**[Competitive Implications of Environmental Regulation]{.smallcaps}**

**[in the]{.smallcaps}**

**[Electric Utility Industry]{.smallcaps}**

by:

Donald A. Geffen, Ph. D. and Alfred A. Marcus, Ph. D.

Carson School of Management

University of Minnesota

Minneapolis, MN 55455

U.S. EPA Cooperative Agreement #CR824410-01

Project Officer:

Dr. Alan Carlin

Office of Policy, Planning and Evaluation

U.S. Environmental Protection Agency

Washington, D.C. 20460

Report prepared for:

Office of Policy, Planning and Evaluation

U.S. Environmental Protection Agency

Washington, D.C. 20460

The Management Institute for Environment & Business

June 1996

**DISCLAIMER**

Although prepared with EPA funding, this report has neither been
reviewed nor approved by the U.S. Environmental Protection Agency for
publication as an EPA report. The contents do not necessarily reflect
the views or policies of the U.S. Environmental Protection Agency, nor
does mention of trade names or commercial products constitute
endorsement or recommendation for use.

# TABLE OF CONTENTS

INTRODUCTION 3

INDUSTRY STRUCTURE 3

Product Description and Function 3

Market Size 7

THREAT OF NEW ENTRANTS 10

Electric Utility Industry 10

Coal 10

Scrubber Suppliers 10

Gas Turbines 10

LEADING SUPPLYING NATIONS 11

COMPETING FIRMS 11

General Electric 11

Westinghouse Electric (WX) 11

Asea Brown Boveri Ltd. (ABB) 11

Siemens 12

GE Environmental Services Inc. (GEESI) and Competitors 12

COMPETING TECHNOLOGIES 14

ENVIRONMENTAL, HEALTH AND SAFETY PRESSURES 15

The Acid Rain Problem and the 1990 CAA 15

INNOVATION IN RESPONSE TO ENVIRONMENTAL PRESSURES 17

The Natural Gas Turbine 17

Low Sulfur Coal from the West 18

Sulfur dioxide scrubbers 20

INNOVATIVE FIRMS 21

Complying with the CAA: Existing Coal-fired Facilities 23

Complying with the CAA with new facilities\--New Source Performance
Standards 29

EFFECT OF ENVIRONMENTAL REGULATIONS ON INDUSTRY 30

Ripple Effect Leading to Improved Environmental Performance 31

National Comparisons 32

Effects on Suppliers 33

SUMMARY 33

APPENDIX A 37

SOURCES 33

**INTRODUCTION**

This study examines the response by the electric utility industry to the
Clean Air Act Amendments of 1990, focusing primarily on the SO~2~
provisions of the Act. It explores the competitive forces that developed
among the providers of air pollution control technologies and the
suppliers of low sulfur coal. It also explores competitive developments
among the developers and vendors of natural gas turbine systems, the
main clean alternative to coal for power generation presently available.

While often not fully recognized as such, this will be a story of highly
successful pollution prevention: the reduction of pollution at the
source by sharply reducing the sulfur contaminants in the fuel employed.
At the nexus of this story is the electric utility industry, challenged
both by deregulation and increasing competition and by new environmental
constraints, and assisted by its key suppliers, competing not only among
themselves in each sector but competing sector against sector to provide
the best and lowest cost solutions to these challenges.

International markets and competition also played a role in this story.
The major competitors for air control equipment and for gas turbine
generating equipment were international companies. Markets abroad for
both control systems and gas generating systems were strong and helped
support the development and sale of new innovative products coming from
these vendors.

**INDUSTRY STRUCTURE**

**Product Description and Function**

[Electrical Energy]{.underline}

This ubiquitous but essential product in the past was almost totally
taken for granted until there was a power failure. Taking electricity
for granted was changing, however, with the advent of widespread use of
computers and other complex electronic devices. Even a small variation
in power output such as a small drop in voltage could disrupt these
devices causing costly losses of time and valuable data and producing
sudden production interruptions. As a result the electrical energy
distributors were increasingly concerned with ensuring the quality as
well as the reliability of their product.

Electric utilities transported energy in electromagnetic form over long
distances from concentrated generating centers, where primary thermal
energy was transformed into a more useful form. They also transported
this energy locally among their customers. In 1993 56.9 percent of
electrical energy came from burning coal and a much smaller percentage
was generated by consuming natural gas[^1].

[Bituminous and Sub-bituminous Coal for Electrical Power
Generation]{.underline}

Coal was the mostly commonly used fuel in the U.S. for generating
electricity. This fossil fuel had, by far, the most ample reserves in
the world. There were two main types of coal.

Bituminous coal tended to be roughly 70 percent carbon and a few percent
hydrogen which together represented the heating value of the mineral.
The rest consisted of water, clays of various oxides (the unburned ash),
oxygen, nitrogen, trace compounds (such as chlorine and calcium), very
small amounts of metals (including mercury), and sulfur in various
forms. The sulfur content could be as high as 6 percent by weight but
grades of coal in use by generating facilities usually contained less
than 4 percent sulfur. In 1993, total bituminous coal purchased by
utilities averaged 1.71 percent sulfur, which at an average of 12,045
Btu/lb, corresponded to 1.42 pounds of sulfur per million Btu (MBtu)
heat content.[^2]

The sulfur content of the coal in Appalachian mines varied, and the
proportion with less sulfur was uncertain and limited. The mines from
which Appalachian (eastern) coal came were mature, fully exploited and
had high extraction costs. Unlike natural gas (pure methane) and fuel
oil (a refined hydrocarbon), coal had many properties with constituents
of different concentrations depending on where it was mined and from
which coal veins in the mine it originated.

Sub-bituminous coals were of lower quality than bituminous coals:
compared with a pound of bituminous coal, a pound of western
sub-bituminous coal supplied about 30 percent less heat. The moisture
content of this coal tended to be much higher. Powder River Basin coal
from Wyoming was about 30 percent water. However, its sulfur content was
low. Sub-bituminous coals contained somewhat less ash than most
bituminous coals but the experience of boiler operators was that it
yielded troublesome amounts of difficult to control fine ash in the flue
gas. In 1993, the average sulfur content of sub-bituminous coal sold to
utilities was 0.41 percent and, with an average heat content of 8,763
Btu/lb, this equated to 0.47 lb/MBtu.^2^

Large reserves (30 years or more) of low sulfur coal were available in
Western states in thick veins close to the surface. Even greater
reserves existed somewhat deeper below the surface necessitating open
pit mining to recover them, but at a cost still much below that in the
East and Mid-West.[^3] Low sulfur sub-bituminous western coal differed
sufficiently from higher sulfur bituminous coals such that it usually
could not be substituted for the latter in boilers without
modifications.

[Clean Coal Technologies]{.underline}

The following air pollutants, released when utilities burned fossil
fuels, were regulated by the U.S. government: sulfur dioxide, nitrogen
oxides, particulates from the ash, and several hazardous air pollutants
(HAPs).[^4] Emission standards for HAPs were under review and it was not
clear to what extent utilities would have clean-up responsibilities. A
variety of scrubbers to control SO~2~ were on the market:[^5]

*Limestone Wet Flue Gas Desulfurization Systems (WFGD)*

The most common form of flue gas desulfurization (FGD) equipment, it
sprayed limestone slurry and water into the flue gas and formed a
calcium sulfite and sulfate sludge that had to be disposed of in a
landfill. These scrubbers usually removed 90 percent of the SO~2~ from
the flue gas; however, they could be enhanced to remove 95 percent and
even as high as 98 percent at relatively low cost (an additional 5-10
percent in capital costs) with the addition of organic acid buffers.
WFGD systems could be employed for a range of coal with different sulfur
contents. They could be used for retrofitting existing units as well as
in new facilities.

The capital costs of a system for a burner using 2 percent sulfur coal
was about \$30/kW less than for a burner using 4 percent sulfur coal.
For the burner using 4 percent sulfur coal, the capital costs were
approximately \$120-150/kW for a new generating facility. Retrofitting
tended to run 10-15 percent higher in capital costs. Some existing coal
burning facilities had insufficient available space to install a WFGD
system making more expensive modifications necessary.

In a variation on the WFGD, instead of sending the sludge to a landfill,
the utility removed water and impurities from the sludge and made
gypsum, a marketable product. According to GE Environmental Services,
Inc. (GEESI), a major producer of WFGD systems, providing this
capability added only \$4/kW to the capital costs. However, adding it in
the U.S. made sense only if a utility was located near an area of high
demand for gypsum. Otherwise, the expense did not make it worthwhile. In
Western Europe, on the other hand, the capability to convert scrubber
sludge into a useful byproduct often was essential. Landfill permits to
dump waste sludge were not easily available. In Germany, for example, a
utility had to have this capability.

Labor and maintenance costs for WFGD systems were about 2.5-3.0 percent
of capital cost per year. Parasitic power losses were about 1.5 percent
of plant output and reagent prices were low, in the neighborhood of
0.05/kWh, with limestone costing only \$10/ton. A good estimate of the
additional revenues needed to pay for WFGD systems was 0.4/kWh, a cost
greater than the added cost of fuel for burning natural gas in a
combined cycle turbine generator in most parts of the U.S.[^6]

*Dry FGD*

This system sprayed an agent, usually lime in a slurry, and the agent
then was vaporized by the flue gas. The waste product was dry and easier
to handle. The SO~2~ removal capability of this system, however, was
about 70-90 percent. Thus, it was less suitable for facilities burning
high sulfur coal and more so for facilities that burned low or medium
sulfur coal. Capital costs were roughly 15 percent lower than for the
wet flue gas systems. Sometimes, a baghouse could be used with higher
sulfur coal to remove more of the sulfur dioxide.

*Sorbent Injection Systems*

Dry sorbent injection was cost effective for retrofitting older power
plants where there was insufficient space to install more effective FGD
systems at reasonable cost. Though more reactive sorbents could be used
to enhance performance, and, in principal, these systems were capable of
removal rates of up to 70 percent, in practice a 50 percent rate could
be expected. Most injected a dry or slurry sorbent, commonly limestone,
into the flue gas upstream of the particulate control system, but other
injection systems had been developed that either injected limestone into
the boiler (limestone injection multistage boiler or LIMB) or into the
flue gas before the electrostatic precipitator (ESP). The Department of
Energy (DOE) estimated that a B&W LIMB process system capable of
removing up to 60 percent of the flue gas sulfur dioxide would have a
capital cost of \$30-100/kW.[^7]

[Natural Gas Turbines]{.underline}

Gas turbines (GTs) and combined cycle gas turbines (CCGTs) had
outstanding environmental benefits: they emitted no SO~2~, much less
NO~x~ (as low as 25 parts per million without controls or less than 10
percent of the emissions limits for coal), and HAPs. Equally important,
they had less neighborhood impact than coal fired units, (i.e.,
communities were less likely to protest the siting of an NG facility.)

*Single Gas Turbine (GT) Units*

This technology was a spin-off of the aircraft jet engine, modified for
stationary power application and for burning natural gas. Units could
use fuel oil (as jet engines did) or either natural gas (NG) or fuel
oil. The models closest to jet engines ranged in power from 1/2 to 40
MW, while more advanced systems produced 150 to 250 MW of power. Their
capital and fixed operating costs were half that of coal-fired systems.
GTs attained thermal efficiencies of up to 40 percent and often were
employed for cogeneration purposes.

*Combined Cycle Gas Turbine Systems (CCGT)*

These were mostly larger power systems that typically consisted of a GT
(100 - 150 MW), a heat recovery steam generator (HRSG), and a steam
turbine generator (50 - 100 MW). The gas turbine ran a separate electric
generator. These systems typically were rated at about 250 MW and
attained thermal efficiencies of over 55 percent. Top of the line Asea
Brown Boveri (ABB) and Westinghouse (WX) models reached 57-58 percent
efficiencies while GE announced a new 60 percent thermally efficient
model in 1995. Existing systems were priced at about \$750**/**kW fully
installed. Extremely stringent new source performance standards for
NO~x~ could be met for an additional \$50/kW capital cost. These systems
also could be used in a cogeneration application.

Both GTs and CCGTs could be arrayed in modular units for additional
power capacity. This feature was an important attraction for electric
utilities and other power generators who preferred to respond to new
capacity demands with an increment at a time so as to avoid the risk of
having too much capacity (which could arise when large 500 MW or greater
coal-fired plants were built). A 250 MW CCGT could be installed within
two years or less. GT systems with low capital costs often were used to
provide peaking power capacity for a few days a year. CCGTs had
sufficiently high thermal efficiencies so that they were suitable for
intermediate and base load applications.

