P.1 

OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

104) IV-K-(A)-2 

Docket Number: 

A-83-27 

Printed 12/3/2008 9:15:33 AM Sheet 104 of 105 
P.2 

A 

e^ci^ 

-f ^ 

/ • 

IV-K-(A)-2 

ANALYSIS OF THE 

RESPONSE OF COAL PRICES 

TO LOWER OIL PRICES 

Prepared for: 

Energy & Environmental Analysis, Inc. 

Arlington, Virginia 

and 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Durham, North Carolina 

1986 

FIELDSTON COMPANY 1133 15lh Street N.W., Suite 1000, Washington, D.C. 20005 1202) 775-0240 
Section 

I. 

II. 

III. 

IV. 

V. 

VI. 

VII. 

TABLE OF CONTENTS 

Title 

Executive Summary 

Purpose 

Scope 

Methodology, Assumptions and Caveats 

New England Market Analysis 

South Atlantic Market Analysis 

Gulf Coast Market Analysis 

Paee 

1 

2 

3 

3 

14 

20 

28 
P.4 

I. Executive Summary 

This study tests the hypothesis that delivered coal costs cannot decline 

sufficiently in the 1990-1995 time frame to make coal competitive with oil or 

natural gas in new industrial boilers. The hypothesis was examined in three 

sample markets where interfuel competition has been at least partially responsible 

for reductions in delivered coal prices. These three markets were New England, 

the South Atlantic, and the Gulf Coast. 

Since data on delivered fuel prices to utilities are available through 

government filings while industrial prices are generally not, much of this analysis 

addresses changes in delivered coal prices to utilities in the selected markets. 

These results are then discussed relative to possible changes in industrial coal 

prices. The analysis is not meant to cover all regions and coal types. It is 

simply intended as a quick test, using case studies, of the proven downward 

flexibility of coal prices in recent months in responding to interfuel competition. 

Conclusion: Despite the recent decline in delivered coal prices, it does not 

appear that in the markets examined, the delivered price of industrial coal in 1985 

dollars would fall $3/MMBtu or more below the delivered prices of 1.6% resid or 

natural gas (based upon EEA price predictions shown below) in the 1990-1995 time 

frame. Consequently, in these markets, it is unlikely that the model being used 

to predict the fuel choice for new industrial boilers will select coal. The results 

of this analysis cannot necessarily be extended to industries which because of 

their proximity to the coal fields will experience lower delivered coal prices. In 

fact, coal will probably be selected as a boiler fuel in certain of these site 

specific cases. 

1985 

4.46 

4.37 

1987 

3.50 

3.42 

2.28 

High Oil Price Scenario 

Delivered Price 

1985 $/MMBtu 

1990 

4.14 

4.06 

3.44 

199? 

4.67 

4.59 

4.43 

2000 

5.29 

5.21 

5.06 

MARKET (Region) FUEL 

New England(l) 1.6% Resid 

South Atlantic(4) 1.6% Resid 

Southwest(6) Natural Gas 

Findings: In 1985-1986, many delivered utility coal prices in the markets tested 

have declined substantially (20-25%) from peak levels reached in the early 1980's. 

While these price declines are not universal, they do appear to be widespread and 

to affect the prices of coals delivered either in the spot market or under 

contracts which because of their duration or terms are responsive to market 

prices. These price declines are not due solely to interfuel competition, although 

that competition has affected prices. 

The main cause of depressed coal prices has been a market imbalance where 

coal supplies have greatly exceeded demand. This has forced coal prices down, 
P.5 

resulting in higher cost mines and producers, not protected by long term 

contracts, being forced out of the market place, and in some coals being sold at 

prices which do not reflect their full costs of production. In addition, coal 

transportation prices have generally been reduced where competition has been a 

factor and where transportation contracts have been signed. 

With the recent decline of oil prices into the $10-$12/barrel range, some 

utilities which either directly or through power pooling arrangements have 

competing coal, oil or gas-fired generation, have dispatched oil and gas-fired units 

ahead of coal-fired ones. Coal producers and transporters have been able to 

respond to this interfuel competition through further reductions in delivered coal 

prices with mixed success. Some of these competitive markets have experienced 

the most dramatic declines in coal prices. 

Because the time period over which this recent interfuel competition has been 

active is brief, and because of the multitude of factors which caused coal prices 

to decline, it is difficult to predict whether reduced delivered coal prices can be 

sustained over an extended time period. While excess production capacity 

certainly acted as a depressant on coal prices, structural changes in the coal 

industry and dramatic improvements in productivity in recent years imply that 

some lower level of coal prices is sustainable. It is unlikely that coal prices will 

increase to follow the predicted rise in oil and natural gas prices. These markets 

are driven by very different factors. While coal must compete with oil and gas in 

existing facilities in a "depressed" market for oil and gas, the same relationship 

need not hold in a market where oil and gas prices substantially exceed coal 

prices. 

Industrial coal prices will generally be higher than utility coal prices in part 

because of coal quality requirements. Coal for industrial stoker-fired boilers 

requires additional sizing and preparation. In addition, a premium is generally 

demanded for the smaller transaction sizes. Transportation costs are also 

generally higher for industrial coal users because they are unable to take 

advantage of reduced rates for unit train or trainload size shipments which are 

available to most utilities. 

In markets which are closer to the coal fields, and where oil and natural gas 

are more expensive, it is unclear how the decline in delivered coal prices will 

affect the economics of fuel choice in new industrial boilers. As transportation 

costs decline and delivered coal costs approach fob mine prices in specific cases, 

coal should be competitive. 

II. Purpose 

This forecast is designed to test the hypothesis that delivered coal costs 

cannot decline sufficiently in the foreseeable future to make coal competitive with 

oil or gas in new industrial boilers. Generally, new industrial boilers would 

therefore be expected to burn oil or gas if allowed. In other words, coal prices 

while flexible downward (both fob mine and transportation) are unlikely to fall 

sufficiently to be able to displace oil and gas in major industrial markets in the 

1990-1995 time frame. 
P.6 

III. Scope 

The analysis tested three example markets to determine how coal prices on a 

delivered basis have been able to compete against oil and gas. The markets 

tested included New England, the South Atlantic, and the Gulf Coast. The 

analysis uses these example markets to test the hypothesis regarding whether coal 

prices have been able to decline sufficiently to compete with oil and gas in 

industrial markets. The scope did not include comprehensive forecasts of coal 

prices for all regions and sulfur contents. 

IV. Methodology, Assumptions and Caveats 

The analysis was conducted following the methodology and using the 

assumptions and caveats described below. Where assumptions were required, we 

generally tried to take the position that if the assumption was incorrect, the 

result will be even higher delivered coal prices. Since the hypothesis being tested 

is that coal prices cannot decline sufficiently in the foreseeable future to make 

them competitive with oil or gas in a new industrial boiler, use of alternative 

assumptions which are even less favorable to industrial coal would only strengthen 

the conclusion. 

Methodology 

1. Identification of three test regions: In conjunction with Energy and 

Environmental Analysis, Inc. (EEA), it was decided to test the relationship 

between delivered coal prices and oil or gas prices in New England, the South 

Atlantic, and the Gulf Coast. These regions were selected because they are areas 

where delivered coal prices are likely to experience the greatest competition from 

oil or natural gas. New England and Florida utilities have ready access to 

imported oil and have oil-fired generation capacity. Utilities in the Gulf Coast 

have substantial gas-fired generation capacity. 

2. Identification of sample utilities and plants: Data on delivered fuel prices to 

utility plants within these three regions were examined to identify cases where it 

appeared that declining prices for oil or gas may have forced declines in delivered 

coal prices. In general, we were seeking cases where the data indicated that coal 

producers and transporters may have been required to drop their prices in order 

to preserve their markets. These situations, we hypothesized, were likely to 

provide some indication of the extent to which coal and coal transportation prices 

would be downward flexible. 

