percent to 36 percent of world oil demand over the 1984-1995 period. 

Table 2-7 shows the overall oil supply and demand balance in the Low Oil 

Price Case. Table 2-8 converts this balance into the measures most relevant 

for price determination. OPEC production is projected to grow from 41 percent 

of all world oil supply in 1984 to 56 percent by 1995. From the perspective of 

price determination, the key measures are OPEC capacity utilization and 

revenues. From 1980 to 1984, the capacity utilization rate of OPEC declined 

sharply from 92 percent to 58 percent creating tremendous pressures for a 

collapse in world oil prices. Using simple rules of thumb from historical 

2-6 
P.17 

TABLE 2-3. ENERGY INTENSITY TRENDS IN THE LOW CASE 

(barrels per $1000, in real terms, of GNP) 

U.S. 

Rest of OECD 

OPEC 

Rest of free world 

1984 

3.60 

2.87 

2.22 

3.25 

1990 

3.36 

2.70 

2.07 

3.12 

1995 

3.22 

2.55 

1.94 

3.02 

2-7 
P.18 

TABLE 2-4. U.S. OIL PRODUCTION 

(MMB/D) 

1984 1990 1995 

LOW CASE 

Lower 48 

Alaska 

EOR 

Total 

HIGH CASE 

8.0 

1.7 

0.6 

10.3 

5.4 - 6.1 

1.7 

0.4 - 0.5 

7.5 - 8.3 

9.2 -10.1 

4.4 - 5.0 

1.3 - 1.5 

0.3 - 0.5 

6.0 - 7.0 

8.2 - 9.6 

2-8 
P.19 

TABLE 2-5. U.S. OIL DEMAND OUTLOOK 

1984 1990 

Low Case 

1995 

Industrial (Quads) 

Electric utilities (Quads) 

R/C (Quads) 

Transportation (Quads) 

Total (Quads) 

(MMB/D) 

7.9 

1.3 

2.6 

19.3 

31.1 

14.7 

9.5 

1.5 - 2.0 

2.8 - 3.1 

18.7 -18.9 

32.3 -33.5 

15.4 -15.8 

10.3 -

1.8 -

2.9 -

19.0 -

34.0 -

16.1 -

11.6 

2.7 

3.2 

19.2 

36.7 

17.3 

2-9 
P.20 

TABLE 2-6. WORLD TRANSPORTATION OIL USE IN LOW CASE 

(MMB/D) 

1984 1990 1995 

U.S. 

Rest of OECD 

LDC's* 

Total transportation 

9.8 

5.2 

3.5 

18.4 

9.5 

5.4 

4.0 

18.9 

9.6 

5.2 

4.2 

19.0 

Percent of total oil use 40% 38% 36% 

Less developed countries. 

2-10 

J 
P.21 

TABLE 2-7. WORLD OIL SUPPLY/DEMAND IN LOW CASE 

(MMB/D) 

1984 1990 1995 

DEMAND 

U.S. 

Rest of OECD 

Rest of free world 

Total free world 

14.7 

19.9 

11.2 

45.8 

15.4 

22.1 

12.6 

50.1 

16.1 

22.5 

13.4 

52.0 

SUPPLY 

U.S. 

Rest of OECD 

Rest of free world 

OPEC* 

Processing gain 

** 

CPE exports 

Total free world 

10.3 

6.1 

8.1 

18.5 

1.0 

LS 

45.8 

8.3 

5.8 

8.4 

24.9 

1.1 

LS. 

50.1 

7.0 

5.2 

8.5 

29.2 

1.1 

1.0 

— T 

52.0 

Includes natural gas liquids. 

*Centrally planned economies. 

2-11 
TABLE 2-8. MARKET FACTORS IN THE LOW PRICE CASE 

P.22 

OVERALL OIL BALANCE (MMB/D) 

Free world demand 

Free world supply 

Net demand for OPEC 

1984 1990 1995 

45.8 

27.3 

18.5 

50.1 

25.2 

24.9 

52.0 

22.8 

29.2 

PRESSURES ON OPEC 

1980 1984 1988 1990 1995 

Capacity Utilization (%) 

Gross oil revenues 

(billion 1985 $) 

92 

414 

58 

200 

72 

112 

83 

132 

91 

214 

2-12 
P.23 

experience: 

• Upward pricing pressures have occurred when OPEC capacity utilization has been above 80 percent 

- 93 percent in 1973/1974 during the oil embargo 

- 90-92 percent in the 1978-1980 period of another sharp price 

increase 

• Downward pressures on price have occurred when capacity utilization has been below 70 percent 

- 65-70 percent in 1982-1983 

- below 60 percent in 1984. 

Note also that gross oil revenues of the OPEC nations were already cut in 

half in 1984 (compared to 1980) primarily due to declines in OPEC production 

rather than price. In 1985-1986 revenues have plummeted as oil prices declined 

from $26.50 to roughly $12-15 per barrel. 

The Low Oil Price Scenario shows a very gradual recovery of OPEC as a 

share of world oil production. By 1990, OPEC capacity utilization has just 

exceeded 80 percent (causing prices to begin to increase above $15 per barrel). 

Even in that year, oil revenues have still recovered only to 1984 levels, 

tending to force higher production levels. In this Low Oil Price Scenario 

characterized by minimal responses in world oil supply and demand to a $15 oil 

price, there is very little pressure on OPEC oil production capacity until the 

early 1990's. After 1990, the price rise is fairly moderate in the Low Case 

(from $15 to $20 by 1995) due to the behavioral assumption that continued 

disunity and revenue pressures on the OPEC nations weaken their ability to 

exercise market power as the world oil market tightens up. 

In comparison, under the High Price Scenario, crude oil prices have 

already risen to $23-24 by 1990 due to stronger declines in Non-OPEC production 

and increased energy and oil demands. Prices rise to $27 in 1995 (recover to 

1985 levels) due to a tight market plus the exercise of OPEC market power 

according to historical patterns. 

2-13 
P.24 

3. FUEL OIL PRICES TO THE INDUSTRIAL SECTOR 

3.1 DETERMINANTS OF RESIDUAL OIL PRICING 

The most important competitive fuel oil against natural gas and coal is 

residual oil. Residual oil has traditionally been considered a low valued 

by-product of the refining process. This perception leads many observers to 

note that resid prices in time are set at "whatever the market will bear." 

However, resid prices are determined by a complex set of underlying factors 

including: the price and quality of crude oil, demand for resid and other 

refinery products, refinery configurations and capacity utilization, costs of 

converting resid to lighter petroleum products and desulfurization costs. 

This discussion of residual oil prices is organized by the following key 

analytical elements: 

f The price of residual oil relative to crude oil 

• Price distinctions by sulfur content 

• Regional price differences 

There is, in reality, significant interaction among these factors. For 

example, the determinants of prices by sulfur content differ regionally. 

Differences in regional product demand and existing refinery configurations 

are also important. However, for expositional purposes, each of these key 

elements will be discussed separately. 

3.2 RELATIONSHIP OF HIGH SULFUR RESIDUAL OIL WITH CRUDE OIL PRICES 

In periods where there is a significant excess production capacity for 

high sulfur resid, resid prices can fall low enough relative to crude oil so 

that it becomes economic for refiners to substitute residual oil for crude as 

a feedstock since it can be upgraded to produce lighter, higher valued 

products. Thus, in effect, refinery upgrading economics set a floor price on 

high sulfur residual oil in relation to crude oil prices. 