**Market Size**

[Electricity Markets]{.underline}

In 1993 a record 2.8 trillion kWh of electricity was generated in the
United States, 1.6 trillion of which was fueled by coal and consumed
813.5 million tons of coal in the process.[^8] Using Department of
Energy (DOE) data, one could estimate an average thermal efficiency for
coal generated plants of 33.6 percent. The demand for electricity in the
U.S. was growing at a rate of about 2 percent per year. This growth rate
was slower than real GDP growth due to conservation efforts (demand side
management) which had more than counteracted the economy\'s increased
use of electricity. However, diminishing returns from demand side
management and a turnaround in U.S. manufacturing could yield
acceleration in electricity use in the future.

Electric utilities until recently had monopolies in selling their
products in their franchise areas. Deregulatory forces were changing
their status and they increasingly looked to neighboring regions as
sources of new markets and competition. Transmission losses and
expenses, however, limited the distances from a utility\'s generating
sources that it could serve to a few hundred miles.

[Coal for Power Generation Market]{.underline}

Total coal deliveries to utilities were around 775 million tons per
year, and they showed little growth. Imported coal accounted for less
than 1 percent of the total BTUs delivered. Since coal consumption by
electricity generators was 814 million tons in 1993, it suggested that
inventories were low and that deliveries could be expected to increase
somewhat. Deliveries of bituminous coal had shown very little growth
from 1986-93, but deliveries of sub-bituminous coal increased at a rate
of more than 3 percent per year.[^9] Utilities added very little net new
coal fired capacity and had plans to add very little in the next few
years.

[The Market for Scrubbers]{.underline}

The world wide installed base of WFGD systems from 1981-1993 was 180,000
MW (or 180 GW). In the United States it was just under 63,000 MW. GE
Environmental Services Inc. (GEESI) had a strong lead in this market
with 26 percent of the world wide market share. The three countries with
GEESI\'s largest installed base were the U.S. with 18,839 MW, Germany
with 7,455 MW, and Japan with 5,925 MW. On a per capita basis, Germany
installed proportionately far more systems than the U.S.

GEESI\'s WFGD marketing group projected a potential world wide market of
over \$7 billion for 1994-1997. In the U.S., it estimated retrofitting
of 36,000 MW of coal fired plants for sales of \$2.7 billion (averaging
\$75/kW) as a consequence of Phase II of the Clean Air Act (CAA). Under
Phase I of this act, retrofits of 14,000 MW of electric power generation
had occurred out of 65,000 MW of impacted capacity. With low cost
alternatives to conventional WFGD systems such as clean coal and trading
allowances available, most industry observers expected considerably less
than 36,000 MW going the WFGD route. Sales of scrubbers in the U.S. in
1995 were very slow.

The international market was relatively healthy since Europe and Japan
did not have the option of switching to low sulfur coal. Acid rain was
having greater impact on European forests and lakes than in the United
States. Poland, the Czech Republic, and Slovakia burned very dirty
\"brown\" coal without adequate pollution controls. GEESI\'s projection
of WFGD demand outside the U.S. was a more realistic \$4.3 billion.

[Gas Turbine Market]{.underline}

There was a definite trend away from coal and toward natural gas as an
energy source in the U.S. As of 1990, there were 35 coal fired units
(16.38 GW) scheduled to come on line over the next ten years, and 203
natural gas fired units (18.475 GW) scheduled. By 1993, the number of
coal fired units scheduled had dropped to 16 (6.919 GW and an average of
432 MW per unit), while the number of gas fired units had increased to
278 (28.516 GW and an average of 103 MW per unit). These results have
been summarized in Table 1.

**Table 1**

**Planned U.S. Plant Additions (in the next 10 years), by energy source
and year**

**New Megawatts**

**New Units (Generator Nameplate)**

  ------------- ------------- ------------- -------------- --------------
                as of 1990    as of 1993    as of 1990     as of 1993

  Total         421           480           48,189         44,502

  Coal          35            16            16,380         6,919

  Gas           203           278           18,475         28,516

                                                           

  \% Coal       8.31%         3.33%         33.99%         15.55%

  \% Gas        48.22%        57.92%        38.34%         64.08%
  ------------- ------------- ------------- -------------- --------------

(source: Inventory of Power Plants in the US: Energy Information
Administration, 1990 Edition and 1993 Edition)

Independent power producers (IPPs) played an important role in the
market share gain gas turbine generators achieved.[^10] Lower capital
costs, shorter construction times (often two years or less), easier
siting and permitting, and simpler manufacturing of the modular gas
units added to the low risk of employing this generating mode in
comparison to coal. The long term problem with gas turbine generators
was the availability and price of the fuel. However, expectations were
for stable supply and prices for years to come.

It would be possible to estimate annual increases in electric power
capacity in the U.S. by starting with the total generating capacity in
place in 1995, roughly 500,000 MW (500 GW). With demand growing about 2
percent per year, one could expect annual capacity increases of 1-2
percent or 5 to 10 GW/yr. New capacity in 1994 was about 9.4 GW. Single
gas-turbines were priced at about \$190/kW \-- not including
installation and balance of plant. If 80 percent of new capacity
additions were gas turbine based, many of these being CCGT, one could
anticipate a U.S. market for gas turbine generators of about \$1 billion
per year.

Worldwide, the demand for new generating capacity was strong with
various projections ranging from 629 GW to 820 GW installed during the
period from 1994 to 2003.[^11] A good part of that would be coal fired
and nuclear, however. Siemens, a major international supplier of gas
turbines and steam turbines, estimated that world wide demand would
increase to a rate of 75 GW per year by 2000 of which about 28 GW per
year would be gas turbine systems.[^12] Gas turbine generator sales
could amount to \$4 billion annually.

Suppliers like GE and ABB reported good activity in the market for GTs
both in the U.S. and abroad. However, price competition had become very
prevalent. Siemens reported that power generation systems orders were
down sharply for the June quarter of 1995.

**THREAT OF NEW ENTRANTS**

**Electric Utility Industry**

This industry faced the significant threat of new entrants. Deregulation
was forcing growing competition in a heretofore sleepy regulated sector.
Increasingly, utilities were filling new power generation needs by
opening projects up for bids and treating their own power generation
subsidiaries at arms length. In recent decades, construction delays and
huge cost overruns had plagued many utilities and contributed to wide
electricity price disparities in the U.S.

The burden of environmental regulations was being transferred to the
IPPs that won bids, thus reducing the utilities\' own risk. Utilities
anticipated competition from utilities in adjoining areas and from IPPs
that had lower cost power. All of the utilities were under pressure to
reduce their own costs. This pressure affected their decision making
with regard to SO~2~ compliance, driving them to avoid anything but the
lowest cost solutions.

**Coal**

No threat of new entrants existed here. The Powder River Basin, the
dominant source for low sulfur sub-bituminous coal, was mined, under
lease from the federal government, by 14 different companies including
subsidiaries of five or six major oil companies.[^13] Competition was
strong and there was no visible new entrant on the horizon.

**Scrubber Suppliers**

The threat of new entrants was not a concern for several reasons: (i)
the technology was becoming more advanced; (ii) quite a few companies
had been in the business for some time and were well down the learning
curve, so that the cost of entry was high; (iii) domestic demand was
poor, discouraging new entrants into the U.S. from American and foreign
companies alike; (iv) international demand was much better but the
companies already in the industry had worldwide marketing and
engineering capabilities that gave them a strong advantage; and (v)
though the basic scrubber design was fixed, the final product had to be
customized to each coal burning facility because of the great
variability of these plants, so that only well established firms with
good reputations could be trusted.

**Gas Turbines**

Though there was far less customizing, established international firms
had a big edge. They had benefited from the learning curve for jet
engine manufacture. Either they were a jet engine manufacturer
themselves (GE) or they had formed close ties with other jet engine
manufacturers, such as Pratt and Whitney. All of the existing companies
had these relationships. Competition was fierce and a new advanced
product appeared every two years. Barriers to entry were formidable.

**LEADING SUPPLYING NATIONS**

For scrubbers, United States companies had the lead followed by
Switzerland, Germany, and Japan. In gas turbines, the U.S. led but was
in close competition with Switzerland and Germany. For sulfur dioxide
scrubbing and gas turbine equipment, the major competitors were
multinational corporations like GE, Siemens, ABB, and Westinghouse (WX)
whose home base was secondary to their international presence.

**COMPETING FIRMS**

**General Electric**

GE was one of the largest and most diversified companies in the world
with 1994 total revenues of \$39.6 billion. Excluding GE Capital, one of
the largest commercial lending and leasing companies, GE\'s Power
Generation division, primarily gas and steam turbine generators,
comprised 15 percent of revenues or \$5.9 billion, and its related
Aircraft Engine division 14 percent. In the U.S., GE\'s market share of
gas turbine generators from 1990-95 had been as high as 80 percent. It
achieved this dominance by being the first company to introduce a
combined cycle gas turbine (CCGT) with thermal efficiencies of 55
percent (its F technology).[^14] Most of its competitors ultimately
caught up bringing GE\'s market share down to about 50 percent in 1995.
The four major competitors could offer CCGT systems in the 57-58 percent
efficiency range in 1995. GE\'s announced its G series in 1995 reaching
CCGT efficiency of 60 percent. This product had the potential to
increase its market share again. GE also commanded a leading place in
the international market with about a 50 percent share. It accomplished
this lead by having many partners who were non-U.S. manufacturers and
packagers that used GE components. Twenty percent of GE\'s international
sales were by direct export.

The remaining market shares in the United States and world wide were
divided up among ABB, WX, and Siemens with ABB in second place world
wide and WX and Siemens tied for third place. In the U.S., WX and ABB
had about 20 percent each of the gas turbine market and Siemens about 10
percent. Siemens won a number of important U.S. contracts in 1995. Most
producers had to slash prices to get orders. The industry suffered from
over-capacity and its growth was not as large as expected. Siemens and
ABB did not have flexible labor forces, and they had to preserve market
share to maintain employment.

Earnings and cash flow for GE expanded consistently from 1985-95 at
rates of 11 and 9 percent respectively on revenue growth of only 4
percent per year. Revenue growth was accelerating with the revival in
industrial sector demand. However, power generation profits were under
pressure despite strong revenue growth because of the pricing issue
referred to earlier.

**Westinghouse Electric (WX)**

WX also was a diversified company but much smaller and far less
successful than GE. Its financial services division, which had been
discontinued, was beset with bad loans that put the company under stress
and near bankruptcy. The stock price had fallen from a high of 39 3/8 in
1990 to lows of 9 1/2 in 1992 and 10 7/8 in 1994. In 1995, it rebounded
to 15 with attention focused on the acquisition of CBS. Total revenues
in 1994 were \$8.85 billion. Broadcasting revenues comprised only 10
percent of these revenues, but contributed 33 percent of operating
earnings.[^15] Profitability was being dragged down by WX\'s Energy
Systems division, which serviced the nuclear power markets. It had 14
percent of revenues but only 1 percent of operating earnings. A small
furniture subsidiary had 6 percent of sales and losses totaling 11
percent of operating earnings.

In this context, Westinghouse\'s Power Generation division was doing
comparatively well with 19 percent of sales (or \$1.7 billion) and 15
percent of operating earnings. Power Generation\'s margins, close to 8.6
percent, however, were less than the company\'s overall operating
margins of 11 percent.

Earnings and cash flow had been dropping since 1990 and Power Generation
was having margin pressures despite rising sales due to price
competition overseas and a poor U.S. service market. WX had advertised
\"The World\'s Largest And Efficient 60 Hz Industrial Gas Turbine,\" the
501G, with an output of 230 MW (single turbine), 38.5 percent thermal
efficiency, and producing (when in tandem with a steam generator and
HRSG) the highest efficiency in the industry of about 58 percent.
However, GE\'s G turbine, which it announced in 1995, would be able to
surpass this level of efficiency.

**Asea Brown Boveri Ltd. (ABB)**

ASEA, a Swedish company and a long time leader in utility, electrical
equipment, and electric-rail equipment, merged with BBC Brown Boveri
Ltd. of Switzerland in 1988. 1994 total sales were \$29.7 billion of
which \$15.7 billion were manufactured products for the generation,
transmission, and distribution of electric power, which made it the
world\'s largest manufacturer of electrical energy related equipment.
ABB had purchased Westinghouse\'s transmission and distribution business
and the U.S. engineering firm of Combustion Engineering. The remainder
of ABB\'s revenues were related to the sale of environmental controls,
mass transit systems, and industrial equipment. Headquarters were in
Zurich. The company\'s Industrial and Building Systems division provided
capital improvements for industries such as pulp\\paper and steel and
drilling equipment for oil exploration.[^16]

Growth since 1990 had been negligible. Earnings fluctuated but cash flow
and sales were fairly constant in the 1990-95 time period. ABB\'s
stagnation was not surprising given the worldwide slump in the
industrial capital equipment sector in many parts of the world. ABB,
however, did appear to be breaking out into a period of growth starting
in 1995 with the revival of industrial investment and strong demand for
infrastructure in Asia. ABB\'s gas turbine sales world wide, based on
its 20 percent share, and including steam generators, was about \$2.4
billion in 1994. Its most advanced CCGT boasted an efficiency of 57-58
percent just behind Westinghouse.

