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entitled 'Electricity Restructuring: FERC Could Take Additional Steps 
to Analyze Regional Transmission Organizations' Benefits and 
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Report to the Committee on Homeland Security and Governmental Affairs, 
U.S. Senate: 

United States Government Accountability Office: 
GAO: 

September 2008: 

Electricity Restructuring: 

FERC Could Take Additional Steps to Analyze Regional Transmission 
Organizations' Benefits and Performance: 

GAO-08-987: 

GAO Highlights: 

Highlights of GAO-08-987, a report to the Committee on Homeland 
Security and Governmental Affairs, U.S. Senate. 

Why GAO Did This Study: 

In 1999, as a part of federal efforts to restructure the electricity 
industry, the Federal Energy Regulatory Commission (FERC) began 
encouraging the voluntary formation of Regional Transmission 
Organizations (RTO)—independent entities to manage regional networks of 
electric transmission lines. FERC oversees six RTOs that cover part or 
all of 35 states and D.C. and serve over half of U.S. electricity 
demand. As electricity prices increase, stakeholders—organizations and 
individuals with financial and regulatory interest in the electricity 
industry—have voiced concerns about RTO benefits and how RTO expenses 
and decisions influence electricity prices. 

GAO was asked to review (1) RTO expenses and key investments in 
property, plant, and equipment from 2002 to 2006, the most current data 
available; (2) how RTOs and FERC review RTO expenses and decisions that 
may affect electricity prices; and (3) the extent to which there is 
consensus about RTO benefits. To do so, GAO reviewed documentation and 
data and spoke with FERC officials and experts. 

What GAO Found: 

RTO expenses and investments in property, plant, and equipment vary, 
depending on the size of the RTO and its functions. Expenses for the 
six RTOs FERC oversees totaled $4.8 billion from 2002 to 2006, and 
property, plant, and equipment investments totaled $1.6 billion as of 
December 2006. 

RTOs and FERC rely on stakeholder participation to identify and resolve 
concerns about RTO expenses and decisions that affect electricity 
prices, such as decisions about reliability and whether to develop 
markets for electricity and other services. The stakeholders GAO spoke 
with in two RTO regions value the opportunity for input but have 
concerns about the resources and information required to participate. 
Moreover, although regular review of RTO budgets could help FERC with 
its responsibility to ensure RTO rates remain just and reasonable or 
determine if a new rate proceeding is needed, FERC’s review of RTO 
budgets varies. Furthermore, while FERC requires RTOs to report actual 
expenses annually, it does not regularly review this information for 
accuracy or reasonableness and is at risk of using and providing to the 
public inaccurate and incomplete information. 

FERC officials, industry participants, and experts lack consensus on 
whether RTOs have brought benefits to their regions. Many agree that 
RTOs have improved the management of the transmission grid and improved 
generator access to it; however, there is no consensus about whether 
RTO markets provide benefits to consumers or how they have influenced 
consumer electricity prices. FERC officials believe RTOs have resulted 
in benefits; however, FERC has not conducted an empirical analysis of 
RTO performance or developed a comprehensive set of publicly available, 
standardized measures to evaluate such performance. Without such 
measures, FERC will remain unable to demonstrate the extent to which 
RTOs provide consumers and others with benefits—information that could 
aid FERC in its evaluation of its decision to encourage the creation of 
RTOs and help address divisions about which benefits RTOs have 
provided. 

Figure: U.S. Regional Transmission Organizations: 

[refer to PDF for image] 

This figure is a map of the United States depicting the Regional 
Transmission Organizations. 

Source: FERC (data); map (Platts POWERmap, December 2007). 

Note: FERC regulates California ISO, ISO New England, Midwest ISO, New 
York ISO, PJM, and Southwest Power Pool but does not regulate the 
Electric Reliability Council of Texas. 

[End of figure] 

What GAO Recommends: 

GAO recommends that FERC develop an approach for regularly reviewing 
RTO budgets and annual financial reports, and develop and report on 
standardized measures that track RTOs’ performance. FERC generally 
agreed with our report and recommendations. 

To view the full product, including the scope and methodology, click on 
[hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-08-987]. For more 
information, contact Mark Gaffigan, (202) 512-3841, gaffiganm@gao.gov. 

[End of section] 

Contents: 

Letter: 

Results in Brief: 

Background: 

RTO Expenses and Investments in Property, Plant, and Equipment Varied 
Considerably: 

RTOs and FERC Rely on Stakeholder Input when Evaluating RTO Expenses 
and Decisions That May Affect Electricity Prices: 

Experts, Industry Participants, and FERC Lack Consensus on the Benefits 
of RTOs: 

Conclusions: 

Recommendations for Executive Action: 

Agency Comments and Our Evaluation: 

Appendix I: Objectives, Scope, and Methodology: 

Appendix II: RTO Characteristics and Functions Required by FERC Order 
2000: 

Appendix III: RTO Inflation-Adjusted Expenses and Full-time Equivalents 
from 2002 to 2006, by RTO: 

Appendix IV: Megawatt hour Load Served by RTO from 2002 through 2006: 

Appendix V: Inflation-Adjusted RTO 2006 Expenses Reported on FERC Form 
No. 1: 

Appendix VI: Investment in Property, Plant, and Equipment for RTOs as 
of December 31, 2006: 

Appendix VII: Indexed Electricity Prices, 1990-2007: 

Appendix VIII: Summary of Expert Studies Analyzing the Benefits of 
Restructuring and Regional Transmission Organizations: 

Appendix IX: Comments from FERC: 

Appendix X: GAO Contact and Staff Acknowledgments: 

Tables: 

Table 1: Selected RTO Responsibilities: 

Table 2: Inflation-Adjusted Rates per MWh Charged to RTO Market 
Participants, 2002-2006: 

Table 3: RTO Processes for Acquiring Stakeholder Input: 

Table 4: Estimated Stakeholder Meetings by RTO, Calendar Year 2007: 

Table 5: Last FERC Decision to Approve Rates to Recover Expenses: 

Table 6: RTO Budget Submissions to FERC: 

Figures: 

Figure 1: U.S. Regional Transmission Organizations: 

Figure 2: Components of a Typical Consumer's Electricity Costs in New 
England: 

Figure 3: Total Inflation-Adjusted RTO Expenses, 2002 to 2006: 

Figure 4: Inflation-Adjusted Expenses per MWh by RTO, 2006: 

Figure 5: Inflation-Adjusted Expenses per MWh by RTO, 2002-2006: 

Figure 6: Inflation-Adjusted Expenses per MWh by RTO as Reported in the 
2006 FERC Form No. 1: 

Figure 7: Inflation-Adjusted Investment in Property, Plant, and 
Equipment as of December 2006: 

Figure 8: Midwest ISO's Committee Structure: 

Figure 9: Retail Electricity Prices by State, 2007: 

Figure 10: Change in Inflation-Adjusted Retail Electricity Prices for 
Industrial Consumers, 1990-2006: 

Figure 11: Inflation-Adjusted Prices of Coal and Natural Gas Used to 
Generate Electricity, 1996-2006: 

Figure 12: Change in Nuclear Plant Capacity Factors, 1996-2006: 

Figure 13: Comparison of Relative Electricity Prices for Industrial 
Customers, 1990-2007: 

Abbreviations: 

Btu: British thermal unit: 

FERC: Federal Energy Regulatory Commission: 

FTE: full-time equivalent: 

ISO: Independent System Operator: 

KWh: kilowatt hour: 

MWh: megawatt hour: 

OASIS: Open Access Same Time Information System: 

RTO: Regional Transmission Organization: 

[End of section] 

United States Government Accountability Office:
Washington, DC 20548: 

September 22, 2008: 

The Honorable Joseph I. Lieberman: 
Chairman: 
The Honorable Susan M. Collins: 
Ranking Member: 
Committee on Homeland Security and Governmental Affairs: 
United States Senate: 

The efficient and reliable operation of the electricity industry is 
critical to the health of the U.S. economy and well-being of Americans. 
Residential consumers rely on electricity to power their households, 
and electricity is a key input for businesses that produce trillions of 
dollars in products and services. Consumer expenditures for electricity 
amounted to $343 billion in 2007, the most recent year for which annual 
data were available. After declining in the late 1990s, retail 
electricity prices rose to an average of nearly 9 cents per kilowatt 
hour (KWh) in 2006, an almost 9 percent increase from 2005 and the 
largest annual increase since 1982. Prices surpassed 9 cents per KWh in 
2007, and a number of experts anticipate continued price increases in 
coming years. These rising prices have spurred some to question whether 
federal policies to introduce competition into electricity markets and 
new entities to facilitate that change--referred to in this report as 
wholesale restructuring--have brought improvements or whether they 
themselves are responsible for rising prices. 

For many years, the electricity industry has consisted of regional 
monopolies that were regulated by states--generally through state 
utility commissions--and the federal government--through the Federal 
Energy Regulatory Commission (FERC).[Footnote 1] During the 1990s, 
efforts were made to transform the electricity industry from one 
characterized by monopoly utilities that provided local consumers with 
electricity at regulated rates to one in which companies compete to 
sell electricity to customers at prices that are determined under more 
competitive conditions.[Footnote 2] This restructuring took place in 
response to statutory and regulatory changes at the federal level and 
in many states. The overall goal of this broad restructuring was to 
increase competition in wholesale markets--where power is bought and 
sold by utilities and other resellers--and retail markets--where power 
is sold to the ultimate consumer--with the goal of giving electricity 
consumers benefits such as lower prices and access to a wider array of 
retail services. Many stakeholders--organizations and individuals with 
financial and regulatory interest in the electricity industry, 
including consumer advocacy groups, owners of generation and 
transmission resources, and others--are interested in whether 
restructuring has achieved its goals, and how it may have affected 
prices that consumers pay. 

In 1999, as a part of the wholesale restructuring effort, FERC began 
encouraging the voluntary formation of Regional Transmission 
Organizations (RTO)--independent entities to manage regional networks 
of electric transmission lines, called the grid, and give market 
participants, such as owners of power plants and other sellers of 
electricity, nondiscriminatory access to these lines.[Footnote 3] To 
form an RTO, owners of transmission lines voluntarily agree to turn 
over operational authority--but not ownership--of their lines to the 
RTO. FERC encouraged the formation of RTOs to, among other things, 
improve the pricing of transmission service and ease the entry of new 
generators, thus promoting efficiency in wholesale electricity markets 
and ensuring consumers pay the lowest possible price for reliable 
service. As part of its evaluation of whether to create RTOs, FERC 
estimated that RTOs could provide significant benefits such as enhanced 
electric reliability, improved efficiencies in the management of 
electricity transmission, and lower electricity prices for consumers, 
among others. FERC estimated the benefits of RTOs to be at least $2.4 
billion annually, due to cost savings from the improved operational 
efficiency of generators, easier access to transmission service, and 
other factors. 

To date, seven RTOs have developed across the United States, covering 
part or all of 35 states and the District of Columbia and serving over 
half of U.S. demand.[Footnote 4] These RTOs vary in the amount of 
electricity transmission they manage and the size of territory they 
serve. Their functions generally include administering electricity 
transmission, managing and monitoring the competitiveness of wholesale 
markets for electricity and other services, and planning for long-term 
reliability. 

In parts of the United States with RTOs, wholesale electricity prices 
are related to decisions RTOs make about system reliability, 
transmission planning and how to design markets that establish prices 
for electricity and other services, as well as the operational and 
investment expenses of RTOs that are recovered through FERC-approved 
rates. The prices consumers ultimately pay for electricity are affected 
by the wholesale price, as well as a number of decisions made by 
regulators about transmission and distribution, among other things, and 
by the price of fuel used to generate electricity. FERC has statutory 
responsibility to ensure that prices in wholesale electricity markets-
-including those administered by RTOs--are "just and reasonable" and 
not "unduly discriminatory or preferential."[Footnote 5] To do so, it 
reviews and approves RTO market rules and monitors the competitiveness 
of RTO markets. FERC is also responsible for ensuring the rates RTOs 
charge customers to recover expenses--capital expenses, such as 
software needed to administer electricity markets, and operational 
expenses, such as salaries and benefits--are just and reasonable. To do 
so, FERC conducts formal rate proceedings in which it considers 
information about proposed RTO expenses and comments from interested 
parties, though the proceedings may not occur annually. In certain 
circumstances, it may also consider other sources of information on RTO 
expenses, including budgets RTOs develop annually that contain 
information on proposed expenses and an annual financial report--the 
FERC Form No. 1--that contains information on actual RTO expenses. If 
necessary, such as when facts are in dispute, FERC may hold a trial- 
type evidentiary hearing before an administrative law judge before 
determining the rates for an RTO. Stakeholders also play a role in 
reviewing RTO expenses and decisions that affect electricity prices by 
providing comments to the RTOs and FERC. 

A number of industry participants have voiced concerns about how RTO 
expenses and decisions influence electricity prices and whether RTO 
costs outweigh their benefits. Generally speaking, RTO expenses are 
small compared to wholesale electricity prices. For example, ISO New 
England's non-inflation-adjusted expenses were 87 cents per megawatt 
hour (MWh) in 2006; its average wholesale electricity price was $62.74 
per MWh that same year. Because of the potential for RTO markets to 
influence wholesale, and ultimately consumer, prices, some of 
consumers' most significant concerns relate to RTO decisions about 
developing and operating markets for electricity and other services. 
Experts from industry and the academic community have begun to evaluate 
these issues, as well as the broader effects of restructuring. In this 
context, this report provides information about the steps FERC 
officials and other experts have taken to analyze RTO expenses and 
benefits. Specifically, this report provides information on (1) RTO 
expenses from 2002 to 2006 and key investments in property, plant, and 
equipment; (2) how RTOs and FERC review RTO expenses and decisions that 
may affect electricity prices; and (3) the extent to which there is 
consensus about whether RTOs have provided benefits to consumers. 

To determine the total expenses incurred by RTOs from 2002 to 2006, the 
most current year for which data were available when we began our 
review, and their key investments in property, plant, and equipment, we 
reviewed independent public auditor reports over this period, as well 
as information the RTOs reported on their full-time-equivalent 
personnel and transmission volume.[Footnote 6] We also reviewed 2006 
financial information the RTOs submitted to FERC. We adjusted all 
expense amounts for inflation with 2007 as the base year. We focused on 
six RTOs during our study: California ISO, ISO New England, Midwest 
ISO, New York ISO, PJM Interconnection (PJM), and Southwest Power Pool. 
We did not consider the seventh, the Electric Reliability Council of 
Texas, because it is primarily regulated by the Public Utility 
Commission of Texas, rather than FERC. To determine how FERC and RTOs 
review RTO expenses and decisions, we collected broad information from 
these six RTOs about their analysis of expenses and their decision- 
making processes. We also conducted site visits and collected more in- 
depth information for two RTOs--ISO New England and the Midwest ISO. In 
addition, we spoke with FERC officials and reviewed related 
documentation that outlined FERC's steps to review RTO expenses for 
reasonableness. While we generally considered FERC's oversight of RTO 
decisions, we did not perform an in-depth analysis of FERC's review of 
specific RTO decisions that may affect electricity prices. Finally, to 
understand the extent to which there is consensus about whether RTOs 
have provided benefits to consumers, we interviewed FERC officials and 
reviewed related documentation, including FERC's initial assessment of 
RTO expected benefits and academic and industry studies. We also 
interviewed several experts in the field of electricity restructuring 
to discuss their opinions on the benefits and costs of RTOs and their 
assessments of the adequacy of FERC's analysis of RTOs to date. We 
conducted this performance audit from October 2007 to September 2008 in 
accordance with generally accepted government auditing standards. Those 
standards require that we plan and perform the audit to obtain 
sufficient, appropriate evidence to provide a reasonable basis for our 
findings and conclusions based on our audit objectives. We believe that 
the evidence obtained provides a reasonable basis for our findings and 
conclusions based on our audit objectives. A more complete discussion 
of our scope and methodology is provided in appendix I of this report. 

Results in Brief: 

RTO expenses and investments in property, plant, and equipment vary 
considerably depending on the size of the RTO and functions it carries 
out. Inflation-adjusted expenses for the six RTOs overseen by FERC 
totaled $4.8 billion from 2002 to 2006--ranging from $227 million for 
Southwest Power Pool, a smaller RTO in terms of 2006 transmission 
volume and the number of functions it performs, to $1.4 billion for 
PJM, an RTO with many diverse functions and the largest transmission 
volume in 2006. Despite having the highest expenses, PJM had the second 
lowest inflation-adjusted expense per MWh, because RTOs with greater 
electricity transmission volume can spread their expenses over this 
volume, thus lowering the amount of RTO-related expenses per MWh. These 
per MWh inflation-adjusted expenses have varied for the RTOs from 2002 
to 2006, with inflation-adjusted expenses for three RTOs rising and 
three declining. RTOs' Form No. 1 filings to FERC in 2006 provide 
better visibility of transmission and market expenses than in previous 
years, because FERC revised the Form No. 1 that year to require 
reporting of additional information on these categories of expenses. In 
2006, about 17 percent of all RTO inflation-adjusted expenses were for 
transmission services, 13 percent were for market expenses, 39 percent 
were for administrative and general expenses, and 31 percent consisted 
of other expenses. In addition to expenses incurred from 2002 to 2006, 
the six RTOs also made investments in property, plant, and equipment. 
These investments, when adjusted for inflation, totaled $1.6 billion as 
of December 2006 and consisted primarily of software and equipment used 
to monitor the flow of electricity along transmission lines and 
administer RTO markets. 

RTOs and FERC rely heavily on the participation and views of 
stakeholders when evaluating RTO expenses and decisions that may affect 
electricity prices. Specifically, RTOs seek stakeholder input when 
making decisions that may affect prices, such as developing markets for 
electricity, and evaluating proposed RTO expenses. RTOs have 
facilitated the formation of stakeholder committees and working groups 
to discuss these issues and advise the RTOs' boards of directors, which 
makes the final decisions. The stakeholders we spoke with in two RTO 
regions valued this opportunity for input, but found that attending 
stakeholder meetings was resource intensive. For example, one RTO told 
us over 600 meetings were open to stakeholders in 2007, and some 
stakeholders noted that participating in so many meetings could require 
substantial stakeholder staff and other resources. In addition, 
stakeholders representing consumers expressed concern that the RTOs did 
not place adequate emphasis on how decisions may affect consumer 
prices. For example, some stakeholders expressed concern that RTOs base 
some of their decisions on overly conservative assumptions about 
reliability that may raise consumer prices, such as paying 
noncompetitive generators that these stakeholders did not believe were 
needed for reliability to remain available for electricity production. 
Moreover, one stakeholder was concerned that the costs of operating 
these generators, which may benefit only certain local areas, were 
unfairly borne by consumers outside those local areas. FERC's reviews 
of proposed expenses occur when it considers whether the rates RTOs 
charge are just and reasonable, but the frequency of this review 
varies. Furthermore, although RTO budgets offer one tool FERC could use 
to consider whether rates remain just and reasonable between rate 
proceedings, the extent to which FERC reviews proposed expense 
information in RTO budgets varies. Some consumer groups have expressed 
concern over FERC's lack of more frequent, independent analysis of 
budgets, and without more regular review of this information, FERC may 
be missing an opportunity to improve its oversight of RTO rates. 
Furthermore, while FERC requires RTOs to report their actual expenses 
annually using the FERC Form No. 1, it does not regularly review this 
actual expense information for accuracy or reasonableness. This 
increases the risk that FERC may inappropriately use and provide to the 
public inaccurate and incomplete RTO financial data, limiting the 
effectiveness of the Form No. 1 as a tool for determining whether RTO 
rates are just and reasonable. In fact, in reviewing the 2006 Form No. 
1s, we noted a reporting error that overstated certain expenses 
reported by one RTO by millions of dollars that remained on FERC's Web 
site for more than a year. After being informed of this error, FERC 
initiated an audit of whether one RTO's expenses were reported 
accurately on its Form No. 1. Similar to the RTOs, FERC also emphasizes 
the stakeholder process when reviewing RTO expenses and decisions that 
have the potential to affect consumer electricity prices. FERC 
officials explained that RTO decisions undergo much scrutiny during the 
RTO stakeholder process and acknowledged that this process is integral 
to FERC's process for identifying imprudent and unreasonable expenses 
and its approval of other RTO decisions. While the stakeholder process 
is likely a useful tool that FERC can use in making such decisions, 
more scrutiny of RTO budgets and the Form No. 1s could also have a role 
in supplementing FERC's current oversight of RTO expenses and rates. 

FERC officials, industry participants, and experts lack consensus on 
whether RTOs have brought benefits to their regions that outweigh their 
costs. Many agree that by integrating multiple transmission systems 
into larger service areas, RTOs provide opportunities for certain 
benefits, such as more efficient management of the transmission grid 
and improved generator access to electricity markets, but some believe 
that these benefits could have been achieved without RTOs. Many experts 
and industry participants agree that RTOs are better positioned to more 
frequently use the least costly and most efficient power plants, 
although they do not agree about whether this has translated into 
prices for consumers that are lower than they otherwise would have 
been. Experts and industry participants are divided about whether the 
markets developed and administered by RTOs provide benefits to 
consumers and how they have influenced consumer electricity prices. 
Specifically, advocates and critics of RTOs debate the extent to which 
RTO markets, rising fuel prices, and other factors have contributed to 
rising costs of electricity generation and generally higher prices in 
RTO regions. Assessments developed by RTOs generally find that RTOs 
benefit their regions. FERC officials also believe that RTOs have 
resulted in net benefits to the economy, such as new efficiencies in 
operating the regional transmission grid; however, FERC has not 
conducted an empirical analysis of whether RTOs achieved the benefits 
expected of them or developed a comprehensive set of publicly 
available, standardized measures to help evaluate such performance. 
GAO's Standards for Internal Control identify the value to 
organizations of comparing actual performance to planned or expected 
results; however, according to FERC, neither an empirical analysis nor 
performance measures are necessary parts of FERC oversight of RTOs and 
both would be methodologically challenging to develop.[Footnote 7] 
Experts agreed that a onetime empirical analysis of RTO performance 
would be difficult but added that tracking certain measures of RTO 
success--for example, measures relating to transmission and generation 
investment, plant efficiency, and reliability--could encourage better 
RTO performance and potentially identify areas for improvement. Without 
such measures, FERC will remain unable to demonstrate the extent to 
which RTOs have provided consumers and others with benefits-- 
information that could aid FERC in its evaluation of the success of its 
decision to encourage the creation of RTOs. Furthermore, information 
gleaned from such measures could help FERC address the divisions among 
experts and industry participants about the benefits of RTOs. 

To improve its oversight of RTOs, we recommend that FERC (1) develop a 
consistent approach for regularly reviewing RTO budgets and (2) 
routinely review and assess the accuracy, completeness, and 
reasonableness of the financial information RTOs report to FERC in 
their Form No. 1 filings. To better understand the extent to which RTOs 
have provided consumers and others with benefits, we are recommending 
that FERC work with RTOs, stakeholders, and experts to develop 
standardized measures to track the performance of RTO operations and 
markets and report the performance results to Congress and the public. 
FERC reviewed a draft of this report and generally agreed with our 
report and recommendations. 

