```
                                                                 
Restructured Electricity Markets: Three States' Experiences in	 
Adding Generating Capacity (24-MAY-02, GAO-02-427).		 
                                                                 
Twenty-four states and the District of Columbia have restructured
electricity markets by shifting from service provided through a  
regulated monopoly to service provided through open competition  
among the local utilities and their competitors. The		 
restructuring was intended to boost competition and expand	 
consumer choice, increase efficiency, and lower prices. Of the	 
three states GAO studied, Texas had the greatest need for	 
additional electric power, and it added the most new capacity	 
from 1995 through 2001. In contrast, California added 25 percent 
of the forecasted need for capacity over this period. Although	 
Pennsylvania added less than half of its forecasted need for	 
capacity, the state continues to be a net exporter of electricity
to nearby states. The three states have similar processes for	 
approving applications to build and operate new power plants. In 
all three states, state and local agencies must review the	 
applications to ensure that the developer complies with 	 
environmental, land use, and other requirements before issuing	 
the permits necessary to build and operate a power plant.	 
California also has a state energy commission that reviews each  
power plant application to determine whether the benefits of	 
additional electricity outweigh its likely negative environmental
or other effects. Texas' rules for connecting new power plants to
the electricity transmission system are less costly for 	 
independent developers and are administratively simpler than the 
approaches used in California and Pennsylvania. In deciding where
to build new power plants, independent developers said they weigh
a market's risks, including uncertainty about changes in a	 
state's market rules, against expected profits. Higher risks	 
require higher expected profits.				 
-------------------------Indexing Terms------------------------- 
REPORTNUM:   GAO-02-427 					        
    ACCNO:   A03409						        
  TITLE:     Restructured Electricity Markets: Three States'	      
Experiences in Adding Generating Capacity			 
     DATE:   05/24/2002 
  SUBJECT:   Competition					 
	     Electric powerplants				 
	     Electric utilities 				 
	     Energy marketing					 
	     Utility rates					 
	     California 					 
	     Pennsylvania					 
	     Texas						 

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GAO-02-427
     
Report to Congressional Committees

United States General Accounting Office

GAO

May 2002 RESTRUCTURED ELECTRICITY MARKETS

Three States? Experiences in Adding Generating Capacity

GAO- 02- 427

Page i GAO- 02- 427 Restructured Electricity Markets Letter 1

Results in Brief 3 Background 5 The Three States Had Different Needs for
Additional Electric

Power and Added Different Amounts 9 Regulatory Processes Are Generally
Similar in the Three States,

Although California Requires an Additional Approval 13 Connecting New Power
Plants Is Less Costly and Faster for

Developers in Texas Than in the Other Two States 19 Developers in
Restructured Electricity Markets Weigh a Project?s

Projected Profitability against Risks 25 Conclusions 31 Recommendations for
Executive Action 32 Agency Comments 33

Appendix I Scope and Methodology 34

Appendix II California?s Process for Approving New Power Plant Projects 37

Appendix III Pennsylvania?s Process for Approving New Power Plant Projects
42

Appendix IV Texas? Process for Approving New Power Plant Projects 46

Appendix V Comments from the Federal Energy Regulatory Commission 50

Appendix VI GAO Contacts and Staff Acknowledgments 52 Contents

Page ii GAO- 02- 427 Restructured Electricity Markets Tables

Table 1: Regulatory Approval Time Frames for Power Plants in California,
Pennsylvania, and Texas 15 Table 2: CEC?s Certification Process 38

Figures

Figure 1: The Major U. S. Electricity Transmission Interconnections 7 Figure
2: Generating Capacity Proposals in the Three States, as of

December 31, 2001 11 Figure 3: Ozone Non- Attainment Areas for EPA?s 1- Hour
Standard

as of January 2002 17

Abbreviations

BTU British thermal unit CEC California Energy Commission DEP Department of
Environmental Protection EPA U. S. Environmental Protection Agency ERCOT
Electric Reliability Council of Texas FERC Federal Energy Regulatory
Commission NERC North American Electric Reliability Council PUC Public
Utility Commission RDI Resource Data International TNRCC Texas Natural
Resource Conservation Commission

Page 1 GAO- 02- 427 Restructured Electricity Markets

May 24, 2002 The Honorable Stephen Horn Chairman, Subcommittee on Government
Efficiency,

Financial Management and Intergovernmental Relations Committee on Government
Reform House of Representatives

The Honorable Doug Ose Chairman, Subcommittee on Energy Policy, Natural

Resources and Regulatory Affairs Committee on Government Reform House of
Representatives

In response to the Energy Policy Act of 1992, the Federal Energy Regulatory
Commission, 24 states, and Washington, D. C., restructured electricity
markets by shifting from service provided through a regulated monopoly- the
local electric utility- to service provided through open competition among
the local utility and its competitors. The 24 states and Washington, D. C.,
accounted for about 55 percent of total U. S. electricity retail sales in
1999. The restructuring was intended to increase competition and expand
consumer choice in order to lead to increased efficiency and lower prices.
In states that have restructured, decisions about whether to build new power
plants to add to a region?s generating capacity are made by independent
developers- private companies not regulated by state utility commissions.
Previously, the utilities and states? utility regulators made these
decisions. To evaluate the adequacy of supplies of electricity, the North
American Electricity Reliability Council- a voluntary organization of
utilities- forecasts the generating capacity needed to meet future
electricity demand.

Federal and state environmental laws have historically made the fossil
fueled electric power generation industry, which relies on coal, oil, and
natural gas, one of the most highly regulated industries, according to the
U. S. Environmental Protection Agency (EPA). These large plants emit
pollutants into the air and may also discharge pollutants into water
systems. In addition, these power plants can occupy large areas of land, in
some cases about 30 acres, and as a result, could harm wildlife and
ecosystems. Consequently, power plant developers generally have to address
air and water quality, and may also have to address endangered species
issues when obtaining pre- construction and operating permits. EPA has
delegated responsibility to many states for enforcing compliance

United States General Accounting Office Washington, DC 20548

Page 2 GAO- 02- 427 Restructured Electricity Markets

with both the Clean Air Act and the Clean Water Act. The developer, state
agencies, and the U. S. Fish and Wildlife Service are responsible for
ensuring that a power plant project does not adversely affect any endangered
or threatened species. State and local agencies review developers?
applications for environmental and other permits needed to build new power
plants in restructured markets, as they did before restructuring.

Restructuring issues gained national visibility in May 2000, when
California?s electricity prices rose dramatically, with average costs rising
four- fold. This increase in prices occurred, in part, because the total
demand for electricity was too close to the total electricity supplies.
Industry experts cited the limited development of new power plants within
California as one contributor to the crisis. While prices subsequently fell,
experts remain concerned that the planned development of new power plants
may not be sufficient to meet future needs in California. In response to
California?s experience, some states have delayed or suspended their plans
to open their markets to competition, while other states have decided
against restructuring their electricity markets at this time.

Citing the importance of quickly adding new power plants when needed as a
key factor in balancing the supply and demand for electricity in
restructured markets, you asked us to compare the experience of California
in adding new power plants with the experiences of two other restructured
states- Pennsylvania, which operates as part of an innovative regional
electricity market, and Texas, which has successfully added new plants. In
response, we agreed to (1) compare the need for electric power in
California, Pennsylvania, and Texas, as well as the extent to which these
states have added new generating capacity; (2) compare the states?
regulatory processes for approving new power plants; (3) compare the states?
rules for connecting new power plants with local electricity transmission
systems; and (4) identify the key factors that independent developers
consider in deciding where to propose new power plant projects. In 1999,
power plants in California, Pennsylvania, and Texas accounted for 21 percent
of the generating capacity in the United States- about 166,000 megawatts of
power. One megawatt is sufficient to meet the demand of 750 households.

To compare California?s experience with those of Pennsylvania and Texas, we
analyzed state and industry data on power generation needs and developers?
proposals to build power plants and visited each state to interview
cognizant state and federal officials. To identify the factors that power
plant developers consider in making investment decisions, we met

Page 3 GAO- 02- 427 Restructured Electricity Markets

with six independent private developers- three of these were among the
largest and the other three were smaller; a manufacturer of large turbines
used to generate electricity; and representatives from the financial
community, including two investment ratings companies and four investment
banks that help finance power plants. Our detailed scope and methodology is
presented in appendix I.

In 1995, Texas had the greatest identified need of the three states for
additional electric power, and it added the most new capacity from 1995
through 2001- more than twice as much as the North American Electricity
Reliability Council forecasts indicated would be necessary through 2004. In
contrast, over this period, California added about 25 percent of the
forecasted need for capacity through 2004. Although Pennsylvania added less
than half of its forecasted need for capacity, the state continues to be a
net exporter of electricity to nearby states. Of the 49,600 megawatts of
capacity built or under construction in these three states between 1995 and
2001, 59 percent was in Texas, 24 percent in California, and 17 percent in
Pennsylvania. More recently, partly because of the national economic
slowdown, the terrorists? attacks on September 11, and the collapse of Enron
Corporation, developers have cancelled or postponed 23,000 of the 68,000
megawatts of proposed capacity not yet under construction in the three
states.

The three states have similar processes for approving applications to build
and operate new power plants, although California requires an additional
approval. In all three states, state and local agencies must review the
applications to ensure that the developer complies with environmental, land
use, and other requirements before issuing the permits necessary to build
and operate a power plant. In addition, California has a state energy
commission that reviews each power plant application to determine whether
the benefits of additional electricity outweigh its likely negative
environmental or other effects. From 1995 through 2001, obtaining regulatory
approval for building new power plants in California and Pennsylvania took
14 months, on average, compared with 8 months, on average, in Texas.
Furthermore, the duration of the regulatory review process was less
predictable in California than in the other two states- approval for 5 of
California?s 21 medium- to large- scale projects took 18 months or longer.
In California and Pennsylvania, most plants were proposed for areas with air
quality that did not meet federal standards; in Texas most proposals were
for areas that met these standards. As a result, over 60 percent of the
plants approved in California and Pennsylvania needed to install more
advanced pollution control equipment to obtain an Results in Brief

Page 4 GAO- 02- 427 Restructured Electricity Markets

air quality permit, while only 18 percent of the approved power plants in
Texas had to meet the more stringent requirements.

Texas? rules for connecting new power plants to the electricity transmission
system are less costly for independent developers and administratively
simpler than the approaches California and Pennsylvania use. Regarding
costs, Texas requires developers to pay only for the direct costs of
connecting the plant to the local transmission system, not for any upgrades
to the transmission system to carry the additional capacity; instead,
consumers pay for the cost of these upgrades directly through their
electricity bills. In contrast, under market rules approved by the Federal
Energy Regulatory Commission for California, Pennsylvania, and many other
states, developers must pay for both direct costs and upgrades. For upgrade
costs, developers negotiate with the transmission system owner over the
necessity and degree of upgrades, as well as the allocation of these costs.
Developers will seek to recover these costs through electricity sales once
the plant is operating. Furthermore, Texas? rules are administratively
simpler than those in the other two states because Texas requires developers
and local transmission system owners to use a standard agreement that
specifies responsibilities of each party for connecting new power plants.
The agreement also ensures that local transmission owners provide comparable
treatment for their own power plants and those of independent developers, as
the commission requires for restructured electricity markets. In contrast,
California and Pennsylvania allow developers and the local transmission
system owner to negotiate their responsibilities for each project. The
process for completing an agreement in Texas took less than half the time it
took the other two states. In November 2001, the Federal Energy Regulatory
Commission requested comments and suggestions for developing a standard
agreement. We believe such standard agreements make sense as a first step
because, in Texas, they expedited the process of connecting a power plant to
the transmission system. In the longer term, we believe that clarifying the
allocation of upgrade costs offers additional benefits for facilitating the
connection process and potentially power development. Accordingly, we are
recommending that the Federal Energy Regulatory Commission develop a
standard agreement for connecting new power plants to the electricity
transmission system and clarify how the local transmission owner and
developer should allocate costs to upgrade a transmission system.