Demand for residual oil has declined sharply in the U.S. in recent years 

from approximately 2.8 million barrels per day (MMB/D) in the 1976-1979 period 

to 1.4 MMB/D in 1983. This drop in resid consumption by one-half over a four 

year period has been more severe than the decline in overall petroleum product 

consumption, which dropped by about 20 percent over the same period. The 

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P.25 

decline in resid demand affected imported supplies more severely than output 

from U.S. refineries. In the late 70's, resid imports accounted for nearly 

two-thirds of domestic supply but by 1982 imports had dropped to 40-45 percent 

of resid supply to U.S. markets. This led to price declines for residual oil 

which fell below the trigger level causing refiners to install facilities 

(particularly coking units) to upgrade residual oil into lighter products, 

reducing the degree of excess resid supply in the market place. 

The key issues in forecasting the relationship of high sulfur resid to 

crude oil are: 

• What constitutes a parity relationship or differential between high 

sulfur resid and crude in the future? 

• How sensitive is this differential to lower crude oil prices? 

The latter point relates to whether high sulfur resid prices will move proportionately with the decline in crude oil prices or less than proportionately. 

For example, if all of the costs of upgrading resid to light products were 

dependent on the cost of crude oil, then one would expect the floor price for 

high sulfur resid to drop at the same percentage rate as the crude oil price. 

In fact, all of the fixed cost of resid upgrading and a portion of the variable 

costs are not dependent on crude oil. Hence, from the perspective of refinery 

economics, as the price of crude oil declines, we would expect high sulfur 

resid to decline but less rapidly. These factors would tend to make high 

sulfur resid prices converge (in absolute dollars per barrel) with crude oil 

prices under our two crude oil price scenarios. On the other hand, the value 

of the light product slate may be dropping relative to crude oil due to the 

weak forecast demand for gasoline in the future. To the extent that the 

average price of the light product slate drops relative to crude oil, this will 

tend to increase the differential of high sulfur resid below crude because the 

value of products converted from resid would be lower relative to crude oil. 

When these concepts are incorporated into the forecast framework, the 

price differential between crude oil and high sulfur residual fuel oil drops 

from $3.54 per barrel in 1985 to $2.46 per barrel in 1988 as a result of the 

drop in crude price from $26.76 to $13.34 per barrel over the same period. 

This drop in differential continues the historical trend of shrinking differentials during periods of falling prices. As projected crude oil prices increase 

3-2 
P.26 

after 1988, the differential between crude and resid will start to increase 

again, although not as rapidly as the projected increase in crude oil prices. 

3.3 DIFFERENCES IN RESIDUAL OIL PRICES BY SULFUR CONTENT 

Sulfur content and viscosity are two major quality distinctions which 

result in price differences. For the purposes of this study, sulfur distinctions are the relevant issue. The forecast of residual oil prices by sulfur 

content is intended to match the four classes used in the impact analysis of 

the New Source Performance Standard: 3%, 1.6%, 0.8% and 0.3% sulfur by weight. 

The long run price differential between high and low sulfur residual oil 

will be determined by the costs of desulfurization. A critical issue, once 

again, is the extent to which desulfurization costs are dependent upon crude 

oil as an input. To the extent that crude oil accounts for a share of desulfurization costs, the differential between high and low sulfur residual oil 

will decrease in our oil price scenario. EEA's analysis of desulfurization 

costs indicated that at $27 per barrel crude, crude oil related costs 

(indirectly, hydrogen production and process utility costs) accounted for 

roughly two-thirds of desulfurization costs. Costs independent of crude oil 

prices (return on capital, catalyst replacement, chemicals and other operating 

expenses) accounted for the balance of costs. 

Table 3-1 reflects the incorporation of these concepts in the forecast 

sulfur content price differential in the Low Oil Price Scenario. From 1985-

1988, while the crude oil price falls by one-half, the residual oil sulfur 

content differential narrows sharply but not to' the same extent. 

3.4 REGIONAL PRICE DIFFERENCES 

Residual oil prices also differ by region within the U.S. For the 

purposes of these forecasts, three major regional groups can be distinguished:* 

• East and Gulf coasts 

• Midwest 

• West coast 

*0ther distinctions could add the inland waterway system and the mountain 

states. However, these areas are less important in terms of the volume of oil 

and natural gas consumption in these areas. 

3-3 
P.27 

TABLE 3-1. RESIDUAL OIL PRICE DIFFERENTIALS BY SULFUR CONTENT: 

LOW OIL PRICE SCENARIO 

(1985 $) 

Residual Oil 

:ur Different 

($/bbl) ($/MMBtu) ($/MMBtu) 

Crude Oil* Sulfur Differential** 

1985 26.76 4.61 0.80 

1988 13.34 2.30 0.52 

1990 14.47 2.49 0.54 

1995 20.08 3.46 0.63 

2000 24.61 4.24 0.69 

2005 30.79 5.31 0.79 

*Average U.S. refiner acquisition cost of crude oil 

0.3 to 3.0% sulfur. 

3-4 
The large east coast markets for residual oil are supplied primarily by 

the Caribbean refiners, local refineries and small shipments from Gulf coast 

refineries. The key determinant of resid prices on the east coast is the Gulf 

coast price plus tanker costs to reach terminals along the eastern seaboard. 

This is because the more complex refineries along the Gulf coast are the 

lowest cost sources of residual oil. The refineries located on the east cost 

are less efficient and tend to generate resid yields of 12-14 percent (percent 

of product output) compared to lower yields in the Gulf coast. The Caribbean 

refiners are basically price takers, even though imports from the Caribbean 

historically provided the bulk of resid supplies on the east coast. Price 

differences along the Atlantic seaboard are fairly small, reflecting 

differences in transportation costs. 

Resid markets in the midwest have undergone major shifts due to the 

decline of resid consumption. Resid consumption is now heavily concentrated 

in large end users, such as the steel plants. Amoco, one of the major resid 

suppliers in this region, has withdrawn from this market. The ceiling on 

midwestern resid prices is presently set by Gulf coast products barged up the 

river system. Midwestern refineries are relatively efficient producers of low 

sulfur resid due to a high share of coking capacity and a lower sulfur mix of 

crude oil than in the Gulf coast. Hence, if resid demand were strong, these 

refineries could make low and medium sulfur resid at relatively lower cost than 

Gulf coast refiners. In a strong market, production of these resid grades can 

be a profitable business. Resid prices can swing over a relatively wide range 

in the midwest depending on the size of the resid market. This analysis 

assumes continuation of a relatively weak market for resid, hence resid prices 

in the midwest are set at $0.19/MMBtu ($1985) above Gulf coast prices. 

West coast markets are essentially isolated from other resid markets. The 

crude oil mix is heavier than on the Gulf coast, due to the quality of 

Californian and Alaskan crudes. Due to a declining resid market and a heavier 

crude mix, refineries in this region have already installed upgrading capacity 

to convert resid to lighter products. Hence, resid tends to be a higher valued 

product relative to crude costs on the west coast due to its value as a 

feedstock. Low sulfur Indonesian crude oil prices would set a ceiling on 

3-5 
P.29 

resid prices on the west coast low sulfur resid due to the relatively high 

share of stringent sulfur regulations in this area. In effect, compared to the 

Gulf coast, resid price is related to the lower price of west coast crudes, 

offset partially by a higher resid to crude price ratio. We have assumed resid 

prices on the west coast are slightly below Gulf coast prices in a relatively 

weak resid market due to the lower average crude oil costs on the west coast. 

3.5 DISTILLATE OIL PRICES 

These prices have been projected based on historical relationships with 

crude oil prices. 