Background: 

The electricity industry includes four distinct functions: generation, 
transmission, distribution, and system operations. Once electricity is 
generated--whether by burning fossil fuels; through nuclear fission; or 
by harnessing wind, solar, geothermal, or hydro energy--it is sent 
through high-voltage, high-capacity transmission lines to areas where 
it will be used. Once there, electricity is transformed to a lower 
voltage and sent through local distribution wires for end use by 
industrial plants, businesses, and residential customers. Because 
electric energy is generated and consumed almost instantaneously, the 
operation of an electric power system requires that a system operator 
constantly balance the generation and consumption of power. 

Historically, the electric industry developed as a loosely connected 
structure of individual monopoly utility companies, each building and 
operating power plants and transmission and distribution lines to serve 
the exclusive needs of all the consumers in its local area. Because 
these companies were monopolies, they were overseen by regulators who 
balanced different stakeholder interests in order to protect consumers 
from unfair pricing and other undesirable behavior. Retail electricity 
prices were regulated by the states, generally through state public 
utility commissions. States retained regulatory authority over retail 
sales of electricity, construction of transmission lines within their 
boundaries, and intrastate distribution. Generally, states set retail 
rates based on the utility's cost of production plus a fair rate of 
return. States also approved plans and spending for building new power 
plants to serve regulated customers. In contrast, wholesale electricity 
pricing and interstate transmission were regulated by the federal 
government, principally FERC. Under law, FERC has the obligation to 
ensure that the rates it oversees are "just and reasonable" and not 
"unduly discriminatory or preferential."[Footnote 8] To meet this 
responsibility, FERC approved rates for transmission and wholesale 
sales of electricity in interstate commerce based on the utilities' 
costs of production plus a fair rate of return on the utilities' 
investment. 

Since the early 1990s, the federal government has taken a series of 
steps to restructure the wholesale electricity industry, generally 
focused on increasing competition in wholesale markets. Federal 
restructuring efforts have (1) changed how electricity prices are 
determined, replacing cost-based regulated rates with market-based 
pricing in many wholesale electricity markets, and (2) allowed new 
companies to enter electricity markets.[Footnote 9] Some of these 
efforts have focused on allowing nontraditional utilities to buy and 
sell electricity in wholesale markets, while others have focused on 
allowing nontraditional utilities to build new power plants and sell 
electricity to utilities and others. 

To facilitate formation of these markets and these companies' efforts 
to buy and sell electricity, FERC initially required that transmission 
owners under its jurisdiction, generally large utilities, allow all 
other entities to use their transmission lines under the same prices, 
terms, and conditions as those they apply to themselves. To do this, 
FERC required the regulated monopoly utilities--which had historically 
owned the power plants, transmission systems, and distribution lines-- 
to separate their generation and transmission functions, and encouraged 
these companies to form independent entities, called Independent System 
Operators (ISO), to manage the transmission network.[Footnote 10] In 
recognition that these initial efforts were not sufficient, FERC issued 
Order 2000 in December 1999 to encourage owners of transmission systems 
to develop more robust organizations, called RTOs, to manage the 
transmission networks and perform other functions that FERC believed 
were important. FERC believed RTOs were needed to address impediments 
to competitive wholesale markets: growing stresses on the transmission 
grid and remaining discrimination in the provision of transmission 
service--transmission owners operating their grids in a way that 
favored their own interests over those of their competitors. FERC Order 
2000 encouraged, but did not mandate, that transmission owners join 
RTOs and allowed companies engaged in purchase and sale of electricity 
in markets to continue to own power plants, retail utilities, 
distribution lines, transmission lines, and other assets regulated by 
FERC or the states. 

FERC outlined minimum characteristics that RTOs were to have: 
independence from control by any market participant, sufficient scope 
to maintain reliability and support nondiscriminatory power markets, 
operational authority for transmission facilities under their control, 
and exclusive authority for maintaining the short-term reliability of 
the grid they operate. Appendix II describes these characteristics in 
more detail. In Order 2000, FERC opined that RTOs would achieve the 
following benefits: 

* eliminate multiple charges incurred when crossing transmission 
systems owned by different utilities, 

* improve management of electricity congestion--bottlenecks resulting 
from insufficient transmission capacity to accommodate all requests to 
transport power and maintain adequate safety margins for reliability, 

* provide more accurate estimates of transmission system capacity--the 
amount of electric power the transmission system can manage, 

* increase efficiency in planning for transmission and generation 
investments; 

* improve grid reliability, and: 

* reduce opportunities for discriminatory transmission practices. 
[Footnote 11] 

FERC expected the formation of RTOs to result in significant cost 
reductions, additional efficiencies, and better wholesale market 
performance, ultimately lowering prices for electricity consumers. 
Specifically, it estimated RTOs would bring at least $2.4 billion in 
annual benefits to the industry. Because of their independence, FERC 
expected RTOs to lead to lighter regulation by reducing the need for 
resolving stakeholder disputes through the FERC complaint process and 
allowing FERC to provide additional latitude to RTOs in their 
transmission pricing proposals, among other things. 

FERC's efforts to encourage the formation of RTOs have been relatively 
successful and RTOs now serve many parts of the country and extend into 
Canada, as figure 1 shows. FERC oversees six RTOs: California ISO, ISO 
New England, Midwest ISO, PJM, New York ISO, and Southwest Power Pool. 
[Footnote 12] The Electric Reliability Council of Texas is primarily 
regulated by the Public Utility Commission of Texas. 

Figure 1: U.S. Regional Transmission Organizations: 

[See PDF for image] 

This figure is a map of the United States depicting the Regional 
Transmission Organizations. The following are indicated on the map: 

ISO New England; 
New York ISO; 
PJM Interconnection; 
Midwest ISO; 
Southwest Power Pool; 
Electric Reliability Council of Texas; 
California ISO. 

Sources: FERC (data); map (Platts POWERmap, December 2007). 

Note: This graphic represents the seven U.S. RTOs. FERC regulates six 
of these RTOs--California ISO, ISO New England, Midwest ISO, New York 
ISO, PJM, and Southwest Power Pool. It does not regulate the seventh, 
the Electric Reliability Council of Texas. 

[End of figure] 

RTOs operate, but do not own, electricity transmission lines and are 
responsible for ensuring nondiscriminatory access to these lines for 
all market participants.[Footnote 13] As shown in table 1, the six RTOs 
under FERC's jurisdiction, in general, are responsible for managing 
transmission in their regions--by implementing the rules and 
transmission pricing outlined in their tariffs and performing 
reliability planning by considering factors such as weather conditions 
and equipment outages that could affect electricity supply and demand-
-as well as operating wholesale markets for electricity and other 
services. 

Table 1: Selected RTO Responsibilities: 

Category: Transmission functions; 
Responsibility: Service provider; 
Description: Administers the transmission tariff and provides 
transmission services. Receives and processes transmission service 
requests. Determines available capacity; 
California ISO: Yes; 
ISO New England: Yes; 
Midwest ISO: Yes; 
New York ISO: Yes; 
PJM: Yes; 
Southwest Power Pool: Yes. 

Category: Transmission functions; 
Responsibility: Balancing authority; 
Description: Integrates resource plans regionally and maintains in real 
time the balance of electricity resources and electricity demand; 
California ISO: Yes; 
ISO New England: Yes; 
Midwest ISO: No[A]; 
New York ISO: Yes; 
PJM: Yes; 
Southwest Power Pool: No. 

Category: Transmission functions; 
Responsibility: Reliability coordinator; 
Description: Ensures the real-time operating reliability of the 
transmission system; 
California ISO: Yes; 
ISO New England: Yes; 
Midwest ISO: Yes; 
New York ISO: Yes; 
PJM: Yes; 
Southwest Power Pool: Yes. 

Category: Transmission functions; 
Responsibility: Planner; 
Description: Works with stakeholders to develop overall plans for new 
transmission needed to meet future projected electricity demand; 
California ISO: Yes; 
ISO New England: Yes; 
Midwest ISO: Yes; 
New York ISO: Yes; 
PJM: Yes; 
Southwest Power Pool: Yes. 

Category: Wholesale energy market functions; 
Responsibility: Real-time market administrator; 
Description: Administers a market where electricity is bought and sold 
at prices determined in real-time to satisfy the difference between 
projected needs and actual demand. Many of these markets price 
electricity differently at various locations across the region in order 
to reflect the costs associated with congestion; 
California ISO: Yes; 
ISO New England: Yes; 
Midwest ISO: Yes; 
New York ISO: Yes; 
PJM: Yes; 
Southwest Power Pool: Yes. 

Category: Wholesale energy market functions; 
Responsibility: Day-ahead market administrator; 
Description: Administers a forward market where electricity is bought 
and sold for use the following day based on projected customer needs; 
California ISO: No[B]; 
ISO New England: Yes; 
Midwest ISO: Yes; 
New York ISO: Yes; 
PJM: Yes; 
Southwest Power Pool: No. 

Category: Wholesale energy market functions; 
Responsibility: Ancillary services market administrator; 
Description: Category: Manages services necessary to support the 
reliable operation of the transmission system and provision of 
electricity at appropriate frequency and voltage levels;
California ISO: Yes; 
ISO New England: Yes; 
Midwest ISO: No[A]; 
New York ISO: Yes; 
PJM: Yes; 
Southwest Power Pool: No. 

Category: Wholesale energy market functions; 
Responsibility: Capacity market administrator; 
Description: Administers a system to procure a sufficient portfolio of 
supply and demand resources to meet future electricity needs and 
encourage investment; 
California ISO: No; 
ISO New England: Yes; 
Midwest ISO: No; 
New York ISO: Yes; 
PJM: Yes; 
Southwest Power Pool: No. 

Source: GAO analysis of FERC and RTO documentation. 

[A] These functions for the Midwest ISO are expected to become 
effective in December 2008, the proposed start date of its ancillary 
services market. 

[B] California ISO's day-ahead markets are expected to start in 2009. 

[End of table] 

Decisions an RTO makes when carrying out these responsibilities can 
influence the wholesale price of electricity and ultimately the price 
consumers pay. A number of other factors outside an RTO's control, such 
as regulator decisions about what transmission and distribution rates 
to approve and whether to implement price caps, also influence the 
prices consumers pay for electricity. Prices are also highly dependent 
on the cost of fuel used to generate electricity. 

Typically, consumer electricity prices are composed of three broad 
components: (1) distribution, which, for four states GAO contacted, 
accounts for about 15 to 30 percent of the final price of electricity; 
(2) transmission, which accounts for about 5 to 10 percent of the final 
price; and (3) electricity generation or production, which accounts for 
about 55 to 65 percent of the final price.[Footnote 14] In RTO regions, 
distribution rates continue to be set by state regulators, and 
transmission rates continue to be set by state and federal regulators. 
FERC also approves RTO procedures for planning transmission 
infrastructure, as well as the recovery of transmission expenses. The 
electricity generation component was previously set by regulators based 
on the cost of providing electricity plus a rate of return. The price 
of this component is now determined in RTO-administered markets-- 
regulated by FERC to ensure they are competitive--to the extent that 
entities choose to buy electricity in these markets.[Footnote 15] Some 
RTOs also administer markets that determine the price of other services 
needed to maintain reliability, such as capacity and ancillary 
services, in lieu of charging a cost-based rate.[Footnote 16] The 
generation portion of consumers' bills may also include 
administratively determined payments made to generators to maintain 
reliability--reliability payments, as well as a FERC-approved rate to 
recover RTO expenses. The size of these components varies from region 
to region. In New England, for example, on average approximately 47 
percent of a typical consumer's bill in 2006 was for electricity, 
capacity, and ancillary services, the prices of which are determined 
through the markets this RTO administers. A very small portion of a 
typical consumers' bill, less than 1 percent, was from ISO New 
England's rate to recover operational and investment expenses. Figure 2 
provides more information. 

Figure 2: Components of a Typical Consumer's Electricity Costs in New 
England: 

[See PDF for image] 

This figures contains the following descriptive text accompanying a pie-
chart indicating the percentage represented by each component: 

Components of a Typical Consumer's Electricity Costs in New England: 

Distribution costs[A]: ($68.90/MWh); 
Reflect the cost of building the distribution system, as well as
operating and maintaining it (47%). 

Wholesale energy price[B]: ($66.32/MWh); 
Reflects a market-determined price for energy (electricity) that
includes an energy, congestion, and loss component (45%). 

Out-of-market payments (reliability payments)[B]: ($5.41/MWh); 
Reflect nonmarket payments to generators that the RTO determines are 
needed for reliability (4%). 

Transmission costs[C]: ($3.60/MWh); 
Reflect the cost of building the transmission system, as well
as operating and maintaining it (2%). 

Capacity costs[B]: ($1.44/MWh); 
Reflect a market-determined price for procuring power resources to 
satisfy the region’s future needs (1%). 

Ancillary service costs[B}: ($1.10/MWh); 
Reflect the costs associated with providing services to support the 
reliable operation of the electric grid (<1%). 

RTO expenses[D]: ($0.82/MWh); 
Reflect the administrative rate charged to ISO New England market 
participants in 2006 to recover operating and investment expenses 
(<1%). 

Source: GAO analysis of information provided by ISO New England. 

[A] Distribution costs were determined by ISO New England by surveying 
the Web sites of distribution companies in New England. 

[B] The wholesale energy price, out-of-market payment, capacity, and 
ancillary service components were calculated by ISO New England 
according to a FERC-defined methodology and can be found in the 2006 
Annual Markets Report. 

[C] Transmission costs were provided by ISO New England and represent 
the total revenue requirement of transmission-owning utilities in the 
New England region. This revenue requirement covers the transmission 
owners' costs of building the transmission system and operating and 
maintaining it. The transmission cost estimate does not include any 
transmission costs associated with electricity imported into the ISO 
New England region--those costs would be subsumed in the wholesale 
price of electricity as reflected in the energy costs estimates. 

[D] RTO expenses were provided by ISO New England and reflect the rate 
charged to market participants to recover operating and investment 
expenses in 2006. 

[End of figure] 

Because RTOs charge for the use of transmission lines, for certain 
wholesale sales of electricity, and to recover their own expenses, they 
are subject to FERC oversight and regulation. In general, FERC 
regulates RTOs as it does other utilities. FERC's basic rate authority 
stems from Sections 205 and 206 of the Federal Power Act of 1935 and is 
to ensure that wholesale electricity rates are just and reasonable and 
not unduly discriminatory or preferential. Under Section 205, FERC 
generally has the authority to review and approve expenses and, if 
applicable, a reasonable rate of return on investment used to serve 
customers. For RTOs, which are nonprofit entities, rates are generally 
based on proposed annual expenses and are periodically adjusted based 
on the actual expenses incurred by the RTOs. RTOs must also seek FERC 
approval for decisions to implement initiatives such as new markets and 
changes to existing markets and market rules, among other things. 
Section 206 authority provides for FERC review of rates already in 
effect. FERC may initiate Section 206 proceedings if it deems an 
investigation is needed or in response to a complaint filed by an 
outside party.[Footnote 17] FERC has authority to determine if these 
rates are just and reasonable, set new rates, and may, in some cases, 
order refunds. 

Under Section 205 or Section 206, RTOs or other parties, respectively, 
file evidence with FERC to support their proposed rates or rate 
changes. Others can file comments and present any contrary evidence 
under either provision. FERC conducts hearings, which may include 
proceedings before an administrative law judge, and makes final 
decisions. Parties may file appeals, first with FERC and later in 
federal court. 

RTO Expenses and Investments in Property, Plant, and Equipment Varied 
Considerably: 

From 2002 to 2006, RTO expenses totaled $4.8 billion when adjusted for 
inflation and varied considerably depending on the size of the RTO and 
functions it carried out.[Footnote 18] In general, RTOs with greater 
electricity transmission volume benefit from economies of scale by 
spreading their expenses over more units of electricity volume, thereby 
reducing their expenses per MWh. On a per MWh basis, RTO inflation- 
adjusted expenses have varied from 2002 to 2006, with ISO New England, 
Midwest ISO, and New York ISO expenses rising and California ISO, PJM, 
and Southwest Power Pool expenses decreasing. The expenses per MWh we 
calculated for PJM for 2002 and 2003 are significantly higher than the 
amounts it billed its market participants, because we did not 
retroactively apply financial statement reclassifications to data from 
prior years. Form No. 1 filings for 2006 made by the RTOs to FERC 
provide better visibility of transmission and market expenses than 
prior years' reports did. In 2006, about 17 percent of all RTO expenses 
were for transmission services, 13 percent were for market expenses, 39 
percent were for administrative and general expenses, and 31 percent 
consisted of other expenses. RTOs also made major investments in 
property, plant, and equipment--$1.6 billion when adjusted for 
inflation as of December 2006. 

RTO Expenses Totaled $4.8 Billion from 2002 to 2006: 

From 2002 to 2006, total inflation-adjusted expenses reported in RTO 
financial statements totaled $4.8 billion, ranging from $227 million 
for Southwest Power Pool, a smaller RTO in terms of 2006 transmission 
volume and the number of functions it performs, to $1.4 billion for 
PJM, an RTO with many diverse functions and the largest 2006 
transmission volume. As shown in figure 3, the largest category of 
expenses for RTOs over this time period was salaries and benefits, 
accounting for about $1.6 billion, or 33 percent of RTOs' expenses from 
2002 to 2006. According to RTO officials, due to the highly technical 
and sophisticated nature of the functions RTOs must carry out, RTOs 
require highly trained staff, such as power system engineers, 
economists, and software engineers. In 2006, all RTOs combined employed 
2,737 full-time equivalents (FTE) with an average salary and related 
benefits of approximately $134,000.[Footnote 19] Appendix III shows the 
inflation-adjusted expenses, number of full-time equivalents, and 
average salary and expenses per full-time equivalent for each RTO from 
2002 to 2006. Our analysis reflects total annual expenses as reported 
in the RTOs' audited financial statements. We did not retroactively 
apply financial statement reclassifications to data from prior years. 
Because PJM made retroactive reclassifications that affected its 2002 
and 2003 financial statements, in 2002 and 2003, the expenses we 
calculated for PJM are significantly higher than the amounts it billed 
its market participants. 

Figure 3: Total Inflation-Adjusted RTO Expenses, 2002 to 2006: 

[See PDF for image] 

This figure is a pie-chart depicting the following data: 

Total Inflation-Adjusted RTO Expenses, 2002 to 2006 (dollars in 
thousands): 

Salaries and related benefits: $1,565,644 (33%); 
Depreciation and amortization: $902,592 (19%); 
Consulting, professional, and other outside services $704,946; (15%); 
Facility and maintenance: $631,142 (13%); 
Other: $505,991 (11%); 
Regulatory dues and assessments: $292,820 (6%); 
Interest expense: $189,883 (4%). 

Source: GAO analysis of RTO independent auditor reports, 2002 to 2006. 

Note: Dollar amounts represent total expenses from 2002 to 2006 and are 
adjusted for inflation and presented in 2007 dollars. Percentages do 
not add to 100 due to rounding. 

[End of figure] 

Larger RTOs Benefit from Economies of Scale: 

In general, RTOs with greater electricity transmission volume benefit 
from economies of scale--spreading their expenses over more units of 
electricity volume, thus lowering the amount of RTO-related expenses 
per MWh. For example, PJM had the highest total inflation-adjusted 
expenses among RTOs in 2006--$282 million--but had the second lowest 
expense per MWh--$0.39 per MWh--because it transmitted a greater amount 
of electricity than the other RTOs. In contrast, ISO New England had 
the second lowest expenses in 2006--$118 million--but had the highest 
expense per MWh--$0.89 per MWh--because it transmitted less 
electricity. Figure 4 illustrates total RTO expenses in 2006 per unit 
of electricity transmitted by major category. Appendix IV provides 
transmission data and expense per MWh data by RTO from 2002 to 2006. 

Figure 4: Inflation-Adjusted Expenses per MWh by RTO, 2006: 

[See PDF for image] 

This figure is a stacked vertical bar graph depicting the following 
data: 

Dollars of expenses per MHh: 

Salaries and related benefits:	
Interest expense: 
Consulting, professional, and other outside services: 
Facility and maintenance: 
Depreciation and amortization: 
Regulatory dues and assessments: 
Other: 

Southwest Power Pool: 
Salaries and related benefits: 0.15; 
Interest expense: 0; 
Consulting, professional, and other outside services: 0.08; 
Facility and maintenance: 0.04; 
Depreciation and amortization: 0.02; 
Regulatory dues and assessments: 0.06; 
Other: 0.03. 

PJM; 
Salaries and related benefits: 0.11; 
Interest expense: 0.03; 
Consulting, professional, and other outside services: 0.05; 
Facility and maintenance: 0.02; 
Depreciation and amortization: 0.07; 
Regulatory dues and assessments: 0.05; 
Other: 0.06. 

Midwest ISO; 
Salaries and related benefits:	0.12; 
Interest expense: 0.02; 
Consulting, professional, and other outside services: 0.04; 
Facility and maintenance: 0.05; 
Depreciation and amortization: 0.12; 
Regulatory dues and assessments: 0.05; 
Other: 0.01. 

California ISO;	
Salaries and related benefits: 0.31; 
Interest expense: 0; 
Consulting, professional, and other outside services: 0.07; 
Facility and maintenance: 0.14; 
Depreciation and amortization: 0.07; 
Regulatory dues and assessments: 0; 
Other: 0.04. 

New York ISO; 
Salaries and related benefits:	0.28; 
Interest expense: 0.02; 
Consulting, professional, and other outside services: 0.15; 
Facility and maintenance: 0.15; 
Depreciation and amortization: 0.19; 
Regulatory dues and assessments: 0.06; 
Other: 0.03. 

ISO New England; 
Salaries and related benefits: 0.42; 	
Interest expense: 0.02; 
Consulting, professional, and other outside services: 0.11; 
Facility and maintenance: 0.06; 
Depreciation and amortization: 0.19; 
Regulatory dues and assessments: 0.01; 
Other: 0.08. 

Source: GAO analysis of RTO independent auditor reports, 2006. 

Note: Dollar amounts are inflation adjusted and presented in 2007 
dollars. 

[End of figure] 

Our analysis reflects total annual expenses as reported in the RTOs' 
annual audited financial statements, divided by the amount of 
transmission volume within the RTO. These calculations may result in 
MWh expenses that differ from what RTOs charge their market 
participants. Furthermore, we did not retroactively apply financial 
statement reclassifications to data from prior years. Because PJM made 
retroactive reclassifications that affected its 2002 and 2003 financial 
statements, in 2002 and 2003, the expenses per MWh we calculated for 
PJM are significantly higher than the amount it billed its market 
participants. For example, in 2002, PJM had expenses of $0.95 per MWh, 
according to our analysis. According to data provided by PJM officials 
that we adjusted for inflation, market participants were billed $0.51 
per MWh, after refunds and other billing adjustments were taken into 
account. Similarly, in 2003, PJM had expenses of $0.85 per MWh 
according to our analysis, but market participants were billed $0.57 
per MWh when adjusted for inflation. In addition, RTOs utilize 
differing billing methodologies. As a result, the rates they charge to 
market participants may be different than the total expenses per MWh 
calculated in our analysis. Table 2 shows actual electricity rates per 
MWh charged to RTO market participants, adjusted for inflation, from 
2002 to 2006. 

Table 2: Inflation-Adjusted Rates per MWh Charged to RTO Market 
Participants, 2002-2006: 

California ISO: 
2002: $1.15; 
2003: $1.17; 
2004: $1.06; 
2005: $0.95; 
2006: $0.79. 