Several utilities have clearly used the recent decline in oil and gas prices to 

back out coal, or force reductions in delivered coal prices. These include New 

England Electric System and New Hampshire Public Service Company in New 

England; Florida Power Corp. in the South Atlantic; and Lower Colorado River 

Authority, the City of San Antonio Public Service, and Central Power & Light Co. 

in the Gulf Coast. In all of these cases, coal markets have been threatened by 

declining oil or gas prices. 
P.7 

3.' Identification of Utility and Industrial Coal Supply Sources: For each of the 

sample utilities identified, the coal source regions were identified. Instructions 

from EEA indicated that, because of the form of the industrial New Source 

Performance Standard being considered, the industrial coal should be sourced 

without regard to sulfur content. Consequently, we assumed that potential 

industrial coal users would seek to minimize delivered costs of coal in cents per 

MMBtu. 

In New England, this meant that industrial coal users would probably seek to 

originate coal in Pennsylvania or northern West Virginia. This is the area from 

which some of the sample utility coals originate. 

In Florida, utility coals are delivered either by rail or barge. Most industrial 

coal is currently delivered by rail. Depending upon transportation considerations, 

the coals could be sourced in central Appalachia, or the Illinois Basin. We 

assumed rail delivery for industrial coal shipments to Florida, and therefore 

sourced the coals from central Appalachia. 

In the Gulf Coast, coal sourcing is a difficult issue. Utilities generally source 

coal from the Powder River Basin in Montana and Wyoming, or use Texas lignite. 

However, most industrial coal users are likely to source coal from different supply 

regions including Oklahoma, New Mexico and Colorado. This methodological 

anomaly was addressed by considering one utility which does purchase Colorado 

coal, and other information regarding fob mine prices and production costs for 

coals from Colorado, New Mexico and Oklahoma, and transportation prices and 

costs. 

4. Identification Of Utility and Industrial Coal Transportation Routings: For each 

of the coal sources and utility combinations, an assumed transportation routing 

was developed. In New England and Florida, the industrial and utility coal 

sources and transportation routings were matched closely enough to draw some 

conclusions about the likely responses in the industrial coal market from the 

changes in the utility market. In these cases, it was easier to draw analogies 

between the responsiveness of the railroads in adjusting to interfuel competition 

than in the Gulf Coast where most of the coal sources and transportation routings 

differed. 

5. Application of Changes in Utility Prices to Industrial Coal Prices: Drawing 

upon the experience of utilities in being able to obtain lower delivered coal 

prices, in part, by taking advantage of interfuel competition, this experience was 

then applied to the industrial sector. The logic is that an industry planning a 

new boiler and considering coal or another fuel should be able to exert some 

leverage to obtain reduced delivered coal prices. The caveats on this type of 

analysis are numerous. An existing utility and an industry planning a new boiler 

are in very different positions. It is questionable whether an industrial customer 

utilizing much lower coal volumes than a utility would be able to exert sufficient 

leverage to obtain the same concessions as a utility. However, by assuming that 

the industry achieves similar price reductions, we would be likely to understate 

delivered industrial coal prices and thereby maximize the likelihood of industrial 

coal penetration. If under these assumptions, new coal-fired boilers are not 

projected to be built in the markets being examined, the hypothesis would appear 

to be strongly supported (ie. that coal prices cannot decline sufficiently even 

under a high oil price scenario in these markets to result in construction of new 

industrial coal-fired boilers.) 
P.8 

6. Future Price Trend Analysis: The results obtained in the previous analyses 

are extrapolated into the 1990-1995 time period to determine whether industrial 

coal penetration might occur in that period. The question of whether the reduced 

coal prices which are apparent in mid-1986 could be expected to be sustained into 

the future is a complex one. We assume that they can be sustained which 

probably understates long term coal prices (see assumption on "Future Coal Price 

Trends"). Coal prices fob mine are held constant in real terms while 

transportation prices are assumed to increase by 1%/year or less in constant 

dollars. This is based upon assumed cost increases in labor, materials and 

supplies, and the EEA diesel fuel prices. 

7. Comparison of 1986 Utility Delivered Coal Prices to Industrial Gas and Oil 

Forecast Prices: The projected future utility coal prices were then compared with 

the delivered industrial oil or gas prices to see if the $3/MMBtu threshold criteria 

were met in the 1990-1995 time frame. If not, then industrial coal prices are 

clearly non-competitive for a similarly situated industrial consumer who would be 

paying higher delivered coal prices. 

8. Adjustment of Utility Prices to Industrial Prices: For coal production costs, 

some adjustments were made to account for the likelihood that industrial coal 

would cost more fob mine than utility coal purchases due to special screening and 

cleaning requirements, and the higher costs associated with handling smaller 

volumes. Approximately $.20/MMBtu was assumed. By examining the relationship 

between actual transportation rates for unit train and single car movements, some 

adjustments were made to convert utility transportation prices into industrial 

equivalents. 

9. Estimation of Full and Variable Coal Production and Transportation Costs: 

For each of the source and transportation combinations, full and variable coal 

production and coal transportation costs were estimated. The purpose of this 

analysis was to determine the degree to which coal transporters and producers 

could reduce prices and still cover their variable costs of production or 

transportation. It was also intended to reflect how current prices might compare 

with the producers' and transporters' underlying cost structures. 

Variable coal production costs were defined to include out-of-pocket costs such 

as mine labor, materials and supplies, haulage, taxes, and royalties. This is a 

very short term concept and is most likely to reflect spot or very short term 

contract market prices. At these price levels, the producer does not earn a 

return on its invested capital, and would not be expected to reinvest capital once 

the reserves or mining equipment were exhausted. How long prices can remain at 

these levels is largely a function of the industry's excess capacity situation. So 

long as segments of the industry experience excess capacity, and prices in these 

segments need not be strong enough to encourage increased investment in new 

capacity, then industrial coal users may expect to benefit from depressed coal 

price levels. 

Prices which cover full coal production costs are estimated as those which 

provide sufficient cash flow over the mine life to provide a 15% return on 

investment. 

The variable costs of coal transportation are defined by mode. For barges and 

trucks, the concept is very similar to that of coal producers (ie. that needed to 
P.9 

cover the cash costs of transportation). However, for rail, costs are calculated 

based upon "Rail Form A" costs. These are based upon a widely used technique 

of allocating railroad costs among various operating parameters and developing 

unit costs which can then be applied to specific movements. This costing 

technique was applied in this study for specific routings and for specific rail 

carriers to estimate variable costs. However, 135% of Rail Form A calculated 

variable costs was used as the definition of "variable costs" that a rail carrier is 

likely to charge. This is far below the rates charged on most coal traffic, but is 

approximately the level at which the railroad could cover its costs, if all traffic 

paid a similarly calculated rate. 

Full rail costs were calculated as 180% of variable costs. This is a regulatory 

threshold above which the Interstate Commerce Commission can take jurisdiction 

in deciding whether a rate is reasonable. It indicates that a rate will also be 

highly profitable. 

10. Comparison of Costing Results to Sample Utility Plant Prices: The cost 

model results were compared to the actual delivered prices for contract and spot 

coals at the sample utilities to determine the degree to which delivered coal 

prices had been reduced and whether the price reductions which had been 

effected to meet interfuel competition appeared to be sustainable. 

Assumptions and Caveats 

Competitive Fuels: The competitive fuel in New England and the South Atlantic 

(Florida) will be 1.6% sulfur resid. In the Gulf Coast, the competitive fuel will be 

natural gas. Use of 3% sulfur resid would have lowered the resid costs by about 

$.20/MMBtu making coal even less competitive. 