In deciding where to build new power plants, independent developers said
they weigh a market?s risks, including uncertainty about changes in a
state?s market rules, against expected profits- higher risks require higher

Page 5 GAO- 02- 427 Restructured Electricity Markets

expected profits. For example, developers prefer market rules that allow the
use of long- term contracts that set a minimum price for electricity to
ensure a certain level of profits. According to developers and electricity
industry experts at investment firms we interviewed, Pennsylvania and Texas
provided transparent rules and opportunities to manage their risk, giving
these developers and experts greater assurance of reasonable profits. In
contrast, these developers and experts said California?s market structure
before the electricity crisis began in May 2000 attracted less investment
because (1) developers could not enter into long- term contracts or use
other risk management tools and (2) market prices were low. Developers added
that some of California?s responses to the electricity shortages during 2000
and 2001- such as the state?s direct involvement in the market through
electricity purchases- increased the risk of entering the market and
contributed to cancellations and delays of many proposed projects and may
affect future investment.

Before restructuring, electric service was provided primarily by federaland
state- regulated investor- owned electric utilities. A utility typically
owned the power plants, transmission system, and local distribution lines
that supplied electricity to all of the consumers in a geographic area.
Under this system, the Federal Energy Regulatory Commission (FERC)
regulated, among other things, sales of electricity for resale and the
transmission of electricity over high- voltage power lines in interstate
commerce. 1 The states regulated retail markets by participating with
utilities in forecasting growth in demand, planning and building new power
plants, reviewing and approving utility costs, and establishing rates of
return.

In response to the enactment of the Energy Policy Act of 1992, FERC has
opened wholesale electricity markets across the country, 2 and many states
have also opened their retail markets to competition. In these competitive
markets, consumers will eventually pay market- based electricity prices, and
power plant developers are no longer guaranteed that construction costs will
be repaid or that the electricity produced will be sold profitably. In these
markets, it was expected that independent developers would individually
assess the need for new generation and its potential

1 FERC does not regulate most of Texas? electricity system because it is an
independent transmission region that does not engage in interstate commerce.
2 Texas similarly opened its wholesale market to competition in 1995.
Background

Page 6 GAO- 02- 427 Restructured Electricity Markets

profitability. These assessments would be made on the basis of market
signals, such as the prices of electricity and other related products and
forecasts of the generation required to meet growing demand.

As shown in figure 1, the U. S. electricity transmission system consists of
three connected, but independently operating systems: the western
interconnect, the eastern interconnect, and the Texas interconnect. Each of
these systems must maintain a constant balance between the amount of
electricity supplied by power plants and the amount of electricity being
used at homes and businesses. While little electricity moves from one system
to another, electricity produced within each system can move throughout the
system, subject to transmission system constraints that can limit or prevent
the flow of electricity within certain regions of the system. The level of
electricity demand varies considerably throughout the day, with the highest
levels only reached during a small percentage of the hours during a year. In
addition, unlike other commodities, electricity cannot easily or
inexpensively be stored and must be instantly available whenever demand
increases. Because these systems are interconnected, a change in the supply
or demand in one part of the system can affect producers and consumers
elsewhere. To ensure that supply exceeds the demand for electricity, utility
systems have historically maintained additional power plants, as part of a
reserve margin, above the amount needed to meet the highest level of
expected demand. This reserve margin has enabled utilities to meet demand
when a power plant was taken out of service or when demand rose more than
expected.

Page 7 GAO- 02- 427 Restructured Electricity Markets

Figure 1: The Major U. S. Electricity Transmission Interconnections

As part of the western interconnect, California has historically imported
about 20 percent of the electricity that it consumes. While California?s
utilities had owned power plants located in California and other states as
part of their supply mix before restructuring, they have since sold most of
these plants to private companies not regulated by California. In contrast,
in recent years, Pennsylvania has exported more electricity than it has
imported. Although some of the power plants owned by the state?s former
utilities were sold as a result of restructuring, the plants have long- term
contracts to sell electricity in Pennsylvania. Power plants in Texas
generate nearly all of the electricity that the state consumes. The state?s
utilities have leased access to generating capacity at some of their plants
and some have been sold; however, the utility plants that are leased are
operated by subsidiaries of the former utilities.

Page 8 GAO- 02- 427 Restructured Electricity Markets

As part of its efforts to restructure the industry, FERC issued regulatory
orders that require transmission system owners to allow all parties,
including new power plant developers, to transmit electricity under
comparable terms and conditions. FERC has approved the formation of
independent organizations to operate the transmission system in California
and other states. An example of this new type of organization is the PJM
Interconnect, which operates the transmission system in all or parts of
Pennsylvania, New Jersey, Maryland, Delaware, and Washington, D. C. FERC
also directed transmission system owners to create multistate regional
transmission organizations to operate the systems independently of the
transmission owners. 3

To maintain the reliability of the transmission system, transmission owners
and operators participate in the North American Electricity Reliability
Council (NERC) through 10 regional reliability councils. These regions
cooperate in planning and integrating the transmission system and study
trends in long- term supply and demand.

U. S. electricity markets have attracted significant planned investment to
the nearly 770,000 megawatts 4 of generating capacity already on- line at
the end of 1995. Through the end of 2001, developers had proposed or added
about 690,000 megawatts of new electricity generating capacity, of which
about 114,000 megawatts were already built 5 and another 123,000 megawatts
were under construction. Industry data indicate that about 104,000 megawatts
of proposed plants had been either tabled or cancelled- with the remainder
in various stages of planning or development. About 40 percent of the
proposed generating capacity was planned for states identified as active in
implementing restructured electricity markets, and 20 percent for states
that have actively pursued electricity restructuring but have either delayed
or suspended further actions.

3 Alternatively, FERC?s Order 2000 provides that transmission owners may
file with FERC an explanation of what actions they have taken to create a
regional transmission organization and a reason why they will not join such
an organization.

4 A watt is a unit of electrical power. A kilowatt is 1, 000 watts. A
megawatt is 1,000,000 watts. One megawatt can serve the needs of about 750
homes. One kilowatt used for one hour equals 1 kilowatt- hour.

5 This reflects new generating units placed on- line from 1995 through 2001.

Page 9 GAO- 02- 427 Restructured Electricity Markets

While coal, nuclear power, water (hydroelectric dams), and oil are the
primary fuels for older power plants, natural gas- fueled power plants
accounted for over 80 percent of the generating capacity added from 1995
through 2001 and a similar percentage of the plants proposed for
construction through the end of 2001. About 62 percent of the gas- fired
plant capacity proposed through 2001 would use highly energy- efficient
combined- cycle technologies, and 35 percent would use simple- cycle
technologies. Both types of power plants rely on large gas turbines, also
called combustion turbines, with combined- cycle units adding a steam
generator and a steam turbine to convert waste heat in the exhaust stream to
electricity. In general, both types of plants are more fuel efficient, less
costly to operate, and less polluting 6 than many existing power plants.
Because of their higher efficiency and relatively low operating costs,
combined- cycle power plants are often used to generate electricity through
large portions of the day. In contrast, simple- cycle power plants typically
are used to generate electricity only during periods of high demand because
they cost more to operate. These plants are useful in meeting sudden changes
in demand because they can reach full output in as little as 10 minutes. In
general, simple- cycle power plants can be constructed in about 6 to 9
months after regulatory approvals, while combined- cycle power plants need
from 18 to 28 months.

Electricity demand in Texas, California, and Pennsylvania grew faster from
1995 through 2001 than NERC had forecast in 1995. In response, in Texas,
developers added the most new capacity-- about 16,200 megawatts, or more
than double the forecasted need through 2004. In contrast, in California,
developers added about 4,600 megawatts, or 25 percent of the forecasted need
for capacity through 2004, and in Pennsylvania, developers added about 2,100
megawatts, or less than half of its forecasted need through 2004. More
recently, each state has seen significant cancellations and postponements of
projects, with California experiencing the greatest drop. Developers and
investment firms noted that events in the past year- the economic downturn,
the terrorists? attacks on September 11, and the collapse of the Enron
Corporation- contributed to the cancellation of many proposed projects in
the United States and the world.

6 New combined- cycle power plants emit lower levels of air pollutants, such
as nitrogen oxide and sulfur dioxide, as well as lower levels of carbon
dioxide. The Three States Had

Different Needs for Additional Electric Power and Added Different Amounts

Page 10 GAO- 02- 427 Restructured Electricity Markets

In 1995, when U. S. electricity markets were beginning to restructure, NERC
forecast that already planned new plant construction would adequately meet
the needs of the regional markets that include each of the three states
through 2004. Specifically, NERC forecast the following for each of the
reliability regions encompassing the states we reviewed:

 For California, the 16,800 megawatts of additional planned capacity would
adequately meet an estimated 1.8 percent growth in peak demand per year.
This added capacity included 13,600 megawatts of generating capacity and
3,200 megawatts of reduced demand to be achieved through the utilities?
conservation and load management programs.

 For Pennsylvania, the 5,700 megawatts of additional planned generating
capacity would adequately meet an estimated 1.3 percent growth in peak
demand per year.

 For Texas, the 6,600 megawatts of additional planned generating capacity
would adequately meet an estimated 2. 1 percent growth in peak demand per
year. Texas? planned new power plants included 5,300 megawatts of new gas-
fueled simple- cycle and combined- cycle power plants.

Since NERC?s 1995 report, electricity demand in each market has grown more
than expected. Specifically, in 2001, the data for the three reliability
regions reflected the following annual average growth: 4. 7 percent for
California, 2.1 percent for Pennsylvania, and 4. 9 percent for Texas. NERC
also reported that independent developers would need to continue to add new
power plants in order to meet demand over the next 10 years. The States Had
Different

Needs for New Power Plants

Page 11 GAO- 02- 427 Restructured Electricity Markets

According to industry data through 2001, developers had announced proposals
to build about 118,000 megawatts of new generating capacity in California,
Pennsylvania, and Texas- substantially more than NERC?s projection of about
26,000 megawatts by 2004. Figure 2 shows that nearly half of this new
capacity was proposed for Texas, while 35 percent was proposed for
California and 17 percent for Pennsylvania.

Figure 2: Generating Capacity Proposals in the Three States, as of December
31, 2001

Source: GAO compilation of Resource Data International data.

In addition, developers generally proposed power plants earlier in Texas
than in the other two states. Specifically, 69 percent of the new power
plant projects that began the regulatory process in Texas were proposed to
regulators before 2000, while 75 percent of the projects in California More
Capacity Was

Proposed and Built in Texas Than in the Other Two States

Page 12 GAO- 02- 427 Restructured Electricity Markets

and Pennsylvania were proposed to regulators in 2000 and 2001. 7 This early
interest in entering the electricity market in Texas led to earlier
consideration by regulatory agencies involved in the siting approval
process.

Partly because developers had proposed new power plants earlier, they had
built more generating capacity in Texas than in the other two states by the
end of 2001. In total, Texas accounted for about 71 percent, or 16,000
megawatts, of the 23,000 megawatts of generating capacity built in the three
states from 1995 through 2001. California accounted for 20 percent, or 4,500
megawatts, and Pennsylvania accounted for only 9 percent, or 2,000
megawatts, of generating capacity.

In addition to plants already built by the end of 2001, developers had more
capacity under construction in Texas than in either of the other two states.
Total capacity under construction in the three states was almost 26,700
megawatts: almost 13,000 megawatts, 48 percent, in Texas; about 7,500
megawatts in California; and about 6,400 megawatts in Pennsylvania.

As of December 2001, developers had cancelled or postponed over 22,600
megawatts of capacity previously announced for the three states, according
to industry data. In particular, 59 proposed power plants were reported
cancelled or postponed in California, amounting to about 11,500 megawatts of
generating capacity. Although California accounted for only 35 percent of
proposed new capacity for the three states from 1995 through 2001, it
accounted for 51 percent of the cancelled or delayed capacity. Just as the
emergence of the electricity shortfalls and high prices in California in
2000 led to an influx of proposals to build new power plants, the subsequent
drop in electricity prices preceded the cancellations in the state. While
cancelled or postponed projects represented about 28 percent of proposed
additions to total generating capacity in California as of December 31,
2001, cancelled or postponed projects represented only about 13 percent of
the total additions to capacity proposed in Pennsylvania and about 15
percent of proposed capacity in Texas.