3.6 RELATIONSHIP BETWEEN RESIDUAL OIL AND NATURAL GAS PRICES 

Since competition between residual oil and natural gas is taking place in 

1986, there has been a great deal of discussion regarding the interaction of 

the prices of these competitive fuels. Natural gas prices, at least in the 

short run, are clearly affected by residual oil prices as gas marketers try to 

compete with fuel oil. One popular view is that residual oil prices will tend 

to increase, relative to crude oil prices, as a consequence of competition 

with natural gas. This view implicitly assumes that residual oil will win 

substantial markets from natural gas and the increased demand for resid will 

raise its price. 

No adjustments have been made in residual oil prices to account for 

market interaction with natural gas since the methodology for projecting 

natural gas prices depends on assumptions regarding residual oil prices to 

determine whether natural gas will be able to maintain market share against 

residual oil. 

3-6 
P.30 

4. NATURAL GAS PRICES 

•J 

4.1 THE CONTEXT - EVOLUTION OF THE NATURAL GAS MARKET IN THE 1982-1986 PERIOD 

The period between 1982 and 1986 reflected a fast-paced transition of the 

natural gas market from a regulated industry to one which is increasingly 

responsive to market pressures, with the institutions trying to adapt to 

market conditions. 

The dominant market force in this period was the substantial surplus of 

natural gas available in U.S. markets. This surplus led to a rapid decline in 

gas prices over the 1982-1985 period prior to the sharp decline in oil prices. 

Gas demand continued its long run downward trend, aggravated by the recession 

of 1982 and the failure of the industrial sector to rebound strongly in 

1983-1984. Gas producers continued to believe that the end to the gas surplus 

(or "bubble") was just around the corner, hence drilling to find new reserves 

continued at a fairly high level, tending to maintain the surplus. 

The institutional structure of the market became more responsive to market 

pressures as follows: 

• For the most part, producers were willing to compromise on take-orpay payments arising from their pipeline contracts which would have 

created many billions of dollars in financial costs to the 

pipelines. 

• To a lesser extent, pipelines were able to get out of contract 

pricing provisions where prices were above competitive levels, 

although often only by temporary waivers or special, short term 

arrangements. 

• A spot market emerged in the interstate gas market, fed by released 

gas from high priced contracts moving under Special Marketing 

Programs (SMP's) in 1983-1984 and by sales of gas from new reserves 

proven in 1981-1983 but not committed to long term contracts with 

the pipelines. 

• Pipelines competed with each other for market share, chiefly at the 

expense of producers, by lowering wellhead gas prices. 

The Federal Energy Regulatory Commission (FERC) attempted to institutionalize this more market responsive climate which had been evolving in the 

1982-1984 period through Order #436, issued in the fall of 1985 (and still 

being negotiated). Key aspects of this ruling were: 

4-1 
P.31 

9 An attempt to place the pipelines' role as a transporter of gas on 

an equal footing with the traditional pipeline merchant* role 

• Established a system of regulating transmission costs for both 

conventional merchant sales and carriage (or transport) gas which 

allowed for downward flexibility in carriage rates without FERC's 

normal case-by-case approval process 

• Placing the pipelines at risk to recover full "regulatory approved 

costs" in the carriage/transport market 

t Require the pipelines to become open access transporters for all 

legitimate producer/marketers. 

The intent of this order was to legitimize the institutions that had been 

evolving under market pressures so as to: 

• Force all participants to accept or share some degree of market risk 

• Make the pipelines play a role as common carriers 

• Permit responses to market pressures within generic, rather than 

case-by-case, FERC rules. 

From the perspective of the marketplace, the most important ramifications of 

these institutional changes were: 

t It allowed the market to respond to the gas surplus 

• It provided a basis for market discrimination in burnertip prices 

to end users of natural gas 

This last point is particularly important in light of the precipitous 

decline in oil prices which occurred in late 1985-early 1986. The FERC 

actions, accompanied by parallel actions by some of the state Public Service 

Commissions, basically allow for a lower burnertip natural gas price to be 

charged to end users who are likely to shift to alternative fuels than other 

customers. Previously, natural gas wellhead and pipeline transmission rates 

were averaged in at the city-gate (local distribution company or LDC purchase 

point). Only the LDC could charge differential rates to end users. Under the 

new system, one industrial plant could potentially pay a lower natural gas 

wellhead price, transport cost and distributor markup than another industrial 

user in the same LDC market area. In concept, this new structure permits 

*The merchant role included signing contracts with producers, taking 

title to the gas, and signing contracts with lcoal distribution companies 

to sell the gas. 

4-2 
P.32 

natural gas price discrimination among end users within the same broad end use 

categories. 

Since the sharp decline in oil prices by early 1986, producers have 

essentially ceased or at least very sharply curtailed new drilling activities. 

Spot market prices for gas at the wellhead have declined from just below $2.00 

in late 1985 to roughly $1.30 per million Btu's. 

4.2 FOCUS AND METHODOLOGY FOR THIS STUDY 

In developing projections of natural gas prices to industrial end users 

to match the two oil price scenarios described earlier, we have structured 

sensitivity cases to reflect the uncertainty of how gas markets will respond 

to a market environment of lower oil prices. 

One such issue is how flexibly the institutions and participants will 

respond to market pressures. In describing the evolution of institutions 

the greater flexibility of pricing potentially gives the natural gas market a 

much better opportunity to retain gas sales to industrial/electric utility 

customers who could switch to fuel oil. However, this flexibility does not 

guarantee that gas will be more competitive than fuel oil in the future. At 

some point, for example, producers will have to recover finding costs plus a 

reasonable rate of return to justify drilling activities required to develop 

new gas supplies. 

Another type of market rigidity relates to how far pipelines would 

discount rates in the carriage market. FERC rules permit pipelines to set 

transmission rates for carriage sales between variable and full regulatoryapproved costs. This implies a range of $0.06 to 0.70 per million Btu for many 

interstate pipelines. Rates will be determined within this enormous range by 

competitive pressures. However, a key factor is how low this carriage rate 

could fall to maintain gas levels against oil competition. Severe discounting 

of carriage rates to a large volume market could lead to significant revenue 

losses. This provides an incentive for pipelines to resist severe transmission 

rate discounts on carriage gas sales. 

For these reasons, two sets of industrial natural gas price projections 

were developed for the Low Oil Price Scenario (where competition from fuel oil 

will be most severe): 

4-3 
P.33 

jt One reflecting downward flexibility in transmission and distribution 

rates toward variable costs 

• Another more "rigid" case where transmission and distribution costs 

do not fall as far in attempting to meet oil competition. 

Keep in mind that because of the ability to price discriminate within 

industrial markets, each gas scenario generates two burnertip prices to the 

industrial sector: 

• A carriage/transport price 

• Another price for purchases through traditional local distribution 

companies sales. 

The carriage price will tend to be the lower delivered price in all interstate 

markets. 

The resultant scenarios are shown in Table 4-1. With respect to natural 

gas prices, 

• Under the Low Oil Price Scenario, four sets of delivered prices are 

generated reflecting 

- Two subscenarios (flexible versus rigid market) 

- Two prices for each subscenario (carriage and conventional sales 

burnertip prices) 

• Under the High Oil Price Scenario, two sets of gas prices are 

projected (reflecting carriage and conventional sales prices) 

Another factor which varies between gas price scenarios is the volume of 

natural gas imports. Under the flexible gas market/Low Oil Case, gas imports 

are assumed to grow rapidly. This will tend to lower the U.S. wellhead price 

of gas by placing less pressure on domestic resources to satisfy some level of 

gas demand. This matches the intent of the flexible case under Low Oil 

Prices, i.e., where natural gas consumption is most likely to be maintained in 

a climate of very low oil prices. In the market rigidity case, gas imports are 

assumed to face more obstacles, hence a lower level of gas imports will tend 

to lead to higher U.S. natural gas wellhead prices - making gas less 

competitive under the climate of lower oil prices. 