Prices of Competitive Fuels: The delivered prices for natural gas and resid used 

in the case studies were provided by Energy and Environmental Analysis, Inc. 

under their "High Oil Price Scenario" in a report to USEPA "Regional Projections 

of Industrial Fuel Prices" dated August 14, 1986. 

Threshold Price Differential for New Industrial Boilers: EEA indicated that the 

approximate threshold fuel price differential for construction of a new coal-fired 

industrial boiler would be approximately $3/MMBtu. This means that the cost of 

the competing fuel (ie. oil or natural gas) must be expected over some period to 

exceed the cost of coal on a delivered basis by approximately $3/MMBtu before 

the industrial facility is likely to choose to install a coal-fired boiler. This 

differential is required because the capital and operating costs associated with an 

industrial coal-fired boiler far exceed the costs of an industrial oil or gas-fired 

boiler. 

Disaggregation of Delivered Coal Price Data: While utility delivered coal price 

data are readily available through FERC form 423 data, disaggregation of these 

data into transportation and fob mine components is generally confidential. In 

determining what portion of the delivered price reductions were due to changes in 

transportation and fob mine costs, it was necessary to make assumptions based 

upon data from other sources or discussions with the utilities and railroads. In 

general, producers have been more responsive in terms of dropping prices to meet 

competition than have been the railroads. However, this has generally been in 

response to competition from other coal producers. To the extent that further 
P.10 

prfce reductions are needed to meet interfuel competition, this burden has been 

borne in part by the coal transporters. However, some rail carriers have 

resisted these price reductions, in part because the carriers are concerned that it 

will be difficult to increase their rates once the pressure from alternative fuels is 

relieved. 

Relationship Between Industrial and Utility Price Trends: While utility delivered 

coal prices have declined as a result of declining oil and gas prices, it does not 

necessarily follow that industrial coal users would experience the same type of 

delivered coal price response. This analysis is predicated in part on the concept 

that some relationship does exist between utility and industrial coal prices. Since 

the volume of utility coal shipments is more than an order of magnitude greater 

than the volume of industrial steam coal shipments, and because it is utility 

purchasing decisions that largely dictate the market conditions experienced by 

U.S. steam coal producers, it is likely that industrial coal users will be price 

takers in this market. To the extent that the excess of supply over demand, and . 

increasing interfuel competition result in lower coal prices, industrial coal users 

are likely to be beneficiaries of the lower prices. 

The relationship between utility and industrial transportation prices is more 

difficult to establish both actually and conceptually. For barge and trucking 

costs, the market is highly competitive, and prices are essentially cost based in 

the current situation of barge over capacity. The limited barriers to entry in 

coal trucking also result in rates that are probably largely cost-based. However, 

rates for rail transport which is the primary mode for utility and industrial coal 

shipments are not necessarily cost-based. 

Industrial coal shipments by rail occur mostly in single carload lots. Some 

published rates are also established for multiple cars and minimum annual volumes. 

However, many industrial coal movements are covered under transportation 

contracts which were allowed under the 1980 Staggers Rail Act. These contract 

rates are confidential. Since delivered industrial coal prices are also confidential, 

there is little data on the extent to which the railroads may have reduced rail 

rates for the industrial sector to meet interfuel competition. 

Discussions with industrial and utility coal users indicate that the railroads 

have reduced rates for industrial coal shippers under contracts from tariff levels. 

The extent of these reductions is probably a result of the industry's bargaining 

leverage over the railroads, and the company's associated commitment to move 

coal over the tracks of the railroad with whom it contracts. Because some coal 

using industries also ship other products by rail, the contract rates may reflect a 

commitment to further utilize the railroads' services in commodities other than 

simply coal. 

An industry considering installing a new coal-fired boiler and having a noncoal fuel option is likely to be in a position to exercise some leverage over the 

railroad. Specifically, if the carrier is not willing to establish acceptable rates 

under contract, it will lose all of the potential revenues for coal shipments for 

the new boiler. Also if the plant is unsited, or the site is served by more than 

one carrier, the industry may be able to achieve lower rail rates through 

intramodal competition. The benefit of this ex-ante competition can then be 

preserved (to some extent) through a contract. 
P.11 

'The availability of cheap oil and gas and the ability of an industry adding 

boiler capacity to demonstrate to the railroad that lower rail rates would be a 

prerequisite to a decision to build a coal-fired boiler would seem to provide an 

impetus for lower rail rates. However, because industrial coal volumes are low 

relative to utility coal volumes, it is likely that the railroads would not make the 

same sorts of concessions to gain industrial traffic that they would to gain new 

utility traffic. This is especially true if the railroad perceives that the industry's 

leverage is short-lived (eg. oil and gas prices are only temporarily depressed); or 

that granting price concessions would have implications beyond the company to 

whom the concession was granted (eg. Company B will learn that Company A 

received a significant rate reduction and Company B will demand the same 

consideration when its current contract expires). 

We conclude that it is very difficult to predict how railroad rates will respond 

to reduced oil and gas prices. We have assumed that for new industrial coal 

boilers, companies may accomplish the same sorts of reductions that utilities 

achieved. This is a tenuous result, but is useful given the hypothesis being tested 

that industrial coal prices cannot fall enough to result in new coal boiler 

additions. If this hypothesis is wrong, and industrial rail rates do not decline 

proportionately as much as utility rail rates, then the conclusions of the analysis 

will be further strengthened. 

Impact of Quality Constraints: To the extent that industrial coal specifications 

are more stringent than utility coal specs, this will tend to limit the availability 

of acceptable suppliers and thus competition. Industrial coal, especially stoker 

coal is likely to have more stringent specifications than utility coal used in 

pulverized coal boilers. In fact, only certain producers are capable of screening 

and sizing coal for use in stoker applications. Consequently, the spillover effects 

of over capacity in the utility steam coal market may be more limited in their 

effects on the industrial coal market. 

Future Coal Production Price Trends: Most of this analysis flows from an 

examination of the changes in utility coal prices over the past twelve months 

when oil and gas prices plummeted. These reductions in fob mine prices are in 

part attributable to pressure from declining oil and gas prices, but they are 

primarily affected by the over capacity in the coal mining industry resulting from 

the previous decisions of coal producers to expand capacity for a market that 

failed to grow at the rate perceived by the coal industry. This resultant over 

capacity has engendered fierce competition among producers which has helped 

promote marked improvements in productivity and mining efficiency which have 

lead to lower costs. 

Estimates of coal industry capacity utilization vary but many imply that at 

current demand growth rates, new capacity in many regions may not be required 

until the mid-1990's. 

The growth of low cost production which has been driven by many factors of 

which competition is only one is an enduring change that should result in reduced 

industrial coal prices. To the extent that labor productivity improvements are 

maintained or additional gains are realized, the cost structure of the coal mining 

industry will be reduced and some of the competitive prices which utilities have 

experienced to meet oil and gas competition may be maintainable. If this 

observation is wrong, and fob mine prices increase, the hypothesis that coal 

prices cannot be kept low enough to make coal an attractive option in new 
P.12 

FIGURE IV-1 

e 

! 

z 

COAL MINE PRODUCTIVITY 

NATIONAL TRENDS 

i—l—r 

I960 1985 

UNDERGROUND SURFACE 

SOURCE: RESOURCE DATA INTERNATIONAL 
FIGURE IV-2 

1. 