7 In California, of the power plant projects proposed from 1995 through
2001, 72 percent were submitted after electricity shortages began in May
2000. All Three States Have

Experienced Significant Cancellations in Recent Months

Page 13 GAO- 02- 427 Restructured Electricity Markets

Senior electricity industry analysts at investment firms told us that the
combination of three events during the past year- the national economic
slowdown, the terrorists? attacks on September 11, and the collapse of Enron
Corporation- have further limited developers? near- term ability to propose
and build new power plants because the international capital markets are
less willing to invest in energy projects. They explained that the slowdown
has reduced economic growth and expected growth in electricity demand. The
terrorist attacks have, among other things, made insuring and re- insuring
all power plants more difficult and more expensive. In addition, they said,
the collapse of Enron, while not specifically hurting energy markets, has
increased concern about the financial condition of energy companies and led
to, among other things, (1) higher lending standards, (2) lower levels of
allowed borrowing, and (3) higher interest rates for borrowing. In addition,
the stock prices of many major independent developers have dropped
substantially, further limiting their ability to raise capital.

In the three states we reviewed, state and local agencies responsible for
air and water quality and land use decisions review applications for
constructing and operating power plants to ensure compliance with relevant
laws and regulations. In addition, California requires the California Energy
Commission (CEC) to approve all power plant projects with at least 50
megawatts of capacity. Because most developers in California and
Pennsylvania have chosen sites for new plants in areas that have poor air
quality, environmental agencies generally conducted more comprehensive
reviews and required stricter limits on emissions. Both California and Texas
provide enhanced public participation during the application review process,
which can add time to the approval process to address sensitive issues.

In California, 1 of 35 regional air districts and one of 9 regional water
boards, or EPA?s Region 9 in some parts of the state, review the application
to assess the proposed project?s compliance with air and water quality
requirements. Local governments review the applications for compliance with
land use and zoning requirements. If applicable, state and federal agencies
review the application for compliance with the Endangered Species Act. In
addition to these reviews, CEC must approve new power plant projects above
50 megawatts before they can be built, adding another layer of review.
According to the state, CEC exists to ensure that needed energy facilities
are authorized in an expeditious, safe, and environmentally acceptable
manner. As part of its role, CEC oversees Recent Events May Limit

Planned Construction and Additional Plans

Regulatory Processes Are Generally Similar in the Three States, Although
California Requires an Additional Approval

The States Use Similar Review Processes but California Adds Another Level of
Review

Page 14 GAO- 02- 427 Restructured Electricity Markets

compliance with the California Environmental Quality Act, which requires an
evaluation of the environmental impact of state- approved projects planned
for the state. CEC decisions can overturn the permitting decisions of other
state and local agencies. In one case, for example, CEC approved a power
plant even though the local community had refused to grant a land- use
zoning permit. CEC also analyzes other aspects of the project, which may not
be examined by other agencies, including the plant?s technical design, fuel
use and efficiency, transmission equipment, and socioeconomic impacts. The
CEC certification process allows for public participation throughout the
application review process. (See app. II.) In California, the average period
for approval was 14 months, excluding smaller plants that were approved
under the state?s temporary 21- day emergency siting process. 8 Approvals
for large plants- those with generating capacity of more than 200 megawatts-
took about 16 months.

Pennsylvania has no single state agency specifically responsible for
approving new power plant projects. As with other industrial projects, power
plant developers must work through (1) the Pennsylvania Department of
Environmental Protection to obtain air quality and water quality permits and
(2) local government agencies to obtain zoning and other land- use permits.
In addition, developers in eastern or central Pennsylvania would have to
obtain permits from the Delaware River Basin Commission or the Susquehanna
River Basin Commission, respectively, for access to river water. If
applicable, federal and state agencies review the application for compliance
with the Endangered Species Act. (See app. III.) The primary permit needed
for approval to construct a power plant is the air quality permit, and from
1995 through 2001, the average time needed to obtain this permit was about
14 months. Approvals for plants larger than 200 megawatts took about 13
months.

Similarly, Texas has no single state agency specifically responsible for
approving new power plant projects. Instead, the Texas Natural Resource
Conservation Commission is responsible for approving environmental permits
and in some cases, municipal governments regulate land use

8 In response to the electricity crisis, California authorized expedited
reviews of (1) 21 days for small plants that operate only during peak demand
periods, (2) 4 months for simplecycle plants, and (3) 6 months for combined-
cycle and steam power plants with no adverse environmental impacts. CEC
approved 11 projects under the 21- day process. In August 2001, the
California State Auditor, using a different time period, reported that CEC
review and approval took 14 months, on average. See California Energy
Commission: Although External Factors Have Caused Delays in Its Approval of
Sites, Its Application Process Is Reasonable.

Page 15 GAO- 02- 427 Restructured Electricity Markets

through the zoning process. If applicable, federal and state agencies review
the application for compliance with the Endangered Species Act. (See app.
IV.) For plants approved from 1995 through 2001, developers obtained an air
quality permit- the primary permit required- in 8 months in Texas. Approvals
for plants larger than 200 megawatts also took about 8 months.

Table 1 shows the time it has taken to complete the approval process in each
of the three states. As the table shows, the time to complete the review
process was less predictable in California than in the other two states-
approval for 5 of California?s 21 medium- to large- scale projects took 18
months or longer.

Table 1: Regulatory Approval Time Frames for Power Plants in California,
Pennsylvania, and Texas California a Pennsylvania Texas Time for regulatory
approval Projects Percent Projects Percent Projects Percent

6 months or less 4 19 2 9 17 25 6 months to 1 year 5 24 12 55 43 64 1 to 1-
1/ 2 years 7 33 6 27 7 10 1- 1/ 2 to 2 years 3 14 0 0 0 0 More than 2 years
2 10 2 9 0 0

Total 21 100 22 100 67 100 b a Includes three projects that CEC approved
under the expedited 4- month and 6- month processes, but excludes the plants
approved under the temporary 21- day expedited process for peak- demand use.
b Does not add due to rounding.

Sources: CEC, the Pennsylvania Department of Environmental Protection, and
the Texas Natural Resource Conservation Commission.

The gas- fired power plants now being built emit nitrogen oxides, which
directly contribute to ozone pollution. 9 To control these emissions, air
pollution control requirements for these power plants vary according to the
planned location and the amount of the plants? emissions, as well as whether
a state has stricter standards than the federal standards. In general, large
power plants planned for an area that does not meet federal

9 Ozone is not directly emitted into the air. Instead, it is produced in the
atmosphere through the interaction of volatile organic compounds, nitrogen
oxides, and sunlight. Fossil- fueled power plants emit nitrogen oxides. Most
Approved Power

Plants in California and Pennsylvania Are Located in Areas with Stringent
Air Quality Requirements

Page 16 GAO- 02- 427 Restructured Electricity Markets

air quality standards 10 -known as non- attainment areas- must obtain a Non-
Attainment New Source Review permit. 11 This permit requires a new power
plant to install the most advanced pollution control equipment 12 and offset
the new plant?s emission of pollutants by reducing emissions elsewhere in
the area. The new power plant could, for example, buy emission reduction
credits, called offsets, from another industrial facility that has closed or
adopted less polluting technology beyond what is required under regulations.
The advanced pollution control equipment and the purchase of these offsets
from another company can add substantially to a power plant?s costs compared
with the requirements in an attainment area. In attainment areas- areas that
meet federal air quality standards- plants can obtain a Prevention of
Significant Deterioration permit, which requires less stringent technologies
to control emissions. 13

As shown in figure 3, all three states have non- attainment areas for EPA?s
ozone standard. Substantial portions of California and Pennsylvania are non-
attainment areas with many areas of either extreme or severe air quality
impairment. In addition, because Pennsylvania is part of a regional ozone
transport area, the entire state must be treated as a non- attainment area.
In contrast, only the Dallas, Houston, Beaumont, and El Paso metropolitan
areas are non- attainment areas for ozone in Texas. Overall, 65 percent of
the approved plants in California and about 60 percent of the approved
plants in Pennsylvania were required to obtain air permits requiring more
stringent controls, primarily because power plant projects for California
and Pennsylvania generally were proposed for sites in non- attainment areas
for ozone. In contrast, in Texas, only 18 percent of

10 EPA has established health- based air quality standards, as part of the
National Ambient Air Quality Standards, for ozone, carbon monoxide, nitrogen
dioxide, sulfur dioxide, particulate matter, and lead.

11 Developers can avoid stringent Non- Attainment New Source Review
requirements if a power plant?s emissions are below the regulatory
threshold. This can be done by limiting a plant?s operations to a fixed
number of hours per year or by using a process called

?netting,? which allows a developer at an existing facility, such as a
refinery or power plant, to offset the increase in emissions of the new
equipment by reducing the existing facility?s emissions.

12 Plants with large amounts of emissions that are planned for non-
attainment areas are generally required to install equipment capable of
meeting the Lowest Achievable Emission Rate (LAER).

13 Plants with large amounts of emissions planned for attainment areas are
generally required to install the Best Available Control Technology (BACT).

Page 17 GAO- 02- 427 Restructured Electricity Markets

the approved plants had to use more stringent controls, partly because 64
percent of the approved plants were located in attainment areas. 14

Figure 3: Ozone Non- Attainment Areas for EPA?s 1- Hour Standard as of
January 2002

Source: EPA.

California has led other states in requiring pollution reduction beyond what
is federally required. Specifically, California has a 1- hour ozone

14 Of the approved power plant projects in non- attainment areas, 50 percent
did not require more stringent control technologies in Texas, 41 percent did
not require these technologies in Pennsylvania, and 28 percent did not
require them in California. As a result, these power plants are allowed to
have higher emission rates than otherwise would have been allowed under a
Non- Attainment New Source Review permit.

Page 18 GAO- 02- 427 Restructured Electricity Markets

standard of 0.09 parts per million, as compared with EPA?s 0.12 parts per
million standard- which causes more areas of the state to be judged as
having poor air quality. With this standard, power plants in almost all
areas of the state must install some pollution controls. California requires
that smaller gas- fired power plants must limit their emissions- even those
with significantly lower quantities of emissions. Plants emitting more than
10 pounds per day of pollutants, or approximately 1.8 tons per year, must
evaluate pollution controls. In contrast, EPA has a minimum threshold of 10
tons per year for plants located in areas with the worst air quality.
Because California?s standards are more stringent than EPA?s, 9 of the 31
power plant projects approved in California since 1995 had to install
pollution control equipment to lower their emissions, which EPA would not
have required.

Furthermore, while EPA?s standards for new plants apply in all states, the
approved emissions level for a plant depends on how the state applies EPA?s
regulations. California generally required new power plants to reduce
emissions to lower levels than did other states. These lower levels
subsequently are considered by other states in setting their own BACT and
LAER standards.

Each of the three states allows for public involvement at several stages in
the permit review process, including the local community?s consideration of
zoning and other land- use permits and the state agency?s consideration of
environmental permits. Permitting decisions also can be appealed to the
state courts and, in some cases, to a state or federal agency.

In addition, both California and Texas allow members of the public to become
formal participants in the process for a power plant application. In
California, CEC can designate them as approved ?intervenors,? which enables
them to request data from the applicant, file motions, testify, and conduct
cross- examinations in formal hearings. Intervenors often have included
local interest groups, labor unions, and environmental interest groups. In
California, of 72 applications filed with CEC from 1995 through 2001, 39
have had intervenors. In Texas, members of the public meeting certain
requirements may request a ?contested evidentiary hearing? before an
administrative law judge. 15 In these proceedings, parties may present

15 Until recently, only people with a personal interest could request this
type of hearing. However, recently the criteria have broadened to allow more
people to participate. All Three States Seek

Public Comments on a Project, and California and Texas Allow the Public to
Participate in Hearings

Page 19 GAO- 02- 427 Restructured Electricity Markets

testimony, offer evidence, cross- examine other parties? witnesses, and
object to the introduction of evidence. The administrative law judge then
makes a recommendation to the permitting agency. Since 1995, 15 of 84 air
permit applications in Texas had a request for a contested hearing. Two
requests resulted in hearings.

The emergence of substantial local opposition to a new plant is a
significant factor in receiving necessary approvals, delaying regulatory
decisions in many cases, according to regulators in each of the three
states. As a result, developers told us that they look for locations where
their project will receive local community support because its economic
benefits to the local community outweigh its negative effects, such as
increased air pollution. Texas permitting officials told us that communities
generally welcome new natural gas- fired power plants because they add to
the community?s tax base and pose few environmental concerns.