ISO New England: 
2002: $0.55; 
2003: $0.94; 
2004: $1.01; 
2005: $0.89; 
2006: $0.84. 

Midwest ISO: 
2002: $0.23; 
2003: $0.18; 
2004: $0.25; 
2005: $0.39; 
2006: $0.39. 

New York ISO: 
2002: $0.77; 
2003: $0.82; 
2004: $0.84; 
2005: $0.84; 
2006: $0.82. 

PJM: 
2002: $0.51; 
2003: $0.57; 
2004: $0.49; 
2005: $0.38; 
2006: $0.39. 

Southwest Power Pool: 
2002: $0.23; 
2003: $0.21; 
2004: $0.16; 
2005: $0.17; 
2006: $0.16. 

Sources: Rates provided by California ISO, ISO New England, Midwest 
ISO, New York ISO, PJM, and Southwest Power Pool. 

Note: We adjusted these expenses for inflation and present them in 2007 
dollars. 

[End of table] 

Individual RTO Expenses Have Varied over Time: 

When looked at annually, inflation-adjusted RTO expenses from 2002 to 
2006 have varied, reflecting new initiatives implemented by the RTOs 
and other changes made by management. Figure 5 illustrates changes in 
RTO inflation-adjusted expenses per unit of electricity transmitted 
over this period. 

Figure 5: Inflation-Adjusted Expenses per MWh by RTO, 2002-2006: 

[See PDF for image] 

This figure is a multiple line graph depicting the following data in 
dollars of expenses per MWh: 

Year: 2002; 
California ISO:	1.09; 
ISO New England: 0.57; 
Midwest ISO: 0.26; 
New York ISO: 0.71; 
PJM: 0.95; 
Southwest Power Pool: 0.47. 

Year: 2003; 
California ISO:	1.04; 
ISO New England: 0.89; 
Midwest ISO: 0.2; 
New York ISO: 0.82; 
PJM: 0.85; 
Southwest Power Pool: 0.37. 

Year: 2004; 
California ISO:	0.78; 
ISO New England: 0.96; 
Midwest ISO: 0.27; 
New York ISO: 0.91; 
PJM: 0.5; 
Southwest Power Pool: 0.42. 

Year: 2005; 
California ISO:	0.73; 
ISO New England: 0.97; 
Midwest ISO: 0.41; 
New York ISO: 0.91; 
PJM: 0.39; 
Southwest Power Pool: 0.41. 

Year: 2006; 
California ISO:	0.64; 
ISO New England: 0.89; 
Midwest ISO: 0.41; 
New York ISO: 0.89; 
PJM: 0.39; 
Southwest Power Pool: 0.37. 

Source: GAO analysis of RTO independent auditor reports, 2002 to 2006. 

Note: This chart reflects inflation-adjusted expenses as reported on 
each RTO's annual financial statement. Amounts are in 2007 dollars. In 
2004, PJM changed its method of classifying revenues and expenses 
related to study and interconnection fees for financial reporting 
purposes. Had 2002 and 2003 expenses been reported as they were from 
2004 to 2006, PJM's inflation-adjusted expenses per MWh would have been 
$0.52/MWh (instead of $0.95/MWh) in 2002 and $0.59/MWh (instead of 
$0.85/MWh) in 2003. 

[End of figure] 

Several key trends occurred over this period, with the expenses per MWh 
of three RTOs--Midwest ISO, New York ISO, and ISO New England--rising 
as they implemented major market and other initiatives. For example, 
during this period, Midwest ISO expanded its role from coordinating 
reliability, administering its tariff, and performing transmission 
system planning to include operating markets for energy and other 
services. As a result, Midwest ISO's expenses rose in a number of 
areas. Salaries and benefits increased as the RTO increased its full- 
time equivalents from 265 in 2002 to 643 in 2006, in part, to carry out 
the RTO's expanded operations. Expenses for consulting, professional, 
and outside services--used, in part, to develop the new markets for 
electricity and other services--and depreciation and amortization 
expenses--to recover the costs of major investments, such as 
information systems and infrastructure related to the electricity 
market--also increased from 2002 to 2006.[Footnote 20] Increases in 
Midwest ISO's expenses were mitigated by its rising transmission load 
as it took on additional members. 

In contrast, California ISO's expenses per MWh hour declined 
significantly over this time period, particularly in the areas of 
depreciation and amortization and facilities and maintenance. 
California ISO officials attributed declining expenses to an 
organizational focus on keeping expenses low, including a specific cost 
containment management initiative in 2005, and more economically 
advantageous contracts in a few key areas. Additionally, as noted in 
the graphic, PJM changed the way it reported revenues and expenses. 
Starting in 2004, PJM offset revenues and expenses related to study and 
interconnection fees. Had 2002 and 2003 expenses been reported as they 
were in later years, PJM's inflation-adjusted expenses per MWh would 
have fluctuated over the period and ultimately declined from $0.52 per 
MWh in 2002 to $0.39 per MWh in 2006. Finally, Southwest Power Pool's 
expenses per MWh declined slightly over this time period--from $0.47 
per MWh to $0.37 per MWh, as increasing overall expenses were mitigated 
by rising transmission load. 

FERC's Revisions to Its Form No. 1 Provide Better Visibility of RTO 
Expenses Related to Transmission and Markets: 

Starting in 2006, FERC required RTOs and other utilities to provide 
more detailed information about market and transmission expenses on 
their Form No. 1 filings to improve the visibility and uniformity of 
RTO and utility financial reporting, and we found that RTO's 2006 Form 
No. 1s are more transparent than in previous years. FERC officials told 
us these changes would facilitate review by FERC and the public of RTO 
expenses and rates. Form No. 1 filings categorize expenses according to 
two key functions RTOs perform--transmission coordination and market 
operation--as well as other categories such as administrative and 
general expenses. In 2006, about 17 percent of all RTO inflation- 
adjusted expenses were for transmission services, 13 percent were for 
market expenses, 39 percent were for administrative and general 
expenses, and 31 percent consisted of other expenses.[Footnote 21] 
Figure 6 provides information reported in the Form No. 1 about each of 
the RTOs' expenses. Appendix V shows 2006 RTO inflation-adjusted 
expenses as reported on the FERC Form No. 1. 

Figure 6: Inflation-Adjusted Expenses per MWh by RTO as Reported in the 
2006 FERC Form No. 1: 

[See PDF for image] 

This figure is a stacked vertical bar graph depicting the following 
data in dollars of expenses per MWh: 

Southwest PowerPool: 
Transmission expenses: 0.02; 
Regional market expenses: 0.03; 
Administrative and general expenses: 0.26; 
Other expenses: 0.04. 

PJM: 
Transmission expenses: 0.06; 
Regional market expenses: 0.03; 
Administrative and general expenses: 0.15; 
Other expenses: 0.14. 

Midwest ISO: 
Transmission expenses: 0.08; 
Regional market expenses: 0.08; 
Administrative and general expenses: 0.1; 
Other expenses: 0.15. 

California ISO: 
Transmission expenses: 0.14; 
Regional market expenses: 0.07; 
Administrative and general expenses: 0.3; 
Other expenses: 0.12. 

New York ISO: 
Transmission expenses: 0.11; 
Regional market expenses: 0.12; 
Administrative and general expenses: 0.36; 
Other expenses: 0.28. 

ISO New England: 
Transmission expenses: 0.15; 
Regional market expenses: 0.13; 
Administrative and general expenses: 0.35; 
Other expenses: 0.26. 

Source: GAO analysis of RTO 2006 FERC Form No. 1s. 

Note: Dollar amounts are inflation adjusted and presented in 2007 
dollars. New York ISO, Southwest Power Pool, and PJM expenses reported 
on FERC Form No. 1 filings do not agree with the expenses noted on the 
independent auditors' reports due primarily to differences in how 
certain interest, lease, planning, and other revenues were netted 
against related expense accounts in the FERC Form No. 1 filings. 

[End of figure] 

Transmission expenses cover the cost of providing reliability services 
and monitoring and operating the transmission systems, among other 
things. Market expenses include the cost of administering markets for 
electricity and other services, monitoring markets for competitiveness, 
and related computer software and hardware maintenance, among other 
things. Administrative and general expenses consist of employee 
salaries and benefits, rent, and outside services, among other things. 

RTOs Have Made Investments in Property, Plant, and Equipment: 

The six RTOs whose financial statements we reviewed have made 
investments in property, plant, and equipment. Total inflation-adjusted 
investment for all RTOs was $1.6 billion as of December 31, 2006, 
without adjusting for accumulated depreciation.[Footnote 22] Software 
and equipment was the largest category of investment at each of the 
RTOs, as shown in figure 7, and was used by the RTOs to provide various 
transmission and market services across regions. For example, in 2005, 
ISO New England began construction of a replacement control center 
equipped with computer hardware and software to deploy generators, 
forecast electricity requirements, ensure load is not interrupted in 
the event of a contingency, and conduct and monitor electricity 
transfers with other RTOs. Appendix VI shows RTOs' investments in 
property, plant, and equipment as of December 2006. 

Figure 7: Inflation-Adjusted Investment in Property, Plant, and 
Equipment as of December 2006: 

[See PDF for image] 

This figure is a stacked vertical bar graph depicting the following 
data in investment in property, plant and equipment in millions of 
dollars: 

Southwest Power Pool: 
Software equipment: $59.654; 
Construction, work and projects in process: $6.303; 
Buildings and leasehold improvements: $0.513; 
Land: $0.337; 
Furniture and fixtures: $3.246. 

PJM: 
Software equipment: $285.328; 
Construction, work and projects in process: $18.705; 
Buildings and leasehold improvements: $17.454; 
Land: $0.982; 
Furniture and fixtures: $0.788. 

Midwest ISO: 
Software equipment: $325.846; 
Construction, work and projects in process: 0; 
Buildings and leasehold improvements: $33.857; 
Land: $2.216; 
Furniture and fixtures: $3.33. 

California ISO: 
Software equipment: $234.735; 
Construction, work and projects in process: $131.4; 
Buildings and leasehold improvements: $13.763; 
Land: $9.63; 
Furniture and fixtures: $9.685. 

New York ISO: 
Software equipment: $154.053; 
Construction, work and projects in process: $12.112; 
Buildings and leasehold improvements: $24.054; 
Land: $2.098; 
Furniture and fixtures: $2.998. 

ISO New England: 
Software equipment: $174.295; 
Construction, work and projects in process: $24.118; 
Buildings and leasehold improvements: $33.078; 
Land: 0; 
Furniture and fixtures: $2.055. 

Source: GAO analysis of RTO independent auditor reports, 2006. 

[End of figure] 

RTOs and FERC Rely on Stakeholder Input when Evaluating RTO Expenses 
and Decisions That May Affect Electricity Prices: 

RTOs consider stakeholder comments when reviewing RTO expenses and 
other decisions that may affect electricity prices. In the two RTOs we 
visited, stakeholders said they valued the opportunity for discussion 
with the RTOs, but some stakeholders expressed concern that attending 
meetings was resource intensive and that too little emphasis was placed 
on how decisions might affect the prices consumers pay for electricity. 
Furthermore, though RTO budgets offer one tool FERC could use to 
revisit whether rates remain just and reasonable between rate 
proceedings, the extent to which FERC reviews proposed expense 
information in RTO budgets varies. Additionally, although FERC annually 
requires RTOs to report the actual expenses they incurred, FERC staff 
have not regularly reviewed or audited these submissions for accuracy 
and do not look at them for reasonableness. Instead, FERC relies 
heavily on stakeholders to raise concerns over proposed expenses and 
other decisions that may affect consumer electricity prices. 

RTOs Consider Stakeholder Comments when Reviewing RTO Expenses and 
Making Decisions That Affect Electricity Prices: 

According to senior RTO officials, RTO boards and staff give much 
consideration to stakeholder comments when reviewing RTO expenses and 
making decisions that affect electricity prices. They told us that 
while RTO decisions are independent--stakeholder input is generally 
advisory--stakeholders play an important role in evaluating RTOs' 
operations and plans. In particular, although RTOs conduct internal 
reviews of their proposed expenses, establish controls for reviewing 
the prudence of expenses, and may perform formal cost-benefit analysis 
on major initiatives, officials told us stakeholder comments are one of 
the most important factors when reviewing expenses and making 
decisions. In general, RTOs solicit comments from stakeholders about 
their opinions on decisions to modify new market rules, changes to 
governing documents, and budgets and expenses, among other things. 
According to RTO officials, in some instances, RTOs are required to 
secure affirmative stakeholder votes on these decisions prior to 
proceeding. Specific issues for discussion may be raised by the RTOs, 
stakeholders, or in response to FERC orders or directives. 

Stakeholders generally provide input to the RTO boards of directors in 
three ways--written communications, oral discussions, and votes-- 
although each RTO has a unique process for soliciting this input, as 
shown in table 3. RTO officials told us that these processes were 
developed after extensive negotiations with stakeholders when each RTO 
was formed. To ensure stakeholder input reflects a range of interests, 
five of the six RTOs we reviewed group stakeholders with common 
interests, such as electric distribution companies, transmission 
owners, and end users. All six of the RTOs we reviewed involve state 
regulators in their decision-making process, either formally as a 
unique stakeholder group or informally as participants who attend 
stakeholder meetings. Though state regulators are not prohibited from 
voting in stakeholder meetings, most have chosen to participate 
formally in the process but not vote.[Footnote 23] Additionally, in 
several RTO areas, state regulators have formed organizations to 
collectively represent their interests and advise the RTO. For 
instance, state regulators in the Midwest ISO formed the Organization 
of MISO States to discuss what decisions the RTO should make and 
participate in stakeholder meetings. 

Table 3: RTO Processes for Acquiring Stakeholder Input: 

RTO: Stakeholder groups; 
California ISO: Not applicable; California ISO has identified sectors, 
but any interested party is considered a stakeholder and is able to 
participate in meetings; 
ISO New England: Transmission; Generation; Suppliers; End users; 
Publicly owned entity; Alternative resources; 
Midwest ISO: Vertically integrated transmission owner and stand-alone 
transmission companies; Independent power producer/exempt wholesale 
generator; Power marketer; Eligible end use customers; Municipals/ 
cooperatives/transmission dependent utilities; Environmental advocates; 
State regulatory authorities; Public consumer advocate; Coordinating 
members; 
New York ISO: Transmission owners; Generation owners; Other suppliers; 
End use consumers; Public power and environmental stakeholders; New 
York Public Service Commission[A]; 
PJM: Transmission owners; Generation owners; Other suppliers; End use 
customers; Electric distribution companies; 
Southwest Power Pool: Investor owned utilities; Independent power 
producers/marketers; Large retail customer; Small retail customer; 
Cooperatives; Municipals; Alternative power/public interest 
stakeholders; State/federal power agencies. 

RTO: Required stakeholder representation on the primary committee; 
California ISO: Not applicable; 
ISO New England: Stakeholders from each stakeholder group; 
Midwest ISO: Elected representation (Two participants and one or two 
alternates) from each stakeholder group; 
New York ISO: Representation from each member; 
PJM: Representation from each stakeholder group; 
Southwest Power Pool: Representation from each member. 

RTO: Required stakeholder representation on the budget subcommittee; 
California ISO: Not applicable; California ISO has a formal process for 
stakeholder review of the budget that is open to any interested 
stakeholder. It does not have a formal budget subcommittee; 
ISO New England: Open to any interested stakeholder; 
Midwest ISO: Open to any interested stakeholder, typically includes 
representation from each stakeholder group; 
New York ISO: Open to any interested stakeholder; 
PJM: Two members elected by each of the five stakeholder groups and two 
members of the board; 
Southwest Power Pool: Two RTO directors, two representatives of the non-
transmission-owning group, and two representatives of the transmission 
owners. 

RTO: Process through which comments are shared with the board; 
California ISO: Proposals to the board include a matrix of stakeholder 
comments on the proposal; Stakeholders can speak directly with the 
board during board meetings, which are open to the public; 
ISO New England: Board receives information on stakeholder votes on the 
budget and other decisions; Stakeholders can submit documents directly 
to the board; Board meets with stakeholders regularly; 
Midwest ISO: Board receives information on stakeholder votes on the 
budget and other decisions; Stakeholders can submit documents directly 
to the board; Board meets with stakeholders regularly; Stakeholders 
have the opportunity to speak directly with the board during board 
meetings; 
New York ISO: Board receives information on stakeholder votes on the 
budget and other decisions; Stakeholders can submit documents directly 
to the board; Representatives from the liaison committee, composed of 
representatives from each stakeholder group, meet with the board after 
board meetings; Board meets with stakeholders regularly; Stakeholders 
with a minority opinion can appeal a decision with the board; 
PJM: A record of stakeholder votes and summary of comments is provided 
to the board of directors; At least two board members attend each 
meeting of PJM's highest committee; Any PJM member can provide comments 
to the board in writing; Board meets with a liaison committee composed 
of representatives of each sector at least once quarterly to discuss 
current topics; Board holds general sessions with all PJM members for 
panel discussions of current topics twice annually; 
Southwest Power Pool: Board receives information on stakeholder votes 
on the budget and other decisions; Stakeholders in the primary 
committee meet with the board and provide feedback on behalf of 
stakeholders; Stakeholders have opportunity to speak directly with the 
board during board meetings. 

RTO: Voting requirement to approve a decision/budget at primary 
committee; 
California ISO: Not applicable; 
SO New England: Two-thirds support to pass; each stakeholder group has 
a weighted vote; 
Midwest ISO: Simple majority support to pass; each stakeholder group 
has a weighted vote; New York ISO: 58 percent support to pass; each 
stakeholder group has a weighted vote; 
PJM: Two-thirds support to pass; each stakeholder group has a weighted 
vote; 
Southwest Power Pool: 66 percent support to pass;[B] votes are weighted 
among two groups: transmission owners and transmission users. 

RTO: Stakeholder input is advisory to the RTOs' board; 
California ISO: Yes; 
ISO New England: Yes; 
Midwest ISO: Yes; 
New York ISO: Yes[C]; 
PJM: Yes[D]; 
Southwest Power Pool: Yes[E]. 

Source: GAO analysis of data from RTOs. 

Note: This table describes the RTO process for acquiring stakeholder 
input on a variety of decisions. As required by FERC Order 890, each 
RTO must also have an open and transparent transmission planning 
process in which, according to RTO officials, stakeholders play a 
critical role. Each RTO uses a different structure to achieve this 
goal. 

[A] In New York ISO, the New York Public Service Commission 
participates in stakeholder meetings but does not vote. 

[B] In Southwest Power Pool, the primary committee does not vote on the 
budget. The finance committee votes by simple majority to recommend the 
budget to the board. 

[C] In New York ISO, Section 205 filings with FERC require an 
affirmative stakeholder vote except in exigent circumstances since New 
York ISO operates under a shared governance agreement. 

[D] In PJM, a stakeholder vote is required in order to make changes to 
its structure and governance. 

[E] In Southwest Power Pool, some stakeholder committees that report to 
the board have been delegated certain decision-making authority. 

[End of table] 

In general, stakeholders participate in the RTO decision-making process 
through a primary committee that reports to the board of directors and 
a range of lower-level committees and working groups that report to the 
primary committee.[Footnote 24] Lower-level committees and working 
groups tend to focus on narrow subjects or specific initiatives such as 
development of specific markets or proposed changes to existing rules, 
and lower-level committees often involve stakeholders with expertise in 
the specific subject matter. The primary committee and lower-level 
committees and working groups hold regular or episodic meetings that 
stakeholders participate in. These meetings are open to participation 
by any stakeholder with an interest in attending. As shown above, 
stakeholders representing many perspectives, from generators to groups 
representing consumers, participate. Because of the numerous, 
simultaneous matters under consideration, there can be many meetings 
potentially relevant to stakeholders. Subjects discussed and analyzed 
in lower-level committee and working group meetings are eventually 
raised for discussion at the primary committee meeting, where a vote is 
taken about whether to recommend a decision be pursued by the board of 
directors. (See fig. 8 for an example of the Midwest ISO's committee 
structure. Midwest ISO's primary committee is called the Advisory 
Committee.) 

Figure 8: Midwest ISO's Committee Structure: 

[See PDF for image] 

This figure is an organizational chart depicting the Midwest ISO's 
Committee Structure as follows: 

Midwest ISO Board of Directors; 
* Transmission Owners' Committee; 
- Vertically integrated transmission owners; 
- Midwest stand-alone transmission companies; 
* Alternate Dispute Resolution Committee; 
* Advisory Committee; 
- Tariff and Business Practices Subcommittee; 
- Stakeholder Governance Working Group; 
- Finance Subcommittee; 
- Market Subcommittee, including: Credit Practices Working Group; 
Demand Response Working Group; Market Settlements Working Group; 
Revenue Sufficiency Guarantee Task Force; Supply Adequacy Working 
Group; 
- Planning Advisory Committee, including: Planning Subcommittee; 
- Reliability Subcommittee, including: Available Flowgate Capacity 
Working Group; Operations Planning Working Group; Operations Working 
Group; Emergency Preparedness/Power System Restoration Working Group; 
System Operator Training Group; 
- Steering Committee, including: Data Transparency Working Group; 
- Energy and Ancillary Services Market Readiness Task Force. 

Source: Midwest ISO. 

[End of figure] 

RTO staff may facilitate discussions within the primary committee, as 
well as lower-level committees and working groups, and may also prepare 
analyses to help stakeholders understand how a decision might affect 
them. For example, as agreed to when its RTO status was approved, 
Southwest Power Pool must develop a cost-benefit analysis before making 
the decision to implement a new market rather than relying on cost- 
based pricing of a service. Other RTO officials told us that although 
they may develop formal cost-benefit analyses for some major decisions, 
such as changes to key market rules, the stakeholder process is a key 
way in which the cost and benefits of a decision are discussed. 

Most RTOs have a specific lower-level committee to review and analyze 
RTO budgets that contain information about proposed expenses. According 
to RTO officials, RTOs and stakeholders discuss and jointly determine 
organizational priorities, which influence the RTO's preparation of a 
draft budget. Stakeholders serving on the budget committee review the 
budget's proposed expenses and provide recommendations. Discussion of 
the budget is then taken up by the primary stakeholder committee, which 
then votes whether to recommend to the board that the budget be 
adopted.[Footnote 25] The composition of the subcommittee that 
initially reviews the budget differs among the six RTOs. For example, 
PJM's budget committee consists of equal representation from each 
formal stakeholder group plus two members of the independent board. ISO 
New England's budget committee is open to participation by any 
stakeholder. 

Stakeholders Value the Opportunity for Discussion with RTOs, but Some 
Believe Inadequate Emphasis Is Placed on Consumer Prices: 

Most stakeholders we spoke with in the two RTOs we visited--ISO New 
England and Midwest ISO--valued the opportunity for discussion with 
their respective RTOs and believed that RTOs facilitate an open and 
democratic process that focuses on reaching consensus among 
stakeholders. However, most stakeholders in these two RTOs found the 
process resource intensive, specifically the stakeholder meetings, 
which require staff time and travel costs. RTOs may carry out hundreds 
of stakeholder meetings annually, as shown in table 4. 

Table 4: Estimated Stakeholder Meetings by RTO, Calendar Year 2007: 

RTO: Number of Stakeholder Meetings; 
California ISO: 57[A]; 
ISO New England: 184[B]; 
Midwest ISO: 611; 
New York ISO: 280; 
PJM: 330; 
Southwest Power Pool: 202[C]. 