3 

O 

JC 

I 

c 

D 

£ 

c 

o 

Coal Mining Productivity 

Eastern Kanfucky 

1981 1982 1983 1984 1985 

D Underground Surface 

SOURCE: U.S. DEPT. OF ENERGY COAL PRODUCTION 

TJ 
FIGURE IV- 3 

O 

£ 

I 

C 

o 

E 

£ 

Coal Mining Productivity 

Wasf Vfrgfnra 

1981 1982 1983 1984 1985 

• Undarground + Surface 

SOURCE: U.S. DEPT. OF ENERGY COAL PRODUCTION 

v 
z\ 

P.15 

1 

> 

W ed CJ 

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(jnoq— UDUI/SUC»4) 
FIGURE IV- 5 

i . 

D 

O 

£. 

I 

C 

D 

£ 

c 

Coal Mining Productivity 

Pennsylvania 

1981 1982 1983 1984 1985 

• Underground Surface 

SOURCE: U.S. DEPT. OF ENERGY COAL PRODUCTION 

v 
P.17 

industrial boilers will be strengthened. Thus this assumption of constant fob mine 

prices in constant dollars is probably a conservative one in light of the 

hypothesis being tested in this analysis. 

Labor productivity has improved markedly in the coal industry which should 

have a long term stabilizing effect on coal prices. Figure IV-1 shows the 

national trend since 1960 while Figures IV-2 to IV-5 show the trends in various 

regions (eastern Kentucky, West Virginia, western Kentucky and Pennsylvania). 

To the extent that rapid productivity improvements continue through the 1990-

1995 time period (which is generally not expected), fob mine prices could continue 

declining in real terms. This could result in lower industrial delivered prices than 

those assumed in this study. 

Future Transportation Price Trends: Barge and trucking prices are likely to 

reflect changes in future oil prices to the extent that those prices are part of 

their existing cost structures. Rail rates which are our primary focus are 

assumed to increase slightly in constant dollars with real increases occurring in 

labor costs, diesel fuel prices changing with the projected changes in oil prices, 

and most other costs remaining constant. The railroads have made significant 

labor productivity improvements, and the results of those improvements are most 

likely to be realized on competitive traffic including instances where coal must 

compete with other fuels. Thus rail rates are shown increasing by about 1% per 

year. Again, if this assumption understates the case, then coal will simply be 

even less competitive than predicted in this analysis. 

V. New England Market Analysis 

Utility Market 

The utility market for coal in New England has experienced substantial 

declines in delivered coal prices. This is due in part to declining prices for 

imported oil. This price decline is evident in the delivered fuel prices being paid 

by New England Electric System (NEES) from 1973 through March 1986. (Figure 

V-l) Figure V-2 shows the delivered price for coal at NEES's Brayton Point 

station from 1980 through mid-1986. Average delivered coal prices peaked at 

about $2.50/MMBtu in 1982 and declined to an average $1.81/MMBtu in the first 

half of 1986. Contract prices averaged $1.82/MMBtu during the first half of 1986, 

while spot prices averaged $1.56/MMBtu and have fallen as low as $1.45/MMBtu. 

This drop of more than 25% in delivered coal prices is due to a combination of 

declining coal and transportation costs. The declining fob mine prices can be 

related to industrial coal prices since NEES purchases high Btu coal from northern 

West Virginia, an area from which industrial coal consumers are likely to purchase 

coal for new industrial boilers (according to the criteria suggested by EEA). 

However, NEES coal deliveries are routed via rail-coastwise vessel to its Brayton 

Point and Salem Harbor plants. It is unlikely that most industrial facilities in 

New England would be directly water accessible. Part of NEES's ability to 

pressure its rail carriers is due to this water access. Consequently, its 

accomplishments in transportation rate reductions are not likely to be easily 

duplicated by a company installing a coal-fired boiler (having only rail access), 

and, this 25% reduction in delivered coal prices may be a maximum. 

14 
FIGURE V-l 

DELIVERED FUEL PRICES TO 

NEW ENGLAND ELECTRIC SYSTEM 

1973 - 1986 

P.18 

5 T -

M.MlM.lMMMMJH^INMMMlUlinNIMINlMJ U 

2. S- & "fe- fe -fe S .1 I ! • i § § | 

'January, February, and March 1986 

SOURCE: FROM NEW ENGLAND ELECTRIC SYSTEM DATA PUBLISHED IN 

"COAL MINING" JUNE 1986 

15 
/FIGURE V-2 

270 

Delivered Coal Prices 

NEES — Brayton Point 

m 

- M 

260 -

250 -

240 -

230 -

220 -

210 -

200 

190 -

180 -

170 -

160 -

150 -

140 -

130 -

120 -

+ 

A 

110 -

1980 1981 

I 

1982 1983 

I 

1984 1955 1986 

1/ 

D Annua l Average s 

A Lowest Averag e Pric e Durin g Firs t 6 Month s of 1986 

O Averag e Contrac t Pric e Durin g Firs t 6 Month s of 1986 

+ Averag e Spot Pric e Durin g firs t 6 Month s of 1986 

SOURCE: FERC FORM 423 DATA 

1 / Average dat a fo r firs t si x month s of 1986 . 

CO 
P.20 

'NEES has tied its recently negotiated coal and transportation contracts to oil 

prices. As petroleum prices decline, coal prices are reduced to remain competitive 

with a floor set at about $9/bbl, below which the tracking mechanism may be 

altered as coal demand declines. This flexibility is built into the coal supply 

agreements and NEES has attempted to negotiate a parallel arrangement with the 

railroads. At its low point, NEES oil prices fell below this $9/bbl threshold. 

Public Service Co. of New Hampshire has also been able to capitalize on falling 

oil prices and has used this competition to back off coal and base load an oilfired unit. Most of its remaining coal is shipped under long term contract. 

However, its contract involves annual price redeterminations and is expected to 

decline more in the coming year. As shown in Exhibit V-3, average coal prices 

have stabilized in current dollars implying a decline in real dollars. In addition, 

some purchases in 1986 are substantially below the average. 

The PSCNH's Schiller station which burned coal in early 1986 had an average 

delivered coal price of about $2.21/MMBtu. Spot purchases were at $1.92/MMBtu. 

The plant used 1% sulfur central Appalachian coal delivered by barge. In July 

1986, PSCNH's Newington station burned 1.7-2.0% resid at a delivered price of 

$1.46/MMBtu. Low sulfur coal could apparently not compete at that price level. 

Even higher sulfur coals delivered by rail to PSCNH's Merrimack plant shown in 

Figure V-3 are substantially above that price. Only some of the NEES spot coal 

shipments appear competitive at less than $1.50/MMBtu delivered and these coals 

are at a transportation advantage relative to PSCNH's Schiller station. 

PSCNH receives coal for its Merrimack station via unit train over a routing 

which could be typical for a New England industrial coal user. However, PSCNH 

may not have been able to exert significant leverage over the rail carriers 

because its existing coal contract commitments limit its flexibility. In fact, a new 

industrial coal user while it could not obtain the same unit train rates, might be 

able to force additional competition because of its ability to choose a fuel other 

than coal. 

Industrial Coal Use 

Very little industrial coal is used in New England; total consumption in 1985 

was approximately 242,000 tons. For this analysis of industrial coal use, the 

assumed supply-transport combination for a New England industrial facility located 

near Boston would be to take a 13,000+ Btu product on an all-rail movement from 

Pennsylvania or northern West Virginia. For this analysis, a sample movement 

was assumed to be a 682-mile rail movement from a mine in Pennsylvania to 

Boston. 

Because of the relatively long distances and high transportation costs, it is 

likely that the consumer would choose to obtain a high Btu coal from the region 

commensurate with the objective of minimizing delivered costs on a cents/MMBtu 

basis. 

The delivered price of this coal on a variable and full cost basis is shown in 

Figure V-4. The data indicate that the price differences between oil and coal 

under the assumptions used in the industrial fuel choice model would probably not 

be sufficient to obtain industrial coal penetration in the region. 