The market rules for connecting a new power plant to the local transmission
system (referred to as interconnection) in Texas differs markedly from those
in California and Pennsylvania. In Texas, interconnection costs can be
significantly lower for developers because consumers directly pay, through a
charge on their electricity bills, for upgrades to the electric transmission
system that are required with the addition of the new plant. In California
and Pennsylvania, under current FERC- approved rules, developers pay for the
system upgrades with the expectation that they will recoup these costs
through electricity sales. Furthermore, in Texas, developers of new power
plants sign standard interconnection agreements that specify the terms and
conditions of connecting the new plant to the transmission system, which
speeds up the negotiation process; California and Pennsylvania do not have
such agreements. In November 2001, FERC requested comments and suggestions
from interested parties for developing a standard interconnection agreement.

Under Texas? restructuring rules, developers building plants must only pay
for direct interconnection costs (switchyard, substation improvements, line
extension- if applicable). Under these rules, all electricity consumers
directly pay for the entire transmission system including the costs to
upgrade the system to carry the additional electricity produced at the new
power plant. The interconnection of a new plant can affect transmission
lines located elsewhere on the system, requiring the system be upgraded. The
state made this decision, according to officials at the Texas Public
Connecting New

Power Plants Is Less Costly and Faster for Developers in Texas Than in the
Other Two States

Interconnection Is Less Expensive for Developers in Texas Than in the Other
Two States

Page 20 GAO- 02- 427 Restructured Electricity Markets

Utility Commission (PUC), to provide a level playing field on which new
power plants can compete against existing plants.

This rule emerged after the Texas PUC found, in assessing competitiveness in
the wholesale market, 16 that the financial responsibility for needed
transmission system upgrades was not clearly defined. Lack of clear
definitions, it concluded, could lead to conflicts and delays, and
discourage the development of new privately owned power plants.

The Texas PUC has addressed cost allocation issues through the Electric
Reliability Council of Texas (ERCOT) by clarifying the rules for allocating
system upgrade costs. 17 Under these rules, PUC allocates the annual cost of
the transmission costs including these transmission system upgrades and
related maintenance to the entities selling directly to consumers, on the
basis of their total electric demand and passes these costs on to consumers
through a per- kilowatt- hour fee. 18 As a result of these cost allocation
rules, interconnection costs to developers are well defined and known early
in the development process.

To connect a power plant project to the transmission system, developers must
(1) request an interconnection from ERCOT, (2) pay for two ERCOT studies on
the proposed plant?s potential impact on the transmission system, and (3)
provide a security deposit for any costs incurred by the transmission
service provider. 19 ERCOT representatives said that they

16 Project No. 17555, Investigation into the Competitiveness of the
Wholesale Market.

17 In response to concerns raised in the Texas PUC?s rulemaking project
18703, changes were adopted to the transmission rule that clarified the cost
responsibility of transmission upgrades. The PUC Investigation report stated
that these changes and its clear statement of cost responsibility should
minimize the potential for the gaming of the interconnection process by
market participants, because there is now far less incentive to occupy a
place in the interconnection queue merely as insurance against the
assessment of the cost of significant transmission upgrades.

18 The 1999 legislation allowing retail competition authorized river
authorities to provide transmission services statewide. Over the next 5
years, the Lower Colorado River Authority, in a public/ private venture,
plans to add up to $500 million in transmission projects that ERCOT
identified as important to support the electricity market in Texas. These
costs would be recovered through electricity rates within ERCOT.

19 The developer?s deposit covers the cost of planning, licensing, and
constructing any new transmission facilities associated with the requested
transmission service. According to ERCOT officials, the deposit ensures that
transmission improvements are made for only serious projects and prevents
losses resulting from cancellations. The deposit is returned when the new
power plant begins to use the requested transmission service.

Page 21 GAO- 02- 427 Restructured Electricity Markets

conduct these studies in the order received and completion times vary
depending on the application. Generally, the first screening study is
completed within 90 days and the more detailed analysis in another 60 days.
Developers said that because they do not pay for transmission upgrades, they
can locate plants outside of areas with congested transmission systems, such
as Dallas. As a result, power plants in Texas generally have been located
outside non- attainment areas. According to Texas PUC and ERCOT officials,
substantial upgrades to the transmission system were underway because many
new power plants are being located in areas in which the existing
transmission system could not adequately transmit the added capacity. PUC
officials believe that transmission improvements will lead to improved
competition in the long- term and noted that ERCOT has given priority to
addressing bottlenecks in the transmission system to ensure that all the
markets in the state have access to these new supplies of electricity.

In contrast, developers in Pennsylvania pay for both the transmission system
upgrades and the direct interconnection costs. Requiring developers to pay
for system upgrades acts as an incentive for proposing plants in locations
that do not require substantial transmission system improvements or the
addition of new power lines, according to staff at PJM Interconnect,
Pennsylvania?s transmission system operator. Developers must also pay a
deposit for PJM Interconnect to complete interconnection studies- as much as
$7.5 million in one case for one of the three studies. PJM Interconnect
conducts transmission studies for power plant projects as a group- all
proposals received within a specific time period are analyzed together.
According to PJM Interconnect staff, they need to study the system impacts
of all the applications received to accurately assess the interactive
implications of multiple new power plants, even though some of the power
plants in several of the groups may never be built.

Similarly, developers in California pay for both the direct interconnection
costs and upgrades. However, in California, the local transmission system
owner determines the cost of the system upgrades, with limited oversight by
California?s transmission system operator. To connect to the local system, a
developer submits an interconnection request to the transmission system
owner and the operator. To assess the work and associated costs for the
interconnection, the transmission system owner studies the impact of the
proposed plant on the transmission system to identify potential reliability
problems. If this study identifies reliability problems, the developer may
request the transmission system owner to perform a detailed facilities study
to determine the measures needed to

Page 22 GAO- 02- 427 Restructured Electricity Markets

mitigate those impacts and to identify their associated costs. Current rules
require the power plant developer to pay the costs of the interconnection
studies and the system improvements required to mitigate reliability
problems. 20 The California transmission operator critiques these studies,
primarily by evaluating their assumptions and the role of other plants
expected on- line.

To foster competition and facilitate negotiations, Texas requires developers
and the local transmission owners to use a standard interconnection
agreement to (1) assign responsibility for paying the costs of any upgrades
to the transmission system needed for carrying the new plant?s added
electricity capacity, (2) allocate ownership interests in these assets, and
(3) assign responsibility for liability associated with plant and
interconnection facility operations.

In establishing this process, the Texas PUC sought to (1) ensure coordinated
planning for transmission systems, (2) eliminate delays in the
interconnection process, and (3) remove incentives for the transmission
providers to favor their own power plants. The standard interconnection
agreement, a contract between the power plant developer and the owner of the
local transmission system, includes standard terms and conditions and sets
specific deadlines for the local transmission system owner to complete the
connection and for the developer to start plant operations. The agreement
also provides rights to either party to terminate the agreement if the other
fails to meet its deadline. Developers told us that the Texas process is
much faster to negotiate because, to the extent that the cost allocations
can be determined ahead of time, many issues are removed from the business
negotiations. Accordingly, both developers and ERCOT staff said that the use
of a standard interconnection agreement has worked well in Texas.

In contrast, in California and Pennsylvania, developers and the local
transmission system owner do not use a standard agreement and therefore

20 California?s transmission system operator has filed a request with FERC,
referred to as amendment 39, to modify the cost allocation of transmission
additions required when interconnecting new power plants, including the
treatment of system upgrades. According to California?s transmission
operator, this amendment would allow developers to choose to pay for some
transmission system upgrades that allow a plant?s output to reach a specific
location. In return, the developer would acquire a financial transmission
right for use of specific equipment. FERC has not ruled on the transmission
operator?s filing. Texas Uses a Standard

Agreement to Facilitate Interconnection, Unlike California and Pennsylvania

Page 23 GAO- 02- 427 Restructured Electricity Markets

must negotiate the terms and conditions of the interconnection agreement,
which typically adds time to the process. 21 Developers in California said
that they have to accommodate differences in interconnection policies among
transmission owners. These differences, which can occur because different
transmission owners interpret the FERC- approved rules differently, have
resulted in interconnection disputes between the transmission owners and
developers that create barriers or delays to building new power plants. The
developer and the transmission owner can either resolve these disputes or
appeal to FERC for resolution, which would add even more time.

PJM Interconnect staff plan to develop a pro forma interconnection agreement
because it appears to offer advantages over a lengthy negotiation process.
The staff believe that FERC wants the operator of the regional transmission
system to sign the agreement, but the staff would prefer to keep the
agreements between the developer and the transmission owner, citing concerns
about PJM Interconnect?s potential liability if FERC requires it to sign.
They added that, if required, PJM Interconnect would become a party to the
agreement but would need to purchase liability insurance with these costs
passed on to consumers.

We found that reaching agreement on interconnection was substantially faster
in Texas than in the other two states. Specifically, it took 11 months, on
average, in Texas, compared with 28 months in California and 30 months in
Pennsylvania. 22

21 A standardized format is used in Pennsylvania for plants of less than 40
megawatts. 22 This analysis measures from the date of application until the
interconnection agreement was signed. For Texas, data were available for 16
of 34 projects completed since 1995. For Pennsylvania, data were available
for 31 completed projects within PJM Interconnect?s control area. PJM
Interconnect officials said that the process has improved and now takes 20
months, on average, to reach agreement. For California, we excluded smaller
plants approved under CEC?s 21- day expedited process, which took 11 months,
on average. California?s average would be 22 months if these projects were
included.

Page 24 GAO- 02- 427 Restructured Electricity Markets

In November 2001, FERC published an Advance Notice of Proposed Rulemaking in
the Federal Register requesting that affected parties provide suggestions
and comments for developing a standard interconnection agreement. 23 FERC
noted that it had previously required local transmission system owners to
provide non- discriminatory, or comparable, access to transmission service
and established standard terms and conditions for the service provided by
the transmission system owner. However, this requirement did not directly
address power plant interconnections.

In this advance notice, FERC also provided the views of both the independent
developers and transmission system owners. According to FERC, developers
have asserted that, among other things, (1) the treatment they receive is
not comparable to the treatment the transmission provider receives for the
power plants it owns, (2) system upgrade costs charged to developers are
sometimes not related to the interconnection, and (3) delays and
uncertainties occur because the transmission owner?s rules do not specify
binding commitments and firm deadlines for completion of specific actions.
In contrast, FERC reported that transmission owners believe that, among
other things, they need minimum financial commitments from developers
seeking interconnection to weed out plants that are unlikely to be built.
The financial commitments are intended to minimize the number of plants they
will have to study so that they can accurately assess how much total
generating capacity will be added to the system. Transmission owners also
want assurance that consumers in their local transmission system will
benefit from, or at least not be burdened by, adding power plants,
particularly when a developer seeks to locate a plant in one system that
would primarily sell electricity to consumers in an adjacent system.

23 FERC issued a Notice of Proposed Rulemaking for a standardized
interconnection agreement as FERC docket on April 24, 2002, and published
the notice in the Federal Register on May 2, 2002. FERC Is Evaluating

Options for Developing a Standard Interconnection Agreement

Page 25 GAO- 02- 427 Restructured Electricity Markets

Restructured markets change the context for investment by enabling
developers to broaden the number of markets they consider and by requiring
them to make financial commitments long before they actually build a power
plant, according to the developers we interviewed. In this context, they
generally propose power plant projects in markets where prices are high
enough to expect that plants will be profitable. However, they actually
build plants in markets where expected profits outweigh possible risks that
could reduce a plant?s profitability- such as changes in the state,
regional, or national rules for the electricity market.

In restructured markets, developers told us, several conditions have changed
the basis for their decisions to build or not to build power plants.
Restructured markets, unlike regulated markets, require developers to
independently assess the need for new power plants and their potential
profitability. Restructuring allows them to compare opportunities to build
plants across multiple markets- state and regional markets as well as
international markets. If they decide that a particular market will not be
profitable, they will build elsewhere, according to the developers we spoke
with. Furthermore, they propose building power plants at three or more sites
for each plant that they actually intend to build. Multiple proposals ensure
that at least one site will be ready to receive a turbine and other power
plant equipment at a specific date. Uncertainty about market conditions at
each site and about whether and when they will obtain the necessary permits
and approvals to begin construction dictate this multiple site approach,
according to developers. Industry analysts noted that because developers
have proposed many more project sites than they intend to build, future
market prices are less predictable than they otherwise would be.

