Restructured Electricity Markets
Three States' Experiences in Adding Generating Capacity Gao ID: GAO-02-427 May 24, 2002Twenty-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.
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Director: Team: Phone:GAO-02-427, Restructured Electricity Markets: Three States' Experiences in Adding Generating Capacity
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United States General Accounting Office:
GAO:
Report to Congressional Committees:
May 2002:
Restructured Electricity Markets:
Three States‘ Experiences in Adding Generating Capacity:
GAO-02-427:
Contents:
Letter:
Results in Brief:
Background:
The Three States Had Different Needs for Additional Electric Power and
Added Different Amounts:
Regulatory Processes Are Generally Similar in the Three States,
Although California Requires an Additional Approval:
Connecting New Power Plants Is Less Costly and Faster for Developers in
Texas Than in the Other Two States:
Developers in Restructured Electricity Markets Weigh a Project‘s
Projected Profitability against Risks:
Conclusions:
Recommendations for Executive Action:
Agency Comments:
Appendix I: Scope and Methodology:
Appendix II: California‘s Process for Approving New Power Plant
Projects:
Appendix III: Pennsylvania‘s Process for Approving New Power Plant
Projects:
Appendix IV: Texas‘ Process for Approving New Power Plant Projects:
Appendix V: Comments from the Federal Energy Regulatory Commission:
Appendix VI: GAO Contacts and Staff Acknowledgments:
Tables:
Table 1: Regulatory Approval Time Frames for Power Plants in
California, Pennsylvania, and Texas:
Table 2: CEC‘s Certification Process:
Figures:
Figure 1: The Major U.S. Electricity Transmission Interconnections:
Figure 2: Generating Capacity Proposals in the Three States, as of
December 31, 2001:
Figure 3: Ozone Non-Attainment Areas for EPA‘s 1-Hour Standard as of
January 2002:
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:
[End of section]
United States General Accounting Office:
Washington, DC 20548:
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 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 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.
Results in Brief:
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 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 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.
Background:
Before restructuring, electric service was provided primarily by
federal and 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.[Footnote 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,[Footnote 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 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.
Figure 1: The Major U.S. Electricity Transmission Interconnections:
[Refer to PDF for image]
This figure is a map of the continental United States, depicting the
following electricity transmission interconnections:
* Eastern Interconnect;
* Texas Interconnect;
* Western Interconnect.
[End of figure]
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.
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.[Footnote 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[Footnote 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[Footnote 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.
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
[Footnote 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.
The Three States Had Different Needs for Additional Electric Power and
Added Different Amounts:
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.
The States Had Different Needs for New Power Plants:
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.
More Capacity Was Proposed and Built in Texas Than in the Other Two
States:
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:
[Refer to PDF for image]
This figure is a multiple vertical bar graph depicting the following
data (megawatts in thousands):
State: California;
Proposed: approximately 17.5 thousand megawatts;
Under construction: approximately 7.5 thousand megawatts;
Online since 1995: approximately 4.8 thousand megawatts;
Cancelled: approximately 11 thousand megawatts.
State: Pennsylvania;
Proposed: approximately 9 thousand megawatts;
Under construction: approximately 6 thousand megawatts;
Online since 1995: approximately 2 thousand megawatts;
Cancelled: approximately 2.5 thousand megawatts.
State: Texas;
Proposed: approximately 19 thousand megawatts;
Under construction: approximately 13 thousand megawatts;
Online since 1995: approximately 16 thousand megawatts;
Cancelled: approximately 8.5 thousand megawatts.
Source: GAO compilation of Resource Data International data.
[End of figure]
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 and Pennsylvania were proposed to regulators in 2000 and
2001.[Footnote 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.
All Three States Have Experienced Significant Cancellations in Recent
Months:
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.
Recent Events May Limit Planned Construction and Additional Plans:
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.
Regulatory Processes Are Generally Similar in the Three States,
Although California Requires an Additional Approval:
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.
The States Use Similar Review Processes but California Adds Another
Level of Review:
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 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 appendix 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.[Footnote 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 appendix 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
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:
Time for regulatory approval: 6 months or less;
California[A], Projects: 4;
California[A], Percent: 19%;
Pennsylvania, Projects: 2;
Pennsylvania, Percent: 9%;
Texas, Projects: 17;
Texas, Percent: 25%.
Time for regulatory approval: 6 months to 1 year;
California[A], Projects: 5;
California[A], Percent: 24%;
Pennsylvania, Projects: 12;
Pennsylvania, Percent: 55%;
Texas, Projects: 43;
Texas, Percent: 64%.
Time for regulatory approval: 1 to 1-1/2 years;
California[A], Projects: 7;
California[A], Percent: 33%;
Pennsylvania, Projects: 6;
Pennsylvania, Percent: 27%;
Texas, Projects: 7;
Texas, Percent: 10%.
Time for regulatory approval: 1-1/2 to 2 years;
California[A], Projects: 3;
California[A], Percent: 14%;
Pennsylvania, Projects: 0;
Pennsylvania, Percent: 0;
Texas, Projects: 0;
Texas, Percent: 0.