The methodology employed to develop the projected natural gas prices 

relies on several models of the natural gas market developed by EEA. The gas 

supply side of the analysis is based on the Hydrocarbon Supply Model developed 

by EEA for the Strategic Analysis and Energy Forecasting Division of the Gas 

4-4 
P.34 It 

TABLE 4-1. OIL AND NATURAL GAS PRICE SCENARIOS 

Low oil 

t Fuel oil product prices 

• Natural gas 

- Presents prices for two market segments 

--Carriage 

--Non-carriage or local distribution company (LDC) sales 

- Two alternative scenarios of natural gas prices depending 

on market evolution 

--Flexible market - maximizes ability to retain gas sales 

--More rigid market - institutional and behavioral constraints 

limit ability to lower burnertip natural gas prices and retain 

natural gas sales 

High oil 

• Fuel oil product prices 

A Natural gas 

- Presents prices for two market segments 

--Carriage 

--Non-carriage or LDC sales 

4-5 
P.35 

t Research Institute.* EEA also used its proprietary Energy Overview Model 

which integrates demand and supply factors to develop burnertip price projections by region. This model links production flows from twelve gas supply 

regions through model pipeline systems (12) to gas distribution service areas 

(10), with each major end use sector differentiated within each distribution 

company service area. 

4.3 RESULTS FOR THE LOW OIL PRICE/FLEXIBLE GAS PRICE SCENARIO 

In order to provide a concise description of the results of this gas 

price projection, this section covers the Low Oil/Flexible Gas Price Scenario 

in some detail. Section 4.4 then briefly compares the differences in gas 

prices between scenarios. 

Table 4-2 presents the gas demand and supply balance under the Low 

Oil/Flexible Gas Price Case. The results imply that: 

t Gas demand holds up through the 1980's, then begins to decline in 

the early 1990's - losing 2 quads of consumption over the 1984-1995 

period. 

• Most of the load losses are in boiler markets (industrial and 

electric utility) 

• The growth in gas imports leads to a decline of Lower-48 natural 

gas production of 3 quads (or 17 percent) over the 1984-1995 period. 

The price projections in Table 4-3 help to explain the above trends. Gas 

is able to maintain its load through the 1980's due to: 

• The continuation of the surplus, which keeps the marginal wellhead 

cost (hence market price of gas) down 

• Heavy discounting of transmission and distribution rates in carriage 

markets. 

These two factors keep the industrial natural gas burnertip prices in the 

carriage market well below competitive oil prices through 1990 -- as shown by 

the example results for the Mid-Atlantic region (see Figure 2). Even in the 

1980's, the conventional LDC (local distribution company) sales price to 

industrial users is substantially above oil prices. 

*See Gas Research Insights (May 1983) distributed by the Gas Research Institute 

for a description of this model. 

4-6 
P.36 

TABLE 4-2. NATURAL GAS SUPPLY AND DEMAND: 

LOW OIL WITH FLEXIBLE GAS MARKET 

(Quadrillion Btu's) 

1984a 1988 1990 1995 

DEMAND 

Boilers -- 5.5 5.0 4.5 

Other Industrial0 ^ 3.6 3.7 3.7 

Subtotal Industrial/Utility 9.4 9.1 8.7 8.2 

Residential/Commercial 7.2 7.1 7.0 6.8 

Plant & Lease/Pipeline Fuel 1.6 1.5 1.4 1.2 

Total Consumption 18.2 17.7 17.1 16.2 

SUPPLY 

Lower-48 Production 17.4 16.9 16.1 14.5 

Imports/Supplemental s LJD L_3 US 2^2 

Total Supply 18.4 18.2 17.6 16.7 

less unaccounted for 0.2 0.5 0.5 0.5 

Total Disposition 18.2 17.7 17.1 16.2 

a From Natural Gas Annual 1984; EIA (December, 1985) adjusted to 

Continental U.S. coverage. 

D Process heat and feedstock uses. 

4-7 
TABLE 4-3. PROJECTIONS OF GAS PRICES: 

LOW OIL WITH FLEXIBLE MARKET 

($1985 per MMBtu) 

1986 1988 1990 1995 

GAS SUPPLY PRICES 

Marginal gas cost 1.30 1.41 1.95 3.03 

Avg. wellhead price 1.88 1.72 1.95 2.95 

INDUSTRIAL SECTOR FUEL PRICES 

Middle Atlantic 

Natural gas (Carriage) 2.45 2.34 2.54 3.62 

Natural gas (LDC sales) 3.56 3.04 3.32 4.47 

Residual oil (0.8% S) 3.33 2.49 2.70 3.71 

Southwest 

Natural gasa 2.18 2.15 2.34 3.34 

Residual oil (1.6% S) 3.22 2.23 2.42 3.34 

a Industrial and electric utility sectors predominantly served by direct 

sales of gas in intrastate carriage market. 

4-8 
FIGURE 2 

Federal Regions of the United States 

REGION NAMES 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 
P.39 

In the 1990-1995 period, the gas market tightens up and the surplus has 

ended. Wellhead prices in the carriage market begin to closely track natural 

gas wellhead prices in traditional sales markets. In this environment, the 

wellhead price of gas rises to provide sufficient incentive for producers to 

find and develop new reserves. Imports from Canada are increasing in the early 

1990's and, because they are priced competitively with U.S. suppliers, the 

imports help keep down the market price of gas. However, the market price of 

gas (i.e., marginal gas cost) is projected to nearly double in the 1988-1995 

period in order to elicit sufficient new supplies of gas to satisfy demand. 

Although the transmission and distribution costs in the carriage market 

are squeezed from $1.30-1.50 per MMBtu (traditional margins in interstate 

markets) to $0.45-0.60 per MMBtu, this is not enough to avoid significant 

natural gas load losses due to rising natural gas wellhead prices and the low 

oil prices. By the mid-90's, the traditional sales market for industrial users 

is limited to essentially high valued uses of natural gas. 

In this scenario, the industrial natural gas burnertip prices in the 

carriage market rise gradually up to match a moderately low sulfur oil price in 

the Mid- Atlantic while the traditional sales price starts near very low sulfur 

residual oil then rises substantially above the residual oil price structure in 

the 1990's. 

4.4 COMPARISONS OF GAS MARKET SCENARIOS 

In all of the scenarios examined in this study, the natural gas market is 

generally able to maintain a competitively priced position through the 1980's 

in relation to residual fuel oil prices in the industrial sector. As shown 

for the Low Oil/Flexible Market Case, natural gas prices remain depressed at 

the wellhead into the late 1980's while the current condition of excess gas 

supply persists. By 1990, the gas market is poised for the transition to a 

balance of supply and demand with gas prices rising at the wellhead to stimulate the exploration and development of new supplies. 

In the early 1990's, the evolution of the natural gas market begins to 

follow different tracks under the conditions of the three cases: 

§ In the Low Oil/Flexible Case, the industry is largely able to 

retain existing boiler markets. Gas pipelines and distributors 

cut margins to the bone to maintain competitiveness with medium and 

4-10 
P.40 

' low sulfur residual fuel oil in an era of rising gas prices. 

Rapidly increasing imports of gas from Canada help to temper the 

increase in U.S. wellhead prices and provide the supply for the gas 

market. 