These market uncertainties have been further complicated by an increased
worldwide demand for turbines and financing, forcing developers to compete
for these resources. Specifically, because of the increased demand,
developers said they made financial commitments to purchase combustion
turbines several years before they expect to receive them in order to ensure
that they will have turbines when they need them. These commitments can tie
up substantial amounts of capital: large turbines can cost $50 million or
more, while even small turbines can cost $16 million. Moreover, in
restructured markets, without the regulated market?s guarantee that
investors will have their loans repaid, developers have to compete for
investment capital. Bank executives told us they evaluate each power plant
project alongside other potential investments, including power plant
projects in other states and countries. Developers in

Restructured Electricity Markets Weigh a Project?s Projected Profitability
against Risks

Restructured Electricity Markets Have Changed the Basis for Investment
Decisions

Page 26 GAO- 02- 427 Restructured Electricity Markets

General market conditions and specific site conditions affect expected
profitability, according to developers we interviewed. With respect to
general market conditions, they first seek opportunities for new investment
by analyzing future electricity prices and- to a lesser extent-
opportunities to sell other products. 24 In estimating the prices that new
power plants may receive in a restructured market, developers evaluate
market signals, including current electricity prices and prices in the
forward or futures market. 25 Developers then review information about
potential competitors in a given market, including the type and age of
existing plants and their estimated production costs, as well as economic
growth projections that affect demand increases. Finally, developers
estimate the overall profitability of selling electricity in a market by
comparing the estimated future electricity prices with the estimated cost to
generate electricity, based on fuel cost estimates in the area and other
variable production costs. 26 For example, industry analysts told us that
while actual production costs will vary, typical fuel costs for a new
combined- cycle power plant are about 2.1 cents per kilowatt- hour-
substantially less than the 3.7 cents per kilowatt- hour cost of some
existing gas- fired power plants. 27

Once they identify a potentially profitable market, developers told us, they
look for suitable power plant sites and evaluate the sites? estimated
development costs. For gas- fired combined- cycle power plants, developers
prefer locations that are near the intersection of a large natural gas
pipeline and high voltage transmission lines and that have access to an

24 In addition to electricity, a new power plant can sell generating
capacity (available for contingencies such as outages or unanticipated
increases in demand) and specialized services, such as voltage regulation.

25 Forward contracts allow buyers and sellers to enter into contracts for
electricity to be delivered at a future point in time. Futures contracts
allow buyers and sellers to trade future deliveries of electricity.

26 Experts said that they evaluate only a plant?s variable production cost;
not its average cost. Properly estimated variable production costs, they
said, illustrate the profitability of operating the plant at a point in time
and are used in determining which units should operate. Average costs
incorporate construction and other previously incurred costs that do not
reflect the profitability of operating a plant at a point in time.

27 Actual plant costs will vary. Heat rate is commonly used as a fuel
efficiency measure and refers to the rate at which fuel is converted to
electricity in BTUs per unit of electricity output (kilowatt- hours). This
estimate is based on natural gas costs of $3 per thousand cubic feet, 6,700
BTU/ kilowatt- hours heat rate for a new plant and 12, 000 BTU/
kilowatthours heat rate for an older existing plant. Profit Expectations
Drive

Developers? Decisions About Where to Propose New Power Plants, as
Experiences in California, Pennsylvania, and Texas Illustrate

Page 27 GAO- 02- 427 Restructured Electricity Markets

adequate source of cooling water. 28 Developers analyze each site?s
potential for receiving state and local regulatory approval and for
minimizing construction, interconnection, and operating costs. Developers
then seek to acquire the right to develop the property- by either purchasing
the land or obtaining an option to purchase the land- and then may begin
pursuing regulatory and interconnection approvals for the site.

In restructured markets, developers said, they regularly analyze each power
plant project?s market and regulatory risks to determine whether these risks
could significantly reduce expected profitability. Market risks include the
possibility that electricity prices will be lower than expected and/ or that
production costs will be higher than expected. Regulatory risks include the
possibility that the rules for the electricity market will change or that
the rules governing power plant operations will change. 29 Developers
reevaluate market and regulatory risks as the project moves forward to
determine whether to continue the project. Higher risk levels can cause
developers and commercial banks to delay investment until expected profits
outweigh the increased risk, according to developers.

Assessing risk is important, developers said, because a new power plant is
expensive to build- costs could exceed $500 million- and operates for 20
years or more. Some developers and commercial banks prefer investment
opportunities with lower levels of risk, such as when they can sell a
substantial portion of the plant?s electricity production through longterm
contracts with set prices and terms. Other developers said that they will
invest in riskier projects if expected profits are higher.

Developers also told us that regulatory risks, such as lengthy and uncertain
state approval processes and stringent environmental compliance
requirements, were not, by themselves, obstacles to building a power plant
in a state. Rather, they said, these factors can increase a project?s risk
because it is more costly to build and operate and because long- term
projections about market conditions are less reliable. For

28 In addition to rivers and streams, cooling water sources could include at
treatment plantprocessed water, known as ?gray water,? before it is released
into surface waters. 29 Market risk can occur when mild temperatures or
lower levels of local economic activity reduce electricity demand and lower
prices. Regulatory risk can also occur when regulators intervene to alter
electricity market rules by, for example, imposing or removing a price cap.
Market and Regulatory

Risks Counterbalance a Site?s Potential Profitability

Page 28 GAO- 02- 427 Restructured Electricity Markets

example, plants subject to more stringent environmental standards need more
costly emissions- reduction equipment and have less operating flexibility to
respond to changes in demand, according to a turbine manufacturer.
Furthermore, limiting a plant?s ability to respond to changes in demand can
reduce its profitability.

In restructured states, market rules, which set the terms for buying and
selling electricity and related products, can affect the potential
volatility of electricity prices. For example, prohibiting the use of long-
term contracts exposes buyers and sellers to the risk of rapidly fluctuating
prices. Alternatively, a state with a price cap could expose power plants to
the risk that electricity sales will be unprofitable under certain
circumstances.

Given the importance of market rules, developers prefer stable and
transparent rules that clearly describe the opportunities and risks inherent
in a state?s market. They told us that they conduct a detailed analysis of
the rules and participants for each market that they may enter because
market rules vary. For example, restructuring created some multistate
regional markets, while other markets are still dominated by regulated
utilities and are subject to substantial state control.

Furthermore, developers said that they prefer rules that provide clear and
direct opportunities to manage the risk of volatile electricity market
prices. Often, developers can reduce their exposure to this risk by (1)
buying natural gas at fixed prices through long- term contracts and/ or (2)
selling the plant?s future output through long- term contracts that
generally set a future sales price. Several developers told us that they
seek to commit at least 50 percent of a new plant?s output to long- term
sales contracts. Lenders and staff at investment ratings companies also told
us that long- term contracts with financially sound purchasers are important
tools to lower risks when financing new power plants. They noted that long-
term contracts with fixed prices and terms enable developers to obtain more
favorable financing terms because selling a portion of the plant?s future
output reduces the project?s market risk.

While transparent market rules can improve the investment climate for a
specific market, some developers were also concerned about whether the rules
were consistent and equally enforced. Operators of regional transmission
systems, transmission system owners, and federal and state regulators are
each responsible for enforcing market rules. Developers said that
restructured markets were generally improving their treatment of independent
developers. However, some developers were still concerned about the
administration of the transmission system and the potential for

Page 29 GAO- 02- 427 Restructured Electricity Markets

unequal access to market information in markets where they compete with
power plants owned by transmission system owners.

California, Pennsylvania, and Texas, with different market and regulatory
environments, illustrate how developers weigh profitability and risk.

According to electricity industry analysts, profitability and risk
considerations in California delayed proposals to build power plants in the
state. Developers cited the following profitability concerns before prices
began rising dramatically in May 2000: (1) the state required its three
largest utilities to use only the short- term electricity market to buy
nearly all of the electricity sold to their customers and (2) electricity
prices in the short- term markets averaged 2.9 cents per kilowatt hour,
which was generally lower than prices in other U. S. markets, and, as a
result, offered lower potential profits than in other markets. The market
rules limiting the use of long- term contracts in California effectively
increased the risk of building power plants in that state. 30 One power
plant developer told us that because California did not have a robust and
predictable market for long- term electricity sales, it could evaluate only
the prices in the short- term electricity market, which exposed the
developer to more risk without the expectation of higher profits. However,
developers told us that once prices began to rise, they began to propose
building more power plants in the state. From May 2000 through June 2001,
electricity prices increased fourfold, on average, to 13.4 cents per
kilowatt- hour.

In response to the electricity crisis during 2000 and 2001, California took
several actions that increased its involvement in its electricity markets.
First, in January 2001, the state replaced the governing board of its
transmission system operator with members appointed by the Governor. Second,
the state created the California Power Authority, which can,

30 California later revised its market rules to allow utilities to enter
into long- term contracts, but only on a very limited basis through the
state- operated market and without the California PUC?s assurance that
utilities would be able to recover their costs. Experiences in Three

States Illustrate the Influence of Profitability and Risk Considerations on
Decisions to Propose Power Plants

Lower Potential Profits and Higher Risks in California Delayed, and May
Continue to Delay, Investment

Page 30 GAO- 02- 427 Restructured Electricity Markets

among other things, finance up to $5 billion for power plants. Senior state
officials have said that the electricity market would not be sufficiently
competitive until an excess capacity of 15 percent was located in the state
and that state financing provided one way to increase in- state generating
capacity. However, according to investment analysts and developers, the
potential that the state might build up to 15 percent excess generating
capacity increases the risk and uncertainty for investing in California?s
electricity market. Third, California entered into long- term contracts to
buy electricity and bought electricity day- to- day in short- term markets
because the state?s two largest utilities faced severe financial problems
and difficulty purchasing electricity.

Taken together, these actions have created concerns among developers about
whether the operator of the California transmission system will provide
equal treatment for market participants. Specifically, employees for the
state agency responsible for buying electricity had access to the
transmission system operator?s control center and may have had access to
real- time data not provided to other market participants, even though the
transmission system operator?s rules prohibit such treatment for market
participants. Audits of the transmission system?s operations identified
several other violations of the rules. Although FERC ordered state staff to
leave the operations room, developers remain concerned that the state may
receive special treatment from the transmission operator. This concern
continues because the state has so much potential influence over the market,
which raises the risk of entering the market for independent developers.

Furthermore, investment analysts told us that some investors are even more
cautious about investments that rely on California?s electricity markets.
The lack of stable market rules presents uncertainty regarding the eventual
market in the state. In addition, the perception that the state is seeking
to abrogate the long- term contracts it signed last year has raised concerns
about the finances of some projects. These analysts explained that, due to
the risks in the current market, energy investments in California may
require higher returns and/ or more stringent loan terms, 31 as well as
management of risks through, for example, the use of long- term

31 Developers may need to invest more equity and less debt to finance new
power plants. Developers and investment advisors said that many new projects
are being financed as part of multi- plant portfolios and use more rigid
loan terms requiring that loans be repaid sooner than scheduled if terms of
the loan are not met.

Page 31 GAO- 02- 427 Restructured Electricity Markets

contracts with purchasers other than the state as a basis for obtaining
loans.

In Pennsylvania, developers proposed building relatively few power plants
because while the risks were manageable, the profits were too low, according
to developers. In addition, the transmission interconnection process was
protracted, with uncertainty regarding the capital investment needed to fund
transmission upgrades. The market rules have permitted power plant
developers to enter into contracts to sell electricity for delivery at a
future date. These long- term contracts enable developers to manage their
risk by providing fixed prices and terms for electricity sales. However,
electricity prices were too low to attract investment. Low- cost existing
generating capacity was available because the state?s industrial base has
declined as many steel plants and other industries that consumed substantial
quantities of electricity closed or moved out of state, according to
Pennsylvania PUC officials. However, developers said that Pennsylvania has
attracted some investment because of its access to other markets such as
those in northeastern electricity systems in New York State and New England,
which have had relatively high prices.