Time for regulatory approval: More than 2 years;
California[A], Projects: 2;
California[A], Percent: 10%;
Pennsylvania, Projects: 2;
Pennsylvania, Percent: 9%;
Texas, Projects: 0;
Texas, Percent: 0.
Total:
California[A], Projects: 21;
California[A], Percent: 100%;
Pennsylvania, Projects: 22;
Pennsylvania, Percent: 100%;
Texas, Projects: 67;
Texas, Percent: 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.
[End of table]
Most Approved Power Plants in California and Pennsylvania Are Located
in Areas with Stringent Air Quality Requirements:
The gas-fired power plants now being built emit nitrogen oxides, which
directly contribute to ozone pollution.[Footnote 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 air quality standards[Footnote 10]”known as
non-attainment areas”must obtain a Non-Attainment New Source Review
permit.[Footnote 11] This permit requires a new power plant to install
the most advanced pollution control equipment[Footnote 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.
[Footnote 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 the approved plants had to use
more stringent controls, partly because 64 percent of the approved
plants were located in attainment areas.[Footnote 14]
Figure 3: Ozone Non-Attainment Areas for EPA‘s 1-Hour Standard as of
January 2002:
[Refer to PDF for image]
This figure is a map of the continental United States depicting
attainment areas and non-attainment areas. The vast majority of non-
attainment areas are located in Southern California and along the
Atlantic coastline from Maryland to Maine.
Source: EPA.
[End of figure]
California has led other states in requiring pollution reduction beyond
what is federally required. Specifically, California has a 1-hour ozone
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.
All Three States Seek Public Comments on a Project, and California and
Texas Allow the Public to Participate in Hearings:
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.[Footnote 15] In these proceedings, parties
may present 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.
Connecting New Power Plants Is Less Costly and Faster for Developers in
Texas Than in the Other Two States:
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.
Interconnection Is Less Expensive for Developers in Texas Than in the
Other Two States:
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 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,[Footnote 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.[Footnote 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.[Footnote 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.[Footnote 19] ERCOT representatives said
that they 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 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.[Footnote 20]
The California transmission operator critiques these studies, primarily
by evaluating their assumptions and the role of other plants expected
on-line.
Texas Uses a Standard Agreement to Facilitate Interconnection, Unlike
California and Pennsylvania:
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
must negotiate the terms and conditions of the interconnection
agreement, which typically adds time to the process.[Footnote 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.[Footnote 22]
FERC Is Evaluating Options for Developing a Standard Interconnection
Agreement:
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.[Footnote 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.
Developers in Restructured Electricity Markets Weigh a Project‘s
Projected Profitability against Risks:
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.
Restructured Electricity Markets Have Changed the Basis for Investment
Decisions:
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.
Profit Expectations Drive Developers‘ Decisions About Where to Propose
New Power Plants, as Experiences in California, Pennsylvania, and Texas
Illustrate:
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.[Footnote 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.[Footnote 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.[Footnote 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.[Footnote 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 adequate source of cooling water.[Footnote 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.
Market and Regulatory Risks Counterbalance a Site‘s Potential
Profitability:
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.[Footnote 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 long-term 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 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 unequal access to market information in markets where they compete
with power plants owned by transmission system owners.
Experiences in Three States Illustrate the Influence of Profitability
and Risk Considerations on Decisions to Propose Power Plants:
California, Pennsylvania, and Texas, with different market and
regulatory environments, illustrate how developers weigh profitability
and risk.
Lower Potential Profits and Higher Risks in California Delayed, and May
Continue to Delay, Investment:
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.[Footnote 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, 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,[Footnote 31] as well as management of risks
through, for example, the use of long-term contracts with purchasers
other than the state as a basis for obtaining loans.
Pennsylvania and Texas Illustrate How Developers Balance Risks and
Profits:
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.
Conclusions:
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.
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.
Recommendations for Executive Action:
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
interconnection agreement and (2) clarify how transmission system
upgrade costs are allocated.
Agency Comments:
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.
Signed by:
Jim Wells:
Director, Natural Resources and Environment:
[End of section]
Appendix I: Scope and Methodology:
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.
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
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.
[End of section]
Appendix II: California‘s Process for Approving New Power Plant
Projects:
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‘s Certification 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.
Table 2: CEC‘s Certification Process:
Scheduled time: 6 months to 1 year (possibly more);
Phase: Pre-filing (not required);
Action: Applicant meets with CEC and other state agencies (optional) to
discuss the certification process, filing requirements, and project-
specific issues. Applicant prepares application.
Scheduled time: 6 months to 1 year (possibly more);
Phase: Filing;
Action: Applicant files application with CEC.
Scheduled time: 45 days (longer if application is not deemed
complete);
Phase: Determination of data adequacy;
Action: 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.
Scheduled time: 120 days
Phase: Discovery/data requests;
Action: 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.