17 
u 

m 

\ 

-M 

c 

-

FIGURE V-3 

Delivered Coal Prices 

PSCo of New Hampshire — Merrimack 

c-r\J 

2 6 0 -

2 5 0 -

2 4 0 -

2 3 0 -

2 2 0 -

2 1 0 -

2 0 0 -

1 9 0 -

180 -

170 -

1 60 -E 

150 -

140 -

130 -

120 -

1 1 n 

i—i n — 

^ l l— 

1 i u ~t | | | | | 

198 0 1981 198 2 198 3 198 4 198 5 

D Annual Averages 

ok Lowest Average Price During First 6 Months of 1986 

O Average Contract Price During First 6 Months of 1986 SOURCE: 

+• Average Spot Price During first 6 Months of 1986 

1/ Average data for first six months of 1986. 

+ 

Q 

A 

' 1/ 1 

198 6 

-

. 

00 

i—1 

FERC FORM 423 DATA 
P.22 

FIGURE V-4 

Coal Delivery 

Origin: Penn./Northern W.V. underground mine 

Dest: Boston, MA 

Quality: 13,000 

(All Prices in 1985 Dollars) 

Coal Prices 

($/ton) 

F.O.B. Mine 

Variable Cost 

Full Cost 

Truck 

Variable Cost 

Railroad 

Variable Cost 

Full Cost 

Actual Tariff 

Transloader 

Variable Cost 

Barge 

Variable Cost 

Industrial Premium 

Delivered 

($/ton) Variable Cost 

Full Cost 

Delivered 

(cents/MMBtu) Variable Cost 

Full Cost 

EEA 1.6% Sulfur Oil Price 

(cents/MMBtu) High Scenario 

Differences 

EEA Oil Price (verses VC) 

High Scenario (verses FC) 

1986 

17.80 

23.10 

16.40 

21.90 

25.00 

5.00 

39.20 

49.90 

151.00 

192.10 

(1985) 

446.00-

295.00 

253.90 

1990 

17.80 

23.10 

17.10 

22.80 

5.00 

39.90 

50.80 

153.50 

195.50 

414.00 

260.50 

218.50 

1995 

17.80 

23.10 

17.90 

23.90 

5.00 

40.80 

52.00 

156.90 

200.00 

467.00 

310.10 

267.00 

19 
P.23 

C6nclusion 

In order for coal to be attractive to an industrial user in New England, it 

would have to be delivered at a price between $1.14 and $1.67/MMBtu in the 

1990-1995 time frame. This is on a level with the lowest prices received by NEES 

and substantially below the best prices obtained by PSCNH. Since the 

transportation routing for the PSCNH coals are more akin to the routings 

available to a New England industrial user, these prices (which have not been 

below about $1.90/MMBtu) are likely to be the more representative. 

Increasing the delivered coal prices to account for the fact that these are 

industrial shipments (at least $.20/MMBtu fob mine without counting the 

substantial transportation cost differentials) would make it unlikely that a rail 

served New England industry would elect to build a new coal-fired boiler. 

VI. South Atlantic Market Analysis 

In the South Atlantic region, coal use is much wider spread than in New 

England. This is probably due in part to the closer proximity of these facilities 

to the coal fields. Discussions with a number of utilities indicate that while 

delivered coal prices have declined dramatically over the past two years, this 

decline is not generally attributed to lower oil prices. Rather over capacity in 

the coal fields and improving productivity have provided the impetus for dramatic 

declines in prices. Florida is an exception, with some utilities in Florida having 

been able to obtain reduced delivered coal prices because of competition from oil. 

Data from several utilities were examined to determine the extent of delivered 

coal price declines. These were Virginia Electric Power Co., South Carolina 

Electric & Gas, and Florida Power Corp. 

Figure VI-1 shows the decline in delivered prices at Virginia Power Co. 

(Vepco) from a peak of almost $2/MMBtu in 1981 down to about $1.56/MMBtu in 

1986, or more than 20%. Spot prices have fallen as low as $1.40/MMBtu. During 

this period, Vepco has reduced delivered coal costs through mine price reductions, 

and by forcing rail competition at its Chesterfield plant. Vepco does not 

attribute these coal price reductions to competition from oil. 

Figure VI-2 shows the delivered price profile for South Carolina Electric & 

Gas whose delivered prices peaked in 1983 at $2.06/MMBtu and declined more than 

10% to $1.80/MMBtu in 1986. The average price for delivery of spot coal, to 

SCEG was about $1.53/MMBtu during the first half of 1986. These declines 

according to the utility were not caused by oil and gas competition, but by 

weakness in the coal markets. 

Florida is an exception in the South Atlantic region. The state has significant 

amounts of oil-fired capacity, and utilities buy and sell power on a brokering 

system that allows competition between fuels. The drop in imported oil prices 

into Florida have placed pressure on delivered coal prices. 

Florida Power Corp. (FPC) shows the impact of this competition. FPC's 

delivered coal prices shown in Figure VI-3 peaked in 1983 at about $2.60/MMBtu, 

and by 1986 had declined more than 25% to about $1.92/MMBtu. Spot coal prices 

20 
FIGURE VI- 1 

-1-1 

(D 

\ 

W 

r-l 

c 

Delivered Coal Prices 

Virginia Electric Sc Power — All Plants 

270 

26Q -

250 -

24Q -

230 -

220 -

21 O -

20Q -

190 -

180 

170 -

160 -

150 -

140 -

130 -

120 -

+ 

A 

110 

1980 

1— 

1981 1982 198 3 

I 

198 4 1985 

T 

1986 

1 / 

D Annua l Average s 

A. Lowest Averag e Pric e Durin g Firs t 6 Months of 1986 

O Average Contrac t Pric e Durin g Firs t 6 Months of 1986 

+ Average Spot. Price , Durin g firs t 6 Months of 1986 

SOURCE: FERC FORM 42 3 DATA 

1/ Average dat a fo r firs t si x month s of 1986, 

ro 
FIGURE VI- 2 

m 

\ 

c 

0 

Delivered Cool Prices 

S.C. Electric £c Gas — All Coal Units 

270 

260 -

250 -

240 -

230 -

220 -

210 -

200 -

190 -

180 -

170 -

160 -j 

150 -

140 -

130 -

120 

IIO 

CM 

CM 

19SO 1981 1982 

I 

1983 

I 

1984 

I 

1985 

r 

198S 

1/ 

D Annual Averages 

A. Lowest Average Price During First 6 Months of 1986 

^ Average Contract Price During First 6 Months of 1986 

•#• Average Spot Price During first 6 Months of 1986 

SOURCE: FERC FORM 423 DATA 

1/ Average data for first six months of 1986. 
FIGURE VI- 3 

Delivered Cool Prices 

Florida Power Corp. — Crystal River 

270 

-M 

m 

\ 

tn 

r-l 

c 

v 

o 

CO 

CM 

1980 1981 1982 1983 1984 1985 1986 

1 / 

0 Annual Averages 

A Lowest Average Price During First 6 Months of 1986 

^ Average Contract Price During First 6 Months of 1986 

+ Average Spot Price During first 6 Months of 1986 

SOURCE: FERC FORM 423 DATA 

1/ Average data for first six months of 1986. 
in the first half of 1986 averaged $1.75/MMBtu, and the lowest prices were at 

about $1.20/MMBtu, less than half the average price levels of 1983. Because FPC 

buys coals of different qualities from various supply regions and uses both rail 

and water transportation, it is difficult to draw a direct analogy between the 

results it has achieved and those which could be expected by a Florida-based 

industry considering installing a new coal-fired industrial boiler. But clearly the 

market has responded to interfuel competition with dramatically lower delivered 

coal prices. 