In Texas, risks were manageable and profits were attractive. As discussed
earlier, the market rules in Texas reduced risk through its (1) relatively
faster regulatory approval process and (2) interconnection rules, which
lowered development costs and simplified the administrative process. In
addition, the rules in Texas allowed developers to manage their risk through
long- term contracts. Furthermore, developers invested in Texas during the
initial operation of its wholesale electricity market because the market
appeared to be profitable. The electricity prices and the cost of production
at existing plants were relatively high compared with the estimated cost of
producing electricity at new plants. While Texas significantly increased its
generating capacity, several developers and lenders expressed concern that
the Texas market may soon have too much new capacity.

As restructuring broadens electricity markets to span multiple states,
states will become more interdependent for a reliable supply of electricity-
one state?s problems can affect its neighbors. In this context, restructured
electricity markets rely on the investment decisions of individual
developers. Consequently, the reliability of the electricity system- and the
success more generally of restructuring- now hinges on whether these
developers choose to enter a market and how quickly they are able to respond
to the need for new generation capacity. Pennsylvania and Texas

Illustrate How Developers Balance Risks and Profits

Conclusions

Page 32 GAO- 02- 427 Restructured Electricity Markets

Developers decide on which markets to enter by balancing profitability and
risk- that is, by considering how the regulatory processes and markets rules
affect risk in a market and to a lesser extent, the profitability of
building a plant in that market. FERC?s decisions on market rules and the
states? decisions on regulatory rules can affect the balance of
profitability and risk in a state. The experiences of California,
Pennsylvania, and Texas show how these considerations have played out. The
high levels of perceived risk and low levels of estimated profitability in
California appear to have resulted in lower levels of early investment in
new power plants in that state. On the other hand, the experience in Texas
illustrates that the ability to manage risk and higher levels of estimated
profitability combined to attract significant investment into new power
plants from 1995 through 2001. The experience in Pennsylvania illustrates
that while risk may be manageable, estimated profits also have to be high
enough to attract investment.

Developers can be deterred from building a power plant if the market has
lengthy delays between making the proposal and selling electricity. These
delays increase a developer?s uncertainty whether the proposed project will
be approved and whether additional costs will be incurred that reduce the
plant?s profitability. In this context, interconnection agreements are
critical in assessing profit and risk. Lengthy negotiations over
interconnection terms and conditions can increase the risk of developing a
new power plant because forecasts of market conditions in the more distant
future are less reliable than near- term forecasts. Texas was able to reduce
delays in negotiating these agreements, in part because the Texas PUC?s
standard agreement already specified many of the parties? responsibilities.
In contrast, under rules approved by FERC, California and Pennsylvania
allowed developers and transmission system owners to negotiate their
responsibilities, which has resulted in a lengthy process- more than twice
as long as in Texas. A standard agreement also provides better assurance
that transmission owners will treat all developers of new power plants
equally. In addition, Texas? rules provided a clear method for allocating
costs associated with upgrading the transmission system, which appear to
have sped negotiations because the amount and allocation of these costs are
not contested.

To facilitate development of power plants needed in restructured markets and
to provide comparable treatment for all developers, we recommend that the
Chairman of the Federal Energy Regulatory Commission, in consultation with
transmission system owners, power plant developers, and lenders, (1) develop
and require the use of a standardized Recommendations for

Executive Action

Page 33 GAO- 02- 427 Restructured Electricity Markets

interconnection agreement and (2) clarify how transmission system upgrade
costs are allocated.

We provided FERC with a draft of this report for review and comment. The
Chairman of FERC agreed with our recommendation, noting that FERC had issued
a Notice of Proposed Rulemaking on April 24, 2002, which would require
transmission system owners under FERC?s jurisdiction to use a standardized
interconnection agreement. FERC developed the proposed agreement in
consultation with industry participants. (See app. V for FERC?s comments.)
In addition, FERC provided comments to improve the report?s technical
accuracy, which we incorporated as appropriate.

As arranged with your offices, unless you publicly announce its contents
earlier, we plan no further distribution of this report until 30 days after
the date of this letter. At that time, we will send copies to appropriate
congressional committees, the Federal Energy Regulatory Commission, the
Director of the Office of Management and Budget, and other interested
parties. We will make copies available to others on request.

If you or your staff have any questions about this report, please contact me
at (202) 512- 3841. Key contributors to this report are listed in appendix
VI.

Jim Wells Director, Natural Resources

and Environment Agency Comments

Appendix I: Scope and Methodology Page 34 GAO- 02- 427 Restructured
Electricity Markets

To compare the electricity needs of California, Pennsylvania, and Texas, we
examined reliability reports prepared by the North American Electric
Reliability Council and the three regional councils that include most of the
area of the states that we studied- the Western System Coordinating Council
for California, the Mid Atlantic Area Council for Pennsylvania, and the
Electric Reliability Council of Texas (ERCOT) for Texas. To assess the
extent to which these states have added new power plants or received
proposals to add power plants, we used industry databases from Resource Data
International (RDI). We used RDI?s PowerDat database to identify new
generating units that began operation between 1995 and 2001. RDI obtains
data for the PowerDat database from a range of public filings to the Energy
Information Administration, the Federal Energy Regulatory Commission, and
other entities. We also used RDI?s NewGen database to identify proposals to
build new power plants, as well as construction, cancellations and
postponements of new power plants. RDI obtains data for the NewGen database
from various sources, including developers, government agencies, banks,
trade journals, and newspapers. Data on proposals may not fully reflect all
capacity that has been proposed at a point in time. We did not verify the
databases provided by RDI.

To compare the regulatory processes for approving new power plants, we
reviewed reports, interviewed officials in the states, and examined data. We
reviewed reports prepared by the California State Auditor, the California
Energy Commission (CEC), and industry summaries of the permitting process
prepared for the Edison Electric Institute, an industry trade association.
We visited California, Pennsylvania, and Texas to interview federal and
state regulatory and permitting officials to assess (1) each agency?s
responsibilities; (2) each state?s implementation of the Clean Air Act and
Clean Water Act, as well as Endangered Species Act; (3) each state?s process
for public participation; and (4) the amount of time required for approval.
The state agencies we interviewed in California included CEC, the
Electricity Oversight Board, the Governor?s Green Team, and the California
Environmental Protection Agency, as well as two regional air quality
districts. In Texas, we interviewed officials of the Texas Natural Resource
Conservation Commission (TNRCC), which is responsible for issuing permits
for air quality and water quality. For Pennsylvania, we interviewed
officials at the Pennsylvania Department of Environmental Protection (DEP)
and the Delaware River Basin Commission, which manages the Delaware River
System, including eastern Pennsylvania. We also interviewed officials at the
U. S. Environmental Protection Agency (EPA) and the U. S. Fish and Wildlife
Service at their Washington, D. C., headquarters offices and their regional
offices in each state. Appendix I: Scope and Methodology

Appendix I: Scope and Methodology Page 35 GAO- 02- 427 Restructured
Electricity Markets

To calculate the duration of each state?s regulatory review process for
approved power plants, we compared the time from when each application was
deemed administratively complete to the date CEC approved the project in
California, TNRCC approved pre- construction air permits in Texas, and the
Pennsylvania DEP approved pre- construction air permits in Pennsylvania- the
air permit is the primary regulatory process in Texas and Pennsylvania for
gas- fired power plants. We compared approved permits from January 1, 1995,
to December 31, 2001. To compare the implementation of the Clean Air Act
standards for approved permits, we identified the location of the plant
(whether in an attainment area or a non- attainment area), the type of
permit required, and the emissions limits. To compare the extent of formal
public participation prior to permit decisions, we compared the number of
requests for contested hearings and the number of contested hearings in
Texas with the number of permit applications with intervenors in California
for permit applications submitted between January 1, 1995, and December 31,
2001. Pennsylvania?s only mechanisms for formal public participation prior
to permit decisions are the public notification and comment process and
through public hearings.

To compare the processes for connecting new power plants with local
electricity transmission systems, we visited each of the three states and
interviewed officials at the transmission system operator serving the state:
we interviewed officials at the California independent system operator in
California; the PJM Interconnect in Pennsylvania; and ERCOT in Texas. In
addition, we interviewed officials at one of the California?s three major
utilities, which play a large role in completing the studies in that state.
To determine the amount of time needed to reach an interconnection
agreement, we examined data that the three states provided to us. To
determine the time that the process took in each state, we examined data
provided by (1) owners of transmission lines for plants larger than 50
megawatts in California, (2) PJM Interconnect in Pennsylvania, and (3) ERCOT
in Texas. We also met with officials of the Federal Energy Regulatory
Commission and the Edison Electric Institute.

To identify the key factors that developers consider in deciding where to
propose and build new power plants, we examined reports prepared by industry
experts and we met with senior executives of three large and three smaller
independent power plant developers to discuss the key elements in their
investment decisions. To learn more about the current technologies of power
plants being built in the United States and the market for turbines, we
interviewed executives of a large manufacturer of turbines and toured a
combined- cycle power plant. To identify what

Appendix I: Scope and Methodology Page 36 GAO- 02- 427 Restructured
Electricity Markets

factors are important to the financial markets, we interviewed energy market
investment analysts of two investment ratings companies serving the
financial markets and executives of four investment banks that lend money to
power plants developers.

We examined the approval process for building a new natural gas- fueled
power plant because these types of plants are the most common plants being
proposed in the United States. However, as agreed with your office, we did
not address related issues, such as the process for obtaining rights of way
for connecting to a nearby natural gas pipeline or the local transmission
lines. We conducted our work from August 2001 through April 2002 in
accordance with generally accepted government auditing standards.

Appendix II: California?s Process for Approving New Power Plant Projects

Page 37 GAO- 02- 427 Restructured Electricity Markets

Before a developer can begin to construct a new power plant project,
California?s CEC must approve the project, which incorporates all of its
required state and local permits. While CEC conducts its review, each
project is also reviewed by (1) 1 of 35 regional air districts and 1 of 9
regional water boards, or by EPA?s region 9 in some parts of the state, for
compliance with air and water quality requirements; (2) local governments
for compliance with land use and zoning requirements; and (3) if applicable,
state and federal agencies for compliance with the Endangered Species Act.
The CEC certification process allows for public participation through the
intervenor process, a public advisor, as well as by planned public
participation throughout the application review process.

CEC must certify all power plant projects with a generating capacity of 50
megawatts or more before they can be built and operated. As shown in table
2, CEC has established time frames for each phase of its certification
process in order to approve or reject a project within 1 year after a
developer?s application is deemed ?data adequate.? While CEC receives
information from other state and local agencies, it conducts an independent
assessment of each proposed project?s environmental impacts; public health
and safety; compliance with any applicable local, regional, state and
federal laws, ordinances, and regulations; efficiency; and reliability.
However, CEC does not assess the need for each proposed new plant. As the
lead agency for certification, CEC issues all required state and local
permits and is authorized to override the permitting decision of a state or
local government agency. Appendix II: California?s Process for

Approving New Power Plant Projects CEC?s Certification Process

Appendix II: California?s Process for Approving New Power Plant Projects

Page 38 GAO- 02- 427 Restructured Electricity Markets

Table 2: CEC?s Certification Process Scheduled time Phase Action

6 months to 1 year (possibly more) Pre- filing (not required) Applicant
meets with CEC and other state agencies (optional) to

discuss the certification process, filing requirements, and projectspecific
issues. Applicant prepares application. Filing Applicant files application
with CEC 45 days (longer if application is not deemed complete)
Determination

of data adequacy

CEC reviews the application for completeness. If the application is deemed
incomplete, CEC requests additional information from the applicant. CEC must
determine data adequacy within 30 days after the applicant submits a
supplemental filing. Other state and local agencies, including the local Air
Board and Water Board, review the application to assess permitting
requirements. 120 days Discovery/ data

requests CEC collects any other additional data required from the applicant,
agencies, and other relevant sources. CEC holds public workshops on
technical and procedural issues and public hearings. 90 days Analysis CEC
prepares a preliminary staff assessment based on its

independent analysis of the application. Public workshops are held on the
Preliminary Staff Assessment. CEC issues a final staff assessment, which is
the staff?s testimony for CEC?s hearing phase. 90 days Public hearings The
applicant, CEC staff, and relevant agencies present

testimony to the CEC committee assigned to the application. Intervenors and
the public are permitted to testify or provide comments. 65 days Decision
The CEC committee prepares the presiding member?s proposed

decision, which is circulated for public review and comment and revised. The
full Commission adopts, modifies, or rejects the proposed decision and
either approves or denies the application.