**Siemens**

This well known German company was a leader in a range of technologies
for electrical engineering and electronics systems. Its products
included systems and services for telecommunications, electric power
generation and distribution, factory automation, electric-rail systems,
automotive electronics and other electronic and semiconductor
components, computers, and medical engineering. Total sales in 1994 were
\$51.1 billion which made it the largest of the four gas turbine
competitors considered here. This was somewhat misleading, however,
since GE\'s very large and important financial services subsidiary did
not add to GE\'s revenue figure. In 1994 GE\'s cash flow was exactly
twice Siemens\' cash flow of \$3.76 billion dollars. Siemens,
essentially a pure industrial company, was simply larger than GE
industrial.

Like ABB, Siemens had a difficult 1994 due to the economic slowdown in
Europe where its sales were the strongest. Sales to the more vibrant
Asia Pacific were only a small part of the company\'s revenues. Sales of
the Energy Systems division in 1994 were about 16 percent of total sales
or about \$8 billion dollars. June quarter 1995 results showed a slowing
in its power generation business. Although sales continued to climb in
this year over the prior year \-- up 6 percent, orders dropped 29
percent to \$3.4 billion. In June 1994, orders had been \$4.9 billion.

**GE Environmental Services Inc. (GEESI) and Competitors**

This subsidiary of GE was part of its Industrial & Power Systems
division. It was formed in 1981 when GE acquired two separate divisions
from two engineering firms. It had a strong portfolio of air pollution
control devices and its association with GE Power gave it ready access
to its markets. GEESI was a world-wide market leader in WFGD systems
with 26 percent of the installed base from 1981-1993.[^17] Its major
competitors were ABB at 13 percent and Babcock & Wilcox (B&W), a
subsidiary of McDermott International, with 12 percent of the world
market. In the U.S., GEESI shared market share leadership with ABB and
B&W with 30 percent each of the 1981-1993 installed base. ABB\'s
strength in the U.S. was due to its acquisition of Combustion
Engineering. These three closely competing companies had 90 percent of
the U.S. market. Mitsubishi Heavy Industries had managed to garner 6
percent of both world wide and U.S. market share. Deutch-Babcock had 9
percent of the market outside the U.S., but only a 1.5 percent U.S.
market share. ABB\'s and B&W\'s world wide market share were 9 and 8
percent. GEESI was successful in international markets because of its
partnerships with licensees in Europe, India, Southeast Asia, Japan, and
Korea.

**COMPETING TECHNOLOGIES**

No power generating technology threatened to displace the gas turbine as
the low cost environmentally friendly alternative to coal fired systems.
Fuel cells had an even lower environmental impact than gas turbine
technology and they were far quieter. They promised to offer high
thermal efficiencies comparable to the best that CCGT had to offer and
with better performance at lower output levels and for small (several MW
or less) units suitable for commercial, industrial, and institutional
sites. Costs, though, still were very high, so that fuel cells did not
look as if they would be competitive for at least five years or longer.

GE Environmental Services Inc. had developed an ammonia reagent WFGD
system which used most of the components of the limestone WFGD, but
replaced the limestone with ammonia, and yielded a byproduct of
granulated ammonium sulfate, a high value added fertilizer. GE had a
proprietary patented process that the company expected would give it the
entire market for this application for years to come. The capital cost
was 30 percent greater than for a limestone/gypsum WFGD and the SO~2~
removing capabilities were similar to the latter\'s. The additional cost
was for capability to treat the ammonium sulfate sludge to make it
marketable. Unlike gypsum byproduct, which was low priced and whose sale
did not provide a positive cash flow, granulated ammonium sulfate sold
for a high price and could yield positive cash flows.

The first installation of this system was coming on line in North Dakota
in 1996. The cost profile looked very favorable provided a growing
market for the byproduct developed. Although this technology, if it
performed as GEESI claimed, could increase the company\'s market share,
it would not have major impact unless an expanded market could be found
for its byproduct, the granulated ammonium sulfate fertilizer. One other
difficulty was that utilities did not want to enter the fertilizer
production business in which they had no experience and which was
subject to volatile pricing. Nevertheless, this system bore watching as
it was the only new technology that could challenge conventional systems
at a lower cost. World-wide demand for the new, lower cost ammonium
sulfate scrubber (when the facility is near a market for the byproduct)
could conceivably reach \$750 million to \$1.5 billion over the next
five years displacing 10 to 20 percent of the current higher cost
suppliers of ammonium sulfate fertilizer.[^18]

Other air pollution control devices, that could remove substantial
percentages of SO~2~, NO~x~, and many HAPs, were in the testing and
development stages; for example, the Mitsui \-- Bergbau Forschung (BF)
activated coke process that had been installed at facilities in Japan
and Germany. This type of product could become a significant factor in
the U.S. if HAP and NO~x~ standards were tightened to the levels found
in Germany and Japan (see later discussion).

**ENVIRONMENTAL, HEALTH AND SAFETY PRESSURES**

**The Acid Rain Problem and the 1990 CAA**

The 1970 Clean Air Act Amendments (CAAA) authorized the EPA to set
ambient standards for SO~2~ to protect health and prevent damage to
materials. It applied to concentrations at ground level and did not
prevent sources from building high stacks and transporting emissions to
other areas and states. In 1990, after a decade of debate, Congress and
the administration tackled the \"acid rain\" problem from coal fired
power plants and passed additional amendments to the Clean Air Act. Acid
rain, formed primarily when sulfur oxides and to a lesser extent
nitrogen oxides precipitate out of the atmosphere, had damaged many
forests and lakes. A major culprit was the high-sulfur coal used by
electric utilities and the nitrogen oxides, or NO~x~, that were formed
as a consequence of the combustion process. According to the EPA\'s 1989
emissions inventory[^19], utilities were responsible for 69.4 percent of
U.S. SO~2~ emissions and 32.4 percent of total NO~x~ emissions.

Implementation of sulfur dioxide emission reductions was to be achieved
in two phases.[^20] The first phase affected 260 units with power
ratings of 100 MW or greater situated at 110 power plants in 21 states.
These units, owned by 55 electric utility organizations, comprised about
13 percent of total U.S. electric generating capacity. They were chosen
by virtue of their emitting SO~2~ at an average annual rate of over 2.5
lb per MBtu of coal consumed and they were required to cut sulfur
dioxide emissions by January 1, 1995 to 2.5 lb/MBtu or less. Two-year
extensions could be given to plants that committed to buy scrubbing
devices that allowed continued use of high-sulfur coal. Utilities would
have to cut nitrogen oxide emissions as well, beginning in 1995. Except
for areas heavily impacted by smog, or other local situations that
prompted stricter controls, these NO~x~ restrictions were expected to be
met by installing low NO~x~ burners[^21] at a relatively low cost. Local
ambient air standards could result in lowered emission requirements for
SO~2~ necessitating the use of scrubbers.

The 1990 Clean Air Act Amendments also included an innovative
pollution-trading system.[^22] Under Phase I, generators were given
enough allowances (1 ton of SO~2~ per allowance) for them to emit the
maximum allowed 2.5 lb/MBtu. The total number of allowances granted to a
facility was based on its average annual number of BTUs of coal consumed
during the 1985-1987 period. On January 1, 1995, generators were
required to return to the EPA the number of allowances that corresponded
to their actual emissions. They could retain any that remained should
they be emitting below the limit of 2.5 lb/MBtu. This plan offered
electricity generators that cut their emissions by more than the
required amount the option to sell their \"unused\" pollution rights to
other utilities whose cost of SO~2~ emission reduction was higher than
the price of the allowances. Utilities might also have chosen to keep
the allowance for their own future use should they need to expand
capacity. Units that cut emissions by reducing output as a result of
energy conservation efforts were also able to earn allowances. Bonus
credits were awarded to dirty utilities that installed scrubbers, to
power plants in high-growth and extremely low-polluting states, and to
utilities that had already reduced their emissions before the CAA
Amendments took effect. A similar procedure was in place for the lower
limits required in Phase II.

In Phase II, beginning January 1, 2000, more than 1900 additional units
rated at 25 MW or greater as well as the Phase I affected plants would
have to make sulfur-dioxide cuts to attain emission levels of no greater
than 1.2 lb/MBtu. This deadline could be extended until 2004 for plants
that used new clean-coal technology. In addition, allowances would be
used so that a fixed cap on emissions of 8.95 million tons of SO~2~ per
year would be in force. New capacity would not be issued allowances but
instead had to obtain them from existing holders. To put this cap in
perspective, the DOE indicated[^23] that total power plant SO~2~
emissions in 1993 were 14.4 million tons leaving a required reduction of
about 5.4 million tons. The DOE further reported that SO~2~ emissions
dropped by 1.3 million tons from 1989 through 1993. With current SO~2~
Allowance prices near \$130/ton of SO~2~ removed, eliminating 5.4
million tons represented an allowance purchase cost of \$702M. New coal
burning facilities would be even further limited because of the
provisions of the 1970 and 1977 CAA Amendments pertaining to setting
\"New Source Performance Standards.\"

[New Source Performance Standards (NSPS)]{.underline}

The rules were very complex and applied on a case by case basis. The
1977 Amendments empowered the EPA to set NSPS for factories and plants
built after the Act\'s passage. In 1971 the EPA set the standard at no
more than 1.2 lb. of SO~2~ per MBtu. This strongly encouraged utilities
constructing a new coal-fired generating plant to design it for low
sulfur coal with sulfur content  0.6 lb/MBtu. This was a very favorable
development for Powder River Basin coal producers. Both environmental
advocacy groups and high sulfur coal producers were unhappy with this
provision and managed to convince Congress to attach language to the
1977 CAAA that prescribed the use of scrubbers as a part of the NSPS. A
sliding scale was put in place so that the plants using the highest
sulfur coal would have to install scrubbers capable of 90 percent SO~2~
removal rates to 70 percent removal rates for low sulfur coal users.
Although systems with 70 percent absorption rates are less costly than
those with 90 percent absorption rates, this provision dampened the
utilities\' enthusiasm for low sulfur (western) coal. These standards
clearly gave an impetus to the move by generators toward natural gas
turbine generators.

Existing plants that underwent modifications (improvements in boiler
efficiency for example) also might face re-permitting requirements and
come under the stricter provisions of the new source performance
standards. In this way, NSPS had the tendency to inhibit older coal
plant operators from improving their facilities.

[International SO~2~ Regulations]{.underline}

Acid rain provisions around the world varied.[^24] They were negligible
in China and very strict in Sweden, Germany, and Japan. Regulations,
such as in the former Soviet Republics or in Mexico, were quite severe
by law but not effectively enforced. There was more incentive abroad
than in the U.S. to construct flue gas desulfurization systems. Plans to
use FGD systems were strong in Asia. For instance, South Korea\'s 1995
SO~2~ emission standard was 1.2 lb/MBtu, the level the U.S. required
only by the year 2000. By 1999, South Korean facilities would have to
reach an emission level of no more than 0.6 lb/MBtu. While low sulfur
coal could meet the 1995 standard (and apparently South Korea has been
using such coal) it could not attain the 0.6 lb/MBtu standard without
FGD devices. Consequently, limestone/gypsum WFGD systems were being
installed at a 2000 MW station in that country and bids were being
prepared for 16 500 MW FGD systems. Furthermore, by 2006, 27 new
coal-fired plants, totaling 14 GW of capacity were scheduled to be built
and all of these would have to have some type of FGD system.[^25]

[Other Government Interaction]{.underline}

The DOE was involved in a \"Clean Coal Technology\" program to develop
better, lower cost pollution control technologies for coal-fired
generating plants. About \$7 billion had been spent[^26] (34 percent
from the federal government, 3 percent from state agencies, 51 percent
from power generators, and the remainder from the private industry
participants). Over \$4.7 billion of this money was devoted to advanced
electric power generation technologies such as fluidized bed and
integrated coal gasification projects. Another \$687 million was
allocated for developing environmental control devices including several
inexpensive low NO~x~ burner systems and lower cost 50-60 percent SO~2~
removal systems applicable for retrofitting older boilers. Several
advanced WFGD systems were part of the program as well. B&W, ABB, Pure
Air On the Lake, L.P. (a limited partnership jointly owned by Air
Products and Chemicals and Mitsubishi Heavy Industries), and AirPol
participated with SO~2~ control projects. GE Environmental Services,
Inc. did not participate.