In July 1986, Florida Power Corp. and Florida Power & Light were receiving oil 

and natural gas at delivered prices of approximately $1.50-1.75/MMBtu which was 

below the average delivered coal price of about $1.81/MMBtu. However, some 

District 8 compliance coals were competing at delivered prices of $1.50-

$1.60/MMBtu. Between the first half of 1985 and 1986, coal generated power 

increased slightly, but oil consumption jumped 75%, primarily backing out natural 

gas. 

Industrial Coal Use 

In the South Atlantic, industrial coal use is considerably more widespread than 

in New England. For this region, three coal supply and transportation 

combinations were examined: 

Coal Origin Destination Mode Miles 

West Virginia Richmond, VA Rail (CSX) 468 

Virginia Charleston, SC Rail (CSX) 631 

Kentucky Jacksonville, FL Rail (CSX) 754 

These coals were all assumed to be 12,500 Btu/lb. However, to reduce the 

impact of high transportation costs, industrial consumers might opt for higher (eg 

13,000 BTU) coals. 

Figures VI-4, VI-5, and VI-6 show estimated full and variable costs for coal 

production and delivery to potential industrial customers in Virginia, South 

Carolina and Florida. These cost analyses can be compared to the projected costs 

of oil in this region in 1990 ($4.07/MMBtu) and 1995 ($4.60/MMBtu). 

A $3/MMBtu differential requirement would require a $1.07/MMBtu delivered 

coal price in 1990. No utility has achieved these levels on even a spot shipment 

basis and this would be below even the variable costs of the producers and 

transporters. 

In 1995, a $3/MMBtu differential would yield a $1.60/MMBtu delivered coal 

price as the threshold for coal penetration of new boilers. This price is not 

inconceivable, and has actually been achieved for deliveries to Florida, probably in 

unit train shipments or by water. In fact, Colombian coal imports act as a partial 

cap on these prices. However, for industrial users who may generally lack water 

access, require single car shipments, and pay a premium for coal preparation, it is 

unlikely that coal could be delivered competitively into Florida at $1.60/MMBtu. 

24 
P.28 _ 

FIGURE VI-4 

Coal Delivery 

Origin: Harlan, KY 

Dest: Charleston, SC 

Quality: 12,500 

Distance: 631.0 

(All Prices in 1985 Dollars) 

Coal Prices 

($/ton) 

F.O.B. Mine 

Truck 

Railroad 

Variable Cost 

Full Cost 

Variable Cost 

Variable Cost 

Full Cost 

1986 

20.00 

35.50 

13.30 

17.70 

1990 

20.00 

35.50 

14.30 

18.70 

1995 

20.00 

35.50 

15.30 

19.80 

Transloader 

Variable Cost 

Barge 

Variable Cost 

Industrial Premium 

Delivered 

($/ton) Variable Cost 

Full Cost 

Delivered 

(cents/MMBtu) Variable Cost 

Full Cost 

EEA 1.6% Sulfur Oil Price 

(cents/MMBtu) High Scenario 

DIFFERENCES 

EEA Oil Price 

High Scenario 

(verses VC) 

(verses FC) 

5.00 

38.30 

58.20 

153.10 

232.60 

(1985) 

438.00 

284.90 

205.40 

5.00 

39.30 

59.20 

157.30 

236.80 

407.00 

249.70 

170.20 

5.00 

40.40 

60.30 

161.50 

241.00 

460.00 

298.50 

219.00 

25 
P.29 

FIGURE VI-5 

Coal Delivery 

Origin: Southern West Virginia 

Dest: Richmond, VA 

Quality: 12,500 

Distance: 468.0 

(All Prices in 1985 Dollars) 

Coal Prices 

($/ton) 

F.O.B. Mine 

Truck 

Railroad 

Variable Cost 

Full Cost 

Variable Cost 

Variable Cost 

Full Cost 

1986 

20.00 

35.50 

12.00 

16.00 

1990 

20.00 

35.50 

12.50 

16.60 

1995 

20.00 

35.50 

13.10 

17.50 

Transloader 

Barge 

Variable Cost 

Variable Cost 

Industrial Premium 

Delivered 

($/ton) Variable Cost 

Full Cost 

Delivered 

(cents/MMBtu) Variable Cost 

Full Cost 

EEA 1.6% Sulfur Oil Price 

(cents/MMBtu) High Scenario 

DIFFERENCES 

EEA Oil Price 

High Scenario 

(verses VC) 

(verses FC) 

5.00 

37.00 

56.50 

148.00 

225.80 

(1985) 

438.00 

290.00 

212.20 

5.00 

37.50 

57.10 

149.90 

228.40 

407.00 

257.10 

178.60 

Note: Rail movement is assumed to be from Logan, WV. However, 

eastern Kentcky F.O.B. mine prices were used. 

5.00 

38.10 

57.90 

152.50 

231.80 

460.00 

307.50 

228.20 

26 
P.30 

FIGURE VI-6 

Coal Delivery 

Origin: Harlan, KY 

Dest: Jacksonville, FL 

Quality: 12,500 

Distance: 754.0 

(All Prices in 1985 Dollars) 

Coal Prices 

($/ton) 

F.O.B. Mine 

Truck 

Railroad 

Actual 

Variable Cost 

Full Cost 

Variable Cost 

Variable Cost 

Full Cost 

Tariff 

1986 

20.00 

35.50 

15.80 

21.10 

21.00 

1990 

20.00 

35.50 

16.50 

22.00 

1995 

20.00 

35.50 

17.30 

23.10 

Transloader 

Variable Cost 

Barge 

Variable Cost 

Industrial Premium 

Delivered 

($/ton) Variable Cost 

Full Cost 

Delivered 

(cents/MMBtu) Variable Cost 

Full Cost 

EEA 1.6% Sulfur Oil Price 

(cents/MMBtu) High Scenario 

DIFFERENCES 

EEA Oil Price 

High Scenario 

(verses VC) 

(verses FC) 

5.00 

40.90 

61.60 

163.40 

246.50 

(1985) 

438.00 

274.60 

191.50 

5.00 

41.50 

62.50 

166.00 

249.90 

407.00 

241.00 

157.10 

5.00 

42.30 

63.60 

169.40 

254.40 

460.00 

290.60 

205.60 

27 
P.31 

In other parts of the South Atlantic region located closer to the coal fields, 

the differential between coal and oil and gas prices will probably be greater than 

in Florida. This is because the delivered price of oil will be higher while 

delivered coal prices will be lower. Since the data indicate that the recent 

decline in coal prices is not all attributable to downward pressure from oil and 

gas, it is not clear what the impact of fuel price differentials in those locations 

will be. 

Conclusion 

Under the high oil price scenario, the delivered price of 1.6% resid in the 

South Atlantic in 1995 will be about $4.60/MMBtu. In order to achieve a 

$3.00/MMBtu differential, industrial coal would have to be delivered into Florida 

for about $1.60/MMBtu. This is highly unlikely except in some unusual 

circumstances. 

FPC's 1986 spot coal deliveries have averaged about $1.80/MMBtu. While 

occasional spot shipment prices have fallen as low as $1.20/MMBtu, this appears 

to be for small probably distress quantities. Industrial coal transportation prices 

are likely to be about nearly $.80/MMBtu which would allow only about $20.00/ton 

as an fob mine price. It is unlikely that any industry which lacks water access 

could plan to receive coal on a delivered price basis in Florida at these price 

levels. 

In the other states examined in this region, delivered utility coal prices to 

coastal locations have declined to as low as $1.40-$1.50/MMBtu. These prices 

when adjusted to be industrial coal equivalents are likely to produce coal prices 

which are inadequate to meet the $3/MMBtu threshold. This assumes a $5/ton 

adjustment for industrial fob coal mine price differentials (about $.20/MMBtu). 

This alone would be sufficient to make coal non-competitive and does not account 

for substantial transportation cost differentials. 