Scheduled time: 90 days
Phase: Analysis;
Action: 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.
Scheduled time: 90 days
Phase: Public hearings;
Action: 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.
Scheduled time: 65 days
Phase: Decision;
Action: 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.
[End of table]
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:
* 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.
Air Quality Requirements:
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.
Water Quality Requirements:
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 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.
Endangered Species Act:
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.
Other Local and State Government Reviews:
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.
Intervenors:
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 (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.
Public Involvement:
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.
[End of section]
Appendix III: Pennsylvania‘s Process for Approving New Power Plant
Projects:
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.
Air Quality Requirements:
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 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.
Water Quality Requirements:
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 Permit Review Process:
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.
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.
Public Involvement in DEP‘s Permit Review Process:
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.
Water Use Requirements:
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 water quality permits. Commission officials said that
processing the permit usually takes about 60 days once DEP has issued
the water permits.
Endangered Species Act:
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.
[End of section]
Appendix IV: Texas‘ Process for Approving New Power Plant Projects:
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.
Air Quality 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 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.
Water Quality Requirements:
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‘s Permit Review Process:
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.
Contested Case Hearings:
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
administrative law judge.[Footnote 32] 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.
Public Involvement:
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.
Water Use Requirements:
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.
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.
Endangered Species Act:
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.
Local Government Reviews:
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.
[End of section]
Appendix V: Comments from the Federal Energy Regulatory Commission:
Federal Energy Regulatory Commission:
Office Of The Chairman:
Washington, DC 20426:
May 3, 2002:
Mr. Jim Wells:
Director, Natural Resources and Environment:
United States General Accounting Office:
Room 2T23:
441 G Street, NW:
Washington, DC 20548:
Dear Mr. Wells:
Thank you for your letter of April 23, 2002, enclosing your draft
report, Restructured Electricity Markets: Three States' Experience in
Adding Generating Capacity. I congratulate you on your effort and
appreciate the opportunity to comment on this report.
I wholeheartedly agree with the report's recommendation that the
Commission develop and require the use of a standardized
interconnection agreement and clarify how transmission system upgrade
costs are to be allocated. As I am sure you are aware, we took an
important step to do so on April 24, by issuing a Notice of Proposed
Rulemaking (NOPR) in Docket No. RM02-01-000, which would require that
interconnection service be provided by jurisdictional transmission
providers under a standardized interconnection procedure and agreement.
The proposed interconnection agreement was developed, in large part,
through a collaborative process with industry participants, including
generators, transmission providers, and load serving entities.
The interconnection proposal seeks to ensure that transmission
providers show no preference for interconnecting their own generators
over proposals by other market participants. Although the proposal
reflects the Commission's current transmission pricing policies, it
invites recommendations for how final transmission expansion and
upgrade costs should be allocated. Once finalized, the new
interconnection agreement and procedures will supplement existing and
future jurisdictional open access transmission tariffs. It will also be
used by any non-public utility that wants transmission service from a
jurisdictional utility, under existing reciprocity obligations.
While I believe that standard interconnection rules will greatly
facilitate new infrastructure development, I would like to emphasize
that many other factors affect successful generation development, as
your report notes. To that end, this Commission is working on two
additional institutional elements that should do much to improve
certainty and reduce the risk of generation development. The
implementation of independent Regional Transmission Organizations, to
operate and manage large inter-state transmission systems and wholesale
power markets, will do much to assure true open, non-discriminatory
access to the grid and safe, reliable, low-cost grid operations. In
parallel, the development of Standard Market Design - a common market
architecture and set of operating rules for all wholesale market
participants in the Eastern and Western interconnections - will
accelerate the effective operation of wholesale energy markets with
uniform rules and low transactions costs across the nation. Both of
these initiatives should come to fruition, through a series of
regulatory cases and rulemakings, by the end of 2002. We are confident
that the combination of standardized interconnection, standard market
design and RTOs will do much to reduce the risks and enhance the appeal
of new investment in power plants, transmission lines, and demand
response; these in turn will improve competition, lower costs and
improve the reliability of America's wholesale power markets.
I appreciate the hard work your staff put into this report and am
hopeful it will further the understanding of the power supply problems
in California and the West. Thank you again for this opportunity to
comment on your report.
Best wishes,
Pat Wood III:
Chairman:
[End of section]
Appendix VI: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Jim Wells (202) 512-3841:
Richard Cheston (202) 512-3841:
Acknowledgments:
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.
[End of section]
Footnotes:
[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.
[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.
[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.
[7] In California, of the power plant projects proposed from 1995
through 2001, 72 percent were submitted after electricity shortages
began in May 2000.
[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 simple-cycle 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.
[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.
[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).
[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.
[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.
[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.
[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.
[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.
[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.
[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.
[28] In addition to rivers and streams, cooling water sources could
include at treatment plant-processed 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.
[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.
[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.
[32] An individual must demonstrate a personal interest within TNRCC‘s
authority and jurisdiction that could be affected by the application.
[End of section]
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