Total time: 410 days (excluding pre- filing)

Note: A power plant application typically consists of (1) the project
description; (2) site description; (3) engineering description of proposed
facilities; (4) electric transmission lines and any other linear facilities
related to the project; (5) project, site, and linear alternatives; (6)
environmental description and expected impacts including biological surveys
conducted at the appropriate time of year; (7) mitigation measures to reduce
potentially significant environmental impacts; (8) information necessary for
the local/ regional air pollution control district to make a determination
of compliance with local rules and regulations; (9) information necessary
for the regional water quality control board to issue waste discharge
requirements or a national pollution discharge elimination system permit;
(10) compliance with applicable laws, ordinances, regulations, and
standards; (11) financial impacts and estimated cost of project; and (12)
project schedule.

Source: CEC.

In early 2001, in response to the electricity crisis, the Governor of
California authorized CEC to replace the process described in table 2 with
the following expedited reviews of new power plant projects:

Appendix II: California?s Process for Approving New Power Plant Projects

Page 39 GAO- 02- 427 Restructured Electricity Markets

 21- day process for small power plants that operate only during peak
demand periods, provided that the plants could begin operating by September
30, 2001;

 4- month process for power plants using simple- cycle natural gas turbines
that could begin operating by December 31, 2002; and

 6- month process for combined- cycle and steam power plants, with no
adverse environmental impacts, for which applications have been submitted by
January 1, 2004.

CEC identified potential sites to minimize the effect of limited
environmental reviews and reduced opportunity for public participation. As
of December 31, 2001, CEC had approved 11 small power plant projects under
the 21- day process, taking 22 days on average; 2 simple- cycle power plant
projects under the 4- month process; and 1 combined- cycle power plant
project under the 6- month process.

As part of its EPA- approved plan to implement the Clean Air Act, California
has 35 regional air districts responsible for attaining state and federal
ambient air quality standards within their regions. Each air district adopts
its rules and own permitting process and establishes and enforces air
pollution regulations for stationary sources that are at least as stringent
as federal requirements and that address the particular air quality problems
in its region. As a result, the application process for federal and state
air quality permits can vary.

Most of California?s densely populated areas are non- attainment areas for
ozone. Nitrogen oxides, which combine with other pollutants to form ozone,
are emitted by power plants. Building a new power plant in these areas is
more costly because the plant must (1) achieve low nitrogen oxide emission
levels by adding pollution control devices and (2) offset its nitrogen oxide
emissions by acquiring emissions credits. California issues emissions
credits when emissions from existing sources are reduced. Power plant
developers have found that these credits, which can be traded or sold, are
difficult or costly to obtain in many non- attainment areas because of their
scarcity. According to CEC officials, the lack of emissions reduction
credits for offsetting a new project?s emissions could limit the number of
new gas- fired power plants in the state.

As part of its EPA- approved plan to implement the Clean Water Act,
California?s nine regional water quality control boards are responsible for
attaining state and federal water quality standards. Each water board may
Air Quality Requirements

Water Quality Requirements

Appendix II: California?s Process for Approving New Power Plant Projects

Page 40 GAO- 02- 427 Restructured Electricity Markets

establish and enforce water pollution regulations that are at least as
stringent as federal requirements. As a result, the application process for
federal and state water quality permits can vary, making the siting process
more complex.

Under the Endangered Species Act, California has the second highest number
of endangered or threatened species in the country behind Hawaii, increasing
the likelihood that a new power plant project may affect the habitat of a
listed species. EPA?s region 9, which includes California, routinely
notifies the U. S. Fish and Wildlife Service about new power plant projects
because it considers air and water quality permits that it, or a delegated
district, issues are federal actions that trigger notification under the
Endangered Species Act.

A power plant developer must address any applicable local and state laws,
ordinances, regulations, standards, plans and policies as part of its CEC
application. Although CEC issues all state and local permits as part of the
overall certification, it is legally required to ensure that a proposed
project complies with all regulations and laws that would be enforced by any
other local or state agencies. Exceptions to this requirement could occur if
CEC finds that (1) the project is needed for public convenience and
necessity and (2) no more prudent and feasible means of achieving such
public convenience and necessity exists.

The power plant application must be tailored specifically to address the
project?s location. Among other things, the application typically has to
address (1) land use and zoning plans, including development restrictions
under the California Coastal Act and the Delta Protection Act; (2) public
health; (3) worker safety and fire protection; (4) transmission system
engineering and safety; (5) traffic and transportation plans and policies;
(6) noise; (7) visual considerations; (8) socioeconomic issues, including
impacts on local school districts and environmental justice issues; and (9)
biological resource protection, including county open space and conservation
plans and state law protecting wildlife habitat, endangered species, and
native plants.

CEC allows any person to petition to become involved in the certification
process for a new power plant project as an intervenor. Government agencies,
community groups, interest groups, labor unions, businesses Endangered
Species Act

Other Local and State Government Reviews

Intervenors

Appendix II: California?s Process for Approving New Power Plant Projects

Page 41 GAO- 02- 427 Restructured Electricity Markets

(including applicant?s power plant competitors), and individuals can become
intervenors.

An intervenor is a full, legal party to the proceedings with the same rights
and obligations as other parties in the proceeding, including CEC staff and
the applicant. CEC can use evidence provided by intervenors as the basis for
any part of its final decision. Intervenors have the right to (1) obtain
information from the other parties in the proceeding, (2) receive all
documents filed in the case, (3) present evidence and witnesses, and (4)
cross- examine the witnesses of the other parties at public hearings.
Correspondingly, intervenors have the obligation to send copies of all
filings to the other parties, answer data requests from other parties, and
allow other parties to cross- examine their witnesses. Intervenors can play
an important role in the certification process- as many as 16 intervenors
have participated in CEC?s consideration of an application; can add a
considerable amount of time to the certification process; and can
potentially kill a project, according to CEC officials.

In addition to allowing intervenors, CEC?s certification process has a
strong public participation component. The Warren- Alquist Act requires that
CEC ensure meaningful public participation in power plant certification. CEC
has a public advisor, an attorney who serves as an advisor to both the
public and CEC to ensure full and adequate public participation. CEC
conducts public hearings and workshops at several points in the
certification process. Also, the public can submit written comments to CEC
about a power plant application. Public Involvement

Appendix III: Pennsylvania?s Process for Approving New Power Plant Projects

Page 42 GAO- 02- 427 Restructured Electricity Markets

Pennsylvania has no overall state agency responsible for approving new power
plant projects. Power plant developers must work through (1) the
Pennsylvania DEP to obtain air quality and water quality permits and (2)
local government agencies to obtain zoning and other land use permits. In
addition, developers in eastern or central Pennsylvania have to obtain
permits from the Delaware River Basin Commission or the Susquehanna River
Basin Commission, respectively, for access to river water. Since 1995, the
average time needed to obtain a pre- construction air permit for power plant
projects was about 14 months.

EPA has approved Pennsylvania?s program for issuing New Source Review air
quality permits. Almost all air quality permits are issued by DEP?s six
regional offices or the County Health Departments in Allegheny (Pittsburgh)
and Philadelphia counties, which are DEP authorized air pollution control
agencies. DEP has overall approval of the permits prepared by these
counties.

For permitting purposes, DEP treats the whole state of Pennsylvania as an
ozone non- attainment area because it is an ozone transport region as
defined under the Clean Air Act. As a result, new power plant projects must
install control technology that meets the lowest achievable emission rate
for nitrogen oxides. Improved technology has enabled approved nitrogen oxide
emissions levels to drop from 4.5 parts per million to 2.5 parts per million
in recent years. New power plant projects also have to offset their nitrogen
oxide emissions with emissions reduction credits, which can be obtained from
either in- state or out- of- state sources. According to DEP officials, the
vast majority of emissions reduction credits have resulted from the shutdown
of facilities. DEP keeps an online registry of offsets, but companies
typically purchase offsets through brokers at about $10,000 to $12,000 per
ton. DEP officials noted that it is more difficult to obtain emission offset
credits for use in the severe ozone non- attainment areas of the state.

In 1995, the Governor of Pennsylvania established a ?money- back guarantee?
permit review program that would return an applicant?s fees if DEP did not
meet established time frames for issuing environmental permits- 1 year for a
power plant?s air quality permit. (The fee for a new source review permit is
$18,000.) The 1- year time frame includes only DEP?s review and excludes
other agencies? review or the time required to hold a public meeting or
hearing. Processing time is calculated from date of application receipt to
date of final decision, minus time used by the applicant to correct
deficiencies. DEP officials told us that the program Appendix III:
Pennsylvania?s Process for

Approving New Power Plant Projects Air Quality Requirements

Appendix III: Pennsylvania?s Process for Approving New Power Plant Projects

Page 43 GAO- 02- 427 Restructured Electricity Markets

was initiated to demonstrate DEP?s commitment to timely consideration of
permit applications. They noted that missing a final date does not force DEP
to approve a permit and added that they have yet to give money back because
of delays in issuing a power plant permit.

In 1978, EPA authorized DEP to administer the National Pollutant Discharge
Elimination System (NPDES), which controls discharges of pollutants to
surface waters. DEP?s six regional offices issue NPDES permits. According to
a DEP Water Division official, the time frame for reviewing NPDES permits
ranges from 120 to 200 days from application to decision. The Water Division
has not had to return money to applicants under the state?s money- back
guarantee program for permit reviews, according to DEP officials.

DEP?s administrative completeness review determines whether all necessary
information and forms are provided without assessing an application?s
technical quality. DEP has 20 days to review an application for completeness
and notify the applicant whether the application (1) has been accepted, (2)
has minor deficiencies that are identified, or (3) is being returned for
being severely deficient. Applicants are given one opportunity to correct
any administrative deficiencies.

DEP?s preliminary and final technical reviews analyze the proposal for
potential adverse environmental impacts; check for completeness, clarity and
soundness of engineering proposals; ensure conformance with applicable
statutes and regulations; and analyze public comments. If DEP finds
technical deficiencies, it outlines the specific problems that must be
corrected, citing the statutory or regulatory authority that provides the
basis for the deficiency. If the applicant fails to respond within a
reasonable period of time, the applicant waives all rights under DEP?s
money- back guarantee program. If the material submitted in response to the
deficiency letter still fails to meet DEP requirements, DEP sends a second,
pre- denial letter. This letter allows the applicant a last opportunity to
correct the remaining technical deficiencies. DEP will deny the application
if the applicant fails to address the deficiencies. Alternatively, instead
of responding to a deficiency letter, the applicant has the option of asking
DEP to make a decision based on the available information. If DEP denies the
application, the applicant may appeal the decision or file a new
application. Water Quality

Requirements DEP?s Permit Review Process

Appendix III: Pennsylvania?s Process for Approving New Power Plant Projects

Page 44 GAO- 02- 427 Restructured Electricity Markets

DEP renders a final decision on the application based on its assessment of
the technical information, including consideration of reviews required by
other federal or state agencies. Either the applicant or the public may
appeal this decision to the Pennsylvania Environmental Hearing Board, and
the Environmental Hearing Board?s decisions may be appealed to the
Pennsylvania Commonwealth Court.

Pennsylvania requires opportunities for public participation in DEP?s
permitting process through written comments, public meetings, and public
hearings. DEP may also invite additional public participation at its
discretion. DEP provides opportunities for public involvement by (1) making
available a copy of the permit application, emissions data, and other
information related to a permit application; (2) receiving comments and
answering questions at public meetings; (3) in many cases, holding a hearing
to document public concerns as an official part of the public notice
process; and (4) soliciting written comments from the general public on its
draft permit. The need for a hearing depends on the quantity and nature of
comments- DEP typically holds a hearing for large power plant projects or
for projects with a lot of public opposition. DEP considers both solicited
and unsolicited comments in reviewing a permit application. DEP makes its
draft permit available for public review and comment and considers revisions
to the permit based on the comments received. Concurrent with public review
and comment, DEP also sends the draft permit to EPA for its review and
comment in accordance with applicable state and federal requirements.