Sources: California ISO, ISO New England, Midwest ISO, New York ISO, 
PJM, and Southwest Power Pool. 

[A] California ISO's estimated number of stakeholder meetings excludes 
meetings conducted for the start-up of the Market Redesign and 
Technology Update, those hosted by California ISO departments, and 
lower-level committee and working group meetings. 

[B] ISO New England's estimated number of stakeholder meetings excludes 
lower-level committee and working group meetings related to the 
regional system plan process. 

[C] Southwest Power Pool's estimated number of stakeholder meetings 
includes only meetings posted to its Web site that require an agenda 
and minutes. 

[End of table] 

Stakeholders must prepare for meetings by reviewing documentation and 
preparing comments, and the ability of stakeholders we spoke with to do 
so varied significantly. Individual stakeholders in the two RTO regions 
we visited estimated they devoted a range of time--from less than one- 
half of a full-time equivalent to 5 full-time equivalents--to 
stakeholder involvement annually. In some cases, stakeholders told us 
they are not able to attend all meetings they would like to due to 
resource constraints. For example, stakeholders from ISO New England's 
public power sector told us they often have to rely on other 
stakeholders to attend meetings in their place, because they lack the 
resources to participate themselves. Many stakeholders told us they 
believe the level of their participation determines their influence on 
RTO decisions. 

In the two RTOs we visited, many stakeholders representing and serving 
consumers, such as consumer advocates and state commissioners, were 
concerned that RTOs do not place adequate emphasis on assessing the 
implications on consumer electricity prices of decisions, such as 
whether to build new transmission lines, when to create markets for 
services in lieu of charging cost-based rates, and reliability 
decisions. Several of these stakeholders believed that RTOs 
overemphasize ensuring reliability without full consideration as to 
whether lower-cost options are available. For example, some ISO New 
England stakeholders we spoke to believed the RTO was overly 
conservative when determining whether noncompetitive generators were 
needed for reliability. They believed that, as a result, the RTO 
entered into unnecessary and costly contracts to keep these inefficient 
generators running. They observed that this could lead to higher 
consumer electricity prices, which they did not believe were justified, 
since they did not agree the generators were needed to ensure 
electricity was delivered reliably. Moreover, one stakeholder we spoke 
to was concerned that the cost of operating these generators, which may 
benefit only certain local areas, were unfairly borne by consumers 
outside those local areas. Officials from ISO New England acknowledged 
that there can be trade-offs between reliability and costs, but said 
transmission-planning efforts and their new capacity market are 
effective in keeping payments for reliability as low as possible. They 
and other RTO officials explained that fulfilling their mission of 
ensuring reliability and efficient markets will minimize consumer 
prices in the long run. A number of stakeholders representing and 
serving consumers in these two regions were concerned, however, that 
the RTOs do not conduct enough cost-benefit analyses of how decisions 
may affect electricity prices. Others felt they had inadequate access 
to data and resources to conduct such analyses themselves. Some RTO 
officials told us that while they always consider the costs and 
benefits of a decision before making it, formal cost-benefit analysis 
may not always be practical, because it is difficult to estimate the 
potential impact of a decision on electricity prices, how benefits and 
costs could change over time, the appropriate assumptions to be made, 
and how different stakeholders are affected. They noted that individual 
stakeholders already give much consideration to the costs and benefits 
of a given decision when discussing it during stakeholder meetings. 

There was disagreement among stakeholders in ISO New England and 
Midwest ISO about which groups have, and should have, more influence 
with RTOs; however, many stakeholders agreed that participating in 
stakeholder meetings and, in particular, participating in lower-level 
committees and working groups, provided the best opportunity to 
influence RTOs' proposed expenses and decisions that may affect 
electricity prices. Although most stakeholders we spoke with thought 
ISO New England and Midwest ISO worked hard to solicit comments from 
all stakeholders, many believed that when making decisions, the RTOs 
deferred more to certain stakeholders and that because RTOs were 
created through the voluntary agreement of the transmission owners, the 
RTOs were more likely to defer to their interests than to others'. 
Other stakeholder groups we spoke with in ISO New England and Midwest 
ISO commented that state regulators have a large influence on the RTOs' 
decisions. A number of state public utility commission officials 
disagreed with this view. In particular, one state regulator stated 
that because state regulators are charged with protecting the public 
interest, their opinions should carry greater weight than those of 
participants whose interests are primarily profit-oriented. 

The Frequency of FERC's Review of Proposed RTO Expenses Varies: 

The frequency of FERC's review of proposed RTO expenses varies, with 
reviews of certain expenses not being conducted for years at a time. 
FERC's review of proposed expenses occurs when it conducts a proceeding 
to evaluate whether the rate an RTO charges customers to recover these 
expenses is just and reasonable and not unduly discriminatory or 
preferential.[Footnote 26] Because of variation in the manner and 
frequency with which rate proceedings are conducted, FERC's 
consideration of proposed RTO expenses can be infrequent.[Footnote 27] 
For example, in 2001, FERC conditionally approved Midwest ISO's rate 
for recovering expenses associated with administering its tariff and 
ensuring reliability. Because Midwest ISO has not since asked to change 
its rate for recovering these expenses, FERC has not reviewed these 
expenses since 2001.[Footnote 28] FERC officials explained that more 
frequent review of proposed RTO expenses is not necessary because RTO 
expenses and decisions undergo much scrutiny during the RTO stakeholder 
process. Moreover, according to these officials, stakeholders are in 
the best position to know whether RTO expenses are prudent and 
reasonable. As a regulator, FERC may initiate a new rate proceeding if 
it believes an RTO's rates are no longer just and reasonable. While, as 
FERC points out, stakeholder comments and complaints are an important 
piece of FERC's consideration, more frequent review of proposed 
expenses could also aid FERC in determining whether a rate remains just 
and reasonable. Table 5 shows when each RTO's rate for recovering 
expenses was last approved. 

Table 5: Last FERC Decision to Approve Rates to Recover Expenses: 

RTO: California ISO; 
Date of last FERC approval of rates: 2005[A]. 

RTO: ISO New England; 
Date of last FERC approval of rates: 2007. 

RTO: Midwest ISO; 
Date of last FERC approval of rates: 2001 and 2004[B]. 

RTO: New York ISO; 
Date of last FERC approval of rates: 2004. 

RTO: PJM; 
Date of last FERC approval of rates: 2006. 

RTO: Southwest Power Pool; 
Date of last FERC approval of rates: 1999[C[. 

Source: GAO analysis of FERC information. 

Note: FERC allows RTOs and other utilities to bill customers using a 
stated rate or a formula rate. With a stated rate, the RTO cannot 
exceed a fixed rate of x cents per MWh. With a formula rate, FERC 
approves a multipart formula for recovering expenses. Once approved, 
the formula itself does not change, although the expenses inputted into 
that formula and therefore the rate charged to customers may vary. 
Midwest ISO, New York ISO, California ISO, and Southwest Power Pool use 
formula rates. ISO New England and PJM use stated rates. 

[A] California ISO's rates were approved by FERC in 2005 for the years 
2004 through 2006. In 2006 and 2007 FERC reviewed and accepted changes 
to the tariff that extended the same rates through 2008. California ISO 
has subsequently filed rate changes to be effective upon implementation 
of its FERC-approved Market Redesign and Technology Upgrade program, 
which is expected to occur in 2009. These changes have not yet been 
approved by FERC. 

[B] Midwest ISO's rate for recovering tariff administration and 
reliability expenses was conditionally approved in 2001. Its rate for 
recovering expenses associated with operating markets for energy and 
other services was approved in 2004. 

[C] Southwest Power Pool's formula rate for its tariff administration 
charge was last approved in 1999, before Southwest Power Pool became an 
RTO. In 2004, FERC reviewed and accepted revisions to Southwest Power 
Pool's nonrate terms and conditions. On July 31, 2008, SPP filed a 
Section 205 revised tariff request with FERC in order to increase the 
rate cap for its administration charge. 

[End of table] 

RTOs annually develop budgets that contain extensive information on 
proposed expenses; however, FERC's use of RTO budgets as a tool in 
reviewing proposed RTO expenses varies. For example, ISO New England 
agreed with its stakeholders to submit operational and capital budgets 
to FERC for annual approval. Southwest Power Pool submits annual copies 
of its operating and capital budgets for informational purposes, rather 
than for FERC approval. The other RTOs either do not submit budgets or 
do so infrequently, despite the fact that these budgets could provide 
FERC with potentially valuable information about proposed RTO expenses 
that could help it in ensuring the rates RTOs charge customers are just 
and reasonable. For example, FERC could use such information to 
regularly benchmark RTO spending on key categories, such as market 
oversight or capital investments. (Table 6 outlines the frequency with 
which RTOs submit budgets to FERC for review.) FERC officials pointed 
out that FERC staff sometimes attend stakeholder meetings, including 
discussions about the budget, to observe what concerns stakeholders 
raise. They also noted that RTOs post their budgets on their Web sites 
annually, allowing FERC and the public to view them if so desired. 

Table 6: RTO Budget Submissions to FERC: 

RTO: California ISO: 
Budget submission to FERC: Operational: Not currently[A]; 
Budget submission to FERC: Capital: Not currently[A]. 

RTO: ISO New England: 
Budget submission to FERC: Operational: Annually submitted to FERC for 
approval; 
Budget submission to FERC: Capital: Annually submitted to FERC for 
approval with quarterly updates. 

RTO: Midwest ISO; 
Budget submission to FERC: Operational: No; 
Budget submission to FERC: Capital: No. 

RTO: New York ISO; 
Budget submission to FERC: Operational: No; 
Budget submission to FERC: Capital: No. 

RTO: PJM; 
Budget submission to FERC: Operational: No; 
Budget submission to FERC: Capital: No. 

RTO: Southwest Power Pool; 
Budget submission to FERC: Operational: Annually but for informational 
purposes; 
Budget submission to FERC: Capital: Annually but for informational 
purposes. 

Source: FERC and RTOs. 

[A] California ISO last submitted its revenue requirement for approval 
by FERC for the year 2004. A settlement agreement approved by FERC in 
2005 provided that the California ISO need not make an annual filing 
unless its revenue requirement exceeded the cap specified in the 
agreement. The settlement agreement expired at the end of 2006. The 
California ISO filed in 2006 and again in 2007 to extend the provisions 
that allow it to defer filing its revenue requirement. 

[End of table] 

Some representatives of stakeholder groups including public utility 
commissions, consumer groups, and the publicly owned sector expressed 
concerns over FERC's infrequent review of budgets or lack of 
independent analysis of proposed RTO expenses. They expressed concern 
that FERC deferred too much to the stakeholder process within the RTOs, 
assuming stakeholders had adequately resolved all concerns. These 
stakeholders were concerned that without more scrutiny of proposed 
expenses, FERC could not be sure that the RTOs were as cost-effective 
as possible. We found that RTO expenses may change over time, and some-
-such as expenses for outside consultants--may decrease between the 
times FERC reviews the rates. Furthermore, without more consistency in 
how FERC reviews proposed expenses, customers may not fully benefit 
from potential improvements or efficiencies RTOs achieve. For example, 
for the 2008 Midwest ISO budget, expenses as approved by the finance 
subcommittee and the board of directors for outside services decreased 
by 24.4 percent, while its net operating expense increased by 1.2 
percent. The total cost of salaries and benefits increased by 10 
percent, offsetting some of the increased efficiency in the area of 
outside services. In the stakeholder process for the 2007 budget, the 
finance subcommittee expressed concerns about the continued increase in 
staffing levels and how that need was determined. They recommended that 
Midwest ISO develop financial metrics to evaluate and compare and 
contrast Midwest ISO's financial results. Since Midwest ISO's proposed 
expenses were not regularly reviewed by FERC, FERC may have missed an 
opportunity to determine whether Midwest ISO's salaries were reasonable 
and ensure that Midwest ISO customers benefited from lower outside 
service expenses.[Footnote 29] More broadly, without regular, recurring 
analysis of RTO expenses, such as through review of RTO budgets, it is 
not clear that FERC is as well positioned as it could be to know 
whether certain expenses are reasonable and RTOs are as cost-effective 
as possible. Such knowledge could supplement comments from stakeholders 
and help FERC determine whether rates remain just and reasonable or 
when a new rate case should be initiated. 

FERC Does Not Regularly Review or Assess Actual RTO Expenses: 

FERC does not routinely review or assess the accuracy or reasonableness 
of expenses RTOs report annually using the Form No. 1. FERC officials 
told us they use the financial information in the Form No. 1 to carry 
out FERC's responsibilities and post this information to their Web site 
for use by public utility customers, state commissions, and the public 
so that they can assess the reasonableness of electric rates. However, 
during the course of our work, FERC officials told us they did not 
routinely audit or review the Form No. 1s for accuracy or completeness. 
When we began our work, FERC had not audited any RTO FERC Form No. 1 
filings for accuracy or completeness, although in 2004 it performed 
some limited review of the Form No. 1s during the course of other 
audits. In May 2008, FERC initiated an audit of Midwest ISO that 
includes a more in-depth examination of its Form No. 1. FERC officials 
told us it is the RTOs' responsibility to ensure that the FERC Form No. 
1 filings are accurate and complete and said that it requires public 
accounting firms to attest that they have audited RTOs' balance sheets, 
statements of income, retained earnings, and cash flows contained in 
their Form No. 1s in conformity with FERC's Uniform System of Accounts 
requirements. Auditor opinions confirm that CPAs audit the above 
statements in the Form No. 1 but may not audit all supporting 
schedules. 

Without more regular audits and review of actual expense information 
for accuracy, FERC may be at risk of unknowingly using and providing to 
the public inaccurate and incomplete RTO financial data, limiting the 
effectiveness of the Form No. 1 as a tool for determining whether rates 
are just and reasonable. For example, during the course of our audit 
work, we noted a significant reporting error on Southwest Power Pool's 
2006 Form No. 1 filing. In 2006, Southwest Power Pool reported $88 
million in rent and $175 million in maintenance of general plant 
expenses; however, we noted actual rent and maintenance of general 
plant expenses were $830,000 and $440,000, respectively. FERC officials 
said that in 2006 several RTOs experienced problems using FERC's 
software program to file their Form No. 1s, due to an unforeseen delay 
in implementing software updates. To correct the errors, a revised 
schedule was added to Southwest Power Pool's 2006 Form No. 1 filing. 
However, maintenance of general plant expenses was still overstated in 
the revised schedule by approximately $3 million, and the revised 
schedule was not clearly referenced by the original schedule. FERC said 
the error did not affect electricity rates; however, the overstated 
expense information remained posted on FERC's Web site for over a year, 
where public utility customers, state commissions, the public, and 
other parties that may be interested in reviewing RTOs' expenses could 
access it. In August 2008, Southwest Power Pool submitted a revised 
FERC Form No. 1 that corrects the error. Furthermore, according to FERC 
officials, the Office of Enforcement is taking steps to incorporate a 
system of electronic data validation checks into the FERC Form No. 1 
submission software to help ensure the accuracy of the FERC Form No. 1 
filings before they are submitted. FERC anticipates having the 
validation checks in place for the 2008 FERC Form No. 1 submission year 
and told us that once the checks are implemented, an error like the one 
identified at Southwest Power Pool can be corrected prior to the entity 
submitting its FERC Form No. 1 filing. Because these checks have not 
yet been implemented, we cannot review their effectiveness. We believe 
that while they will likely help identify and correct some reporting 
errors, they do not constitute the comprehensive review of the Form No. 
1s for accuracy and completeness that FERC staff could perform through 
audits or other review. 

FERC does not routinely review RTOs' reported expenses to ensure that 
they are reasonable, noting that Form No. 1 information on expenses is 
made public and interested parties can file a complaint about their 
concerns. FERC officials from the Office of Energy Market Regulation 
observed that the Form No. 1 might sometimes be used to detect 
potentially unreasonable expenses but told us they do not analyze them 
due to limited resources. Moreover, although FERC compared expenses 
across RTOs in 2004 as a means to estimate the potential expense 
involved in creating new RTOs, FERC officials do not regularly compare 
expenses across RTOs or create expense benchmarks to use as an 
analytical tool in evaluating just and reasonable rates or as a way of 
determining whether efficiencies realized by one RTO could be applied 
to another.[Footnote 30] FERC and RTO officials said that the varied 
nature of RTO functions would make regular comparison of actual RTO 
expenses challenging and of limited value. Several stakeholders we 
spoke with, including a former RTO executive, disagreed, observing that 
comparisons among RTOs could help raise questions about the 
appropriateness of expenses. Without reviewing actual RTO expenses for 
reasonableness, FERC may not be as well positioned as it could be to 
ensure the rates RTOs charge to recover their expenses are just and 
reasonable and that RTO funds were spent according to how FERC and the 
stakeholders approved them to be. 

FERC Relies on Stakeholders to Raise Concerns over RTO Expenses and 
Decisions: 

FERC relies heavily on stakeholders to raise concerns about RTO 
expenses and other decisions with the potential to affect electricity 
prices. FERC officials acknowledged that the process through which RTO 
stakeholders review information on proposed expenses contained in RTO 
budgets is integral to identifying imprudent and unreasonable expenses 
between RTO rate cases. Parties who disagree with RTO expenses can file 
comments when an RTO's rate for recovering these expenses is being 
evaluated at FERC during rate-setting proceedings. In one instance, in 
November 2005, the Attorneys General of Connecticut and Massachusetts 
submitted comments to FERC about ISO New England's proposed 2006 
budget, contesting executive salaries that they believed were 
unnecessarily high. FERC found the proposed salary expenses to be just 
and reasonable after reviewing the entire record in the proceeding, 
including all comments and ISO New England's comments that surveys and 
benchmarks showed the salaries were competitive. However, FERC did not 
perform any independent analysis of ISO New England salaries or review 
the surveys or benchmarks ISO New England cited.[Footnote 31] FERC also 
did not conduct comparisons of salaries across RTOs, although FERC 
officials said that had this information been introduced into the 
record, it would have considered it. As with stakeholder review of 
proposed expenses, FERC officials told us the Form No. 1 is a tool to 
provide stakeholders with ready access to data needed to assess the 
prudence of actual RTO expenses, and that its information is key to 
stakeholders knowing when a new rate case may be needed. 

FERC also explained that stakeholders can file a complaint that rates 
are not just and reasonable at any time. [Footnote 32] However, several 
stakeholders told us that because FERC places the burden of proof on 
the complaining party, it is difficult and resource intensive to file a 
complaint. These stakeholders told us that they typically lack the 
staff and resources to file a complaint and said that it is difficult 
to obtain the data and conduct the analysis necessary to support it. 
For example, one state regulator noted that the data needed to show 
that expenses are not just and reasonable is typically proprietary and 
that such complaints are difficult to win, since the burden of proof is 
high. FERC officials confirmed that they have heard over the years that 
it can be challenging to make complaints and win. They said consumer 
groups sometimes felt they were at a disadvantage compared to 
transmission owners and generators because they have fewer resources, 
including staffing and funding, to file and support complaints. FERC 
officials also noted that if an evidentiary hearing was deemed 
necessary, their staff might provide some analytical assistance. 

As in its reviews of expenses, FERC also places much emphasis on the 
stakeholder process when reviewing RTO decisions with the potential to 
affect electricity prices, and FERC offers stakeholders the opportunity 
to provide additional evidence for its consideration prior to making a 
final decision. For example, in 2006, FERC conducted a proceeding 
related to a proposed PJM decision to develop a capacity market--a 
market designed to attract new generation and other resources to ensure 
PJM can meet future electricity needs. PJM's proposal resulted from 
years of work and numerous stakeholder meetings. Additionally, PJM and 
numerous parties submitted thousands of pages of comments in support 
and against the proposed decision, which FERC evaluated. FERC issued a 
final order on this proceeding in December 2006. In May 2008, numerous 
stakeholders, including public utility commissions and consumer 
advocacy groups, filed a complaint with FERC alleging the initial model 
PJM used for establishing the price of capacity produced excessively 
high prices and did not deliver commensurate benefits. Complainants are 
asking for rate relief, which they estimate to be about $12 billion. 
The Maryland Office of the People's Counsel calculates that excess 
charges to Maryland residential customers will average $570 over 3 
years. FERC evaluated the merits of this complaint and supporting 
documents. On September 18, 2008, it dismissed the complaint but 
granted a request for a technical conference to determine if further 
action would better achieve this market's goals. 

Experts, Industry Participants, and FERC Lack Consensus on the Benefits 
of RTOs: 

Experts, industry participants, and FERC lack consensus about whether 
RTOs have provided net benefits to consumers. Many key experts and 
industry participants agree that RTOs can provide certain benefits, 
such as more efficient management of the transmission grid and improved 
access by independent generators. However, there is some disagreement 
about whether RTOs' access to additional lower-cost generating 
resources has led to electricity prices for consumers that are lower 
than they otherwise would have been. Furthermore, experts and industry 
participants are divided on the benefits of RTO markets and their 
effect on consumer electricity prices. Some critics of RTO markets 
believe that RTO markets have not fully achieved anticipated benefits 
and contribute to higher consumer electricity prices, while proponents 
believe RTO markets have kept prices lower than they otherwise would 
have been. Some RTOs have developed assessments to demonstrate the 
benefits they have provided to their regions. FERC officials share the 
view that RTOs have resulted in benefits to the economy, such as new 
efficiencies in operating the regional transmission grid, but FERC has 
not conducted an empirical analysis to measure whether these benefits 
were realized or developed a comprehensive set of publicly available, 
standardized measures that can be used to evaluate RTO performance. 

Many Agree That RTOs Can Improve Management of the Transmission Grid 
and Access: 

Many industry participants and experts agree that RTOs provide 
opportunities for more efficient management of the transmission grid 
and can improve access by independent generators. They believe that 
because RTOs integrate multiple transmission systems into a larger 
service area, they have broader knowledge of the grid's transmission 
capacity and wider perspective on events that can affect reliability, 
allowing them to more efficiently manage the grid. For example, Midwest 
ISO now centrally controls operation of a vast transmission network 
spanning 15 states that was once overseen by 24 different system 
operators who had to work together to address any reliability problems 
such as the unexpected loss of a key transmission line or power plant. 
Some also believe that because RTOs integrate multiple transmission 
systems into a larger service area, they keep electricity buyers and 
sellers from paying multiple fees for each transmission network they 
use--previously a disincentive to trade power across multiple 
utilities' transmission systems. In addition to the benefits of 
centralized management of the transmission grid, many experts and 
industry participants believe RTOs have improved independent 
generators' access by reducing discrimination. They note that because 
RTOs operate the grid independently and do not own generation or 
transmission resources themselves, they have no incentive to 
discriminate when providing transmission access. According to a 
representative of independent developers of new generation we spoke to, 
this improved access has allowed new generators to more easily connect 
to and use the transmission system. A representative of buyers of 
power, on the other hand, told us this improved access has allowed 
buyers of power opportunities to purchase electricity from new 
suppliers, although this representative questioned whether the prices 
they receive for that electricity are better. Despite much agreement 
that RTOs have provided opportunities for more efficient management of 
the transmission grid and improved access, some industry participants 
we spoke with believed RTOs were not the only way to provide these 
benefits. They question whether similar benefits could be achieved 
using other mechanisms, such as power pools--groups of utilities that 
have entered into agreements to coordinate electricity supply, like 
those that have existed along the East Coast for more than 30 years. 