VII. Gulf Coast Market Analysis 

The Gulf Coast market area includes the major natural gas producing region 

comprising in part Texas, Oklahoma, and Louisiana. Many utilities in this region 

have the capability of burning either coal or natural gas, and in some instances, 

natural gas has effectively "backed out" coal. 

Figure VII-1 shows the decline in delivered coal prices at Lower Colorado 

River Authority (LCRA) from a peak of about $2.58/MMBtu in 1984 down to an 

average of $1.84/MMBtu in 1986. This decline of more than 25% was due to 

declines in both coal prices and rail rates through contract litigation or renegotiation. The lowest prices occurred in 1986. Contract prices fell to 

$1.57/MMBtu reflecting the steep decline in the coal market and natural gas 

competition. LCRA pays almost exactly that price for natural gas. 

Figure VII-2 shows the steep decline in delivered coal prices to City Public 

Service of San Antonio. Prices peaked at $2.16/MMBtu in 1982, stayed above 

$2.10/MMBtu through 1985 and then plummeted more than 20% to about 

$1.73/MMBtu in the first half of 1986. Spot prices on a delivered basis fell to 

$1.59/MMBtu again probably reflecting competition from natural gas. These 

declines were due both to transportation and coal price declines. 

28 
FIGURE VII- 1 

Delivered Coal Prices 

Lower Colorado River Authority 

rs 

CD 

t/i 

c 

1) 

270 

260 

250 

240 -

230 -

220 -

210 -

200 -

190 -

180 -

170 -

160 -

150 -

140 -

130 -

120 -

110 -

- & • 

CTi 

CSI 

19SO 1981 

I 

1982 

I 

1983 1984 1985 

I 

1986 

1 / 

D Annual Averages 

A Lowest Average Price During First 6 Months of 1986 

O Average Contract Price During First 6 Months of 1986 

+ Average Spot Price During first 6 Months of 1986 

SOURCE: FERC FORM 423 DATA 

1/ Average data for first six months of 1986. 

ro 
FIGURE VII- 2 

270 

Delivered Coal Prices 

City Public Service of San Antonio 

4-1 

CD 

4-1 

c 

o 

260 -

250 -

240 -

230 -

220 -

210 -

200 -

190 -

18Q -

170 -

160 -

150 -

140 -

130 -

120 -

110 

o 

p-> 

& 

1980 

1— 

198 1 

I 

1982 

I 

1983 

I 

198 4 

I 

1985 1986 

1 / 

0 Annua l Average s 

A Lowest Averag e Pric e Durin g Firs t 6 Months o f 1986 

O Averag e Contrac t Pric e Durin g Firs t 6 Months of 1986 

+ Averag e Spo t Price - Durin g firs t 6 Months o f 1986 

SOURCE: FERC FORM 423 DATA 

1 / Averag e dat a fo r firs t si x month s o f 1986. 
FIGURE VII- 3 

CD 

\ 

</i 

4-< 

c 

1) 

o 

270 

Delivered Coal Prices 

Central Power &c Light — Coleto Creek 

260 -

250 -

240 -

230 -

220 

210 -j 

200 -

190 -

180 -

170 -

160 -

150 -

140 -

130 

120 

110 

+ 

A 

198 0 1981 

I 

1982 198 3 1984 

I 

1985 1986 1/ 

D Annual Averages 

A Lowest Average Pric e During First 6 Months of 1986 

O Average Contrac t Pric e During First 6 Months of 1986 

+ Average Spot Pric e During firs t 6 Months of 1986 

SOURCE: FERC FORM 423 DATA 

1/ Average dat a for firs t si x months of 1986, 
P.35 

' Figure VII-3 shows the change in delivered coal prices to Central Power & 

Light Company's (CP&L) Coleto Creek plant in Texas. This plant is unique in 

Texas in that it receives, or has received, Colorado and New Mexico coals. 

CP&L's delivered coal price peaked in 1985 at $2.68/MMBtu and then declined 

more than 15% to $2.26/MMBtu for the first half of 1986. Spot coal shipments in 

July 1986 from Colorado had fallen to $1.74/MMBtu, 35% below the 1985 average 

delivered price. During this same period, CP&L was receiving substantial volumes 

of gas at a delivered price of about $1.55/MMBtu. 

In 1985, CP&L also received New Mexico coal at a delivered price of about 

$1.90/MMBtu. These shipments ceased in 1986, and less expensive spot coals were 

purchased from Colorado. 

These declines in delivered coal prices to utilities cannot be readily translated 

into changes in industrial coal prices. Most utilities in the Gulf Coast purchase 

low Btu sub-bituminous coal from the Powder River Basin and often transport it 

more than 1,000 miles in unit trains of 10,000 tons or more. The fob mine prices 

may be only 25-35% of the delivered price of the coal. Industrial coal users in 

these regions by contrast tend to buy higher Btu coals from less distant origins 

in Oklahoma, Colorado, and New Mexico, or by barge from the Illinois basin or 

central Appalachia. For these coal consumers, the price of the coal fob mine is 

not likely to be directly affected by the prices that utilities in the Gulf Coast are 

paying for coal in the Powder River Basin. 

Fob mine prices in the areas from which industrial consumers in the Gulf 

Coast purchase coal are likely to be determined by the demand for coal from 

those regions by the primary consumers of that coal. These consumers vary 

depending upon the origin of the coal. 

Discussions with industrial coal users in Texas indicate that some industrial 

coal users do have the option of burning either natural gas or coal, and have 

been able to obtain reductions in delivered coal prices. These reductions are 

partially a result of the existing weakness in the coal markets, and partially a 

result of interfuel competition. In general, transporters and producers are 

thought to be aware of natural gas competition, and have been willing to adjust 

prices to some extent to stay competitive. 

By using the percentage reductions obtained by Gulf Coast utilities as a 

measure of the reductions available to industrial coal users, we would probably 

tend to overstate the degree of delivered industrial coal price reductions. 

Utilities in the Gulf Coast which purchase coal from the Powder River Basin have 

benefited from tremendous over capacity among producers which has accompanied 

a sharp slide in both the spot and contract market prices for Powder River Basin 

coal. In addition, intense competition between the Burlington Northern Railroad 

and the Chicago & North Western Railroad for coal originations from portions of 

the Powder River Basin have substantially reduced rail rates. 

While the coal markets for Colorado, New Mexico and Oklahoma have weakened 

during the past few years, no equivalent change in transportation competition has 

occurred which would be as likely to benefit industrial coal consumers. In 

addition, the "lumpiness" of the utility market, where millions of tons of coal 

demand may turn on individual contract decisions, is likely to cause the rail 

carriers and producers to make more generous concessions on utility contract 

business than would be available to industrial coal users in the region. 

32 
P.36 

Mode 

Rail 

Truck 

Barge 

Rail 

Miles 

1,034 

204 

1,113 

1,154 

The Central Power & Light case may provide a bit of insight into the 

delivered costs of industrial coal in Texas. CP&L's lowest delivered coal price for 

Colorado coal has been $1.74/MMBtu and from New Mexico, the minimum price 

was about $1.90/MMBtu. (These may also involve the use of shipper owned coal 

cars.) While exact location, and therefore transportation costs, would be 

important, it seems unlikely that a Texas industry located far from New Mexico 

or Colorado would find coal from these locations able to compete with 

$4.43/MMBtu gas in 1995 in planning a new coal-fired boiler (assuming that the 

coal must be delivered at $1.43/MMBtu). 