**INNOVATION IN RESPONSE TO ENVIRONMENTAL PRESSURES**

**The Natural Gas Turbine**

Natural gas turbine (GT) and combined cycle gas turbine (CCGT) electric
power generating systems had experienced dramatic technological and cost
improvements driven, at first, by non-environmental forces, but more
recently by environmentally friendly features as well as technical and
economic benefits.

Two important but independent technological developments, not
environmentally driven, came together to open the market for gas turbine
generating systems:

\(i\) The costs of finding natural gas fell dramatically due to high
performance PCs and work stations capable of processing 3D seismic data
and due to advanced drilling technologies such as horizontal drilling
systems. These technologies were a byproduct of the need to find
petroleum more cheaply and of the explosive innovations in
microprocessors and memory devices.

\(ii\) Constant technological advances in jet engine design and
manufacture, fostered by a high level of both military spending and
spending for commercial aircraft, enabled these engines to be
successfully adapted for electric power generation.

Environmental pressures also contributed to these advances. Natural gas,
recognized as a \"clean\" fuel was regarded as being even more
attractive after passage of the 1990 CAA. There were no SO~x~ emissions
to control. NO~x~ emissions, even without controls, were considerably
below that coming from coal-fired boilers. HAP emissions were less and
mercury and other heavy metals were not present. The CAA focused the
natural gas industry on competing for the new power generation market.
It contributed to directing increased resources to finding and
developing natural gas reserves in response to the expected growth in
demand. It also played a role in the increased investment in gas turbine
technology development and the rapid technological advance.

In both natural gas exploration and gas turbine technologies, the
innovations came from incremental steps nurtured and facilitated by
countless innovations in other areas ranging from better materials to
computer aided design and analysis.

After the passage of the 1990 CAA Amendments, the four fiercely
competitive major manufacturers, led by GE, drove the thermal efficiency
of combined cycle gas turbine generators (CCGT) from under 55 percent to
the 60 percent achieved by GE\'s 1995 announced G series model. Because
coal-fired systems have much lower efficiencies, a 60 percent efficient
CCGT has equal fuel operating costs at a natural gas price of 1.8 times
the price of coal. With low sulfur western coal priced in 1995 near
\$1/MBtu and natural gas delivered price to large industrial or utility
customers in many parts of the country in the neighborhood of
\$2.00/MBtu, the fuel operating cost difference between advanced CCGT
and coal systems became small. Of significance was the fact that 1995
natural gas discovery costs had fallen to about \$1.70-1.80/MBtu. With
the capital costs for NG fired plants being much lower than coal fired
plants, NG plants had clear advantages over coal.

**Low Sulfur Coal from the West**

The Powder River Basin in Wyoming and to a lesser extent Montana, had
large reserves of low sulfur coal (mostly ranging from 0.25 lb/ MBtu to
0.60 lb/MBtu) contained in thick veins lying close to the surface.[^27]
Serious development of the mines began with the passage of the CAA in
1970. The 1971 version of new source performance standards created
demand for low sulfur coal. The oil supply crises of the 70s and
skyrocketing energy prices inspired investment. The 1980s saw
substantial advances by the mining companies[^28] in improving
productivity with larger more efficient earth movers, trucks, and other
equipment. As a result, 1995 operating costs were estimated to be
\$3-4/ton or about 14-23/MBtu. A miner in Wyoming and Montana produced
over 20 tons of coal in an hour, in contrast to Appalachia where an
hour\'s labor brought in only 3 tons of coal.

Western coal was selling for about \$1/MBtu delivered to utilities in
such states as Nebraska, Iowa, Kansas, Minnesota, and Wisconsin (spot
prices as low as \$0.80/MBtu existed). A large fraction of the delivered
cost of Powder River Basin low sulfur coal was the cost of
transportation. Burlington Northern (BN) led the way in developing rail
transportation from the Powder River Basin. During the 70s, tracks to
the many mines had to be laid and, while the Chicago & Northwestern
(C&NW) jointly owned the rights of way, it was BN which had the initial
capital to lay the tracks.[^29]

Burlington Northern began delivering coal to utilities first and enjoyed
several years of monopoly and high rates until the ICC stepped in after
protests from BN\'s customers.[^30] Chicago and Northwestern (C&NW)
joined with Union Pacific (which now owns C&NW) to offer competing
service in mid 1984. Competition was unleashed, rates dropped, and the
rails entered the long struggle to cut operating costs and improve
efficiency.

The railroads engaged in an ongoing process of improving operating
efficiency bringing together technology advances from many sectors:
computers and automation for better scheduling and traffic controls (a
major problem given the enormous volume of traffic involved), electric
and diesel motor technologies for more powerful locomotives at lower
cost (here GM and GE were in strong competition), better coal hoppers,
and better tracks. The end result was that the transportation costs to
deliver a ton of Powder River Coal to distant utility markets was lower
than it was before 1984 and comparable to prices in 1984 before C&NW
entered the market. In current dollars prices were down over 40 percent
in real terms since 1984.[^31]

The continued growth prospects the railroads saw for western coal
hauling continued to spur technological improvements. A new, more
powerful locomotive introducing AC electric traction motors promised to
lower operating costs.[^32] Burlington Northern designers and engineers
designed a \"Trough Train\" composed of extended cars of 13 articulated
sections that increased the coal carrying capacity of a unit train by
30-40 percent. The doors were completely redone for easier unloading and
the new more aerodynamic exterior reduced wind resistance. Lighter car
bodies made of aluminum replaced steel to further improve the efficiency
of the coal delivery system.[^33] BN\'s vision of the future was to
develop the low-sulfur Powder River Basin coal market in the Eastern
U.S., Canada, the Pacific Rim, Europe, Mexico, and beyond. Thus, it
needed to drive prices down still further. As Table 2 below shows, this
vision was close to becoming a reality.

**Table 2**

  --------------- ------------- ------------- -------------- --------------
  Receiving State Wyoming Coal  Wyoming Coal  Avg. Price All Avg. Sulfur
                  Delivered     Sulfur        Coal Delivered Content All
                  Price         Con-tent      (\$/MBtu)      Coal (lb/MBtu)
                  (\$/MBtu)     (lb/MBtu)                    

  Arkansas        1.70          0.38          1.70           0.38

  Georgia         1.45          0.37          1.78           1.14

  Indiana         1.20          0.39          1.27           1.61

  Kentucky        1.22          0.59          1.17           2.09

  Louisiana       1.63          0.52          1.59           0.66

  Massachusetts   1.75          0.34          1.68           0.80

  Michigan        1.09          0.33          1.53           0.59

  Texas           1.67          0.40          1.44           1.15
  --------------- ------------- ------------- -------------- --------------

(source: U.S. Department of Energy, Energy Information Administration,
*Cost and Quality of Fuels for Electric Utility Plants 1993)*

**Sulfur dioxide scrubbers**

The scrubber industry took two approaches to competing with low sulfur
coal and gas turbine generators: (i) reducing the costs of limestone
WFGD systems; and (ii) seeking alternative scrubbing technologies. From
1985-95, conventional limestone WFGD systems came down in real price as
overall costs stayed roughly constant in current dollars.[^34] Though it
was a substantial reduction in cost, it was not enough for WFGD systems
to be competitive with the fuel switching option at many utilities.
Technological development centered on speeding up the limestone feeding
system, thereby enabling designers to reduce the size of the unit and
hence its cost. Overall advances were spurred by sales opportunities
abroad and stiff competition for these opportunities.

An alternative approach was to take advantage of stricter NO~x~ emission
standards and coming HAP emission requirements and develop an all-in-one
system to reduce the cost compared to separate units to solve each
problem. All the major competing air pollution control companies had
combination (SOX-NOX) scrubbing systems.

*Babcock and Wilcox* had a \"SO~x~-NO~x~-Rox Box\" removing 80-90
percent SO~2~, 90 percent NO~x~, and 99 percent particulates (Rox).
According to the DOE[^35], the capital cost was estimated at \$260/kW
for a 250 MW plant which was comparable to the sum of the cost for
scrubbers, NO~x~ control systems and particulate capture devices such as
electrostatic precipitators (ESP) or baghouses. This capital cost was
high and while the NO~x~ removal rate was excellent the SO~2~ removal
rate could have been higher. The DOE report cited the \"potential for
lower capital and operating costs and smaller space requirements than
for a combination of control technologies.\" The system was operating
successfully at an Ohio Edison plant in Dilles Bottom.

*ABB Environmental Systems* had a SNOX^TM^ technology that was also
being tested at an Ohio Edison facility, this one at Niles Station.
According to the DOE, \"The utility is making the technology a key part
of its 1990 CAA compliance strategy.\"[^36] The SNOX system was
achieving 94 percent removal rates for NO~x~ and 96 percent SO~2~
absorption resulting in marketable sulfuric acid as the byproduct. No
solid waste was produced. No cost figures were available. ABB\'s
approach combined the strategy of a marketable, more valuable byproduct
and a combined removal system. Neither ABB nor B&W had attacked the
problem of HAP emission controls. Both of the above systems were
developed with the help of DOE funding under the Clean Coal Technology
program.

*GEESI* licensed to develop a system by Bergbau Forschung and for
Japanese markets by Mitsui Mining (see earlier mention of this
technology). GEESI planned to adapt the system for North American
markets. The system used activated coke produced by Mitsui, which was
much cheaper than activated carbon. The system had been tested in plants
in Germany and Japan and was capable of very high (\>98 percent) SO~2~
removal rates, 70-90 percent NO~x~ removal, \>90 percent flyash capture,
and high removal rates for several air toxics (including 99 percent
mercury capture). It produced either sulfur or sulfuric acid as a
marketable byproduct. The system did not seem to be able to handle the
higher inlet concentrations associated with burning high sulfur coal.
The capital costs, still uncertain, were estimated to range from
\$80-190/kW. This system could be a competitive offering with the coming
of HAP and new source performance standards.

**INNOVATIVE FIRMS**

The customers for these technologies were in the electric utility
industry.[^37] This industry was undergoing dramatic change driven by
industrial customers in search of lower costs and by state and federal
regulators slowly moving towards increased deregulation and competition.
Most utilities charged their captive industrial customers an electricity
price that was higher than the marginal cost. Neighboring utilities
often had different prices for their electricity, a disparity that could
arise from a variety of causes.[^38] Large consumers of electric energy
saw nearby utilities offering power at lower rates than their own
utility did and pressed regulators to permit \"retail wheeling.\" They
sought to require the local utility to transmit the power of another
utility to supply them with electricity. Regulators were reluctant to do
so for fear that higher cost utilities would be forced to write off
inefficient plants. Most utilities, however, expected some degree of
retail wheeling to evolve and were planning for it.

These new competitive forces in the electric utility industry were the
result of similar forces in the global economy. Manufacturers were in a
position where cost increases could not be easily passed on to
customers. They had to cut costs to maintain profitability and market
share. Inject the 1990 Clean Air Act Amendments and the utility
industry, beset by cost conscious customer, had to absorb costs that
could not be passed-on. The result was the utilities\' relentless search
for lowest cost solutions to problems posed by CAA compliance.

The utilities faced two challenges:

\(i\) how to comply with Phase I and II of this act?

\(ii\) how to meet new generation capacity needs given NSPS?

To illustrate how they faced these challenges let us take the example of
a group of utilities located in a region that sweeps an arc from the
Southeast into Texas. These utilities were all large and in an area of
the country with above average growth in the demand for electricity
because of its vibrant economy and expanding population. In the case of
augmented competition and advancing deregulation, they would become
competitors for some of the same industrial customers. Together they
generated 22 percent of all power in the U.S.