Many Agree That RTOs Provide Opportunities to Lower Costs of Producing 
Electricity, but Some Question whether This Improves Consumer Prices: 

Many experts and industry participants agree that RTOs are better 
positioned than individual utilities to make use of lower-cost 
generators more frequently, although they do not agree whether this has 
resulted in electricity prices for consumers that are lower than they 
otherwise would have been.[Footnote 33] By overseeing a region formerly 
run by many individual utilities, RTOs have more generators at their 
disposal than the individual utilities did. Because RTOs generally use 
the generators with the lowest bid first--according to some, the least 
costly and most fuel efficient--they may be able to more efficiently 
meet requirements for electricity reserves, lower the cost of producing 
electricity, and use fuel more efficiently. However, some industry 
participants we spoke with questioned whether this has kept electricity 
prices for consumers lower than they otherwise would have been. They 
noted that generator bids may not always reflect their costs of 
production and that in some cases, lower costs of production have led 
to higher profits for generators rather than lower consumer prices. 

Experts and Industry Participants Are Divided on the Benefits of RTO 
Markets and Their Effect on Consumer Electricity Prices, Generator 
Efficiency, and Infrastructure Investment: 

Experts and industry participants are divided on whether RTO efforts to 
create and oversee markets have lowered electricity prices and led to 
other benefits, such as improved generator efficiency and more 
investment in electricity infrastructure. Studies of restructuring draw 
differing conclusions. 

Experts and Industry Participants Are Divided on RTOs' Influence on 
Electricity Prices: 

Experts and industry participants debate how RTO markets have 
influenced the prices consumers pay for electricity. Critics of RTO 
markets believe these markets have not fully achieved anticipated 
benefits and have contributed to the higher prices for electricity seen 
by consumers, because markets are expensive to establish and operate, 
and as currently designed, produce higher wholesale prices than would 
otherwise occur. RTO markets use multiple types of generators--coal, 
nuclear, natural gas, and others--in satisfying consumer demand, and 
the different costs of fuels for these generators, among other factors, 
contribute to different costs of electricity production. RTO markets 
select the smallest amount of generating resources needed each day to 
provide reliable service. To do so, these markets generally rank and 
accept generator bids in the market in order of lowest to highest and 
pay generators, regardless of their costs of production or fuel, the 
price bid by the last generating unit needed to satisfy demand. Critics 
believe this pricing approach reduces the benefits for consumers of 
using varied types of generators, because low-cost generators, like 
nuclear and coal plants, receive the same price as higher-cost 
generators, like natural gas plants, when higher cost generators are 
needed to satisfy demand. Supporters of RTOs believe this pricing 
approach, by rewarding low-cost generators, promotes efficiency and 
provides an incentive for new low-cost generators to enter the market, 
leading to lower prices in the long run than otherwise would have been 
the case. They note that price transparency in RTO markets is valuable 
and can signal profit-making opportunities for potential new entrants. 
They believe that this, coupled with improved access to the grid, can 
encourage market entry by, among others, developers of renewable energy 
sources, such as wind power. Proponents of RTO markets observe that 
price transparency may also encourage demand response--consumers 
lowering electricity usage in response to price signals--which can lead 
to lower, less volatile prices. RTO officials explained that while RTO 
markets establish wholesale prices for electricity traded in them, a 
number of other factors also influence the price consumers ultimately 
pay. Furthermore, much electricity is supplied from sources outside RTO 
markets, for example, when utilities use their own generators to self- 
supply or when two parties directly negotiate a transaction with each 
other. However, critics believe that the pricing approach used by RTO 
markets has led to higher prices for directly negotiated contracts as 
well, because low-cost generators recognize that they can often receive 
the price bid by higher-cost generators in the RTO marketplace. 

A state-by-state analysis of electricity prices reveals differences 
between RTO and non-RTO regions that have likely led to concerns about 
the impact of RTO markets on electricity prices. We considered retail 
electricity prices in four regions of the country: (1) original RTO 
states--states that joined an RTO in 1999 or earlier and were 
historically in a power pool, (2) new RTO states--states in an RTO 
region after 1999, (3) non-RTO states--states outside RTO regions, and 
(4) California.[Footnote 34] As shown in figure 9, 11 of the 17 states 
with above-average retail electricity prices are in the original RTO 
group. California also had above average prices in 2007. 

Figure 9: Retail Electricity Prices by State, 2007: 

[See PDF for image] 

This figure is a multiple vertical bar graph depicting average 
electricity price, cents per KWh. The average U.S. electricity price is 
9.14 cents per KWh. 

Idaho: 
Non-RTO: 5.06. 

West Virginia: 
New RTO: 5.27. 

Wyoming: 
Non-RTO: 5.27. 

Kentucky: 
Non-RTO: 5.76. 

Nebraska: 
Non-RTO: 6.21. 

North Dakota: 
New RTO: 6.41. 

Washington: 
Non-RTO: 6.41. 

Utah: 
Non-RTO: 6.42. 

Indiana: 
New RTO: 6.48. 

Missouri: 
New RTO: 6.48. 

Iowa: 
New RTO: 6.8. 

South Dakota: 
Non-RTO: 6.84. 

Kansas:	
New RTO: 6.88. 

Arkansas: 
Non-RTO: 6.92. 

Oregon:	
Non-RTO: 7. 

Virginia: 
New RTO: 7.1. 

Tennessee: 
Non-RTO: 7.1. 

South Carolina:	
Non-RTO: 7.16. 

Oklahoma: 
New RTO: 7.29. 

Minnesota: 
New RTO: 7.36. 

New Mexico: 
Non-RTO: 7.39. 

Montana: 
Non-RTO: 7.51. 

Alabama: 
Non-RTO: 7.52. 

Colorado: 
Non-RTO: 7.71. 

North Carolina: 
Non-RTO: 7.8. 

Georgia: 
Non-RTO: 7.81. 

Ohio: 
New RTO: 7.88. 

Mississippi: 
Non-RTO: 8.08. 

Wisconsin: 
New RTO: 8.4. 

Louisiana: 
Non-RTO: 8.4. 

Arizona: 
Non-RTO: 8.54. 

Illinois: 
New RTO: 8.56. 

Michigan: 
New RTO: 8.6. 

Pennsylvania: 
Original RTO: 9.07. 

Nevada:	
Non-RTO: 10. 

Texas: 
10.27. 

Florida: 
Non-RTO: 10.3. 

Delaware: 
Original RTO: 11.35. 

Maryland: 
Original RTO: 11.42. 

Vermont: 
Original RTO: 11.99. 

District of Columbia: 
Original RTO: 12.06. 

California: 
12.77. 

Alaska: 
Non-RTO: 13.15. 

Rhode Island: 
Original RTO: 13.19. 

Maine: 
Original RTO: 13.26. 

New Jersey: 
Original RTO: 13.43. 

New Hampshire: 
Original RTO: 13.96. 

Massachusetts: 
Original RTO: 15.23. 

New York: 
Original RTO: 15.35. 

Connecticut: 
Original RTO: 16.18. 

Hawaii: 
Non-RTO: 21.29. 

Source: GAO analysis of Energy Information Administration data on 
estimated 2007 retail electricity prices. 

Note: Information for California is presented separately from the three 
primary groups in the legend. We also present information on Texas in 
this graph for purposes of comparison, although the wholesale market in 
most of Texas is not regulated by FERC. 

[End of figure] 

To further understand the basis for these disagreements, we analyzed 
retail electricity prices for industrial customers, because we believe 
that trends in industrial prices more closely reflect trends in 
wholesale prices, which RTOs are most capable of influencing. However, 
this relationship is not perfect, because, as noted earlier in the 
report, many other factors influence retail prices. Furthermore, 
numerous wholesale transactions occur outside RTO markets. 

As shown in figure 10, inflation-adjusted electricity prices for 
industrial consumers have been consistently higher in the original RTO 
states than in the new and non-RTO states over the entire period. 
Prices in the original RTO states fell from 1990 to 1999 but have since 
risen close to prior levels.[Footnote 35] However, in recent years, the 
rate of price increases in the original RTO states has generally been 
higher than in the non-RTO states. It is important to note that this 
price analysis does not isolate the impact of RTOs on prices. It is not 
possible to draw conclusions about what impact the establishment of 
RTOs has had on electricity prices without properly accounting for and 
isolating the impacts of other factors, such as the cost of fuels used 
to generate electricity, changes in the fuel mix, and changes in 
consumer demand.[Footnote 36] 

Figure 10: Change in Inflation-Adjusted Retail Electricity Prices for 
Industrial Consumers, 1990-2006: 

[See PDF for image] 

This figure is a multiple line graph depicting the following data in 
cents per KWh: 

Year: 1990; 
California: 11.52; 
Original RTO: 9.76; 
New RTO: 7.09; 
Non RTO: 6.57. 

Year: 1991; 
California: 10.74; 
Original RTO: 9.27; 
New RTO: 6.47; 
Non RTO: 5.84. 

Year: 1992; 
California: 10.51; 
Original RTO: 9.17; 
New RTO: 6.31; 
Non RTO: 5.7. 

Year: 1993; 
California: 9.93; 
Original RTO: 9.04; 
New RTO: 6.06; 
Non RTO: 5.72. 

Year: 1994; 
California: 9.4; 
Original RTO: 8.75; 
New RTO: 5.84; 
Non RTO: 5.56. 

Year: 1995; 
California: 9.57; 
Original RTO: 8.32; 
New RTO: 5.68; 
Non RTO: 5.35. 

Year: 1996; 
California: 8.88; 
Original RTO: 8.08; 
New RTO: 5.52; 
Non RTO: 5.22. 

Year: 1997; 
California: 8.72; 
Original RTO: 7.84; 
New RTO: 5.41; 
Non RTO: 4.93. 

Year: 1998; 
California: 8.05; 
Original RTO: 7.47; 
New RTO: 5.38; 
Non RTO: 4.9. 

Year: 1999; 
California: 7.66; 
Original RTO: 6.8; 
New RTO: 5.28; 
Non RTO: 4.77. 

Year: 2000; 
California: 8.55; 
Original RTO: 7.37; 
New RTO: 5.22; 
Non RTO: 4.91. 

Year: 2001; 
California: 10.79; 
Original RTO: 7.46; 
New RTO: 5.12; 
Non RTO: 5.18. 

Year: 2002; 
California: 11.27; 
Original RTO: 6.83; 
New RTO: 5.11; 
Non RTO: 4.96. 

Year: 2003; 
California: 10.79; 
Original RTO: 7.26; 
New RTO: 5.09; 
Non RTO: 5.08. 

Year: 2004; 
California: 10.14; 
Original RTO: 7.43; 
New RTO: 5.03; 
Non RTO: 5.1. 

Year: 2005; 
California: 10.11; 
Original RTO: 8.01; 
New RTO: 5.1; 
Non RTO: 5.4. 

Year: 2006; 
California: 10.36; 
Original RTO: 8.87; 
New RTO: 5.31; 
Non RTO: 5.56. 

Source: GAO analysis of Energy Information Administration data. 

Note: At the time of our review, the annual data series from Energy 
Information Administration used for this figure did not include 2007 
estimates. 

[End of figure] 

Experts generally agree that fuel prices play a large role in 
determining electricity prices. However, they disagree about the 
magnitude of their influence. Prices for fuels commonly used to 
generate electricity--such as coal and natural gas--have increased in 
recent years, with prices of natural gas rising more dramatically than 
those for coal over this period. Figure 11 illustrates how average 
prices of fuels used in the electricity sector have changed from 1996 
through 2006. Compounding this overall trend, the original RTO region 
tends to rely more heavily on natural gas than the non-RTO region. 

Figure 11: Inflation-Adjusted Prices of Coal and Natural Gas Used to 
Generate Electricity, 1996-2006: 

[See PDF for image] 

This figure is a line graph depicting the following data in dollars per 
million British thermal units: 

Year: 1996; 
Coal: $1.64; 
Natural gas: $3.37. 

Year: 1997; 
Coal: $1.59; 
Natural gas: $3.46. 

Year: 1998; 
Coal: $1.55; 
Natural gas: $2.95. 

Year: 1999; 
Coal: $1.49; 
Natural gas: $3.14. 

Year: 2000; 
Coal: $1.44; 
Natural gas: $5.14. 

Year: 2001; 
Coal: $1.44; 
Natural gas: $5.25. 

Year: 2002; 
Coal: $1.44; 
Natural gas: $4.09. 

Year: 2003; 
Coal: $1.44; 
Natural gas: $6.06. 

Year: 2004; 
Coal: $1.49; 
Natural gas: $6.52. 

Year: 2005; 
Coal: $1.63; 
Natural gas: $8.69. 

Year: 2006; 
Coal: $1.74; 
Natural gas: $7.13. 

Source: GAO analysis of Energy Information Administration data. 

Note: Prices are presented in 2007 dollar values. 

[End of figure] 

Proponents of RTOs acknowledge that consumer electricity prices have 
increased in RTO regions, but they believe that higher fuel prices, 
greater demand for electricity, increasing costs for infrastructure 
needed after years of underinvestment, the high costs of complying with 
environmental regulations, and regulatory decisions made by states 
about transmission and distribution rates are the principal reasons for 
rising electricity prices across the country and in RTO regions. They 
believe RTO markets have kept prices to consumers lower than they 
otherwise would have been. Critics of RTO markets disagree, observing 
that problems with RTO markets have exacerbated the effect of other 
factors, such as higher fuel prices, on electricity prices. 

Experts and Industry Participants Disagree on RTOs' Influence on 
Generator Plant Efficiency: 

Experts and industry participants are also divided about the ways in 
which RTO markets may influence how efficiently existing plants are 
used. Some believe prices established competitively in RTO markets have 
given generators an incentive to improve the maintenance and operation 
of their facilities and operate them a greater percentage of the time, 
thereby improving efficiency and lowering the overall cost of 
generating electricity. By operating plants more efficiently, 
generators can better compete against rival bidders, resulting in 
either greater profits for themselves, lower prices to consumers, or 
both. Some studies conclude that nuclear plants in RTO and restructured 
regions have increased their capacity factors--the electricity 
generated by a plant as a percentage of that plant's maximum capacity 
to generate electricity. As seen in figure 12, our analysis illustrates 
that nuclear plant capacity factors show more pronounced improvement in 
recent years in the original RTO states and new RTO states than in the 
non-RTO group. We did not attempt to account for other potential causes 
for this improvement, such as technological or institutional factors 
that may have improved efficiencies prior to the advent of 
restructuring and RTO markets or determine whether aggregate trends 
were the result of widespread efficiency improvements or a few improved 
generating units. While many agree that the results of capacity factor 
analysis would inform discussions of the benefits of RTO markets, they 
do not agree on how to isolate the influence of these markets and 
restructuring on capacity factors or determine whether improvements 
preceded restructuring changes or resulted from them. 

Figure 12: Change in Nuclear Plant Capacity Factors, 1996-2006: 

[See PDF for image] 

This figure is a multiple line graph depicting the following data in 
terms of capacity factor: 

Year: 1996; 
California: 0.82013; 
Original RTO: 0.713181; 
New RTO: 0.737435; 
Non RTO: 0.802424. 

Year: 1997; 
California: 0.808148; 
Original RTO: 0.657538; 
New RTO: 0.622566; 
Non RTO: 0.799064. 

Year: 1998; 
California: 0.916267; 
Original RTO: 0.734444; 
New RTO: 0.687337; 
Non RTO: 0.86925. 

Year: 1999; 
California: 0.883892; 
Original RTO: 0.86009; 
New RTO: 0.823568; 
Non RTO: 0.863455. 

Year: 2000; 
California: 0.931663; 
Original RTO: 0.867312; 
New RTO: 0.875078; 
Non RTO: 0.882375. 

Year: 2001; 
California: 0.877008; 
Original RTO: 0.909215; 
New RTO: 0.889445; 
Non RTO: 0.886679. 

Year: 2002; 
California: 0.906915; 
Original RTO: 0.91349; 
New RTO: 0.885168; 
Non RTO: 0.912864. 

Year: 2003; 
California: 0.93969; 
Original RTO: 0.912904; 
New RTO: 0.861592; 
Non RTO: 0.872387. 

Year: 2004; 
California: 0.799084; 
Original RTO: 0.918643; 
New RTO: 0.910052; 
Non RTO: 0.895349. 

Year: 2005; 
California: 0.954503; 
Original RTO: 0.928592; 
New RTO: 0.899034; 
Non RTO: 0.858666. 

Year: 2006; 
California: 0.831035; 
Original RTO: 0.928419; 
New RTO: 0.915969; 
Non RTO: 0.859144. 

Source: GAO analysis of Energy Information Administration data. 

Note: Capacity factors represent the electricity generated by a plant 
as a percentage of that plant's maximum capacity to generate 
electricity. 

[End of figure] 

Some experts and industry participants believe improved generator 
efficiency at existing plants benefits consumers because it reduces the 
need to construct new generating plants and allows less expensive 
generating options, such as previously constructed nuclear plants, to 
satisfy a greater portion of electricity demand. Others question the 
role of RTO markets and restructuring in improving nuclear plant 
generator efficiency and whether efficiencies have resulted in lower 
prices for consumers than would have otherwise occurred. 

Experts and Industry Participants Disagree about RTO Influence on 
Infrastructure Investment: 

There is also disagreement about whether RTOs have led to other 
regional benefits, such as increased construction of transmission and 
generation infrastructure. For example, some industry participants and 
experts believe a practice a number of RTOs employ of pricing 
electricity differently at various locations in a region to reflect the 
costs associated with transmission congestion provides valuable signals 
by indicating where additional generation or transmission is needed. 
[Footnote 37] Some critics, however, charge that this method of pricing 
electricity has not produced the expected investment in transmission 
and generation in the locations where it is needed. Furthermore, they 
believe this practice, combined with what they characterize as limited 
competition in RTO markets, allows generators to keep their bids high 
and earn excess profits. 

Studies of Restructuring and RTOs Draw Differing Conclusions: 

In order to weigh in on these issues, a number of academics and private 
consulting firms have conducted studies about the benefits of 
restructuring and RTOs and their effect on electricity prices, although 
their studies have drawn differing conclusions. Some of these studies 
seek to isolate the effect of restructuring and RTO membership from 
other factors, such as fuel prices, to determine whether restructuring 
and RTOs themselves have influenced prices and led to other benefits. 
We identify and describe in appendix VIII a selection of 13 studies 
that are representative of these varied conclusions. Several of the 
studies conclude that the formation of RTOs resulted in greater 
efficiencies in the electricity industry, significantly benefited local 
economies, and, in some cases, kept electricity prices lower than they 
otherwise would have been. Others conclude that RTO market design and 
operations have not kept prices to consumers lower, but rather have led 
to higher consumer prices and higher generator profits. 

RTO-Developed Assessments of Performance Find Benefits: 

As a way of addressing concerns about whether they have provided 
benefits, some RTOs have quantified the benefits they believe they have 
provided to their regions. ISO New England, for example, developed 
measures related to wholesale electricity prices, power production 
costs, emissions, and other areas to quantify the value it has provided 
to New England. According to ISO New England, average wholesale 
electricity prices in its region, when adjusted for rising fuel costs, 
have declined from $45.95 per MWh in 2000 to $42.64 per MWh in 2006. 
ISO New England reports that over this same period, non-fuel-adjusted 
prices rose from $45.95 per MWh to $62.74 per MWh. Midwest ISO also 
recently developed an initiative to quantify its performance. According 
to its analysis, Midwest ISO has improved electric service reliability 
and is more efficiently using generation resources, a fact that, along 
with other factors, has contributed to between $555 million and $850 
million in annual net benefits. Midwest ISO is currently soliciting 
comments from stakeholders on its analysis. We did not analyze or 
validate either of these efforts. 

FERC Believes RTOs Have Produced Benefits but Has Not Conducted a Study 
or Developed a Comprehensive Set of Publicly Available Measures for 
Tracking RTO Performance: 

FERC officials believe that RTOs have resulted in benefits to the 
economy, such as new efficiencies in operating the regional 
transmission grid; however, it has not conducted an empirical analysis 
or developed a comprehensive set of performance measures to analyze 
these benefits. FERC officials told us they consider RTO benefits when 
they review proposals to create RTOs and approve RTO decisions, such as 
new markets for electricity and other services. FERC also recently 
initiated a proceeding to consider specific reforms to RTO markets--for 
example, considering how to strengthen market monitoring and increase 
opportunities for long-term power contracts.[Footnote 38] FERC believes 
RTOs have produced numerous benefits, including the following: 

* improving the efficiency of the regional transmission grid, including 
resolving operating problems such as transmission congestion; providing 
more efficient transmission pricing policies; and minimizing market 
power; 

* improving transmission reliability by facilitating more accurate 
calculations of regional transmission capacity; 

* improving access to the grid by reducing opportunities for 
discriminatory transmission practices; 

* improving competition in regional power markets by facilitating the 
entry of new independent generators; 

* facilitating stakeholder consensus solutions to regional problems; 

* enhancing transparency and oversight regarding how prices are 
determined and how access to the grid is granted; and: 

* providing a process of regional transmission planning, thus resulting 
in more efficient planning and use of resources across a region, as 
well as an opportunity for input by a broad range of stakeholders. 

However, FERC has not conducted an empirical analysis to measure 
whether RTOs have achieved these expected benefits or how RTOs or 
restructuring efforts more generally have affected consumer electricity 
prices, costs of production, or infrastructure investment. FERC 
believes data exist to support its conclusion that RTOs have provided 
benefits--for example, data illustrating changes in generating capacity 
in RTO regions and data about the number of transmission interruptions 
used by system operators to address congestion. However, FERC has not 
used these or other available data to analyze whether RTOs have 
produced benefits. Furthermore, FERC has not reexamined its prospective 
estimate of the benefits RTOs were expected to produce--estimated in 
1999 at $2.4 billion annually in cost savings--to determine whether 
these expected benefits are actually being realized or how actual 
outcomes have differed from original estimates. Some of the projections 
used to develop this estimate were too conservative, indicating that 
the estimate is not as reliable as it could be.[Footnote 39] Rather 
than incorporating a range of assumptions about future fuel prices to 
account for uncertainty, the model used one set of fuel price 
projections that turned out to be lower than what actually occurred. 
For example, the model's projections assumed the average price of 
natural gas delivered to electric generation plants in the United 
States would rise to $3.25 per million British thermal units (Btu) by 
2005.[Footnote 40] In fact, the actual price rose much faster, reaching 
$8.50 per million Btu in 2005. Similarly, the model assumed that U.S. 
electric generation capacity using natural gas and oil as fuel would 
increase from about 230,000 megawatts in 1997 to about 284,000 
megawatts in 2005, but in fact, U.S. electric generation capacity rose 
to about 440,000 megawatts. FERC officials acknowledge that some of the 
study's assumptions were low but maintain that RTOs have provided 
benefits. 