• In the Low Oil/Rigid Case, gas suffers a sharp loss of boiler 

demand in the industrial/utility sectors, with delivered gas prices 

in the carriage market rising to the level of low-sulfur resid, as 

pipelines and distributors are less willing to discount their 

margins. With a slower increase in Canadian imports, U.S. production levels and wellhead prices for gas are comparable to the Low 

Oil/Flexible Case, but overall gas supply is reduced leading to a 

smaller market. 

• In the High Oil/Rigid Case, natural gas experiences significantly 

less market pressure from alternative fuels and can continue to be 

competitively priced to the industrial sector through 1995. 

Incentives for domestic exploration recover more quickly in pace 

with the oil price recovery, and the U.S. resource base is able to 

sustain essentially the current market through the mid-1990's 

without significant increases in imports or price discounting by gas 

pipelines and distributors. 

Key model results in the market trends for gas consumption, wellhead 

prices, and burnertip price competition are highlighted below. 

Gas Consumption 

Table 4-4 summarizes the major trends in gas consumption through 1995 for 

the three cases. Overall consumption of natural gas (hence the size of the 

gas market) is primarily the result of gas versus oil competition in the 

industrial and electric utility sectors. Residential and commercial gas use 

is projected to remain near current levels. 

Under both Low Oil cases, industrial and electric utility gas consumption 

declines during the late 1980's to a level of approximately 8.7 quads compared 

to 9.4 quads in 1984 and 9.0-9.2 quads in 1985.* This decline is consistent 

with two trends: 

• Gas losing small portions of the existing boiler market to high 

sulfur residual fuel oil; and 

• Gas losing potential markets in new boiler construction to residual 

fuel oil and long-term electric utility decisions favoring coal and 

nuclear energy. 

*Estimated based on preliminary 1985 EIA data published in the Natural Gas 

Monthly. 

4-11 
TABLE 4-4. PROJECTED TRENDS IN NATURAL GAS CONSUMPTION 

(Quadrillion Btu's) 

P.41 

1984 1990 1995 

Low oil with flexible market 

Residential/commercial 

Industrial/utility 

Other** 

Total consumption 

Low oil with market rigi 

Residential/commercial 

Industrial/utility 

Other** 

Total consumption 

High oil with market rig 

Residential/commercial 

Industrial/utility 

Other** 

Total consumption 

dity 

iditv 

7.2 

9.4 

LS 

18.2 

7.2 

9.4 

LS 

18.2 

7.2 

9.4 

1.6 

18.2 

7.0 

8.7 

1.4 

17.1 

7.0 

8.6 

1.4 

17.0 

7.1 

9.5 

1.5 

18.1 

6.8 

8.2 

1.2 

16.2 

6.8 

7.4 

1.2 

15.4 

6.9 

9.1 

1.4 

17.4 

Natural Gas Annual 1984, EIA (December 1985) adjusted to Continental 

U.S. coverage. 

** Includes pipeline fuel and plant/lease uses. 

4-12 
P.42 

, Beyond 1990, the gas market outlook differs significantly between the Low 

Oil cases: 

• With market flexibility, gas experiences a load loss of only 0.5 

quads during 1990-1995 consistent with continuation of the same 

long-term trends 

t Under the assumptions of the market rigidity case, gas loses 1.2 

quads in the industrial/utility sectors, with the incremental load 

loss occurring primarily in markets where gas must compete against 

high or medium sulfur residual fuel oil. 

In the High Oil case, natural gas is a low-priced fuel through 1990 

relative to residual fuel oil and competes well both in existing and new 

boiler markets. Through 1995, gas consumption in the industrial/utility 

sector remains below current levels. 

Gas Supply and Wellhead Prices 

The key trends for gas supply and wellhead prices are summarized in Table 

4-5. Under the Low Oil cases, domestic U.S. (Lower-48) natural gas production 

capacity falls significantly during the late 1980's under the outlook for 

continued low wellhead prices and contraction of exploration and development 

activity. Two trends are important in the 1985-1990 period for the Low Oil 

cases: 

• Canadian imports increase to approach the export levels (1.6 tcf) 

currently authorized by Canada's National Energy Board 

• Gas prices recover from the current distress levels of $1.30/MMBtu 

to the range of $1.90-1.95. 

The two Low Oil cases then diverge in the 1990-1995 time frame. The Low 

Oil/Flexible Market case assumes continued expansion in Canadian imports to 

reach levels of 2.2 quads by 1995, substantially beyond current export authori 

zations. By 1995, gas prices have risen sharply at the wellhead to the 

$3.00/MMBtu level to stimulate the domestic exploration and development 

activity needed to sustain Lower-48 production of 14.5 quads. However, the 

move by Canadian producers to expand U.S. sales eases pressures on the declining U.S. resource base which would occur in maintaining a total gas supply to 

16.5-17.0 quads. 

The other two cases follow very different tracks beyond 1990: 

4-13 
P.43 

TABLE 4-5. PROJECTED TRENDS IN GAS SUPPLY AND WELLHEAD PRICES 

1984 1990 1995 

Low oil with flexible market 

Gas supply (quads) 

Lower-48 production 

Imports/supplementals 

Total supply 

Marginal gas cost (1985 $/MMBtu) 

Low oil with market rigidity 

Gas supply (quads) 

Lower-48 production 

Imports/supplemental s 

Total supply 

Marginal gas cost (1985 $/MMBtu) 

High oil with market rigidity 

Gas supply (quads) 

Lower-48 production 

Imports/suppl emental s 

Total supply 

Marginal gas cost (1985 $/MMBtu) 

17.4 

1.0 

18.4 

2.80 

16.1 

1.5 

17.6 

1.95 

14.5 

2.2 

16.7 

3.03 

17.4 

1.0 

18.4 

2.80 

16.0 

1.5 

17.5 

1.90 

14.2 

1.7 

15.9 

2.95 

17.4 

1.0 

18.4 

2.80 

17.1 

1.5 

18.6 

2.75 

15.9 

1.9 

17.8 

4.03 

Natural Gas Annual 1984, EIA (December 1985) adjusted to Continental 

U.S. coverage. 

4-14 
P.44 

>• In the Low Oil/Rigid case, imports do not expand significantly 

during 1990-1995. Lower-48 production and prices are comparable to 

the flexible low case, but provide for a total gas supply below 

16.0 quads. 

• In the High Oil case, Lower-48 production levels are higher throughout the 1985-1995 period leading to a more rapid recovery of gas 

prices and the ability to sustain domestic production of 16 quads or 

more into the mid-1990's. 

Burnertip Gas Prices 

The major trends in industrial burnertip prices between oil and gas are 

illustrated in Table 4-6 using the Middle Atlantic as an example of a regional 

market. 

In the Low Oil cases, 0.8 percent sulfur residual fuel oil is priced to 

industrial customers at $2.70/MMBtu in 1990 and $3.71/MMBtu in 1995. As shown, 

natural gas prices in the carriage market are: 

• Competitive with residual fuel oil in the Flexible Market case 

through 1995 

• At parity with resid in 1990 in the Rigid Market case and priced 

above resid in 1995. 

Gas distribution company sales rates to industrial customers are significantly higher than 0.8 percent sulfur residual fuel oil prices in both cases. 

Since gas wellhead prices during the period 1990-1995 were not significantly different between the Flexible and Rigid cases, these differences in 

burnertip (delivered) prices are a result of underlying assumptions on discounting of transmission and distribution (T&D) costs: 

• In the Flexible case, pipelines would heavily discount carriage 

market transport margins if necessary to compete with oil. For 

1995, the Mid-Atlantic carriage price is essentially a $3.00/MMBtu 

wellhead price plus a $0.60 total T&D margin. The transmission 

component accounts for approximately $0.35 with distribution (and 

sales taxes) the remaining $0.25. 