Below in parentheses were the average prices in /kWh that they charged
their industrial customers in 1994, the population served in millions,
and the percentage of capacity provided by their coal-fired
facilities.[^39]

 Baltimore Gas and Electric (4.64/kWh, 2.6M, 44% coal)

 Dominion Resources (Virginia Power) (4.33/kWh, 1.8M, 39% coal)

 Duke Power (4.24/kWh, 4.9M, 43% coal)

 Carolina Power and Light (5.29/kWh, 3.5M, 60% coal)

 Southern Company (Georgia Power, Alabama Power, Mississippi Power,
etc.) (3.70-4.52 with a system wide average of 4.30/kWh, 11M, 73% coal)

 Florida Power and Light (FPL Group) (4.91/kWh, 6.5M, 6% coal)

 Florida Progress Company (FPC) (4.84/kWh, 1.2M, 31% coal)

 Entergy Corporation (Louisiana Power & Light, Gulf States, Arkansas
Power and Light, etc.) (3.98-5.21 with a system wide average of
4.47/kWh, 2.4M, 16% coal)

 Houston Industries (Houston Lighting and Power) (4.38/kWh, 1.4M, 43%
coal/lignite)

 Texas Utilities (4.24/kWh, 5.7M, 26% lignite by capacity but over 40%
lignite for actual power generated)

A high level of coal fired power and high industrial prices meant a
larger competitive effect from the 1990 CAA. Thus, the Southern Company
and Carolina Power and Light (CPL) were the most adversely affected by
the passage of this act.

**Complying with the CAA: Existing Coal-fired Facilities**

Below, we summarize how these utilities complied with the CAA.[^40]

*Baltimore Gas & Electric* met the requirements of Phase I by installing
flue gas desulfurization systems, switching fuel, and retiring some
units. The necessity for compliance with existing standards and
regulations (not just the Clean Air Act) caused BGE to increase capital
expenditures by approximately \$206 million during the five-year period
1990-1994. If all the expenditure were on coal-fired capacity only,
which is unlikely, it would mean capital spending of \$81/kW. BGE
estimated that the capital expenditures necessary to comply with such
standards and regulations would be approximately \$16 million, \$9
million, and \$16 million for 1995, 1996, and 1997, respectively.

The DOE\'s 1993 Cost and Quality of Fuels Received by Electric Utilities
reported on three coal-fired BGE facilities. One very large plant,
Brandon Shores, and a small one, Wagner, comprising 78 percent of the
total output of the three plants, used low sulfur coal from Kentucky and
West Virginia with an average sulfur content of 0.56 lb/MBtu costing
about \$1.55/MBtu and putting them in compliance with Phase I of the
1990 Clean Air Act Amendments and earning allowances. The remaining
small plant, Crane, burnt higher sulfur coal from mines in these two
states with sulfur content averaging 1.47 lb/MBtu at a price of
\$1.51/MBtu.

BGE planned to meet Phase II by using some combination of fuel
switching, flue gas desulfurization, unit retirements, and/or allowance
trading. The sulfur content of the utility\'s large Brandon Shores
facility at 0.53 lb/MBtu would meet Phase II requirements but the small
Wagner plant burning 0.66 lb/MBtu sulfur coal would be just barely out
of compliance, a situation it could easily remedy by contracting for a
slightly lower sulfur content coal or purchasing a small number of
allowances each year.

BGE estimated that the NO~x~ controls at its generating plants would
cost approximately \$70 million (about \$28/kW if all coal-fired plants
are involved) sometime between now and 1999.

*Dominion Resources (Virginia Power)* installed a scrubber on one of its
three units, at its Mt. Storm coal-fired facility, at a cost of \$147
million (very roughly about \$250/kW). Mt. Storm was by far the
utility\'s largest coal-fired generating station. The company was
assessing whether to install two more scrubbers at Mt. Storm or to rely
on allowance purchases for compliance. Dominion estimated that the three
scrubbers, NO~x~ controls, and continuous monitoring (CEM) equipment
would come to \$481 million in 1992 dollars (or about \$526 million in
1995 dollars).

DOE 1993 coal purchasing data indicated that Virginia Power consumed low
sulfur Appalachian coal at all but its Mt. Storm facility which was
responsible for about 40 percent of the utilities coal based capacity.
The sulfur content of the latter plant\'s fuel was 1.42 lb/MBtu, while
the sulfur content of the coal used elsewhere ranged from 0.75-0.85
lb/MBtu except at one small facility employing 1.18 lb/MBtu coal. Mt.
Storm was, therefore, out of compliance with Phase I, while the
remaining plants were out of compliance with Phase II. Mt. Storm\'s
higher sulfur coal was about \$0.17/MBtu cheaper than the low sulfur
Appalachian consumed elsewhere.

*Carolina Power & Light* reported that no further action was necessary
in order to comply with Phase I. Phase II compliance would be achieved
by burning low sulfur coal and eventually installing scrubbers but
delaying their installation until 2007 by purchasing allowances. Some
allowances already had been purchased in 1993 and 1994. Phase II
compliance costs were estimated at \$273 million for the period
1995-1999 and \$272 million for 2000-2007. These total expenditures, if
spread out over Carolina\'s entire coal-fired capacity of 6,331 MW, came
to \$86/kW. Since scrubber installation was not scheduled until 2007,
most of the expenditures were probably for NO~x~ controls. The company
asserted that its plans for compliance were not \"finalized\" and that
they were still under review and consideration.

The DOE 1993 data for Carolina Power & Light\'s coal purchases revealed
that of the utility\'s eight coal-fired plants included in the survey,
two were very small, three small, and one was very large, with about
half its total generating capacity. All the plants consumed coal from
Kentucky, West Virginia, and to a lesser extent Virginia. With one
exception, the second largest plant, Mayo, the sulfur content of the
coal was about 0.80 lb/MBtu putting them in compliance with Phase I but
out of compliance with Phase II. (0.80 lb/MBtu sulfur becomes 1.6
lb/MBtu of SO~2~ in the flue gas while Phase II requires no more than
1.2 lb/MBtu.) The Mayo facility was burning low sulfur coal in
compliance with Phase II. If 1993 coal purchases approximated the
quantity, quality, and sulfur content of the coal to be burned during
the Phase II non-compliance years, the utility would have to spend about
\$5.2 million on allowances per year from 2000 until 2007, based on an
allowance price of \$130/ton. However, this price could rise near the
year 2000 if enough utilities adopted Carolina\'s approach to
compliance.

*Duke Power* met all its requirements under Phase I by burning low
sulfur Appalachian coal. Environmentally related capital costs (not
exclusively CAA related) for 1995-1999 were only \$50 million or less
than \$7/kW of coal based capacity. These costs did not include plans
for compliance with Phase II. Plans for the latter were being developed
with a wide range of estimated capital costs of \$260 to \$750 million.
Even the high end estimate, however, was relatively modest, coming to
only \$98/kW of coal-fired capacity, with \$260M equating to \$34/kW.

The DOE data for 1993 showed that Duke purchased coal from Kentucky,
Virginia, and W. Virginia with a sulfur content ranging from 0.69 to
0.91 lb/MBtu and averaging in the neighborhood of 0.8 lb/MBtu. Delivered
coal prices varied from plant to plant, ranging from \$1.54 to
\$1.80/MBtu. Duke\'s coal-fired capacity was dominated by two very large
facilities which paid \$1.65 and \$1.71/MBtu. Price differences were not
directly correlated with the variations in the sulfur content of the
coal, although coal with twice the sulfur content was quite a bit
cheaper. Similar to the case for Carolina Power & Light, the sulfur
content of Duke\'s coal was in compliance with Phase I but not with
Phase II. Allowance purchases totaling approximately \$6.8 million per
year would keep Duke in compliance with Phase II, provided allowance
prices remained at \$130/ton.[^41] However, the company wanted to take a
diversified approach to compliance: employing a mix of allowance
trading, using low sulfur coal, and installing scrubbers.

In order to earn bonus allowances from 1995-1999, Duke agreed, under
404E of Title IV of the CAA, to switch from 0.8-0.9 lb/MBtu sulfur coal
to 0.7 lb/MBtu. The company\'s supply of low sulfur Appalachian coal was
fairly secure because of the long term relationship established between
Duke and its coal suppliers. A decision was being weighed on whether or
not to install scrubbers at a capital cost of \$350 million (\$156/kW)
at Duke\'s 2,240 MW Belews Creek Station. The utility was unwilling to
rely too heavily on allowance purchases to make up any Phase II
non-compliance because, in its 20-30 year horizon, allowances were too
uncertain.

*Southern Company* was a large utility holding company that included
Georgia Power, Alabama Power, Gulf Power, Mississippi Power (not to be
confused with Mississippi Power & Light), and Savannah Electric Power.
Its generating capacity was heavily weighted towards coal and it was the
most heavily CAA impacted utility in our group. Eight plants, 35 percent
of Southern\'s capacity, were affected by Phase I. Compliance
requirements were met by switching to low sulfur coal and installing low
NO~x~ burners. This approach earned the company surplus emission
allowances that it could employ towards achieving Phase II compliance.
All of Southern\'s coal-fired plants were affected by the CAA Phase II
requirements and the company was assessing the optimal mix of the three
options \-- fuel switching, installing FGD equipment, and purchasing
allowances. Additional NO~x~ controls would also be needed.

DOE coal purchasing data showed that by 1993 most of Georgia Power\'s
plants were in compliance with Phase I by virtue of burning low sulfur
coal from Appalachia but were not in compliance with Phase II. Georgia
Power was sampling Powder River Basin coal at its large Schemer
facility. This coal was delivered at the spot price of \$1.45/MBtu.[^42]

*Entergy Corporation* had no need to install additional SO~2~ control
equipment to comply with Phase II. Phase I was no problem for the
company as it had been issued more allowances than it needed and it
expected to have excess allowances for sale to others under Phase II.
The company\'s compliance requirements necessitated spending of \$5.7
million on NO~x~ controls and \$14.7 million on continuous emissions
monitoring equipment (CEM). Future capital investments were estimated to
be \$16 million in NO~x~ controls \-- a relatively minor sum, and \$3
million for additional CEM equipment.

DOE data on Entergy\'s coal purchases in 1993 revealed that its
subsidiary, Arkansas Power & Light, used 100 percent low sulfur coal
from Powder River Basin (0.24 and 0.48 lb/MBtu priced at \$1.68 and
\$1.80/MBtu respectively). Its Louisiana subsidiary, Gulf States
Utilities\' coal-fired facility did so as well (0.52 lb/MBtu priced at
\$1.71/MBtu). The state of Louisiana as a whole consumed a mixture of 20
percent (by heat content) low Btu Louisiana coal with 1.12 lb/MBtu
sulfur and priced at \$1.39/MBtu and 80 percent Wyoming coal with 0.52
lb/MBtu of sulfur and priced at \$1.63/MBtu for an average sulfur
content of 0.66 lb/MBtu. It should be noted that most if not all of
these coal purchases were by contract and the delivered spot price was
lower. This use of coal put Louisiana\'s utilities just outside of Phase
II compliance but it could be remedied by increasing the percentage of
Wyoming coal consumed by the year 2000. It is clear from this example
that Powder River Basin low sulfur coal had extended its reach as far
South and East as Arkansas and Louisiana. This low cost coal mining
center and the railroads that serve it are looking even further East as
can be attested by the fact that Georgia Power is sampling its product.

*Florida Power & Light* had very little coal-fired generating capacity.
Its expected capital expenditures for the 1995-1999 period were from \$5
to \$16 million per year. The company did not comment explicitly on its
CAA requirements. There were no DOE coal purchase data. Phase I & II
compliance requirements for coal-fired facilities were not a material
issue for this very large Florida utility.

*Florida Progress Corporation (Florida Power)* also stated that it was
not \"materially affected by either Phase I or Phase II.\" To meet Phase
II limitations, it was implementing a strategy based primarily on
burning cleaner fuels. Continuous emission monitors were installed on
most of Florida Power\'s units by the end of 1994 at a total cost of
approximately \$11 million. Compliance with nitrogen oxide limitations
would require the installation of low nitrogen oxide burners on some
coal fired units. These costs would be approximately \$8 million between
1995 and 2000. Florida Power\'s construction program included
approximately \$14 million of planned environmental expenditures for air
quality projects for the two-year period ending December 31, 1996.

DOE data for 1993 indicated that the utility was burning low sulfur
Appalachian coal, primarily from Kentucky and with a sulfur content
averaging 0.64 lb/MBtu. Thus, Florida Power was almost in compliance
with Phase II. The difference could be made up easily with small
purchases of allowances, switching to slightly lower sulfur coal,
installing a scrubber at one of its facilities, or some combinations of
these options. The company was paying about an average of \$1.80/MBtu
for the coal.

*Houston Lighting and Power Company* built all its coal fired generating
capacity after New Source Performance Standards (NSPS) were in force and
consequently had no SO~2~ emission compliance requirements under Phase I
or II aside from expenditures for CEM equipment of \$4 million in 1994
and a projection of \$7 million for 1995. Houston estimated that the
1977 low NO~x~ emission standards would cost the company up to an
additional sum of \$40 million.