Although FERC collects a wide range of data from the RTOs, it has not 
developed a report or other assessment with comprehensive, standardized 
measures that Congress and the public could use to identify and track 
RTO performance. FERC has taken a step in this direction by developing 
a nonpublic document that provides some standardized measures of RTO 
market performance, and these measures are also addressed in public 
reports issued by the RTOs.[Footnote 41] However, FERC officials 
explained that these measures were not intended to be used to assess 
RTO benefits or evaluate the performance of individual RTOs. Moreover, 
they are not comprehensive, since they do not address the extent to 
which RTOs have achieved the full range of expected benefits--such as 
improved reliability, more efficient planning for generation and 
transmission investments, or prices for consumers that are as low as 
possible--and do not compare performance between RTO and non-RTO 
regions. FERC also includes some statistics about RTOs on its Web site 
and in its annual report on the electricity industry, but these data 
are of limited scope and do not contain measures of operational and 
market performance.[Footnote 42] The RTOs themselves publish large 
volumes of data about market and operational performance in publicly 
available annual reports and other documents available on their Web 
sites; however, the large amount of information and, in some cases, its 
lack of standardization, make it difficult for the public or Congress 
to easily compare and interpret it. Moreover, FERC has not synthesized 
these data in a way that allows Congress and the public to draw 
conclusions about the benefits of RTOs and their effectiveness or 
discern whether RTOs and organized markets are in their best interest. 

According to FERC officials, quantitative analyses of whether benefits 
were achieved and identification of performance measures are not a 
necessary part of its oversight of RTOs. Rather, FERC officials believe 
FERC's continual review of RTO performance--through its evaluation of 
RTO decisions, proceedings about RTO market reforms, and market 
monitoring--is sufficient to ensure RTOs continue to benefit consumers 
as expected. Furthermore, FERC officials cited methodological 
challenges to performing an empirical analysis of whether benefits were 
achieved and developing performance measures, which it believes would 
limit their value. FERC officials also explained that RTO participation 
is voluntary, and that participants are able to assess for themselves 
the benefits of RTO membership and join or depart based on their own 
determination. 

Experts from the electricity industry and the academic community we 
spoke with acknowledged that empirical analysis and measures of RTO 
performance would be methodologically challenging to conduct. In 
particular, these experts noted that there are difficulties in 
isolating the influence of RTOs on prices, efficiency, and investment 
from other factors, such as fuel prices. However, these experts 
observed that tracking performance measures across RTOs would encourage 
better performance and could identify potential areas for improvement. 
Some added that, in certain cases, the same measures could be developed 
for non-RTO regions to provide points of comparison. These experts 
suggested measuring and providing standardized information to the 
public on market competitiveness, transmission and generation 
investment, plant efficiency, reliability, and changes in prices in RTO 
regions, among other things. Some industry groups have also called for 
the development of common measures of RTO performance, such as measures 
to track the difference between generator costs and prices charged in 
RTO markets, changes in congestion costs over time, and RTO costs of 
acquiring capital for major investments. Another industry group 
commissioned an independent study to identify and begin tracking 
standardized measures of RTO performance. 

GAO's Standards for Internal Control identify the value to 
organizations of comparing actual performance to planned or expected 
results. More specifically, past GAO work recognizes that federal 
agencies can use performance information to identify problems in 
existing programs, develop corrective actions, and identify more 
effective approaches to program implementation, among other things. 
[Footnote 43] By developing standard performance measures that draw 
upon its own internal analysis or work being conducted by RTOs, 
industry experts, market monitors, and others, FERC could, over time, 
develop a more thorough empirical understanding of RTO performance and 
whether and to what extent RTOs have provided benefits to the industry 
and to consumers. This could help FERC in evaluating the success of the 
decision to encourage the creation of RTOs and understand whether RTOs 
have led to the benefits expected of them. Measures may also help FERC 
determine whether to encourage the creation of additional RTOs or 
identify areas where its RTO policy and RTOs themselves could be 
improved. Moreover, if available to Congress and the public, measures 
could allow FERC to weigh in on the disagreements among experts and 
industry participants about the benefits RTOs provide. 

Conclusions: 

It has been over 10 years since major federal electricity restructuring 
was introduced and some of the first RTOs were developed to facilitate 
it, yet there is little agreement about whether restructuring and RTOs 
have been good for consumers, how they have affected electricity 
prices, and whether they have produced the benefits FERC envisioned. 
Compounding this, rising electricity prices and diverse regional 
interests complicate an unbiased discussion of the merits of RTOs and 
restructuring. Although there are challenges to answering questions 
about the benefits of RTOs, a more structured and formalized approach 
to RTO oversight would be beneficial. 

FERC's initial approach to allow a diverse range of RTO types, 
governance structures, and rate recovery mechanisms provided a means 
for regions to quickly build upon existing institutions like power 
pools and past participant experience working together. However, much 
has changed since the first RTOs came into existence, and it has become 
clear that FERC's efforts to regulate RTOs as it does utilities may no 
longer be sufficient. Furthermore, the specific characteristics of RTOs 
devised by FERC and its expectation that these entities would lead to 
lighter regulation by FERC give RTOs a unique position in the 
electricity industry. Some RTO functions, such as operating the 
transmission grid, typically fell within the purview of utilities. 
Others, including market monitoring and balancing different stakeholder 
interests, were more traditionally performed by regulators. As a result 
of this unique set of responsibilities, RTOs face much public scrutiny-
-something RTOs have implicitly embraced in part through their varied 
stakeholder processes--and may require different oversight by FERC. 
Although stakeholders told us they value the stakeholder process at 
each of the RTOs, the concerns they raised about its resource 
intensiveness and the challenges involved in analyzing RTO decisions 
highlight the importance of FERC involvement and oversight. In this 
regard, without more regular, consistent review of RTO expenses and 
budgets, FERC may be missing an opportunity to better ensure the cost- 
effectiveness of RTOs and that their rates remain just and reasonable, 
even between rate proceedings. Furthermore, FERC's lack of regular 
review of RTO financial reports, filed annually in the Form No. 1, 
limits its ability to ensure RTO expenses are accurately and completely 
reported and reassure Congress, industry participants, stakeholders, 
and the public that the billions of dollars in expenses RTOs have 
incurred in recent years were reasonable and spent in accordance with 
budgets previously approved. 

Finally, while FERC believes RTOs have produced numerous benefits, the 
fact that it has not developed a comprehensive set of publicly 
available standardized measures to track RTO performance contributes to 
uncertainty about what those benefits have been and their magnitude. We 
acknowledge that FERC's review of RTO decisions that affect electricity 
prices and consideration of stakeholder comments and complaints 
sometimes results in new rules designed to improve the ability of RTOs 
to deliver benefits to their regions. However, in the absence of 
measures for evaluating the success of the decision to encourage the 
creation of RTOs, FERC may be missing opportunities to facilitate 
improvements in RTO operations and markets and is not as strongly 
positioned as it could be to evaluate the success of its decision to 
encourage the creation of RTOs and determine whether to encourage 
further RTO development. 

Recommendations for Executive Action: 

To help ensure that FERC, industry participants, and the public have 
adequate information to inform their assessment of whether rates to 
recover RTO expenses are just and reasonable, we recommend the Chairman 
of FERC take the following two actions: 

* develop a consistent approach for regularly reviewing expense 
information contained in RTO budgets and: 

* routinely review and assess the accuracy, completeness, and 
reasonableness of the financial information RTOs report to FERC in 
their Form No. 1 filings. 

To provide a foundation for FERC to evaluate the effectiveness of its 
decision to encourage the creation of RTOs and help Congress, industry 
stakeholders, and the public understand RTO performance and net 
benefits, we recommend the Chairman of FERC take the following two 
actions: 

* work with RTOs, stakeholders, and other experts to develop 
standardized measures that track the performance of RTO operations and 
markets and: 

* report the performance results to Congress and the public annually, 
while also providing interpretation of (1) what the measures and 
reported performance communicate about the benefits of RTOs and, where 
appropriate, (2) changes that need to be made to address any 
performance concerns. 

Agency Comments and Our Evaluation: 

We provided FERC a draft of this report for review and comment. In a 
letter dated August 28, 2008, we received written comments from the 
Chairman of FERC. These comments are reprinted in appendix IX. We also 
received technical comments, which we incorporated into the report as 
appropriate. 

In his letter, the Chairman generally agreed with our report and its 
recommendations. We commend FERC for its interest in addressing the 
concerns we raised. The Chairman also provided comments in response to 
each of the recommendations and outlined plans to address them. 
Specifically: 

* Regarding our first recommendation, that FERC develop a consistent 
approach for regularly reviewing expense information contained in RTO 
budgets, FERC agreed to increase its efforts to review RTO budgets and 
the reasonableness of RTO costs, and the Chairman has directed FERC 
staff to evaluate possible approaches for doing so. 

* Regarding our second recommendation, that FERC perform additional 
review of the financial information in Form No. 1 filings, FERC 
indicated that, in addition to the one audit it has already begun, it 
plans to perform periodic audits of the financial information in Form 
No. 1 filings in the future. 

* Regarding our third and fourth recommendations, that FERC work with 
RTOs, stakeholders, and other experts to develop standardized measures 
that track the performance of RTO operations and markets and report on 
those measures to Congress and the public, the Chairman noted that FERC 
is considering appropriate procedures for developing such measures and 
how best to report them. Regarding reporting, the Chairman observed 
that RTO "State of the Market" annual reports may be a vehicle for 
providing data and additional information to the public on RTO 
performance. While we agree that these annual reports of data on RTOs 
could be helpful for providing the public with additional performance 
information, we urge the Commission to consider what role it can play 
in helping Congress, industry stakeholders, and the public interpret 
and evaluate data and other information from RTOs in order to draw 
conclusions about RTO performance and value. It is clear that 
electricity markets and RTO operations are complex. FERC's expertise 
and independence make it well positioned to help Congress and others 
assess RTO performance and net benefits, and its oversight authority 
gives it the ability to use this information to encourage continued 
improvement. The Chairman also expressed uncertainty about whether 
annual evaluation of results and recommendations for change was 
feasible or cost-effective. We recognize that FERC must balance 
numerous responsibilities and that the extent of its evaluation of RTO 
performance may vary from year to year. However, we believe significant 
value could be realized from (1) providing Congress and others with a 
consistent, annual source of data for tracking the performance of RTOs 
and (2) ongoing analysis of performance information and consideration 
of how it could aid FERC in carrying out its RTO responsibilities. 

Finally, along with its general agreement with our recommendations, 
FERC provided two clarifying comments. 

* The first clarifies FERC's role in approving RTO procedures for 
planning transmission infrastructure, and we incorporated this comment 
into our report. 

* In the second, FERC commented on a statement in our draft report's 
conclusions that RTOs are in a position of greater public trust than 
utilities. FERC observes that all utilities have a position of public 
trust and that a number of utilities are responsible for administering 
transmission systems that are as large as or larger than those of some 
RTOs. We agree that all utilities carry out important activities in the 
public interest that necessitate vigilant regulatory oversight and 
acknowledge that a number of large utilities exist. However, we also 
recognize that FERC had a number of unique expectations for RTOs that 
it did not have for utilities, believing the creation of RTOs could 
lead to lighter regulation by FERC. For example, FERC expected RTOs to 
assist it in its oversight of the electricity industry through, among 
other things, their market monitoring activities and the stakeholder 
process in which market development and other issues are discussed and 
potentially resolved without resorting to FERC's complaint process. It 
is for these reasons that we believe FERC should take certain 
regulatory steps specific to RTOs like those we recommend in our 
report--for example, evaluating RTOs using performance measures--in 
order to improve RTOs and educate the public on their performance. 
However, in response to FERC's comments, we revised the report's 
conclusions to emphasize the unique role of RTOs and avoid relative 
comparisons of trust between RTOs and utilities. 

As agreed with your offices, unless you publicly announce the contents 
of this report earlier, we plan no further distribution until 30 days 
from the report date. At that time, we will send copies of this report 
to interested congressional committees; the Chairman of FERC; and other 
interested parties. We will also make copies available to others upon 
request. In addition, the report will be available at no charge on the 
GAO Web Site at [hyperlink, http://www.gao.gov]. 

If you or your offices have any questions about this report, please 
contact me at (202) 512-3841 or gaffiganm@gao.gov. Contact points for 
our Offices of Congressional Relations and Public Affairs may be found 
on the last page of this report. GAO staff who made major contributions 
to this report are listed in appendix X. 

Signed by: 

Mark Gaffigan: 
Director, Natural Resources and Environment: 

[End of section] 

Appendix I: Objectives, Scope, and Methodology: 

At the request of the Chairman and Ranking Member of the Senate 
Committee on Homeland Security and Governmental Affairs, we reviewed 
(1) Regional Transmission Organizations' (RTO) key expenses and 
investments in property, plant, and equipment; (2) how RTOs and the 
Federal Energy Regulatory Commission (FERC) review RTO expenses and 
decisions that may affect electricity prices; and (3) the extent to 
which there is consensus about what benefits RTOs have provided. Our 
review focused on the six RTOs in FERC's jurisdiction--California 
Independent System Operator (ISO), ISO New England, Midwest ISO, New 
York ISO, PJM Interconnection (PJM), and Southwest Power Pool. 

To determine the total expenses incurred by RTOs from 2002 to 2006, the 
most recent data available when we began our review, and their key 
investments in property, plant, and equipment, we reviewed independent 
public auditor reports over this period, as well as full-time- 
equivalent personnel and transmission volume as reported to us by the 
RTOs. We summarized RTO expense, personnel, and transmission volume and 
property, plant, and equipment balances by RTO, and calculated average 
salary and related benefits per full-time equivalent and total expenses 
per megawatt hour (MWh) from 2002 through 2006 for each RTO. Our 
analysis reflects total annual expenses as reported in the RTOs' annual 
audited financial statements. We did not retroactively apply financial 
statement reclassifications to data from prior years. In addition, RTOs 
utilized differing billing methodologies, and consequently, the rates 
they charged to market participants may be different from the total 
expenses per MWh calculated in our analysis. 

To illustrate the total amount of investments in property, plant, and 
equipment as of December 31, 2006, we used total property, plant, and 
equipment in our analysis without reducing those amounts by accumulated 
depreciation. We also reviewed 2006 RTO FERC Form No. 1 filings, the 
most current available at the time of our audit, to determine the 
amount of RTO expenses attributable to transmission expenses and 
regional market expenses, as well as administrative and general 
expenses. Independent public auditor reports did not aggregate expenses 
by these categories. We adjusted all expense amounts for inflation 
utilizing 2007 as the base year. 

To determine how FERC and RTOs review RTO expenses and decisions and 
discuss other aspects of RTO costs and benefits, we collected general 
information, interviewed representatives from the six RTOs, and spoke 
to the ISO/RTO Council about how FERC and the RTOs review proposed 
budget expenses and consider how RTO decisions affect electricity 
prices. For two RTOs--ISO New England and Midwest ISO--we collected 
more in-depth information and interviewed stakeholders from each of the 
major stakeholder sectors. We selected these two RTOs because they are 
multistate and perform a breadth of functions and services, but also 
reflect geographical and historical differences. For example, ISO New 
England evolved from a power pool; Midwest ISO did not. We interviewed 
state agency officials from these RTO areas, including state regulatory 
agencies (such as the Connecticut Department of Public Utility Control, 
Illinois Commerce Commission, Indiana Utility Regulatory Commission, 
Maine Public Utilities Commission, and Massachusetts Department of 
Public Utilities), state consumer agencies (such as the Connecticut 
Office of Consumer Counsel and Maine Office of the Public Advocate), 
and state regulatory associations (such as the Organization of MISO 
States, National Association of Regulatory Utility Commissioners, and 
the New England Conference of Public Utility Commissioners). We also 
interviewed representatives from each of these RTOs' stakeholder groups 
to understand how FERC and RTOs review RTO decisions and expenses. We 
interviewed officials from the North American Electric Reliability 
Corporation to understand their interaction with RTOs. We spoke with 
officials from FERC's Office of Enforcement and Office of Energy Market 
Regulation and reviewed related documentation that outlined FERC's 
steps to review RTO expenses for reasonableness and accuracy. We 
reviewed selected FERC rate proceedings to better understand the type 
of information provided to FERC about proposed RTO expenses and the 
analysis it performs. We also considered FERC's process for reviewing 
actual expenses as reported in FERC Form No. 1 filings and reviewed 
FERC audits of RTOs conducted in 2004 which focused primarily on 
governance. While we generally reviewed FERC's oversight of RTOs, we 
did not perform an in-depth analysis of FERC's review of specific RTO 
decisions. 

Finally, to address the extent to which there is consensus about what 
benefits RTOs have provided, we interviewed FERC officials and reviewed 
related documentation, including FERC's 1999 prospective assessment of 
RTO expected benefits. We interviewed several experts in the field of 
electricity restructuring to discuss their opinions on the benefits and 
costs of RTOs and their assessment of the adequacy of FERC's analysis 
of RTOs to date. These included experts from the Analysis Group, 
Cornell University, Northeastern University, Penn State University, the 
University of California Berkeley, and Vermont Law School. We chose 
experts affiliated with academic institutions and research firms with 
extensive knowledge of electricity restructuring and RTOs. We selected 
experts with a balanced range of views about the economic benefits of 
RTOs. We also interviewed a number of industry participants, including 
representatives from electricity industry associations and consumer 
organizations, such as the American Public Power Association, Compete 
Coalition, Consumer Federation of America, Electric Power Supply 
Association, Edison Electric Institute, Electricity Consumers Resource 
Council, Industrial Energy Consumers of America, National Rural 
Electric Cooperative Association, and Public Citizen to more fully 
understand where there was agreement and disagreement about the costs 
and benefits of RTOs. We reviewed reports and analyses from these and 
other industry participants that discussed the costs and benefits of 
RTOs. 

We also reviewed expert studies on the economic effects of 
restructuring and competition in the electricity industry and 
electricity consumers. In deciding which studies to include in our 
summary table, we selected some studies that were sponsored by both 
advocates and critics of the existing RTOs, as well as studies that are 
more academic in nature. Some of these studies specifically addressed 
the impact of RTOs on electricity costs and prices, while others 
addressed the impacts of restructuring and competition more generally, 
without specifically isolating the impact of RTOs. We conducted basic 
analyses of data on electricity prices, intensity of the use of 
generation resources (capacity factors), and type of generation 
resources (by fuel use). For the analysis of prices and capacity 
factors, we divided states into four categories: (1) original RTO 
states--states joining an RTO in 1999 or earlier and historically in a 
power pool, (2) new RTO states--states joining an RTO region after 
1999, (3) non-RTO states--states outside RTO regions, and (4) 
California. The original RTO states category included Connecticut, 
Delaware, Massachusetts, Maryland, Maine, New Hampshire, New Jersey, 
New York, Pennsylvania, Rhode Island, Vermont, and the District of 
Columbia. The new RTO states category included Iowa, Illinois, Indiana, 
Kansas, Michigan, Minnesota, Missouri, North Dakota, Ohio, Oklahoma, 
Virginia, Wisconsin and West Virginia. The non-RTO states category 
included Alaska, Alabama, Arkansas, Arizona, Colorado, Florida, 
Georgia, Hawaii, Idaho, Kentucky, Louisiana, Mississippi, Montana, 
North Carolina, Nebraska, New Mexico, Nevada, Oregon, South Carolina, 
South Dakota, Tennessee, Utah, Washington and Wyoming. We placed 
California in a separate category because its electricity industry went 
through a turbulent restructuring process during part of the time 
period that we analyzed. We did not include Texas in our analysis, 
because most of the state constitutes a separate grid from the two 
other main grids in the United States and is largely unregulated by 
FERC. For the other three groupings, states that were partially in an 
RTO region were considered part of the region if electricity for most 
major cities was provided by a utility that participated in an RTO. Our 
analysis was based on electricity data obtained from the Energy 
Information Administration. For the price analysis, we used electric 
power retail sales and electric revenues data. We developed average 
price estimates by aggregating state-level data, dividing revenues by 
sales, and adjusting for inflation using the gross domestic product 
price index. We focus on the prices in the industrial sector because 
the retail portion of its electricity prices is typically smaller than 
the retail portion of residential and commercial electric prices. RTOs 
operate wholesale markets and do not determine the retail portion of 
electric prices. We also conducted a specific analysis of relative 
industrial electricity prices. A description of that analysis and our 
methodology is presented in Appendix VII. For the analysis of the 
intensity of the use of generation resources, we calculated capacity 
factors from Energy Information Administration state-level data on 
electric power generation capacity and actual generation. We also 
interviewed representatives from the Energy Information Administration 
to understand the type of data that agency collects related to 
estimating the benefits and costs RTOs. 

We conducted this performance audit from October 2007 to September 2008 
in accordance with generally accepted government auditing standards. 
Those standards require that we plan and perform the audit to obtain 
sufficient, appropriate evidence to provide a reasonable basis for our 
findings and conclusions based on our audit objectives. We believe that 
the evidence obtained provides a reasonable basis for our findings and 
conclusions based on our audit objectives. We provided a draft of this 
report to FERC for its review. FERC's comments are reprinted in 
Appendix IX. 

[End of section] 

Appendix II: RTO Characteristics and Functions Required by FERC Order 
2000: 

RTO characteristics: Independence; 
Description: RTOs must be independent of control by any market 
participant and have the authority to propose rates, terms, and 
conditions of transmission services provided over the facilities they 
operate. An RTO's employees must not have financial interest in any 
market participant. 

RTO characteristics: Scope and regional configuration; 
Description: RTOs must serve an appropriate region of sufficient scope 
to maintain reliability, support efficient and nondiscriminatory power 
markets, and carry out their other functions. 

RTO characteristics: Operational authority; 
Description: RTOs must have operational authority for all transmission 
facilities under their control. 

RTO characteristics: Short-term reliability; 
Description: RTOs must have exclusive authority for maintaining the 
short-term reliability of the grid they operate. 

RTO functions: Tariff administration and design; 
Description: RTOs must administer their own transmission tariff--an 
agreement that outlines the terms and conditions of transmission 
service--and employ a transmission pricing system that promotes 
efficient use and expansion of transmission and generation facilities. 

RTO functions: Congestion management; 
Description: RTOs must ensure the development and operation of market 
mechanisms to manage transmission congestion. These mechanisms should 
accommodate broad participation by all market participants and provide 
transmission customers with efficient price signals. 

RTO functions: Parallel path flow; 
Description: RTOs must develop and implement procedures to address 
engineering and reliability problems caused by parallel path flows--a 
term that refers to electricity flowing over all possible transmission 
lines regardless of who owns the lines and what transmission contracts 
were agreed to. According to FERC, prior to RTOs many transmission 
owners found their grids overloaded by the actions of others because of 
this engineering reality. Since they were unable to determine the 
responsible party, these owners had to curtail their own use of their 
grid. 

RTO functions: Ancillary services; 
Description: RTOs must serve as the provider of last resort for 
ancillary services--services to maintain the reliable operation of the 
transmission system--and have the authority to decide the minimum 
required amounts of each ancillary service. RTOs must also ensure that 
transmission customers have access to a real-time balancing market. 

RTO functions: OASIS and capacity; 
Description: RTOs must be the single administrator for the Open Access 
Same Time Information System (OASIS) site--an Internet-based electronic 
communication and reservation system through which transmission 
providers provide information about the availability and price of 
transmission and ancillary services and customers procure those 
services. Furthermore, RTOs must independently calculate total and 
available transmission capacity--measures of the amount of electric 
power that the transmission system is capable of transferring from one 
point in the grid to another. 

RTO functions: Market monitoring; 
Description: RTOs must provide for objective monitoring of markets 
administered to identify market design flaws, market power abuses, and 
opportunities for efficiency improvements. 