• In the Rigid case, pipelines are assumed not to fully discount 

in this manner. The $3.81/MMBtu delivered carriage price is thus 

composed of roughly $3.00 for wellhead gas costs plus $0.55 for 

transmission and $0.25 for distribution and taxes. 

Industrial sales prices offered by local gas distribution companies 

(LDC's) reflect the continuation of the traditional utility rate structures in 

the gas industry prior to FERC Order 436. Burnertip gas prices to industrial 

4-15 
P.45 

TABLE 4-6. PROJECTED TRENDS IN INDUSTRIAL BURNERTIP 

PRICES IN THE MIDDLE ATLANTIC REGION 

(1985 $/MMBtu) 

1990 1995 

2.70 

2.54 

3.32 

3.71 

3.62 

4.47 

Low oil with flexible market 

0.8% S residual oil 

Carriage market gas price 

LDC sales price 

Low oil with market rigidity 

0.8% S residual oil 2.70 3.71 

Carriage market gas price 2.73 3.81 

LDC sales price 3.30 4.53 

High oil with market rigidity 

0.8% S residual oil 

Carriage market gas price 

LDC sales price 

4.39 

4.18 

4.61 

4.96 

4.74 

5.91 

4-16 
customers of LDC's are much higher than in the carriage market due to the 

higher T&D margins -- e.g., a $0.70-$1.10 transmission margin and $0.40-$0.80 

distribution margin. These higher margins: 

• Fully recover the costs of the transmission costs authorized in 

FERC rate-setting procedures. 

• Are applicable only to segments of the industrial sector (primarily 

high valued uses and applications not switchable to oil) which do 

not gain access to carriage. 

Thus, the degree of pipeline willingness to discount transmission margins on 

carriage transactions becomes a crucial factor in gas versus oil competition 

under low oil prices. 

The High Oil/Rigid scenario reflects a competitive outcome for gas which 

is very similar to the Low Oil/Flexible case, although the overall price 

levels for gas and oil are significantly higher. Gas can be delivered to the 

industrial sector at competitive prices without full flexibility in carriage 

discounting because: 

• Higher demand levels decrease the unit costs of operating pipeline 

and distribution systems, and 

• Higher oil prices decrease the alternate fuel netback pressures on 

gas wellhead costs, providing more "room" for recovery of T&D 

margins. 

4-17 
P.47 

APPENDIX A 

REGIONAL INDUSTRIAL OIL AND GAS 

PRICE FORECASTS FOR THE LOW 

OIL PRICE SCENARIO 

(SUMMER 1986) 
P.48 

LIST OF TABLES 

TABLE NO. TITLE 

A-1 CRUDE OIL PRICE FORECAST 

A-2 INDUSTRIAL 3.0% SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS 

A-3 INDUSTRIAL 1.6% SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS 

A-4 INDUSTRIAL 0.8% SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS 

A-5 INDUSTRIAL 0.3% SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS 

A-6 INDUSTRIAL DISTILLATE FUEL OIL PRICE PROJECTIONS 

A-7 INDUSTRIAL NATURAL GAS PRICE PROJECTIONS: CARRIAGE MARKET 

ESTIMATES ASSUMING FLEXIBLE CARRIAGE MARKET 

A-8 INDUSTRIAL NATURAL GAS PRICE PROJECTIONS: NON-CARRIAGE 

MARKET ESTIMATES ASSUMING FLEXIBLE CARRIAGE MARKET 

A-9 INDUSTRIAL NATURAL GAS PRICE PROJECTIONS: CARRIAGE MARKET 

ESTIMATES ASSUMING MARKET RIGIDITY 

A-10 INDUSTRIAL NATURAL GAS PRICE PROJECTIONS: NON-CARRIAGE 

MARKET ESTIMATES ASSUMING MARKET RIGIDITY 
P.49 

TABLE A-1. CRUDE OIL PRICE FORECAST* 

Average Refiner Acquisition 

Cost of Crude Oil 

Year (1985 $/bbl, 

1985 (actual) 26.76 

1988 13.34 

1990 14.47 

1995 20.08 

2000 24.61 

2005 30.79 

Energy and Environmental Analysis, Inc. 

A-1 
TABLE A-2. INDUSTRIAL 3.0% 

SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS* 

(1985 $/MMBta) 

P.50 

Federal region 1985** 1988 1990 1995 2000 2005 

1. New England 4.25 2.15 2.34 3.29 4.06 5.10 

2. New York/New Jersey 4.18 2.09 2.28 3.23 4.00 5.04 

3. Middle Atlantic 4.18 2.09 2.28 3.23 4.00 5.04 

4. South Atlantic 4.16 2.07 2.26 3.21 3.97 5.02 

5. Midwest 4.33 2.24 2.43 3.38 4.14 5.19 

6. Southwest 4.14 2.05 2.24 3.19 3.95 5.00 

7. Central 4.30 2.21 2.40 3.34 4.11 5.15 

8. North Central 4.24 2.16 2.35 3.31 4.08 5.14 

9. West 4.06 2.05 2.24 3.16 3.91 4.94 

10. Northwest 4.01 2.01 2.19 3.12 3.87 4.89 

*Energy and Environmental Analysis, Inc. 

**Estimate, not actual. 

A-2 
TABLE A-3. INDUSTRIAL 1.6% 

SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS* 

(1985 $/MMBtu) 

P.51 

Federal region 1985** 1988 1990 1995 2000 2005 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

4.46 2.33 2.52 3.48 4.26 5.32 

4.40 2.27 2.46 3.43 4.21 5.26 

4.40 2.27 2.46 3.43 4.21 5.26 

4.37 2.25 2.44 3.41 4.18 5.24 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

4.54 2.42 2.61 3.57 4.35 5.41 

4.35 2.23 2.42 3.38 4.16 5.22 

4.51 2.39 2.57 3.53 4.32 5.37 

4.46 2.33 2.52 3.49 4.28 5.35 

9. West 4.28 2.22 2.41 3.34 4.11 5.15 

10. Northwest 4.24 2.18 2.37 3.30 4.07 5.11 

*Energy and Environmental Analysis, Inc. 

**Estimate, not actual. 

A-3 
TABLE A-4. INDUSTRIAL 0.8% 

SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS* 

(1985 $/MMBtu) 

P.52 

Federal region 1985** 1988 1990 1995 2000 2005 

1. New England 4.80 2.56 2.76 3.77 4.59 5.70 

2. New York/New Jersey 4.74 2.49 2.70 3.71 4.52 5.64 

3. Middle Atlantic 4.74 2.49 2.70 3.71 4.52 5.64 

4. South Atlantic 4.72 2.47 2.68 3.69 4.50 5.61 

5. Midwest 

6. Southwest 

7. Central 

4.89 2.64 2.85 3.86 4.67 5.78 

4.70 2.45 2.66 3.67 4.48 5.60 

4.86 2.61 2.81 3.82 4.64 5.75 

8. North Central 4.80 2.53 2.73 3.73 4.55 5.66 

9. West 4.64 2.43 2.63 3.61 4.40 5.49 

10. Northwest , 4.60 2.39 2.58 3.57 4.36 5.45 

*Energy and Environmental Analysis, Inc. 