The DOE coal purchasing data for 1993 showed that Houston Lighting &
Power had two very large coal burning facilities, Limestone and Parish
Stations. The larger plant, Parish, responsible for about 60 percent of
the power generated by Houston\'s coal-fired facilities, burned Powder
River Basin coal with a sulfur content of 0.45 lb/MBtu and at a
relatively high [contract]{.underline} price of \$2.08/MBtu. Houston
Lighting, therefore, decided to satisfy its NSPS requirements at Parish
by burning low sulfur western coal despite its relatively high cost. The
Limestone plant consumed Texas lignite with a 1.77 lb/MBtu sulfur
content but priced at only \$1.27/MBtu. The latter facility installed
scrubbers in order to meet its New Source Performance Standards.

*The Texas Utilities Company* asserted in its 1994 10K that Phase I had
no impact on the company and that 52 of Texas Utilities\' 56 generating
units were already in compliance with Phase II. The utility further
asserted that compliance with Phase II would not have a significant
impact on the company but if it did it would simply pass the costs on to
its customers. The company did warn that certain of its lignite burning
facilities might have to operate at reduced loads from time to time in
order to maintain compliance. Texas Utilities had spent \$38 million
from 1992-1994 on CEM equipment at its lignite generating plants.
However of these 56 generating units referred to above only 9 were coal
fired systems, the remainder being either nuclear or natural gas
fueled.[^43] Five of these nine coal based units were constructed after
NSPS was in place. All had wet limestone flue gas desulfurization
systems installed capable of scrubbing 60 to 80% of the flue gas\' SO~2~
to meet the NSPS emission limit of 1.2 lb/MBtu. These scrubbers were
early models and proved difficult to bring up to full performance
capabilities. The remaining 4 coal fired generating units were all built
before NSPS and are the only facilities to come under phases I & II of
the 1990 CAA Amendments. Since coal based generation was relatively new
to Texas, a state that relied heavily on natural gas as a plentiful,
locally produced fossil fuel, these 4 pre-NSPS units are the only
coal-fired systems in the state impacted by phase I and phase II.

DOE data showed the utility with four large to very large lignite-fired
facilities. The fuel was of low quality with a high ash content and
heating values that varied from 5848 to 6649 BTUs per pound (Powder
River Basin coal has about 8500 BTUs per pound and Appalachian coal,
while varying, tends to be around 12,000 BTUs per pound.). Out of a
total coal fired name-plate capacity of 5875 MW, the 5 units with
scrubbers comprised 61% of the total. Four of the five consumed lignite
with sulfur content of about 1.7 lb/MBtu and an average 1993 price of
approximately \$1/MBtu, the fifth plant burned somewhat lower sulfur
lignite priced near \$1.30/MBtu.

The four older Texas Utilities\' units that had to meet Phase I and
Phase II requirements were in compliance with Phase I by burning low
sulfur lignite: the two 575 MW units at *Big Brown* consumed, in 1993,
lignite averaging 1.19 lb/MBtu of sulfur and contracted at a price of
\$1.06/MBtu and the two 575 MW units at *Monticello* burned lignite
averaging 0.87 lb/MBtu of sulfur and contracted at a price of
\$1.27/MBtu. The utility had yet to make the decision to either switch
to lower sulfur Phase II compliant western coal or install scrubbers.
The company earned no allowances under Phase I but would be eligible for
them under Phase II. In contrast to the situation for generators
replacing higher heat content Appalachian coal with low sulfur but low
heat content western coal, Texas Utilities needed no boiler
modifications to substitute western coal for its lignite since the
former\'s heat content tended to be about 25% higher and its ash easier
to handle. It should be noted that the company had contracts for
purchasing its Phase I lignite at very attractive prices. If Texas
Utilities chose Phase II compliant western coal instead of installing
scrubbers, the Wyoming coal had to come down to an acceptable delivered
price, probably in the neighborhood of \$1.50/MBtu or less. Furthermore,
since the utility was burning low sulfur lignite, its cost of capturing
a ton of SO~2~ was high although the cost per kWh was not. This made
allowances priced at \$130 to \$200/ton of SO~2~ a very attractive
alternative. Texas Utilities had deferred construction of any new coal
fired base load capacity for at least ten years as a new nuclear
facility was projected to satisfy any growth in demand.

Utilities in Texas purchased by far the largest amount of Powder River
Basin coal of all the states receiving shipments in 1993. This would
include many electric energy generators not considered above such as
Southwestern Public Service, Southwestern Electric Power, the City of
San Antonio, and others. The sulfur content of this western coal was in
all cases below 0.40 lb/MBtu corresponding to 0.8 lb SO~2~/MBtu and well
below the 1970 Amendments to the CAA New Source Performance Standard
(and the phase II compliance level) of 1.2 lb SO~2~/MBtu. All of these
generating units in Texas came under this NSPS. It is highly unlikely
that any facility coming under the more stringent NSPS of the 1977 CAA
Amendments[^44] had switched to the higher priced Powder River Basin or
other western coal. The average 1993 price paid for Texas lignite by all
Texas utilities was \$1.17/MBtu while the average price for all Powder
River Basin coal delivered to Texas in 1993 was \$1.67/MBtu. The
variation in price of the Wyoming coal was considerable with contract
prices as high as \$2.10/MBtu at a Southwestern Public Service plant and
as low as \$1.18/MBtu at San Antonio. Some facilities also purchased
Wyoming coal on the spot market at considerably lower prices, for
example, the SW Public Service plant that paid the highest contract
price bought 11% of its supplies from Powder River on the spot market at
\$1.08/MBtu. It is clear that the high priced contracts would be rolled
over at considerably lower prices.

All Texas electric power generators purchased 90.71 million tons of coal
in 1993: 40.8% from Wyoming, 2.0% from Colorado (similarly low in sulfur
but with a higher heat content than Wyoming coal), and 57.1% from Texas
(low quality lignite with an average sulfur content of 1.7 lb/MBtu).
Texas lignite had a considerably [lower]{.underline} heat content than
the Powder River Basin coal, the reverse of the usual situation when the
Wyoming coal replaced Appalachian coal. This eliminated the need, when
substituting Powder River coal for Texas lignite, for costly
modifications of the boilers and of a derating of the facility.

**Complying with the CAA with new facilities\--New Source Performance
Standards**

New electric energy generating systems also faced stricter SO~2~
emission standards which would force them to install scrubbers on new
coal-fired units. For instance, NSP\'s last large base load coal-fired
unit in 1986 was designed to consume western low sulfur coal in
compliance with Phase II, but it had to install scrubbers and other air
pollution control devices. The total capital cost incurred was \$275/kW
which added to the facility\'s cost by about 1/3.[^45] These high
additional costs were having a dampening effect on utilities\' decisions
to install new coal based capacity.

The ten utilities in our sample had planned a total of 7 coal-fired
units in 1990 but only 3 of these remained in 1993 plans. In contrast, 9
gas units were planned in 1990 but 21 were planned by 1993. Since then,
Duke was completing its huge Lincoln Gas Turbine Station designed to
provide peaking power up to 1,184 MW. This \$500 million facility
(\$422/kW)[^46] was not included in the 21 units planned in 1993.
Carolina Power & Light was planning the addition of one gas unit
according to the 1993 DOE report, but announced in 1994 that it was
planning 225 MW of GTs at \$320/kW in 1997, 1,200 MW of GTs at about
\$250/kW for 1998-2000, and 1,400 MW of GTs between 2000 and 2007. It
also announced that it would build 500 MW of coal-fired capacity for
2008.[^47]

Florida Power and Light, had met its capacity needs beyond 2000 by
acquiring an existing 646 MW coal based unit from Southern Company and
two 430 MW combined cycle gas turbine units. This addition was base load
gas-fired capacity where the high efficiency of the CCGT compensated for
the higher fuel cost. FP&L already relied a great deal on oil and gas
for its fossil fuel based generating systems \-- largely for
environmental reasons but also because of its long distance from coal
supplies.

**EFFECT OF ENVIRONMENTAL REGULATIONS ON INDUSTRY**

In the last section we saw that switching to low sulfur coal, albeit in
most cases eastern low sulfur coal, was still the primary approach taken
by the group of utilities analyzed to reach compliance under the 1990
Amendments to the Clean Air Act (see Appendix A). They were slow to
install scrubbers. Those that did made them a part of a three pronged
solution: low sulfur coal, allowances, and scrubbers. Fuel switching
usually was the low cost option, allowances could make an important
contribution but uncertainties about them were restricting their wider
use, and scrubbers were still too expensive but were being employed
judiciously by utilities as part of a mix of all three approaches.

A number of these utilities were also beginning to use low sulfur
western coal. The efforts of Burlington Northern and Union Pacific to
expand markets for Powder River Basin coal bore watching. As of 1993,
the contract price for this coal along Southern rail routes, i.e. Texas,
Louisiana, and Arkansas remained high but spot prices indicated that
contract prices would be falling. Further East, Georgia Power\'s Scherer
plant was sampling Powder River Basin coal (26.3% of the facility\'s
1993 coal purchases) at an attractive price on the spot market of
\$1.45/MBtu, well below the utility\'s average coal purchase cost of
\$1.78/MBtu for that year.

Finally, it was clear that gas turbines had captured the new peaking
capacity market. Prices from \$250-422/kW made them ideal for this
purpose. The new Duke Power Lincoln Gas Turbine Station would employ a
staff of only 12 people for almost 1,200 MW of peak demand
capacity.[^48] However, the above sample of 10 publicly owned electric
utilities did not turn up many examples of large CCGT systems being
installed or planned.

Cost issues for these utilities were complex even aside from the
regulated aspects of their cost accounting. Each case was highly
peculiar to the operating characteristics of the system: what was the
demand profile like, what was peak demand like and for how long did it
last, what kind of coal was being used and what were its characteristics
(sulfur and ash content, etc.), how were boilers designed, what were the
labor costs, were there space limitations for installing scrubbers, and
so on?

For example, with the exception of units burning Texas lignite, it was
much easier for a coal-fired boiler to switch to Appalachian low sulfur
coal than it was to switch to Powder River Basin coal. The reason was
that the heat content of the Appalachian coal was the same as the heat
content of the higher sulfur Appalachian coal it was replacing. Ash
characteristics also were the same. Western low sulfur coal had a
significantly lower heat content necessitating modifications in the
boiler, the coal feeding system, and the ash treatment system. More
western coal had to be introduced to generate the same amount of heat.
Adjustments had to be made.[^49] Switching to Powder River Basin coal
for an existing boiler was not cost free and not all boilers would be
able to switch at reasonable cost.

**Ripple Effect Leading to Improved Environmental Performance**

The sulfur dioxide (SO~2~) provisions of the 1990 Clean Air Act (CAA)
Amendments Phase I and II threatened to impose substantial costs on coal
fired electric power generating plants using high or even intermediate
sulfur coal. Original projections of cost were from \$400 to as much as
\$1000 per ton of SO~2~ removed. Though not a very useful way to
quantify acid rain clean-up costs, this range of estimates could have
put the cost of SO~2~ removal to a level of 1/kWh or higher. To place
this in perspective: electric utility coal fuel costs had been about
1/kWh.

In response to these estimates and to the protests of the coal industry,
the federal government, in partnership with private industry, spent 7
billion dollars on clean coal technology R&D, about \$2.5 billion coming
from the government and the rest from utilities and other electricity
generators, and from clean coal technology companies. Though SO~2~
scrubbing, particulate capture, and NO~x~ reductions have turned out to
cost much less than projected, these investments have had little
immediate impact. The government was looking at end-of-pipe (EOP)
solutions but the market brought a pollution prevention remedy (fuel
switching) instead at dramatically lower cost. Utilities simply reduced
the amount of pollutant sulfur at the source. Out of the 65,000 MW of
the 1990 CAA Amendments\' Phase I impacted facilities, only about 14,000
MW involved the installation of limestone WFGD systems to comply. The
remainder, or 78 percent, switched instead to low sulfur coal.

Competition and productivity improvements at Western low sulfur coal
(LSC) mines as well as competition and tremendous productivity
improvements by the railroads delivering the coal drove the price of LSC
down sharply and moved its availability steadily eastward.

At the same time natural gas (NG) prices fell and the availability of
this fuel increased, thanks in large part to advances in the
technologies for finding and extracting natural gas and oil. As a
consequence, the long term prospects for using NG to generate
electricity improved markedly. On the generating side a low cost, highly
thermally efficient technology for using natural gas was developed as a
spin-off of jet engine technology. The fear that high clean-up costs
would be imposed on newly constructed coal fired systems and the growing
local opposition to siting coal plants were important contributing
factors to the increased demand for GT and CCGT systems. The independent
power producers (IPP) became a major force driving demand, and the power
systems suppliers responded, led by GE, and engaged in a fierce
competition that has increased the thermal efficiencies and reduced the
prices of these systems.