RTO functions: Planning and expansion; 
Description: RTOs must be responsible for planning and directing 
necessary transmission expansions, additions, and upgrades that will 
enable it to provide efficient, reliable, and nondiscriminatory 
service. In doing so, they must coordinate such efforts with 
appropriate state authorities and must encourage market-driven 
operating and investment actions for preventing and relieving 
congestion. 

RTO functions: Interregional coordination; 
Description: RTOs must ensure the integration of reliability practices 
across regions. 

Source: FERC Order 2000 and GAO analysis. 

[End of table] 

[End of section] 

Appendix III: RTO Inflation-Adjusted Expenses and Full-time Equivalents 
from 2002 to 2006, by RTO (Dollars in thousands): 

California ISO: Expenses; Salaries and related benefits; 
2002: $76,427; 
2003: $80,949; 
2004: $84,451; 
2005: $81,600; 
2006: $75,393; 
Total: $398,820. 

California ISO: Expenses; Interest expense (income); 
2002: $13,716; 
2003: $5,542; 
2004: $5,133; 
2005: $211; 
2006: $223; 
Total: $24,825. 

California ISO: Expenses; Consulting, professional, and other outside 
services; 
2002: $20,286; 
2003: $21,954; 
2004: $22,427; 
2005: $22,163; 
2006: $17,425; 
Total: $104,255. 

California ISO: Expenses; Facility/maintenance; 
2002: $67,234; 
2003: $67,365; 
2004: $41,373; 
2005: $40,311; 
2006: $33,178; 
Total: $249,461. 

California ISO: Expenses; Other; 
2002: $11,020; 
2003: $27,748; 
2004: $9,709; 
2005: $8,864; 
2006: $9,227; 
Total: $66,568. 

California ISO: Expenses; Depreciation and amortization; 
2002: $52,471; 
2003: $26,178; 
2004: $17,198; 
2005: $19,026; 
2006: $17,123; 
Total: $131,996. 

California ISO: Expenses; Regulatory dues/assessments; 
2002: 0; 
2003: 0; 
2004: 0; 
2005: 0; 
2006: 0; 
Total: 0; 

California ISO: Total expenses; 
2002: $241,154; 
2003: $229,737; 
2004: $180,291; 
2005: $172,174; 
2006: $152,569; 
Total: $975,925. 

California ISO: Full-time equivalents (FTE); 
2003: 572; 
2003: 591; 
2004: 576; 
2005: 484; 
2006: 506. 

California ISO: Salaries and related benefits per FTE; 
2002: $134; 
2003: $137; 
2004: $147; 
2005: $169; 
2006: $149. 

ISO New England: Expenses; Salaries and related benefits; 
2002: $39,345; 
2003: $46,581; 
2004: $50,632; 
2005: $53,956; 
2006: $55,499; 
Total: $246,013. 

ISO New England: Expenses; Interest expense (income); 
2002: $911; 
2003: $3,448; 
2004: $2,800; 
2005: $2,603; 
2006: $3,110; 
Total: $12,872. 

ISO New England: Expenses; Consulting, professional, and other outside 
services; 
2002: $13,570; 
2003: $13,992; 
2004: $18,349; 
2005: $18,428; 
2006: $15,051; 
Total: $79,390. 

ISO New England: Expenses; Facility/maintenance; 
2002: $9,918; 
2003: $9,771; 
2004: $8,505; 
2005: $7,116; 
2006: $7,334; 
Total: $42,644. 

ISO New England: Expenses; Other; 
2002: $5,515; 
2003: $6,078; 
2004: $8,945; 
2005: $8,447; 
2006: $10,893; 
Total: $39,877. 

ISO New England: Expenses; Regulatory dues/assessments; 
2002: 0; 
2003: 0; 
2004: 0; 
2005: 0; 
2006: $1,465; 
Total: $1,465. 

ISO New England: Expenses; Depreciation and amortization; 
2002: $4,104; 
2003: $35,886; 
2004: $38,515; 
2005: $41,219; 
2006: $24,653; 
Total: $144,377. 

ISO New England: Total expenses; 
2002: $73,362; 
2003: $115,757; 
2004: $127,745; 
2005: $131,768; 
2006: $118,005; 
Total: $566,638. 

ISO New England: FTEs; 
2002: 345; 
2003: 373; 
2004: 401; 
2005: 413; 
2006: 401. 

ISO New England: Salaries and related benefits per FTE; 
2002: $114; 
2003: $125; 
2004: $126; 
2005: $131; 
2006: $138. 

Midwest ISO: Expenses: Salaries and related benefits; 
2002: $29,160; 
2003: $39,899; 
2004: $58,497; 
2005: $75,344; 
2006: $80,727; 
Total: $283,628. 

Midwest ISO: Expenses: Interest expense (income); 
2002: $10,690; 
2003: $12,646; 
2004: $17,710; 
2005: $19,435; 
2006: $14,149; 
Total: $74,629. 

Midwest ISO: Expenses: Consulting, professional, and other outside 
services; 
2002: $10,234; 
2003: $26,374; 
2004: $50,237; 
2005: $53,298; 
2006: $29,698; 
Total: $169,841. 

Midwest ISO: Expenses: Facility/maintenance; 
2002: $9,635; 
2003: $16,601; 
2004: $23,156; 
2005: $27,761; 
2006: $31,612; 
Total: $108,764. 

Midwest ISO: Expenses: Other; 
2002: $18,573; 
2003: -$44,851; 
2004: -$30,112; 
2005: $424; 
2006: $4,411; 
Total: -$51,556. 

Midwest ISO: Expenses: Regulatory dues/assessments; 
2002: 0; 
2003: $20,343; 
2004: $21,646; 
2005: $34,769; 
2006: $32,748; 
Total: $109,506. 

Midwest ISO: Expenses: Depreciation and amortization; 
2002: $16,536; 
2003: $22,477; 
2004: $26,474; 
2005: $72,011; 
2006: $81,731; 
Total: $219,229. 

Midwest ISO: Total expenses; 
2002: $94,828; 
2003: $93,489; 
2004: $167,607; 
2005: $283,041; 
2006: $275,075; 
Total: $914,040. 

Midwest ISO: FTEs; 
2002: 265; 
2003: 373; 
2004: 517; 
2005: 590; 
2006: 643. 

Midwest ISO: Salaries and related benefits per FTE; 
2002: $110; 
2003: $107; 
2004: $113; 
2005: $128; 
2006: $126. 

New York ISO: Expenses: Salaries and related benefits; 
2002: $33,158; 
2003: $36,824; 
2004: $41,258; 
2005: $48,391; 
2006: $48,351; 
Total: $207,982. 

New York ISO: Expenses: Interest expense (income); 
2002: $2,559; 
2003: $1,489; 
2004: $2,652; 
2005: $3,337; 
2006: $3,863; 
Total: $13,901. 

New York ISO: Expenses: Consulting, professional, and other outside 
services; 
2002: $23,621; 
2003: $28,086; 
2004: $29,519; 
2005: $27,882; 
2006: $25,563; 
Total: $134,671. 

New York ISO: Expenses: Facility/maintenance; 
2002: $16,931; 
2003: $15,451; 
2004: $22,092; 
2005: $23,424; 
2006: $25,713; 
Total: $103,611. 

New York ISO: Expenses: Other; 
2002: $19,505; 
2003: $20,371; 
2004: $19,789; 
2005: $5,761; 
2006: $5,708; 
Total: $71,135. 

New York ISO: Expenses: Regulatory dues/assessments; 
2002: $8,740; 
2003: $10,526;
2004: $7,455; 
2005: $11,209; 
2006: $9,733; 
Total: $47,663. 

New York ISO: Expenses: Depreciation and amortization; 
2002: $9,671; 
2003: $19,761; 
2004: $26,651; 
2005: $37,974; 
2006: $32,892; 
Total: $126,949. 

New York ISO: Total expenses; 
2002: $114,185; 
2003: $132,508; 
2004: $149,416; 
2005: $157,979; 
2006: $151,824; 
Total: $705,912. 

New York ISO: FTEs; 
2002: 316; 
2003: 345; 
2004: 393; 
2005: 383; 
2006: 391. 

New York ISO: Salaries and related benefits per FTE; 
2002: $105; 
2003: $107; 
2004: $105; 
2005: $126; 
2006: $124. 

PJM: Expenses: Salaries and related benefits; 
2002: $54,412; 
2003: $62,037; 
2004: $65,913; 
2005: $78,024; 
2006: $80,971; 
Total: $341,358. 

PJM: Expenses: Interest expense (income); 
2002: $12,046; 
2003: $10,092; 
2004: $7,777; 
2005: $9,802; 
2006: $18,502; 
Total: $58,218. 

PJM: Expenses: Consulting, professional, and other outside services; 
2002: $28,045; 
2003: $25,962; 
2004: $32,709; 
2005: $41,147; 
2006: $38,914; 
Total: $166,778. 

PJM: Expenses: Facility/maintenance; 
2002: $20,742; 
2003: $23,208; 
2004: $22,830; 
2005: $20,413; 
2006: $16,223; 
Total: $103,415. 

PJM: Expenses: Other; 
2002: $154,422; 
2003: $103,037; 
2004: $23,775; 
2005: $37,243; 
2006: $45,951; 
Total: $364,428. 

PJM: Expenses: Regulatory dues/assessments; 
2002: $11,256; 
2003: $12,409; 
2004: $25,713; 
2005: $29,689; 
2006: $33,358; 
Total: $112,425. 

PJM: Expenses: 
Depreciation and amortization; 
2002: $30,735; 
2003: $54,512; 
2004: $56,553; 
2005: $67,902; 
2006: $47,648; 
Total: $257,351. 

PJM: Total expenses; 
2003: $311,657; 
2003: $291,257; 
2004: $235,271; 
2005: $284,220; 
2006: $281,568; 
Total: $1,403,973. 

PJM: FTEs; 
2002: 484; 
2003: 531; 
2004: 562; 
2005: 578; 
2006: 551. 

PJM: Salaries and related benefits per FTE; 
2002: $112; 
2003: $117; 
2004: $117; 
2005: $135; 
2006: $147. 

Southwest Power Pool: Expenses: Salaries and related benefits; 
2002: $12,616; 
2003: $13,503; 
2004: $15,852; 
2005: $19,638; 
2006: $26,233; 
Total: $87,842. 

Southwest Power Pool: Expenses: Interest expense (income); 
2002: $2,414; 
2003: $2,138; 
2004: $1,003; 
2005: $454; 
2006: -$571; 
Total: $5,438. 

Southwest Power Pool: Expenses: Consulting, professional, and other 
outside services; 
2002: $11,764; 
2003: $5,215; 
2004: $8,181; 
2005: $10,750; 
2006: $14,100; 
Total: $50,012. 

Southwest Power Pool: Expenses: Facility/maintenance; 
2002: $3,323; 
2003: $3,687; 
2004: $4,215; 
2005: $4,802; 
2006: $7,221; 
Total: $23,247. 

Southwest Power Pool: Expenses: Other; 
2002: $1,877; 
2003: $1,435; 
2004: $3,488; 
2005: $4,131; 
2006: $4,609; 
Total: $15,540. 

Southwest Power Pool: Expenses: Regulatory dues/assessments; 
2002: $930; 
2003: $701; 
2004: $757; 
2005: $8,712; 
2006: $10,661; 
Total: $21,760. 

Southwest Power Pool: Expenses: Depreciation and amortization; 
2002: $5,028; 
2003: $4,956; 
2004: $5,839; 
2005: $3,041; 
2006: $3,825; 
Total: $22,689. 

Southwest Power Pool: Total expenses; 
2002: $37,953; 
2003: $31,635; 
2004: $39,335; 
2005: $51,528; 
2006: $66,078; 
Total: $226,529. 

Southwest Power Pool: 
FTEs; 
2002: 110; 
2003: 116; 
2004: 131; 
2005: 169; 
2006: 245. 

Southwest Power Pool: Salaries and related benefits per FTE; 
2002: $115; 
2003: $116; 
2004: $121; 
2005: $116; 
2006: $107. 

Total salaries and related benefits for RTOs: 
2002: $245,119; 
2003: $279,794; 
2004: $316,603; 
2005: $356,953; 
2006: $367,175; 
Total: $1,565,644. 

Total FTEs: 
2002: 2,092; 
2003: 2,329; 
2004: 2,580; 
2005: 2,617; 
2006: 2,737. 

Total salaries and related benefits per FTE; 
2002: $117; 
2003: $120; 
2004: $123; 
2005: $136; 
2006: $134. 

Source: GAO analysis of independent auditors' reports. FTE information 
provided by RTOs. 

Note: Dollar amounts are inflation-adjusted and presented in 2007 
dollars. Additionally, the sum of component data in this appendix may 
not equal the totals due to rounding. In 2004, PJM changed its method 
of classifying revenues and expenses related to study and 
interconnection fees for financial reporting purposes. The expenses we 
calculated for PJM for 2002 and 2003 are significantly higher than the 
amounts it billed market participants, because we did not retroactively 
apply financial statement reclassifications to data from prior years. 

[End of table] 

[End of section] 

Appendix IV Megawatt hour Load Served by RTO from 2002 through 2006: 

California ISO: Load served in megawatt hours (MWh); 
2002: 220,888,474; 
2003: 220,572,396; 
2004: 229,981,261; 
2005: 234,978,833; 
2006: 240,171,616; 
Total: 1,146,592,580. 

California ISO: Total expenses (Dollars in thousands); 
2002: $241,154; 
2003: $229,737; 
2004: $180,291; 
2005: $172,174; 
2006: $152,569; 
Total: $975,925. 

California ISO: Total expenses per MWh (Dollars); 
2002: $1.09; 
2003: $1.04; 
2004: $0.78; 
2005: $0.73; 
2006: $0.64; 
Total: $0.85. 

ISO New England: Load served (MWh); 
2002: 128,029,400; 
2003: 130,777,700; 
2004: 132,520,500; 
2005: 136,355,200; 
2006: 132,091,800; 
Total: 659,774,600. 

ISO New England: Total expenses (Dollars in thousands); 
2002: $73,362; 
2003: $115,757; 
2004: $127,745; 
2005: $131,768; 
2006: $118,005; 
Total: $566,638. 

ISO New England: Total expenses per MWh (Dollars); 
2002: $0.57; 
2003: $0.89; 
2004: $0.96; 
2005: $0.97; 
2006: $0.89; 
Total: $0.86. 

Midwest ISO: Load served (MWh); 
2002: 365,911,866; 
2003: 460,340,014; 
2004: 628,868,057; 
2005: 691,478,733; 
2006: 668,033,817; 
Total: 2,814,632,487. 

Midwest ISO: Total expenses (Dollars in thousands); 
2002: $94,828; 
2003: $93,489; 
2004: $167,607; 
2005: $283,041; 
2006: $275,075; 
Total: $914,040. 

Midwest ISO: Total expenses per MWh (Dollars); 
2002: $0.26; 
2003: $0.20; 
2004: $0.27; 
2005: $0.41; 
2006: $0.41; 
Total: $0.32. 

New York ISO: Load served (MWh); 
2002: 160,500,000; 
2003: 159,800,000; 
2004: 163,700,000; 
2005: 173,800,000; 
2006: 170,300,000; 
Total: 828,100,000. 

New York ISO: Total expenses (Dollars in thousands); 
2002: $114,185; 
2003: $132,508; 
2004: $149,416; 
2005: $157,979; 
2006: $151,824; 
Total: $705,912. 

New York ISO: Total expenses per MWh (Dollars); 
2002: $0.71; 
2003: $0.83; 
2004: $0.91; 
2005: $0.91; 
2006: $0.89; 
Total: $0.85. 

PJM: Load served (MWh); 
2002: 329,462,687; 
2003: 343,709,652; 
2004: 472,688,685; 
2005: 727,989,643; 
2006: 729,139,288; 
Total: 2,602,989,955. 

PJM: Total expenses (Dollars in thousands); 
2002: $311,657; 
2003: $291,257; 
2004: $235,271; 
2005: $284,220; 
2006: $281,568; 
Total: $1,403,973. 

PJM: Total expenses per MWh (Dollars); 
2002: $0.95; 
2003: $0.85; 
2004: $0.50; 
2005: $0.39; 
2006: $0.39; 
Total: $0.54. 

Southwest Power Pool: Load served (MWh); 
2002: 80,520,302; 
2003: 86,135,886; 
2004: 92,601,921; 
2005: 125,478,287; 
2006: 179,096,451; 
Total: 563,832,847. 

Southwest Power Pool: Total expenses (Dollars in thousands); 
2002: $37,953; 
2003: $31,635; 
2004: $39,335; 
2005: $51,528; 
2006: $66,078; 
Total: $226,529. 

Southwest Power Pool: Total expenses per MWh (Dollars); 
2002: $0.47; 
2003: $0.37; 
2004: $0.42; 
2005: $0.41; 
2006: $0.37; 
Total: $0.40. 

All RTOs: Load served (MWh); 
2002: 1,285,312,729; 
2003: 1,401,335,648; 
2004: 1,720,360,424; 
2005: 2,090,080,696; 
2006: 2,118,832,972; 
Total: 8,615,922,469. 

All RTOs: Total expenses (Dollars in thousands); 
2002: $873,140; 
2003: $894,382; 
2004: $899,664; 
2005: $1,080,711; 
2006: $1,045,120; 
Total: $4,793,017. 

All RTOs: Total expenses per MWh (Dollars); 
2002: $0.68; 
2003: $0.64; 
2004: $0.52; 
2005: $0.52; 
2006: $0.49; 
Total: $0.56. 

Source: GAO analysis of data supplied by RTOs. 

Note: Dollar amounts are inflation-adjusted and presented in 2007 
dollars. Additionally, the sum of component data in this appendix may 
not equal the totals due to rounding. In 2004, PJM changed its method 
of classifying revenues and expenses related to study and 
interconnection fees for financial reporting purposes. The expenses per 
MWh we calculated for PJM for 2002 and 2003 are significantly higher 
than the amounts it billed its members because we did not retroactively 
apply financial statement reclassifications to data from prior years. 
Had 2002 and 2003 expenses been reported as they were from 2004 to 
2006, PJM's inflation-adjusted expenses per MWh would have been $0.52/ 
MWh (instead of $0.95/MWh) in 2002 and $0.59/MWh (instead of $0.85/MWh) 
in 2003. In addition, RTOs utilize differing billing methodologies. As 
a result, the rates it charges market participants may be different 
from the total expenses per MWh calculated in our analysis. 

[End of table] 

[End of section] 

Appendix V: Inflation-Adjusted RTO 2006 Expenses Reported on FERC Form 
No. 1: (Dollars in thousands): 

California ISO: Expenses; Administrative and general expenses; 
$73,220; 48%. 

California ISO: Expenses; Other expenses; 
$28,005; 18%. 

California ISO: Expenses; Transmission expenses; 
$33,678; 22%. 

California ISO: Expenses; Regional market expenses; 
$17,667; 12%. 

California ISO: Expenses; Total; 
$152,570; 100%. 

ISO New England: Expenses: Administrative and general expenses; 
$46,682; 40%. 

ISO New England: Expenses: Other expenses; 
$34,927; 30%. 

ISO New England: Expenses: Transmission expenses; 
$19,845; 17%. 

ISO New England: Expenses: Regional market expenses; 
$16,550; 14%. 

ISO New England: Expenses: Total; 
$118,005; 100%. 

Midwest ISO: Expenses: Administrative and general expenses; 
$68,891; 25%. 

Midwest ISO: Expenses: Other expenses; 
$97,626; 35%. 

Midwest ISO: Expenses: Transmission expenses; 
$53,877; 20%. 

Midwest ISO: Expenses: Regional market expenses; 
$54,681; 20%. 

Midwest ISO: Expenses: Total; 
$275,076; 100%. 

New York ISO: Expenses: Administrative and general expenses; 
$61,145; 42%. 

New York ISO: Expenses: Other expenses; 
$47,114; 32%. 

New York ISO: Expenses: Transmission expenses; 
$17,891; 12%. 

New York ISO: Expenses: Regional market expenses; 
$20,610; 14%. 

New York ISO: Expenses: Total; 
$146,760; 100%. 

PJM: Expenses: Administrative and general expenses; 
$108,979; 39%. 

PJM: Expenses: Other expenses; 
$104,916; 37%. 

PJM: Expenses: Transmission expenses; 
$45,609; 16%. 

PJM: Expenses: Regional market expenses; 
$22,037; 8%. 

PJM: Expenses: Total; 
$281,541; 100%. 

Southwest Power Pool: Expenses: Administrative and general expenses; 
$46,234; 76%. 

Southwest Power Pool: Expenses: Other expenses; 
$6,428; 11%. 

Southwest Power Pool: Expenses: Transmission expenses; 
$3,769; 6%. 

Southwest Power Pool: Expenses: Regional market expenses; 
$4,587; 8%. 

Southwest Power Pool: Expenses: Total; 
$61,018; 100%. 

Total 2006 expenses reported to FERC: Expenses: Administrative and 
general expenses; 
$405,152; 39%. 

Total 2006 expenses reported to FERC: Expenses: Other expenses; 
$319,017; 31%. 

Total 2006 expenses reported to FERC: Expenses: Transmission expenses; 
$174,669; 17%. 

Total 2006 expenses reported to FERC: Expenses: Regional market 
expenses; 
$136,132; 13%. 

Total 2006 expenses reported to FERC: Expenses: Total; 
$1,034,970; 100%. 

Source: GAO analysis of FERC Form No. 1 filings. 

Note: Dollar amounts are inflation-adjusted and presented in 2007 
dollars. Additionally, percentages in this appendix may not add to 100 
due to rounding, and the sum of component data may not equal the totals 
due to rounding. New York ISO, Southwest Power Pool, and PJM expenses 
reported on FERC Form No. 1 filings do not agree with the expenses 
noted on the independent auditors' reports due primarily to differences 
in how certain interest, lease, planning, and other revenues were 
netted against related expense accounts in the FERC Form No. 1 filings. 

[End of table] 

[End of section] 

Appendix VI: Investment in Property, Plant, and Equipment for RTOs as 
of December 31, 2006 (Dollars in thousands): 

California ISO: Property and equipment at cost: Software and equipment; 
$234,735; 59%. 

California ISO: Property and equipment at cost: Construction, work, and 
projects in process; 
$131,400; 33%. 

California ISO: Property and equipment at cost: Buildings and leasehold 
improvements; 
$13,763; 3%. 

California ISO: Property and equipment at cost: Land; 
$9,630; 2%. 

California ISO: Property and equipment at cost: Furniture and fixtures; 
$9,685; 2%. 

California ISO: Property and equipment, gross; 
$399,213; 100%. 

ISO New England: Property and equipment at cost: Software and 
equipment; 
$174,295; 75%. 

ISO New England: Property and equipment at cost: Construction, work, 
and projects in process; 
$24,118; 10%. 

ISO New England: Property and equipment at cost: Buildings and 
leasehold improvements; 
$33,078; 14%. 

ISO New England: Property and equipment at cost: Land; 
0; 0. 

ISO New England: Property and equipment at cost: Furniture and 
fixtures; 
$2,055; 1%. 

ISO New England: Property and equipment, gross; 
$233,546; 100%. 

Midwest ISO: Property and equipment at cost: Software and equipment; 
$325,846; 89%. 