Industrial Coal Use 

Industrial coal in this region comes from a number of sources, both in the 

region itself and outside the region. The following combinations were examined: 

Coal Origin Destination 

New Mexico Austin, TX 

Oklahoma Dallas, TX 

Indiana Donaldsonville, LA Barge 

Wyoming Fort Worth, TX 

The New Mexico and Oklahoma origins are the most likely coal sources 

although Louisiana industry does use some coal delivered by barge from central 

Appalachia and the Illinois Basin. The Wyoming origin movement is presented 

simply as an illustration of a utility coal movement. 

Although it was not selected for study here, large volumes of Texas lignite are 

being used in the industrial sector, particularly by the Aluminum Company of 

America (ALCOA) which has large industrial facilities in eastern Texas. These 

operations are likely to be mine mouth or captive, and this analysis does not 

address the relative economics of mining lignite vs. using an alternative fuel. It 

is not known whether the $3/MMBtu would be accurate for such a comparison. 

Figures VII-4, VII-5, VII-6 and VII-7 show the estimated delivered industrial 

coal costs for movements from New Mexico, Oklahoma, Indiana and Wyoming to 

sample locations in Texas and Louisiana. Both variable and full costs are shown 

in these examples. The Louisiana barge movement appears to be the only one 

likely to meet the $3/MMBtu threshold required for a new industrial boiler. 

However, an industrial facility sited close to Oklahoma coal sources could also 

meet this threshold test. 

Conclusion 

EEA projections show that natural gas can be delivered to industrial consumers 

in the Gulf Coast at approximately $3.44/MMBtu in 1990 and $4.43/MMBtu in 1995. 

Assuming a $3/MMBtu differential, coal is obviously not competitive in this region 

33 
P.37 

FIGURE VII-4 

Coal Delivery 

Origin: York Canyon, NM 

Dest: Austin, TX 

Quality: 12,500 

Distance: 1034.0 

(All Prices in 1985 Dollars) 

Coal Prices 

($/ton) 

F.O.B. Mine 

Truck 

Railroad 

Variable Cost 

Full Cost 

Variable Cost 

Variable Cost 

Full Cost 

1986 

17.30 

21.40 

22.90 

30.50 

1990 

17.30 

21.40 

23.80 

31.80 

1995 

17.30 

21.40 

25.00 

33.40 

Transloader 

Barge 

Variable Cost 

Variable Cost 

Industrial Premium 

Delivered 

($/ton) Variable Cost 

Full Cost 

Delivered 

(cents/MMBtu) (DVC) 

(VC) 

EEA Industrial Natural Gas Price 

(cents/MMBtu) High Scenario 

DIFFERENCES 

Natural Gas (verses VC) 

(verses FC) 

5.00 

45.20 

56.90 

180.90 

227.80 

(1985) 

228.00 

47.10 

0.20 

5.00 

46.20 

58.20 

184.70 

232.70 

344.00 

159.30 

111.30 

5.00 

47.40 

59.80 

189.50 

239.20 

443.00 

253.50 

203.80 

34 
FIGURE VII-5 

Coal Delivery 

Origin: Latimer, OK 

Dest: New Braunfels, TX 

Quality: 13,000 

Distance: 204 

(All Prices in 1985 Dollars) 

Coal Prices 

($/ton) 

F.O.B. Mine 

Truck 

Railroad 

Variable Cost 

Full Cost 

Variable Cost 

Variable Cost 

Full Cost 

1986 

30.80 

50.10 

20.40 

1990 

30.80 

50.10 

13.80 

1995 

30.80 

50.10 

9.30 

Transloader 

Barge 

Variable Cost 

Variable Cost 

Industrial Premium 5.00 5.00 5.00 

Delivered 

($/ton) Variable Cost 

Full Cost 

Delivered 

(cents/MMBtu) Variable Cost 

Full Cost 

EEA Industrial Natural Gas Price 

(cents/MMBtu) High Scenario 

DIFFERENCES 

Natural Gas (verses VC) 

(verses FC) 

56.20 

75.50 

216.10 

290.40 

(1985) 

228.00 

11.90 

-62.40 

49 

68 

190 

265 

344 

153 

79 

60 

90 

70 

00 

00 

30 

00 

45 

64 

173 

247 

443 

269 

195 

10 

40 

60 

.80 

00 

40 

20 

35 
P.39 

FIGURE VII-6 

Coal Delivery 

Origin: Chandler, IN 

Dest: Donaldsonville, LA 

Quality: 11,500 

Distance: 1112.5 

(All Prices in 1985 Dollars) 

Coal Prices 

($/ton) 

F.O.B. Mine 

Truck 

Railroad 

Transloader 

Barge 

Variable Cost 

Full Cost 

Variable Cost 

Variable Cost 

Full Cost 

Variable Cost 

1986 

20.10 

28.60 

1.30 

1990 

20.10 

28.60 

1.30 

1995 

20.10 

28.60 

1.30 

Variable Cost 8.90 9.50 10.00 

Industrial Premium 5.00 5.00 5.00 

Delivered 

($/ton) Variable Cost 35.20 35.80 36.30 

Full Cost 43.70 44.30 44.80 

Delivered 

(cents/MMBtu) Variable Cost 153.10 155.80 158.00 

Full Cost 190.10 192.80 195.00 

EEA Industrial Natural Gas Price (1985) 

(cents/MMBtu) High Scenario 228.00 344.00 443.00 

DIFFERENCES 

Natural Gas (verses VC) 74.90 188.20 285.00 

(verses FC) 37.90 151.20 248.00 

36 
P.40 

• .., 

*• » 

FIGURE VII-7 

Coal Delivery 

Origin: Gilette, WY surface mine 

Dest: Ft. Worth, TX 

Quality: 8,400 

Distance: 1154.0 

(All Prices in 1985 Dollars) 

Coal Prices 

($/ton) 

F.O.B. Mine 

Variable Cost 

Full Cost 

1986 

6.70 

12.70 

1990 

6.70 

12.70 

1995 

6.70 

12.70 

Truck 

Variable Cost 

Railroad 

Transloader 

Variable Cost 

Full Cost 

Variable Cost 

Barge 

Variable Cost 

Industrial Premium 

24.6 0 

32.8 0 

5.00 

25.6 0 

34.2 0 

5.00 

26.9 0 

35.9 0 

5.00 

Delivered 

($/ton) Variable Cost 

Full Cost 

Delivered 

(cents/MMBtu) Variable Cost 

Full Cost 

EEA Industrial Natural Gas Price 

(cents/MMBtu) High Scenario 

DIFFERENCES 

Natural Gas (verses VC) 

(verses FC) 

36.30 

50.50 

216.10 

300.70 

(1985) 

228.00 

11.90 

-72.70 

37. 

51. 

222 

308 

344 

122 

35 

30 

90 

00 

70 

.00 

.00 

.30 

38. 

53. 

229 

319 

443 

213 

124 

60 

60 

80 

00 

.00 

.20 

.00 

37 
P.41 

<• *• ' -

in* 1990. In 1995, it would have to be delivered at a price of approximately 

$1.43/MMBtu. 

Even with major price reductions, neither San Antonio nor LCRA have been 

able to obtain delivered coal prices in that range for Powder River Basin coals. 

While industrial coals would come from different origins and via different routes, 

it does not appear that coals from New Mexico or Oklahoma could be delivered 

throughout the region at a cost which would allow them to compete in this 

market. 

The only combination which appears to be possibly competitive would be for an 

industrial facility capable of receiving Illinois Basin coal by water (eg. in 

Louisiana). This would be a close call, but such a facility might select coal for a 

new boiler if it could foresee increasing gas prices beyond 1995. 

Unique situations may arise, such as a large industrial facility that decides to 

use local lignite or.locate near a coal source, or a water served industrial plant 

which can use relatively inexpensive Illinois basin coal. But in general, it appears 

that local natural gas will preclude construction of new industrial coal-fired 

boilers in the Gulf Coast region during the time period of investigation. 

38