Gas turbine generating technology blossomed with 60 percent thermal
efficiency CCGT systems appearing on the market. This innovation, bred
not by environmental regulation alone, was aided by the CAA, especially
by the new source performance provisions of the Act. This technology was
enabling utilities, either by their own initiation or by IPPs, to meet
new capacity needs, especially peak power demand but base load as well,
at very low capital and operating costs.

**National Comparisons**

The competition in the U.S. was between low sulfur coal and natural gas.
SO~2~ scrubbers, when not mandated, were not a viable option unless they
lowered their costs substantially. Globally, however, scrubbers competed
with natural gas because low sulfur coal was not as readily available as
it was in the U.S. The growth prospects for low sulfur coal and for gas
turbine generating systems were high because strong competitive forces
stimulated R&D and cost cutting which improved efficiencies and brought
down prices. The Clean Air Act (CAA) added to these pressures. It had
been expected that the 1990 Amendments to the CAA would also stimulate
innovations in scrubber technology. However, it was markets outside the
U.S. that were driving technology improvements and lowering costs in
this industry. Global market opportunities and not opportunities in the
U.S. had the potential to make scrubbers more competitive in U.S.
markets.

In Western and Central Europe, acid rain problems were greater than in
the United States. Basic industry \-- centered in a triangle comprising
parts of Poland, the Czech Republic, and Slovakia \-- used very low
quality, high sulfur coal or lignite resulting in acid rain damage to
forests throughout the area and beyond. German forests also suffered
significant damage. Low sulfur coal was not readily available as an
alternative solution to retrofitting existing plants with FGD devices.
Consequently, the market for WFGD was strong and projects were underway
or being planned in Poland, Germany, Italy, and elsewhere. Two
[new]{.underline} lignite burning power plants at Konin, for example,
were going to install a large limestone WFGD system to remove 95 percent
of the flue gas sulfur.[^50]

**Effects on Suppliers**

The development of the Powder River Basin by the mining companies, of
the rail delivery system by BN and C&NW (now UP), and of new low sulfur
coal burning technology by the utilities constituted a first class
innovative system developed to a large extent in response to
environmental regulations on SO~2~ emissions. This system provided a low
cost pollution prevention solution to many utility CAA compliance
problems and promised to provide solutions for more utilities as the
rails expanded their markets Eastward. The cost of compliance turned out
to be far less than predicted as a result.

Though some power plants were located at the mine mouth, most bituminous
coal had to be transported from the mine mouth to the electric
generating plant. The overwhelming majority of this coal had been
carried by eastern railroads, though barge transport played a minor
role. There were two dominant rail carriers in the East: CSX and Norfolk
Southern. Conrail and Illinois Central were lesser players. In 1994,
coal deliveries were responsible for 32 percent of CSX\'s and Norfolk
Southern\'s total revenues. CSX and Norfolk Southern, however, were not
as aggressive as the western carriers in cutting costs and their rates
were higher than those of the western rails.

Key to the success of western coal were the Burlington Northern and
Union Pacific Railroads. Chicago & Northwestern, which operated at
Powder River Basin jointly with Union Pacific, also was an important
player. In 1995 Union Pacific acquired Chicago & Northwestern. The
company also announced an offer to purchase Southern Pacific. Southern
Pacific had a rail line to the South that could increase the
transportation of low sulfur coal to the East. Burlington Northern,
meanwhile, was awaiting ICC approval to purchase the Santa Fe Railroad.
These acquisitions would leave two large and dominant carriers to serve
the western half of the U.S.

The growth in demand for low sulfur sub-bituminous coal had attracted
capital, especially to the western railroad companies\' coal train
operations. Increased competition between Union Pacific and Burlington
Northern, and among the many different western coal mine operators,
combined with steady productivity improvements to result in a steadily
declining price for low sulfur coal and an increased penetration of the
product into new markets to the East. Federal courts overturned state
laws in Indiana and Illinois that raised barriers to their utilities
switching from locally mined high sulfur coal to western low sulfur
coal. Test shipments of western coal were delivered to utilities in
Georgia and Florida at prices that were competitive with the prices for
eastern and mid-western coal currently in use.

The 1970 Amendments to the CAA gave the initial impetus to the
exploitation of the Powder River Basin coal reserves. The Federal
Government, through the Interstate Commerce Commission, played an
important role in encouraging the Chicago & Northwestern and the
Burlington Northern to develop jointly and share the track that had to
be built from the mines to their main rail lines rather than build two
separate but parallel lines to serve each of the rail companies. This
approach contributed to the reduction in transportation costs. The ICC
was persistent in encouraging the financially weak C&NW to enter the
market to provide competition. When it did, after considerable delays,
transportation prices plummeted.[^51]

In 1994, coal transport generated 33 percent of Burlington Northern\'s
rail revenues and 19 percent of Union Pacific\'s. Burlington\'s and
Union Pacific\'s systems reached as far East as Chicago to the North and
St. Louis and Memphis on the Mississippi to the South and a bit beyond
to the Tennessee River. The coal then could be carried further South by
barge or further East and South by passing the cargo off to the CSX and
Norfolk Southern railroads. Rail was by far the cheapest overland mode
for carrying coal. There were no barge carrying waterways available to
Powder River Basin mines. Burlington Northern and Union Pacific, while
in fierce competition with one another, had complete control of this
market.

**SUMMARY**

Two lessons were clear: competition was a creative force that had helped
to improve the environment at lower cost; and the way in which the
competitive forces had unfolded would have been hard for the government
to predict.

For instance, competition in the rail industry and the working out of
costly work rules helped lead to the dramatic cost reductions in the
delivery of low sulfur coal and the opening up of markets further East
than had been previously imagined. By leasing low sulfur coal reserves
on Western Federal lands to a number of companies, the government
ensured a fully competitive market that had helped to achieve low
mine-mouth coal prices.

The Federal Government had also played a role in the productivity
improvements in natural gas by deregulating and encouraging competition.
The wellhead price and cost of delivery of natural gas fell after the
federal government deregulated prices. Technology developments in
finding gas and oil were encouraged. They made the long term outlook for
sufficient supplies of NG at reasonable prices more favorable.

These technology innovations came at a critical time in the evolution of
the utility industry. Increased competition, deregulation, and the
consequent need to reduce costs required the industry to find solutions
to CAA regulations at much lower costs than originally envisioned when
the legislation was forged. In turn, the increased competition in the
electric utility industry fed back on the competing solutions providers:
the low sulfur coal providers, the gas turbine makers, and the scrubber
manufacturers. These suppliers had to continue to innovate to drive
costs down further.

SO~2~ trading allowances were another innovation that was helping to
lower costs, though deficiencies in this market (too thin) and
uncertainties as to future prices and even to the future existence of
the market were hindering further innovation.

**APPENDIX A**

**The Phase I & II Compliance Strategies of the Utilities**

1\. All (with the exception of Florida Power & Light, which had almost
no coal based generating capacity) resorted to using low sulfur coal as
the core of their compliance strategy. Along the Southeast and closest
to Appalachian coal mines, the source of the coal was Appalachian that
was in most cases Phase I compliant only. Southern Company, however,
with plants running from Georgia to Alabama, Louisiana, and Mississippi
was using some western coal that was Phase II compliant. Of great
significance was the fact that Georgia Power was testing some Powder
River Basin coal delivered at a competitive price.

2\. Powder River Basin coal had penetrated to the South Central United
States. It provided Entergy Corporation the complete solution to its
SO~2~ compliance problems and helped Houston P&L meet New Source
Performance Standards.

3\. While many of the units in this sample burned non-compliance coal,
none of the coal had high sulfur content, the highest tending to be
about 1.8 lb/MBtu. Consequently, none of the utilities were
contemplating the use of scrubbers as the sole supplement to using low
sulfur Appalachian coal in order to meet Phase II compliance
requirements by 2000.

4\. The purchase of allowances as part of the solution to Phase II needs
was being considered by all the out of compliance companies. Because low
sulfur Appalachian coal was not very far out of compliance for Phase II,
the purchase of allowances appeared to be the cheapest way for units
burning this coal to satisfy Phase II SO~2~ emission limits. Carolina
Power & Light was adopting this approach but only from 2000 to 2007. The
uncertainty about the long term stability or even existence of allowance
trading was strongly inhibiting the utilities from relying solely or
heavily on them for their compliance needs.

5\. As a consequence, those utilities using low sulfur Appalachian coal,
several with some units consuming intermediate sulfur coal, were in the
process of analyzing their three options: lower the sulfur content of
their coal even further, install scrubbers, or purchase allowances. In
developing a solution, the utilities had to consider not only the lowest
cost option but the risks and volatility of the solution.

 What would happen to the price of allowances as the year 2000
approached and Phase II demand drove up the price?

 Would the allowance program survive for 30 years, the time horizon for
the analysis?

 Would the regulations survive 30 years?

 What if they were made less stringent? What would the Republican
controlled Congress do?

 What would the supply and demand characteristics of low sulfur
Appalachian coal be as everyone sought to switch to it?

 Was there a 30 years supply of this coal at an acceptable price?

 If a scrubber was installed, would it be accepted as part of the rate
base?

 With growing competition, would industrial customers be willing to pay
for its cost?

 What if a much better, lower cost scrubber came along in a few years?
Perhaps delaying the installation of a scrubber made sense?

 The fact that none of the utilities pondering these issues had
reported a final decision indicated that the answers to these and other
vexing questions were not easily and that, perhaps, there was no clear
or optimal solution.

6\. The Baltimore, Virginia, Carolina utilities had not considered
Powder River Basin coal as a viable alternative strategy, yet Burlington
Northern, was ready to bring western coal East and beyond. If Georgia
Power made more aggressive use of Powder River Basin coal would this
change the perspective of the other companies in the region.

**SOURCES**

General Electric Environmental Services Inc. (GEESI), Private
communication.

Interview of Gerald Grinstein, C.E.O. of Burlington Northern Inc., by
*Siemens Review,* May 1993, reprint courtesy of Burlington Northern.

The McIlvaine Company, Northbrook, IL, *Gold Dust \-- The \"Air
Pollution Management\" Newsletter,* July 1995, No. 206.

The McIlvaine Company, Northbrook IL, *FGD and DeNOx Newsletter,* May
1995, No. 205.

Reinhardt, Forest, \"Acid Rain:Burlington Northern, Inc. (A),\" Harvard
Business School, case 792-018, 1991.

Samsom, Dr. Robert L., Energy Ventures Analysis, Inc., *Review of Powder
River Basin Coal Supply,* June 1990.

Sanchez, Carol, *Environmental Regulatory Impact and Firm Level
Innovation: A Study of Electric Utilities\' Responses to the Clean Air
Act Amendments of 1990 (*PH.D dissertation, Department of Management,
SIU, 1995).

U.S. Department of Energy, *Electric Power Annual 1993*.

U.S. Department of Energy, Energy Information Administration, *Cost and
Quality of Fuels for Electric Utility Plants 1993,* DOE/EIA-0191(93),
July 1994.

U.S. Department of Energy, *Estimation of Coal Reserves by Coal Type,
Heat, and Sulfur Content,* Energy Information Administration,
DOE/EIA-0529, 1989.

U.S. Department of Energy, *Electric Plant Costs and Power Production
Expenses 1991*, Energy Information Administration, 1993.

U.S. Department of Energy, Assistant Secretary for Fossil Fuels, *Clean
Coal Technology Demonstration Program - Program Update 1993,* p ES-5,
DOE/FE-0299P, March 1994.

U.S. Environmental Protection Agency, *The NAPAP Emissions Inventory
(Version 2),* November 1989.

U.S. EPA Publications: EPA430/F-92/016 & 019, December 1992 for a
discussion of this program.

U.S. EPA Publication EPA430/F-92/019, December 1992.

[^1]: U.S. Department of Energy, *1993 Power Annual*

[^2]: U.S. Department of Energy, Energy Information Administration,
    *Cost and Quality of Fuels for Electric Utility Plants 1993,*
    DOE/EIA-0191(93), July 1994. For a typical bituminous coal
    composition see, for example, \"The Harrison Power Station,\"
    *McGraw-Hill\'s Power Magazine,* April 1994

[^3]: U.S. Department of Energy, *Estimation of Coal Reserves by Coal
    Type, Heat, and Sulfur Content,* Energy Information Administration,
    DOE/EIA-0529, 1989

[^4]: Carbon dioxide was an unregulated air pollutant of concern to the
    world because of climate change. It had been the subject of much
    discussion and a treaty at the 1992 Rio Conference.