**Estimate, not actual. 

A-4 
P.53 

TABLE A-5. INDUSTRIAL 0.3% 

SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS* 

(1985 $/MMBtu) 

Federal region 1985** 1988 1990 1995 2000 2005 

1. New England 5.04 2.68 2.88 3.92 4.75 5.89 

2. New York/New Jersey 4.98 2.61 2.82 3.86 4.69 5.83 

3. Middle Atlantic 4.98 2.61 2.82 3.86 4.69 5.83 

4. South Atlantic 4.95 2.59 2.80 3.83 4.67 5.81 

5. Midwest 5.13 2.76 2.97 4.01 4.84 5.98 

6. Southwest 4.93 2.57 2.78 3.81 4.65 5.79 

7. Central 5.09 2.73 2.93 3.97 4.81 5.94 

8. North Central 5.06 2.64 2.85 3.89 4.72 5.85 

9. West 4.88 2.53 2.74 3.74 4.55 5.65 

10. Northwest 4.84 2.49 2.69 3.70 4.51 5.61 

*Energy and Environmental Analysis, Inc. 

**Estimate, not actual. 

A-5 
P.54 

TABLE A-6. INDUSTRIAL 

DISTILLATE FUEL OIL PRICE PROJECTIONS* 

(1985 $/MMBtu) 

Federal region 1985** 1988 1990 1995 2000 2005 

1. New England 6.17 3.16 3.38 4.61 5.60 6.96 

2. New York/New Jersey 6.15 3.13 3.36 4.59 5.58 6.94 

3. Middle Atlantic 6.15 3.13 3.36 4.59 5.58 6.94 

4. South Atlantic 6.03 3.05 3.27 4.49 5.47 6.80 

5. 

6. 

7. 

8. 

9. 

10. 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

5.98 3.02 3.24 4.45 5.42 6.75 

5.85 2.89 3.11 4.32 5.30 6.63 

5.98 3.02 3.24 4.44 5.42 6.75 

5.65 2.82 3.01 4.21 5.19 6.42 

5.46 2.72 2.91 4.16 5.01 6.21 

5.39 2.72 2.91 4.10 4.94 6.13 

*Energy and Environmental Analysis, Inc. 

**Estimate, not actual. 

A-6 
TABLE A-7. INDUSTRIAL NATURAL 

GAS PRICE PROJECTIONS: CARRIAGE MARKET ESTIMATES 

ASSUMING FLEXIBLE CARRIAGE MARKET* 

(1985 $/MMBtu) 

Federal region 1988 1990 1995 2000 2005 

1. New England 2.41 2.60 3.62 4.37 5.45 

2. New York/New Jersey 2.49 2.70 3.71 4.52 5.64 

3. Middle Atlantic 2.34 2.54 3.62 4.33 5.39 

4. South Atlantic 2.17 2.51 3.62 4.33 5.36 

5. Midwest 2.49 2.69 3.67 4.46 5.54 

6. Southwest 2.15 2.34 3.34 4.14 5.16 

7. Central 

8. North Central 

9. West 

2.31 2.51 3.62 4.33 5.36 

2.38 2.60 3.62 4.38 5.46 

2.43 2.63 3.62 4.40 5.49 

10. Northwest 2.21 2.51 3.62 4.33 5.36 

Energy and Environmental Analysis, Inc. 

A-7 
TABLE A-8. INDUSTRIAL NATURAL 

GAS PRICE PROJECTIONS: NON-CARRIAGE MARKET ESTIMATES 

ASSUMING FLEXIBLE CARRIAGE MARKET* 

(1985 $/MMBtu) 

Federal region 1988 1990 1995 2000 2005 

1. New England 3.23 3.63 4.58 5.39 6.42 

2. New York/New Jersey 3.70 3.91 4.49 5.30 6.32 

3. Middle Atlantic 3.04 3.32 4.47 5.28 6.30 

4. South Atlantic 3.05 3.29 4.59 5.46 6.55 

5. 

6. 

7. 

8. 

9. 

10. 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

2.98 3.26 4.41 5.23 6.27 

2.15 2.34 3.34 4.14 5.16 

2.71 2.96 4.23 5.01 5.99 

2.53 2.73 3.63 4.32 5.21 

2.62 3.00 4.11 4.89 5.88 

2.42 2.75 3.90 4.74 5.82 

Energy and Environmental Analysis, Inc. 

Equivalent to carriage rate for intrastate markets, 

A-8 
P.57 

TABLE A-9. INDUSTRIAL NATURAL GAS 

PRICE PROJECTIONS: CARRIAGE MARKET ESTIMATES 

ASSUMING MARKET RIGIDITY* 

(1985 $/MMBtu) 

Federal region 1988 1990 1995 2000 2005 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 

2.41 2.78 3.89 4.70 5.87 

2.49 2.74 3.84 4.65 5.81 

2.34 2.73 3.81 4.63 5.79 

2.18 2.67 3.78 4.59 5.76 

2.49 2.73 3.77 4.58 5.75 

2.15 2.34 3.46 4.19 5.36 

2.31 2.61 3.69 4.51 5.67 

2.38 2.61 3.60 4.41 5.57 

2.43 2.63 3.62 4.43 5.60 

2.21 2.50 3.54 4.35 5.51 

Energy and Environmental Analysis, Inc. 

A-9 
P.58 

TABLE A-10. INDUSTRIAL NATURAL GAS 

PROJECTIONS: NON-CARRIAGE MARKET ESTIMATES 

ASSUMING MARKET RIGIDITY* 

(1985 $/MMBtu) 

Federal region 1988 1990 1995 2000 2005 

1. New England 3.23 3.75 4.76 5.50 6.67 

2. New York/New Jersey 3.20 3.69 4.55 5.28 6.44 

3. Middle Atlantic 3.04 3.30 4.53 5.27 6.43 

4. South Atlantic 3.05 3.27 4.59 5.37 6.61 

5. Midwest 2.98 3.23 4.42 5.16 6.34 

6. Southwest ** 2.15 2.34 3.46 4.19 5.36 

7. Central 

8. North Central 

9. West 

10. Northwest 

2.71 2.93 4.21 4.90 6.02 

2.53 2.73 3.63 4.26 5.26 

2.60 2.87 3.97 4.66 5.77 

2.42 2.67 3.95 4.70 5.91 

Energy and Environmental Analysis, Inc. 

Equivalent to carriage rate for intrastate markets. 

** 

A-10 
P.59 

APPENDIX B 

REGIONAL INDUSTRIAL OIL AND GAS 

PRICE FORECASTS FOR THE HIGH 

OIL PRICE SCENARIO 

(SUMMER 1986) 
. LIST OF TABLES 

TABLE NO. TITLE 

B-l CRUDE OIL PRICE FORECAST 

B-2 INDUSTRIAL 3.0% SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS 

B-3 INDUSTRIAL 1.6% SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS 

B-4 INDUSTRIAL 0.8% SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS 

B-5 INDUSTRIAL 0.3% SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS 

B-6 INDUSTRIAL DISTILLATE FUEL OIL PRICE PROJECTIONS 

B-7 INDUSTRIAL NATURAL GAS PRICE PROJECTIONS: CARRIAGE MARKET 

ESTIMATES 

B-8 INDUSTRIAL NATURAL GAS PRICE PROJECTIONS: NON-CARRIAGE 

MARKET ESTIMATES 
P.61 

I 

1 

1 

I 

1 

1 

TABLE B-l. CRUDE OIL PRICE FORECAST* 

Average Refiner Acquisition 

Cost of Crude Oil 

Year (1985 $/bbl) 

1985 (actual) 26.76 

1987 20.13 

1990 23.87 

1995 27.02 

2000 30.61 

2005 37.42 

'Energy and Environmental Analysis, Inc. 