Although members of the public can participate in DEP?s public hearings,
they cannot intervene in the administrative appeal process until the permit
has been issued. After a permit has been issued, the permittee or the public
can appeal the issuance of the permit to the Environmental Hearing Board.

If a power plant proposed for the eastern or central part of Pennsylvania
would withdraw more than 100,000 gallons of water a day from a river basin
for operations, the developer must obtain permit approval from the Delaware
River Basin Commission or the Susquehanna River Basin Commission. The
Delaware River Basin Commission?s review of a water use application in
eastern Pennsylvania often takes between 6 months and 1 year, according to
commission officials. Developers can apply for a permit while their other
permit applications are being considered. However, the commission cannot
issue a permit until DEP has issued all Public Involvement in

DEP?s Permit Review Process

Water Use Requirements

Appendix III: Pennsylvania?s Process for Approving New Power Plant Projects

Page 45 GAO- 02- 427 Restructured Electricity Markets

water quality permits. Commission officials said that processing the permit
usually takes about 60 days once DEP has issued the water permits.

Three Pennsylvania state agencies are responsible for protecting endangered
and threatened species: (1) the Fish and Boat Commission is responsible for
fish, other aquatic organisms, reptiles, and amphibians; (2) the Game
Commission is responsible for birds and mammals, including 14 endangered
species; and (3) the Department of Conservation and Natural Resources is
responsible for native wild plants. The Department of Conservation and
Natural Resources maintains the Pennsylvania Natural Diversity Inventory,
which includes all of the department?s lists of where threatened and
endangered species, critical habitats, and areas of critical dependence are
known to occur. The U. S. Fish and Wildlife Service and Pennsylvania?s Fish
and Boat Commission provide DEP with additional listings of species and
habitat ranges.

Permit applicants are required to (1) conduct a database search of the
Pennsylvania Natural Diversity Inventory to determine the potential presence
of a listed species in the vicinity of the permit application area and (2)
check any other readily available sources provided by the natural resource
agencies. If the applicant finds that the project might affect a habitat
area, the applicant is responsible for contacting the responsible natural
resource agency. The agency then provides advice about species presence,
critical habitat, and critical dependence issues. If the activity may harm
the species, the applicant must work with the natural resource agency to
conduct surveys, modify the project, or devise any other relevant actions to
protect the species and its critical habitat.

An applicant submitting its permit application to DEP must provide proof of
coordination. Alternatively, the applicant must provide documentation if no
habitats for listed species were found in the affected area. In addition,
the public may identify threatened or endangered species issues not
previously addressed when DEP made the draft permit available for comment.
Pennsylvania does not consider the air and water quality permits to be
federal actions that trigger notification of the U. S. Fish and Wildlife
Service. While DEP does not specifically consult with the U. S. Fish and
Wildlife Service about individual permit applications, the Fish and Wildlife
Service may provide comments during the comment period. Endangered Species
Act

Appendix IV: Texas? Process for Approving New Power Plant Projects

Page 46 GAO- 02- 427 Restructured Electricity Markets

TNRCC is responsible for approving environmental permits in Texas. TNRCC
must issue air and water quality permits to an applicant that has
demonstrated compliance with federal and state requirements.

EPA has delegated responsibility for approving air quality permits to TNRCC,
which has 16 regional offices throughout the state. All air pollution
sources are required to obtain an operating permit, unless they are a
?grandfathered? facility in existence on the effective date of the Texas New
Source permit program in 1971 and have not increased the emissions of any
air pollutant. TNRCC?s Air Permits Division conducts a new source review of
all major industrial projects- in both non- attainment and attainment areas.

The extent of and time frame for TNRCC?s review depend on (1) the ambient
air quality around the proposed project, (2) whether the project is a major
or minor source of emissions, and (3) the amount and type of public
participation. The Dallas- Fort Worth, Houston- Galveston, Beaumont- Port
Arthur and El Paso metropolitan areas are non- attainment areas in Texas. If
a project is in a non- attainment area and emits more than federally defined
levels of the relevant pollutant, TNRCC must consult with EPA?s region 6 and
the developer typically would have to install advanced emission control
technologies and purchase emissions credits to offset added pollution. A
proposed power plant project in an attainment area generally would qualify
for minor source permitting if it emits less than the federally defined
level of any criteria pollutant. Alternatively, if the proposed project is
in an attainment area and emits more than federally defined levels of the
relevant pollutant, it would have to comply with a ?prevention of
significant deterioration? permit. TNRCC generally approves an air quality
permit within 6 to 9 months and an amendment to a permit within 4 to 6
months.

To comply with a prevention of significant deterioration permit, applicants
reduce pollutant emissions using best available control technology-
developers generally use selective catalytic reduction technology to reduce
nitrogen oxide pollution. TNRCC recommends nitrogen oxide limits of 5 parts
per million as best available control technology for natural gas- fired
combined- cycle operations. TNRCC staff told us that Texas uses

?not to exceed? emissions limits based upon a 1- hour averaging time period.
For example, to meet very low emissions limits, some applicants seek to
average emissions levels over a longer period- which can range from 1 hour
to 30 days. The longer period provides a buffer for the plant?s actual
operations- certain conditions, such as startup and cycling, force Appendix
IV: Texas? Process for Approving

New Power Plant Projects Air Quality Requirements

Appendix IV: Texas? Process for Approving New Power Plant Projects

Page 47 GAO- 02- 427 Restructured Electricity Markets

emissions higher over a short period. TNRCC also does not recommend lower
nitrogen oxide limits because reduction controls involve trade offs with
increased ammonia slip, a contaminant under the Texas Clean Air Act. TNRCC?s
recommended carbon monoxide limits range from 9 to 25 parts per million as
best available control technology for all gas- fired turbines.

TNRCC is responsible for issuing water quality permits under the Clean Water
Act. TNRCC?s Water Quality and Water Supply Divisions are responsible for
the quality, quantity, and availability of water in Texas. In 1998, EPA
authorized TNRCC to administer certain permitting processes under the Texas
Pollutant Discharge Elimination System, instead of EPA?s National Pollutant
Discharge Elimination Program. TNRCC staff said it takes about 9 months to 1
year to obtain a water permit.

TNRCC staff assist developers in preparing applications by providing
preapplication consultations and guidance documents. TNRCC?s permits and
modeling groups consult with developers about 3 months before the
application is submitted. Once it receives a permit application, TNRCC
reviews it for administrative completeness. If the application is incomplete
and additional information is necessary, this review takes about 30 days.
Once it considers an application as complete, TNRCC requires the developer
to (1) notify the public of the project by publishing notices in local
newspapers and posting a sign at the proposed site and (2) perform air
dispersion modeling for all emission sources using EPA- approved computer-
based mathematical models. TNRCC staff audit the modeling and evaluate the
resulting predicted off- property impacts. TNRCC generally completes its
technical review and prepares a draft permit within 90 days and mails the
draft permit to the applicant for comment and negotiation, which takes about
30 days. Local and county officials, federal officials, and other interested
persons then receive a second public notice announcing the draft permit and
providing a 30- day comment period. TNRCC sends each draft permit to EPA.
EPA has 30 days to provide comments, although it may ask for an additional
time to address comments it receives from the public.

In addition to giving members of the public the opportunity to submit
written or oral comments about a proposed project, Texas allows individuals
who oppose an application and who meet certain requirements to request to
participate in a contested evidentiary hearing before an Water Quality

Requirements TNRCC?s Permit Review Process

Contested Case Hearings

Appendix IV: Texas? Process for Approving New Power Plant Projects

Page 48 GAO- 02- 427 Restructured Electricity Markets

administrative law judge. 1 In such hearings, parties have the right, for
example, to present testimony, offer evidence, cross- examine other parties?
witnesses, object to the introduction of evidence, and file legal motions.
The administrative law judge issues a formal recommendation to the TNRCC
commission, which issues a final decision. TNRCC officials told us that a
contested permit application could add from 1 to 3 years to the project.
Since 1995, 15 of 84 air permit applications in Texas had requests for
contested hearings. Two requests resulted in hearings, and three requests
were denied a hearing. Of the remaining requests, seven were withdrawn, one
was pending, and two were relocated.

TNRCC makes its draft permit available for public comment for a 30- day
period by providing notice in a widely read local newspaper and directly
notifying the local mayor and other local government officials, the county
judge, EPA, the U. S. Fish and Wildlife Service, the Advisory Council on
Historical Preservation, the Texas Historical Commission, and the Texas
Parks and Wildlife Department. If TNRCC receives a request for a hearing, it
determines whether it should hold a hearing, which it does generally about
30 days after the request. TNRCC may adopt the proposed permit, adopt the
proposed permit with changes, or deny the permit application. Appeals may be
filed with TNRCC once it makes a final decision on permit issuance.

Texas requires a water rights permit for the use of state surface water.
TNRCC typically approves a permit for water rights in from 9 months to 1
year for an uncontested application. Each application for a permit is
reviewed for administrative completeness; applicants have 30 days to respond
if the application is deficient. The technical review, which may take 180
days, evaluates impact on other water rights, bays and estuaries,
conservation, and water availability through modeling. Once the
administrative process is complete, TNRCC provides notice to the public and
gives other water rights holders the opportunity for a hearing. Permits may
be issued in perpetuity, for a limited number of years, or for temporary
uses.

1 An individual must demonstrate a personal interest within TNRCC?s
authority and jurisdiction that could be affected by the application. Public
Involvement

Water Use Requirements

Appendix IV: Texas? Process for Approving New Power Plant Projects

Page 49 GAO- 02- 427 Restructured Electricity Markets

Because of increasing water demands for municipal, industrial, and other
uses, TNRCC grants new water rights only where normal flows and levels are
sufficient to meet demand. As a result, some power plant developers have
looked for alternative options to meet their water needs. For example, a
company recently negotiated a contract to obtain surface water from a nearby
city. When the city submitted an application to amend its water rights
permit, opponents to the sale asked for hearings to contest the permit. The
company then decided to use another city?s existing water right and effluent
for the power plant cooling towers. In another case, a company purchased the
water rights from another holder to appropriate water from the Colorado
River instead of applying for new water rights permit. The ownership
transfer was completed in 30 days. An application to amend the water rights
to include industrial use was completed 3 months later.

The Texas Pollutant Discharge Elimination System requires that permits and
water quality standards protect the environment, including habitats for
endangered and threatened species. Texas does not consider the air and water
quality permits to be federal actions that trigger notification of the U. S.
Fish and Wildlife Service. However, if the Endangered Species Act is a
concern for a permit, TNRCC notifies the U. S. Fish and Wildlife Service,
the National Marine Fisheries Service, and the Texas Parks and Wildlife
Department and asks for their comments. According to TNRCC officials, an
Endangered Species Act concern also automatically triggers EPA oversight
under the Memorandum of Agreement between TNRCC and EPA.

Before the permit application is submitted to TNRCC, the applicant usually
visits the community where it plans to locate the power plant to determine
if the local government and community will support or oppose the power plant
project. The applicant is responsible for ensuring that the proposed site is
properly zoned, or can be rezoned within acceptable time frames. Most
communities generally have welcomed gas- fired power plants because they
provide a large tax base for the communities and pose few environmental
concerns. Similarly, environmental groups have not opposed power plants
because natural gas is a low- pollution fuel. Endangered Species Act

Local Government Reviews

Appendix V: Comments from the Federal Energy Regulatory Commission

Page 50 GAO- 02- 427 Restructured Electricity Markets

Appendix V: Comments from the Federal Energy Regulatory Commission

Appendix V: Comments from the Federal Energy Regulatory Commission

Page 51 GAO- 02- 427 Restructured Electricity Markets

Appendix VI: GAO Contacts and Staff Acknowledgments

Page 52 GAO- 02- 427 Restructured Electricity Markets

Jim Wells (202) 512- 3841 Richard Cheston (202) 512- 3841

In addition to those named above, Jon Ludwigson, Ilga Semeiks, Frank Rusco,
Carol Herrnstadt Shulman, Leigh White, and Cleo Zapata made key
contributions to this report. Appendix VI: GAO Contacts and Staff

Acknowledgments GAO Contacts Acknowledgments

(360118)

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