[^5]: Our discussion of scrubber technologies and markets relied greatly
    on marketing material of GE Environmental Services and on interviews
    of GE employees. For a discussion of the effects of the 1977 Clean
    Air Act Amendments on the scrubber market, see Bruce Ackerman and
    William Hassler, [Clean Coal/Dirty Air]{.underline} (New Haven, Ct.:
    Yale University Press, 1981). In this book, the authors maintain
    that a coalition of eastern coal interests and environmentalists
    formed a coalition to strengthen the 1977 Clean Air Act Amendments
    in ways that would stimulate the market for scrubbers, though this
    solution was neither cost effective nor ultimately very good for the
    environment.

[^6]: See Department of Energy, [Electric Plant Costs and Power
    Production Expenses 1991]{.underline}, Energy Information
    Administration, 1993.

[^7]: ^?^ U.S. Department of Energy, Assistant Secretary for Fossil
    Fuels, *Clean Coal Technology Demonstration Program - Program Update
    1993,* p ES-5, DOE/FE-0299P, March 1994

[^8]: U.S. Department of Energy, *Electric Power Annual 1993*.

[^9]: See footnote 2 and also the 1991 DOE report.

[^10]: A 1995 study, reported in the April 1995 issue of McGraw-Hill\'s
    Power Magazine, revealed that IPPs supplied over 57,000 MW of power
    to the U.S. power grid. They brought 91 projects on line totaling
    5,735 MW (63 MW per project) in 1994. Most of the IPPs\' projects
    were for gas turbine generators. According to the DOE\'s *1993
    Electric Power Annual*, independent power generators produced 0.3252
    trillion kWh in 1993, comprising about 12 percent of all electricity
    generated. Of this only 16 percent was by coal fired means. Assuming
    about 80 percent of IPP generation was by natural gas, close to 10
    percent of all electricity generated in 1993 was supplied by
    independent power producers using, with few if any exceptions, gas
    turbine systems.

[^11]: The McIlvaine Company, Northbrook, IL, *Gold Dust \-- The \"Air
    Pollution Management\" Newsletter,* July 1995, No. 206.

[^12]: The McIlvaine Company, Northbrook, IL, *Gold Dust \-- The \"Air
    Pollution Management\" Newsletter,* July 1995, No. 206.

[^13]: Dr. Robert L. Samsom, Energy Ventures Analysis, Inc., *Review of
    Powder River Basin Coal Supply,* June 1990.

[^14]: Private communication. The gas turbine market share information
    was obtained from an interview of a GE employee. Much of the
    information contained in this section is widely available in the
    financial analysis literature.

[^15]: Other profitable segments included the ThermoKing transportation
    refrigeration service with 10 percent of sales and 21 percent of
    operating earnings, Electronic Systems (primarily defense
    contracting) with 28 percent of sales and 27 percent of operating
    profits, Environmental Systems (hazardous and nuclear waste cleanup)
    with 4 percent of sales and 9 percent of operating earnings, and
    Communities (land development) with 3 percent of sales but 11
    percent of operating earnings.

[^16]: ABB was waiting approval to merge its Transportation segment with
    Daimler Benz\'s rail business for further economies of scale and to
    take leading market share in what has been a three way race with
    Siemens and Alcatel.

[^17]: Private communication. Much of the information about this
    industry came from an interview of GEESI staff and their marketing
    material.

[^18]: Private communication

[^19]: U.S. Environmental Protection Agency, *The NAPAP Emissions
    Inventory (Version 2),* November 1989

[^20]: See for example, U.S. EPA Publications: EPA430/F-92/016 & 019,
    December 1992 for a discussion of this program.

[^21]: U.S. EPA Acid Rain Nitrogen Oxides Emission Reduction Rule 40 CFR
    Part 76 of Title IV of the 1990 Clean Air Act Amendments and
    modified by 60 FR 18751 after the *Alabama Power Co. v. EPA,* 40
    F.3d 450, 39 ERC 1737, November 29, 1994 decision of the U.S. Court
    of Appeals for the District of Columbia Circuit.

[^22]: U.S. EPA Publication EPA430/F-92/019, December 1992

[^23]: U.S. Department of Energy, *Electric Power Annual 1993*

[^24]: Carbon taxes were seriously discussed in the European Community,
    but had not been implemented because of concerns they would put
    European manufacturers at a competitive disadvantage globally. The
    German, Dutch, and other governments in Northern and Western Europe
    were strong supporters of carbon taxes.

[^25]: The McIlvaine Company, Northbrook, IL, *Gold Dust \-- The \"Air
    Pollution Management\" Newsletter,* July 1995, No. 206

[^26]: U.S. Department of Energy, Assistant Secretary for Fossil Energy,
    *Clean Coal Technology Demonstration Program, Program Update 1993,*
    DOE/FE-0299P, March 1994. The spending figures and other
    descriptions of the program were taken from this publication.

[^27]: U.S. Department of Energy, Energy Information Administration,
    *Estimation of Coal Reserves by Coal Type, Heat, and Sulfur
    Content,* DOE/EIA-0529, 1989; Dr. Robert L. Samsom, Energy Ventures
    Analysis, Inc., *Review of Powder River Basin Coal Supply,* June
    1990

[^28]: Private communications

[^29]: For a good account of the development of rail transportation out
    of the Powder River Basin see Fred W. Bailey and Gary J Benson,
    *Trains, [The]{.underline} Magazine of Railroading,* Kalmbach
    Publishing Co., November 1989.

[^30]: See Forest Reinhardt, \"Acid Rain:Burlington Northern, Inc.
    (A),\" Harvard Business School, case 792- 018, 1991.

[^31]: For example, PSI Energy\'s Gibson Station in Indiana purchased
    coal with a sulfur content of 0.43 lb/MBtu from Powder River Basin
    for \$1.21/MBtu delivered in 1993 and 0.75 lb/MBtu sulfur coal from
    nearby Kentucky for \$1.37/MBtu. This low sulfur coal was not
    typical of coal coming from Kentucky: all Indiana utilities combined
    purchased Kentucky coal averaging 2.59 lb sulfur/MBtu at an average
    price of \$1.16/MBtu, only five cents below the price of Wyoming
    coal. Since 1993 the price of Powder River Basin Coal fell
    substantially.

[^32]: Interview of Gerald Grinstein, C.E.O. of Burlington Northern
    Inc., by *Siemens Review,* May 1993, reprint courtesy of Burlington
    Northern.

[^33]: Burlington Northern brochure, 1992

[^34]: Private communication, General Electric Environmental Services
    Inc. (GEESI)

[^35]: U.S. Department of Energy, Assistant Secretary for Fossil Energy,
    *The Clean Coal Technology Program \-- Lessons Learned,*
    DOE/FE-031P, July 1994; *Clean Coal Technology Demonstration
    Program*, *Program Update 1993,* DOE/FE-0299P, March 1994

[^36]: U.S. Department of Energy, Assistant Secretary for Fossil Energy,
    *The Clean Coal Technology Program \-- Lessons Learned,* DOE/FE
    031P, July 1994

[^37]: See Carol Sanchez, [Environmental Regulatory Impact and Firm
    Level Innovation: A Study of Electric Utilities\' Responses to the
    Clean Air Act Amendments of 1990]{.underline} (PH.D dissertation,
    Department of Management, SIU, 1995).

[^38]: The lower priced utility may have managed its fuel sources better
    and its portfolio of fuel-based generating capacity. Its labor costs
    may be lower either through better management or having a lower wage
    scale in its region, and its operating and maintenance costs may be
    under better control. The higher cost utility may have had a badly
    managed new capacity addition over the past twenty years whose large
    cost overruns have been partially passed along to consumers. A
    manufacturer in New York paying 6/kWh, sees a competitor in the
    Mid-West paying only 4/kWh and contemplates three options: (i) move
    the facility to a lower cost state, (ii) generate the electricity
    on-site, if possible using the waste heat for process heat, or (iii)
    negotiate with the utility for lower rates. Increasingly industrial
    customers are combining options (ii) and (iii) by presenting the
    utility with a credible plan to build on-site generation unless
    rates are lowered to meet the cost of power the on-site facility
    will provide. In Minnesota where the price of electric energy is
    relatively low, several customers of Northern States Power (NSP)
    have done just that and have obtained a significant lowering in
    their price of power down to the 3/kWh area. This agreement is for
    five years after which time NSP is willing (unless conditions
    change, of course) to let these customers leave the grid and
    generate their own power. NSP has also re negotiated rates with a
    large customer who threatened to leave the state unless his/her
    conditions were met. These examples are being repeated all over the
    U.S. and are most frequent in high cost areas.

[^39]: Data comes from the companies\' 1994 10K reports and the
    financial analysis literature (in particular work done at Prudential
    Securities and Merril Lynch); also see Department of Energy,
    [Financial Statistics of Major U.S. Investor-Owned Electric
    Utilities 1993]{.underline}, Energy Information Administration,
    1995.

[^40]: The summary below relied on the 1994 10K reports of these
    publicly owned utilities and on U.S. Department of Energy, Energy
    Information Administration, *Cost and Quality of Fuels for Electric
    Utility Plants 1993,* DOE/EIA-0191(93), July 1994.

[^41]: This estimate could be off by as much as 25% since it is based on
    DOE figures for coal [purchases]{.underline} in 1993 and in addition
    may not include all of Duke\'s coal burning plants. Nevertheless it
    is a good order of magnitude estimate. The present value of the
    purchase cost of these allowances for 30 years with a discount rate
    of 12% and an assumed 4% annual increase in the price of these
    allowances starting at \$130 is only \$79 million \-- much less than
    the low end of Duke\'s compliance [capital cost]{.underline} of
    \$260 million. For a present value of \$260 million under the same
    discount rate and inflation rate assumptions, the allowance price in
    the year 2000 would have to reach \$429. The difficulty is that this
    approach would leave Duke without flexibility, especially pertaining
    to adding new coal-fired capacity. Low sulfur Appalachian coal
    prices may rise significantly as well.

[^42]: Gulf Power was not in compliance with Phase I in 1993. Alabama
    Power was in compliance with Phase I with the exception of one very
    small plant, burning primarily Alabama coal. One large facility in
    1993 consumed high quality very low sulfur Alabama coal (0.48
    lb/MBtu at \$2.52/MBtu) putting it in compliance with Phase II.
    Savannah Electric was very small and not of much concern. Finally
    Mississippi Power Co. had one facility, Daniel Station, that
    consumed in 1993 a mixture of Kentucky, Colorado, and Montana coal
    with an average sulfur content of 0.48 lb/MBtu, putting it in
    compliance with Phases I & II. The second one, the Watson plant,
    used primarily Illinois coal supplemented by Kentucky coal with a
    small amount of W. Virginia and Alabama coal that averaged 1.86
    lb/MBtu sulfur.

[^43]: Private communication, Texas Utilities. Our discussion of Texas
    Utilities and other utilities in the state benefitted from an
    interview of a staff member in the generating division of Texas
    Utilities.

[^44]: Units for which construction began after September 18, 1978 were
    required to install scrubbers removing up to 90% of its flue gas
    SO~2~ if burning high sulfur coal and 70% if consuming low sulfur
    coal. The 1970 CAA NSPS applied to units whose construction began
    after August 17, 1971 and required that they reduce sulfur dioxide
    emissions to no more than 1.2 lb/MBtu of fuel consumed.

[^45]: Based on interviews with NSP staff

[^46]: Interview of Duke Power staff individual.

[^47]: It was unlikely that Carolina Power could actually carry out all
    these new construction plans, as the utility had relatively high
    prices and was losing some wholesale power contract sales in 1996
    with potentially more to follow. Carolina was under severe pressure
    to reduce its costs. As part of that process, it had negotiated
    contracts to purchase 250 MW per year from American Electric Power
    to 2010 and 400 MW per year until 2000 from Duke Power.

[^48]: Private communication

[^49]: In some instances a high heat content fuel had to be mixed in
    with the low sulfur coal. In many instances the generating system
    experienced a reduction in maximum output. On average, this
    reduction or \"derating\" as it was called could be as high as 10
    percent during periods of peak demand. Scrubbers also reduce net
    busbar output through parasitic power losses. However, this is only
    about 1.5% of a unit\'s energy output.

[^50]: The McIlvaine Company, Northbrook IL, *FGD and DeNOx Newsletter,*
    May 1995, No. 205.

[^51]: If the railroads were simply deregulated and the ICC played no
    role, then it was likely that the Union Pacific would have entered
    the market anyway and perhaps sooner and more effectively.