B-l 
TABLE B-2. INDUSTRIAL 3.0% 

SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS* 

(1985 $/MMBtu) 

Federal region 1985** 1987 1990 1995 2000 2005 

1. New England 4.25 3.30 3.93 4.46 5.07 6.22 

2. New York/New Jersey 4.18 3.24 3.87 4.40 5.01 6.16 

3. Middle Atlantic 4.18 3.24 3.87 4.40 5.01 6.16 

4. South Atlantic 4.16 3.22 3.85 4.38 4.99 6.14 

5. Midwest 4.33 3.39 4.02 4.55 5.16 6.31 

6. Southwest 4.14 3.20 3.83 4.36 4.97 6.12 

7. Central 4.30 3.35 3.99 4.52 5.12 6.27 

8. North Central 4.24 3.32 3.96 4.50 5.11 6.27 

9. West 4.06 3.17 3.79 4.31 4.91 6.03 

10. Northwest 4.01 3.13 3.75 4.27 4.86 5.98 

*Energy and Environmental Analysis, Inc. 

**Estimate, not actual. 

B-2 
P.63 

» , 

TABLE B-3. INDUSTRIAL 1.6% 

SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS* 

(1985 $/MMBtu) 

Federal region 1985** 1987 1990 1995 2000 2005 

1. New England 4.46 3.50 4.14 4.67 5.29 6.47 

2. New York/New Jersey 4.40 3.44 4.08 4.61 5.23 6.41 

3. Middle Atlantic 4.40 3.44 4.08 4.61 5.23 6.41 

4. South Atlantic 4.37 3.42 4.06 4.59 5.21 6.39 

5. Midwest 4.54 3.59 4.23 4.76 5.38 6.56 

6. Southwest 4.35 3.40 4.04 4.57 5.19 6.37 

7. Central 4.51 3.55 4.20 4.73 5.34 6.52 

8. North Central 4.46 3.52 4.17 4.71 5.33 6.52 

9. West 4.28 3.37 4.00 4.52 5.13 6.28 

10. Northwest 4.24 3.33 3.96 4.47 5.08 6.24 

*Energy and Environmental Analysis, Inc. 

**Estimate, not actual. 

B-3 
P.64 

• i 

TABLE B-4. 

SULFUR RESIDUAL FUEL 

Federal region 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

*En 

**£ 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

ergy and Environmental 

stimate, not actual. 

INDUSTRIAL 0.8% 

OIL PRICE PROJECTIONS* 

(1985 $/MMBtu) 

1985** 

4.80 

4.74 

4.74 

4.72 

4.89 

4.70 

4.86 

4.80 

4.64 

4.60 

Analysis, 

1987 

3.78 

3.72 

3.72 

3.70 

3.87 

3.68 

3.83 

3.74 

3.62 

3.58 

Inc. 

B-4 

1990 

4.45 

4.39 

4.39 

4.37 

4.54 

4.35 

4.51 

4.41 

4.27 

4.23 

1995 

5.02 

4.96 

4.96 

4.93 

5.10 

4.92 

5.07 

4.98 

4.83 

4.78 

2000 

5.67 

5.60 

5.60 

5.58 

5.75 

5.56 

5.72 

5.63 

5.46 

5.41 

2005 

6.98 

6.83 

6.83 

6.81 

6.98 

6.79 

6.94 

6.85 

6.65 

6.61 
P.65 

\ m 

1 1 

i 

, 

TABLE B-5. INDUSTRIAL 0.3% 

SULFUR RESIDUAL FUEL OIL PRICE PROJECTIONS* 

Federal region 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

(1985 $/MMBtu) 

1985** 

5.04 

4.98 

4.98 

4.95 

5.13 

4.93 

5.09 

5.06 

4.88 

4.84 

1987 

3.93 

3.87 

3.87 

3.84 

4.02 

3.82 

3.98 

3.90 

3.75 

3.71 

1990 

4.62 

4.55 

4.55 

4.53 

4.70 

4.51 

4.67 

4.58 

4.42 

4.37 

1995 

5.20 

5.14 

5.14 

5.11 

5.28 

5.09 

5.25 

5.16 

4.98 

4.94 

2000 

5.86 

5.80 

5.80 

5.77 

5.95 

5.75 

5.91 

5.83 

5.63 

5.58 

2005 

7.12 

7.05 

7.05 

7.03 

7.20 

7.01 

7.17 

7.08 

6.84 

6.80 

*Energy and Environmental Analysis, Inc. 

**Estimate, not actual. 

B-5 
TABLE B-6. INDUSTRIAL DISTILLATE 

FUEL OIL PRICE PROJECTIONS* 

(1985 $/MMBtu) 

Federal region 1985** 1987 1990 1995 2000 2005 

1. New England 6.17 4.66 5.44 6.13 6.92 8.41 

2. New York/New Jersey 6.15 4.63 5.42 6.11 6.90 8.39 

3. Middle Atlantic 6.15 4.63 5.42 6.11 6.90 8.39 

4. South Atlantic 6.03 4.53 5.31 5.99 6.76 8.24 

5. Midwest 5.98 4.49 5.26 5.94 6.71 8.18 

6. Southwest 5.85 4.37 5.14 5.81 6.59 8.05 

7. Central 5.98 4.49 5.26 5.94 6.71 8.18 

8. North Central 5.65 4.16 4.93 5.61 6.38 7.85 

9. West 5.46 4.01 4.76 5.42 6.17 7.60 

10. Northwest 5.39 3.94 4.69 5.35 6.10 7.52 

*Energy and Environmental Analysis, Inc. 

**Estimate, not actual. 

B-6 
P.67 

TABLE B-7. INDUSTRIAL NATURAL GAS 

PRICE PROJECTIONS: CARRIAGE MARKET ESTIMATES' 

(1985 $/MMBtu) 

Federal region 1987 1990 1995 2000 2005 

1. New England 3.59 4.25 4.79 5.42 6.61 

2. New York/New Jersey 3.72 4.39 4.96 5.60 6.68 

3. Middle Atlantic 3.27 4.18 4.74 5.36 6.54 

4. South Atlantic 2.95 3.95 4.68 5.30 6.44 

5. 

6. 

7. 

8. 

9. 

10. 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

3.09 4.30 4.88 5.51 6.69 

2.28 3.44 4.43 5.06 6.22 

2.84 4.03 4.63 5.25 6.39 

2.53 3.78 4.80 5.43 6.63 

2.89 4.18 4.83 5.46 6.65 

2.33 3.58 4.57 5.19 6.35 

Energy and Environmental Analysis, Inc. 

B-7 
P.68 

TABLE B-8. INDUSTRIAL NATURAL GAS 

PRICE PROJECTIONS: NON-CARRIAGE MARKET ESTIMATES" 

(1985 $/MMBtu) 

Federal region 1987 1990 1995 2000 2005 

1. New England 

2. New York/New Jersey 

3.78 5.29 6.52 7.10 8.18 

3.87 5.11 6.32 6.91 7.99 

3. Middle Atlantic 3.71 4.61 5.91 6.50 7.60 

4. South Atlantic 3.32 4.41 5.81 6.45 7.63 

5. Midwest 3.51 4.43 5.74 6.34 7.45 

6. Southwest * 2.28 3.44 4.43 5.06 6.22 

7. Central 

8. North Central 

9. West 

3.17 3.98 5.21 5.78 6.84 

2.77 3.41 4.39 4.91 5.87 

3.17 4.01 5.14 5.71 6.77 

10. Northwest 2.87 3.59 4.83 5.46 6.64 

Energy and Environmental Analysis, Inc. 

* Equivalent to carriage rate for intrastate market. 

B-8