Midwest ISO: Property and equipment at cost: Construction, work, and 
projects in process; 
0; 0. 

Midwest ISO: Property and equipment at cost: Buildings and leasehold 
improvements; 
$33,857; 9%. 

Midwest ISO: Property and equipment at cost: Land; 
$2,216; 1%. 

Midwest ISO: Property and equipment at cost: Furniture and fixtures; 
$3,330; 1%. 

Midwest ISO: Property and equipment, gross; 
$365,248; 100%. 

New York ISO: Property and equipment at cost: Software and equipment; 
$154,053; 79%. 

New York ISO: Property and equipment at cost: Construction, work, and 
projects in process; 
$12,112; 6%. 

New York ISO: Property and equipment at cost: Buildings and leasehold 
improvements; 
$24,054; 12%. 

New York ISO: Property and equipment at cost: Land; 
$2,098; 1%. 

New York ISO: Property and equipment at cost: Furniture and fixtures; 
$2,998; 2%. 

New York ISO: Property and equipment, gross; 
$195,314; 100%. 

PJM: Property and equipment at cost: Software and equipment; 
$285,328; 88%. 

PJM: Property and equipment at cost: Construction, work, and projects 
in process; 
$18,705; 6%. 

PJM: Property and equipment at cost: Buildings and leasehold 
improvements; 
$17,454; 5%. 

PJM: Property and equipment at cost: Land; 
$982; 0. 

PJM: Property and equipment at cost: Furniture and fixtures; 
$788; 0. 

PJM: Property and equipment, gross; 
$323,256; 100%. 

Southwest Power Pool: Property and equipment at cost: Software and 
equipment; 
$59,654; 85%. 

Southwest Power Pool: Property and equipment at cost: Construction, 
work, and projects in process; 
$6,303; 9%. 

Southwest Power Pool: Property and equipment at cost: Buildings and 
leasehold improvements; 
$513; 1%. 

Southwest Power Pool: Property and equipment at cost: Land; 
$337; 0. 

Southwest Power Pool: Property and equipment at cost: Furniture and 
fixtures; 
$3,246; 5%. 

Southwest Power Pool: Property and equipment, gross; 
$70,054; 100%. 

Total 2006 property, plant, and equipment for RTOs: Property and 
equipment at cost: Software and equipment; 
$1,233,910; 78%. 

Total 2006 property, plant, and equipment for RTOs: Property and 
equipment at cost: Construction, work, and projects in process; 
$192,638; 12%. 

Total 2006 property, plant, and equipment for RTOs: Property and 
equipment at cost: Buildings and leasehold improvements; 
$122,718; 8%. 

Total 2006 property, plant, and equipment for RTOs: Property and 
equipment at cost: Land; 
$15,262; 1%. 

Total 2006 property, plant, and equipment for RTOs: Property and 
equipment at cost: Furniture and fixtures; 
$22,102; 1%. 

Total 2006 property, plant, and equipment for RTOs: Property and 
equipment, gross; 
$1,586,631; 100%. 

Source: GAO analysis of independent auditors' reports. 

Note: Dollar amounts are inflation-adjusted and presented in 2007 
dollars. Additionally, percentages in this appendix may not add to 100 
due to rounding, and the sum of component data may not equal the totals 
due to rounding. 

[End of table] 

[End of section] 

Appendix VII: Indexed Electricity Prices, 1990-2007: 

As part of our effort to examine trends in state-level prices for 
industrial customers, we created indexes of prices at the state level. 
[Footnote 44] The indexes reflect the average of electricity prices 
paid by industrial customers, divided by the comparable national 
average price. As such, a state with an index greater than 1.0 would 
indicate that the state price was greater than the national average and 
vice versa. Such an approach focuses attention on how prices compare to 
the national average and how the different states' standing relative to 
the national average changes over time. This approach also avoids the 
necessity of deciding which deflator is most appropriate for adjusting 
nominal electricity prices for inflation. 

To examine the trends in these indexes for the different regions of the 
country according to their RTO affiliations, we created weighted 
average indexes consistent with our RTO classifications described in 
appendix I. We chose to include Texas in this analysis for purposes of 
comparison. We obtained a weighted average by multiplying each state's 
index for a given year by the share of its retail sales of electricity 
to industrial customers relative to its group's total, and then summing 
up the resulting multiples for all the states in a given group. The 
results of this effort are reasonably consistent with the results of 
the basic price analysis reflected in figure 10 of the report. This 
analysis provides additional insights into price trends over the period 
of analysis. For example, it shows that from about 1997 through 2002, 
the original and new RTO states witnessed relative price decreases 
compared to the non-RTO group. Further, it appears that from 2002 
through the most recent data in 2007, the original RTO states also 
witnessed relative price increases that effectively erased the decline 
in prices from 1997 through 2002. In this analysis, these prices 
(original RTO states) in 2007 are higher, in a relative sense, than 
they were prior to restructuring in 1997. Industrial prices in Texas, 
generally not overseen by FERC, have witnessed notable relative price 
increases since the introduction of restructuring. It is important to 
note that this analysis provides a look at price trends and does not 
provide any indication of RTOs causing these trends or even influencing 
them. Notably, both the original RTO states and Texas are highly 
reliant on natural gas, the prices of which have increased dramatically 
in recent years. 

Figure 13: Comparison of Relative Electricity Prices for Industrial 
Customers, 1990-2007: 

[See PDF for image] 

This figure is a multiple line graph depicting the following data: 

Year: 1990; 
Index of prices, New RTO: 0.95; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.30; 
Index of prices, California: 1.54; 
Index of prices, Texas: 0.95. 

Year: 1991; 
Index of prices, New RTO: 0.96; 
Index of prices, Non-RTO: 0.85; 
Index of prices, Original RTO: 1.35; 
Index of prices, California: 1.57; 
Index of prices, Texas: 0.86. 

Year: 1992; 
Index of prices, New RTO: 0.94; 
Index of prices, Non-RTO: 0.85; 
Index of prices, Original RTO: 1.37; 
Index of prices, California: 1.57; 
Index of prices, Texas: 0.87. 

Year: 1993; 
Index of prices, New RTO: 0.92; 
Index of prices, Non-RTO: 0.87; 
Index of prices, Original RTO: 1.38; 
Index of prices, California: 1.51; 
Index of prices, Texas: 0.89. 

Year: 1994; 
Index of prices, New RTO: 0.92; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.38; 
Index of prices, California: 1.49; 
Index of prices, Texas: 0.90. 

Year: 1995; 
Index of prices, New RTO: 0.94; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.38; 
Index of prices, California: 1.58; 
Index of prices, Texas: 0.86. 

Year: 1996; 
Index of prices, New RTO: 0.94; 
Index of prices, Non-RTO: 0.89; 
Index of prices, Original RTO: 1.38; 
Index of prices, California: 1.51; 
Index of prices, Texas: 0.88. 

Year: 1997; 
Index of prices, New RTO: 0.95; 
Index of prices, Non-RTO: 0.87; 
Index of prices, Original RTO: 1.38; 
Index of prices, California: 1.53; 
Index of prices, Texas: 0.89. 

Year: 1998; 
Index of prices, New RTO: 0.97; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.35; 
Index of prices, California: 1.45; 
Index of prices, Texas: 0.88. 

Year: 1999; 
Index of prices, New RTO: 0.98; 
Index of prices, Non-RTO: 0.89; 
Index of prices, Original RTO: 1.26; 
Index of prices, California: 1.48; 
Index of prices, Texas: 0.90. 

Year: 2000; 
Index of prices, New RTO: 0.94; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.33; 
Index of prices, California: 1.54; 
Index of prices, Texas: 0.95. 

Year: 2001; 
Index of prices, New RTO: 0.87; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.26; 
Index of prices, California: 1.83; 
Index of prices, Texas: 1.04. 

Year: 2002; 
Index of prices, New RTO: 0.91; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.22; 
Index of prices, California: 2.01; 
Index of prices, Texas: 0.95. 

Year: 2003; 
Index of prices, New RTO: 0.89; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.26; 
Index of prices, California: 1.88; 
Index of prices, Texas: 1.03. 

Year: 2004; 
Index of prices, New RTO: 0.88; 
Index of prices, Non-RTO: 0.89; 
Index of prices, Original RTO: 1.29; 
Index of prices, California: 1.76; 
Index of prices, Texas: 1.12. 

Year: 2005; 
Index of prices, New RTO: 0.84; 
Index of prices, Non-RTO: 0.89; 
Index of prices, Original RTO: 1.32; 
Index of prices, California: 1.66; 
Index of prices, Texas: 1.25. 

Year: 2006; 
Index of prices, New RTO: 0.84; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.40; 
Index of prices, California: 1.64; 
Index of prices, Texas: 1.27. 

Year: 2007; 
Index of prices, New RTO: 0.86; 
Index of prices, Non-RTO: 0.88; 
Index of prices, Original RTO: 1.43; 
Index of prices, California: 1.56; 
Index of prices, Texas: 1.22. 

Source: GAO analysis of Energy Information Administration data. 

[End of figure] 

[End of section] 

Appendix VIII: Summary of Expert Studies Analyzing the Benefits of 
Restructuring and Regional Transmission Organizations: 

Study and date: A Cost-Benefit Assessment of Wholesale Electricity 
Restructuring and Competition in New England (2006); 
Author and affiliation: M. Barmack, E. Kahn, and S. Tierney, Analysis 
Group; 
Assessment of net benefits: Restructuring and competition in New 
England resulted in relatively small savings in the capital and 
operating costs of wholesale electricity. No specific analysis of the 
impact of wholesale cost savings on consumer prices; 
Primary measure of net benefits/major data elements: Capital and 
operating costs of electricity generation; 
Study conclusion and GAO comment: Sponsored by an electricity-
generating company. Estimated that restructuring and competition 
resulted in an expected 2 percent savings in wholesale electricity 
costs for New England from 2002 to 2018. Net benefits estimate based on 
comparing model simulations of capital and operating costs of the 
restructured electric industry in New England with simulations of 
investments and operating costs in a "counterfactual" case with more 
traditional regulation and without industry restructuring. Attributed 
very significant benefits to greater nuclear plant efficiency from 
restructuring and competition. 

Study and date: Electricity Prices and Costs under Regulation and 
Restructuring (2008); 
Author and affiliation: S. Blumsack, L. Lave, and J. Apt, Carnegie 
Mellon Electricity Industry Center; 
Assessment of net benefits: Restructuring has been beneficial to 
companies that restructured, but the evidence regarding the impact of 
RTOs on consumers is far less clear; 
Primary measure of net benefits/major data elements: A measure of the 
gap between prices and firm-level costs of generating electricity; 
Study conclusion and GAO comment: Constructed an economic and 
statistical model to study the impact of various elements of retail and 
wholesale restructuring on the price-cost markup of electricity-
generating companies. Asserted that restructuring was beneficial to 
companies that restructured, based on the conclusion that 2 to 3 cents 
per kilowatt-hour of the difference between prices and costs was 
explained by restructuring rather than increases in fuel prices.[A] 
Concluded that of the various restructuring elements, RTO membership 
had little overall impact on the price-cost markup.[B] 

Study and date: Measuring and Explaining Electricity Price Changes in 
Restructured States (2006); 
Author and affiliation: M. Fagan, Mossavar-Rahmani Center for Business 
and Government, Harvard University; 
Assessment of net benefits: The study finds no evidence that RTO 
formation or industry restructuring explains price differences among 
regions of the country; 
Primary measure of net benefits/major data elements: Industrial 
electricity prices; 
Study conclusion and GAO comment: Compared actual average retail 
industrial electricity prices with model-predicted prices in states 
classified as restructured and nonrestructured in 2001-2003. Concluded 
that prices were lower than predicted in two-thirds of restructured 
states and in about one-quarter of nonrestructured states. Concluded 
also that regulatory reform at neither the retail nor wholesale levels 
(RTO participation) was a significant driver of the difference in price 
trends. 

Study and date: Putting Competitive Power Markets to the Test (2005); 
Author and affiliation: Global Energy Decisions; 
Assessment of net benefits: Consumers in the Eastern Interconnect 
region (entire United States except 11 Western states and Texas) 
benefited from large savings in the cost of utility wholesale purchases 
of electric power; 
Primary measure of net benefits/major data elements: Operating costs of 
producing electric power; 
Study conclusion and GAO comment: Commissioned by private energy 
companies. Concluded that wholesale competition in the electricity 
industry in the Eastern Interconnect region resulted in large net 
economic benefits and that RTOs contributed significantly to the 
realization of these benefits. Used a computer model to simulate 
wholesale electricity production costs for 1999-2003 under two 
scenarios: simulating (1) actual restructuring events over 1999-2003 
and (2) the absence of procompetitive FERC reform over the same period. 
Concluded that procompetitive reforms resulted in about $15 billion net 
savings. Savings largely driven by dramatically improved efficiencies 
of power plants. Also specifically estimated large net economic 
benefits from expansion of the PJM Interconnect in 2004, supporting the 
conclusion that RTO formation and operations played an important role 
in realizing the benefits of competition. 

Study and date: Analysis of the Impact of Coordinated Electricity 
Markets on Consumer Electricity Charges (2007); 
Author and affiliation: S. Harvey, B. McConihe, and S. Pope, LECG; 
Assessment of net benefits: Average retail prices are slightly lower 
per megawatt hour for PJM and New York ISO residential consumers than 
if coordinated markets had not been implemented; 
Primary measure of net benefits/major data elements: Average 
residential prices for selected states that are members of RTOs and 
states that are not members of RTOs in 1990-2004; 
Study conclusion and GAO comment: Commissioned by PJM. Used several 
statistical economic models to isolate the impact of electricity 
restructuring from several other variables that affect electricity 
prices. All model specifications indicated somewhat lower prices 
associated with restructuring. Concluded that while current RTO markets 
are imperfect, they have provided material benefits to consumers. 

Study and date: LMP Electricity Markets: Market Operations, Market 
Power, and Value for Consumers (2006); 
Author and affiliation: E. Hausman and others, Synapse Energy 
Economics; 
Assessment of net benefits: LMP markets in RTOs have not delivered 
benefits to consumers in ISO New England and PJM; resource owners have 
reaped windfall profits; 
Primary measure of net benefits/major data elements: Wholesale 
electricity prices; bidding behavior data, measures of investment in 
generation capacity, market concentration, price-cost markup, demand 
response, congestion costs; 
Study conclusion and GAO comment: Commissioned by the American Public 
Power Association. Concluded that location-based pricing of RTO markets 
like PJM and ISO New England represented the best approach available 
for operating large, interconnected power pools efficiently and 
reliably. Also concluded that the benefits of this form of pricing have 
been limited because markets are based on bids rather than costs and 
lack perfect competition. Further, this pricing mechanism in the PJM 
and ISO New England markets resulted in windfall profits for resource 
owners without benefits to consumers. Found no evidence of this form of 
pricing improving the pattern of investments in the industry. 

Study and date: ISO New England: Delivering Value to the Region (2007); 
Author and affiliation: ISO New England; 
Assessment of net benefits: Large savings in wholesale electricity 
costs in New England and in ratepayers' bills, and other benefits 
including service reliability, lower emissions, and greater demand 
response; 
Primary measure of net benefits/major data elements: Electric system 
costs, cost of electric power generation capacity, new investment in 
generation and transmission, demand response participation, others; 
Study conclusion and GAO comment: Summarized unpublished ISO New 
England analyses that estimated RTO benefits in different aspects of 
electricity service in New England. Estimated average annual wholesale 
market savings of about $850 million from 2000 to 2006, equivalent to 
an approximate net monthly savings of $4 for the average New England 
ratepayer. Quantified other RTO benefits, such as lower emissions of 
certain pollutants. Concluded that ISO New England had a significant 
role in enhancing the reliability and efficiency of the region's 
electricity industry and can help achieve the region's environmental 
goals by enabling the interconnection of low-carbon-emitting resources, 
benefit the region's electricity consumers, improve planning, and more. 

Study and date: Markets for Power in the United States: An Interim 
Assessment (2006); 
Author and affiliation: P. Joskow, MIT; 
Assessment of net benefits: Lower prices for residential and industrial 
consumers; 
Primary measure of net benefits/major data elements: Average industrial 
and residential prices; 
Study conclusion and GAO comment: Constructed an economic and 
statistical model to study the effects of retail and wholesale 
competition on electricity prices for residential and industrial 
consumers, using the share of electricity generated by unregulated 
generators in a state as a proxy measure for the effect of wholesale 
restructuring.[C] Concluded that greater activity in a state's 
wholesale electricity market is associated with lower prices for 
residential and industrial consumers, supporting the study's view that 
RTOs improved industry performance. 

Study and date: Restructuring the U.S. Electric Power Sector: A Review 
of Recent Studies (2006); 
Author and affiliation: J. Kwoka; 
Assessment of net benefits: Found no reliable or convincing evidence 
that consumers are better off as a result of restructuring the U.S. 
electric power industry; 
Primary measure of net benefits/major data elements: No data analysis 
conducted (review of other studies); 
Study conclusion and GAO comment: Commissioned by the American Public 
Power Association, reviewed 12 studies on the economic impact of 
restructuring in the U.S. electricity industry. Identified serious 
weaknesses in all 12, concluding that the methodologies consistently 
fell short of the standards for good economic research. Most also 
failed to fully address the effects of restructuring. 

Study and date: Midwest ISO Value Proposition (2007); 
Author and affiliation: Midwest ISO; 
Assessment of net benefits: Large net economic benefits in the Midwest 
ISO region in various aspects of electricity services; no specific 
analysis of how benefits affect consumer prices; 
Primary measure of net benefits/major data elements: Size, duration, 
cost, and probability of electricity outages; measures of the use of 
electricity generation capacity and of the cost of reserve generation 
capacity; RTO administrative and operating costs; etc.; 
Study conclusion and GAO comment: Summarized Midwest ISO and consulting 
firm studies that used different approaches to estimating the economic 
impact of Midwest ISO operations in several areas. Concluded that $555 
million to $850 million in annual net economic benefits for the region 
resulted from more efficient use of the industry's resources 
(generation and transmission assets), more reliable service, and 
improved planning and investment patterns. Pointed to unquantified 
benefits related to greater price transparency, regulatory compliance, 
and improved opportunities for demand response and renewable resources. 

Study and date: The Regional Transmission Organization Report Card: 
Wholesale Electricity Markets and RTO Performance Evaluation, 2nd ed. 
(2007); 
Author and affiliation: M. J. Morey and others, Christensen Associates 
Energy Consulting; 
Assessment of net benefits: No conclusions on whether RTOs yielded net 
economic benefits or whether retail consumers were benefiting from 
RTOs; 
Primary measure of net benefits/major data elements: Numerous metrics 
related to prices, costs (including RTO administrative and operating 
costs), market power, plant efficiencies and availability, reliability 
of service, and investments in generation and transmission; 
Study conclusion and GAO comment: Prepared for the National Rural 
Electric Cooperative Association and intended to provide insight into 
RTO performance in various areas. Stated that many industry 
stakeholders were concerned that no single reference document was 
available for RTO statistics to objectively analyze RTO and RTO market 
performance. Consolidated data from different sources to make 
performance comparisons across RTOs. Mentioned areas of strength of 
individual RTOs and expressed concern, particularly about market power, 
demand response, and investments. 

Study and date: 2006 Performance Review of Electric Power Markets 
(2006); 
Author and affiliation: K. Rose, Institute of Public Utilities, 
Michigan State University, and K. Meeusen, Ohio State University; 
Assessment of net benefits: Restructuring electricity markets at least 
so far has resulted in no discernible benefits to consumers of 
electricity; 
Primary measure of net benefits/major data elements: Retail prices of 
electricity; 
Study conclusion and GAO comment: Commissioned by the Virginia State 
Corporation Commission. Addressed retail and wholesale restructuring. 
Recognized that RTOs' "marginal cost" pricing is needed for an 
efficient market under competitive conditions, but expressed concern 
that RTO markets were not sufficiently competitive because consumers 
had very limited ability to respond to high prices by reducing demand 
and because of evidence of market power on the supply side. 

Study and date: Estimating the Benefits of Restructuring Electricity 
Markets: An Application to the PJM Region (2003); 
Author and affiliation: R. J. Sutherland; Assessment of net benefits: 
Restructuring and competition resulted in significant reductions in the 
prices consumers pay for electricity; 
Primary measure of net benefits/major data elements: Residential, 
commercial, and industrial prices; 
Study conclusion and GAO comment: Used a comparison of prices for 1997 
and 2002, assuming that prices were lower in 2002 due to a large extent 
to restructuring. Estimated that PJM electricity consumers saved about 
$3.2 billion in 2002 from restructuring, equivalent to about 15 percent 
of their electricity bills that year. 

Source: GAO. 

Note: Studies are listed alphabetically by author. 

[A] For comparison, the 2007 average retail price of electricity was 
about 9 cents per kilowatt-hour (see fig. 9). 

[B] Blumsack, Lave, and Apt, Electricity Prices (2008), p. 24: 
"Overall, simply joining an RTO has had little effect on price-cost 
markups, although the combination of RTO membership and retail 
competition appears to dampen the increase in price-cost margins.- 

[C] Although the article did not explicitly model the effect of RTO 
membership, the proxy measure for restructuring in the analysis was 
related to RTO membership. The share of electricity generated by 
unregulated generators is likely to be much higher in states that were 
members of RTOs than in states that were not members of RTOs. 

[End of table] 

[End of section] 

Appendix IX: Comments from FERC: 

Federal Energy Regulatory Commission: 
Office Of The Chairman: 
Washington, DC 20426: 

August 28, 2008: 

Mr. Mark Gaffigan: 
Director, Natural Resources and Environment: 
United States Government Accountability Office: 
441 G Street, NW: 
Washington, DC 20548: 

Dear Mr. Gaffigan: 

Thank you for your July 31, 2008 letter enclosing the draft report, 
FERC Could Take Additional Steps to Analyze Regional Transmission 
Organizations' Benefits and Performance. I appreciate the opportunity 
to comment on this report. 

In general, I want to commend the report's useful discussion of these 
complex issues and I appreciate its helpful conclusions. I respond to 
the report's specific recommendations in more detail below, and also 
address several other statements in the report. 

The report recommends, among other things, that the Commission take the 
following actions with respect to regional transmission organizations 
(RTOs): (1) "develop a consistent approach for regularly reviewing 
expense information contained in RTO budgets;" and (2) "routinely 
review and assess the accuracy, completeness, and reasonableness of the 
financial information RTOs report to FERC in their Form No. 1 filings." 

The Commission already has begun implementing part of this 
recommendation, in the context of audits. As the report notes, the 
Commission commenced an audit in May 2008 of the Midwest Independent 
System Operator (MISO). Docket No. PA08-28. The audit scope includes, 
for example, an examination of the RTO costs reported in the FERC Form 
No. 1 to determine whether MISO: (1) recorded its costs in compliance 
with the Uniform System of Accounts and (2) reported the costs 
correctly in the FERC Form No. 1. In future audit cycles, the 
Commission intends to perform audits periodically of financial 
information reported by RTOs in the FERC Form No. 1. 

As to reviewing RTO budgets and the reasonableness of RTO costs, the 
report correctly notes that RTOs provide extensive opportunities for 
stakeholder input on RTO costs, and that RTOs consider such input when 
making decisions on expenditures. This open, transparent process allows 
consumer input in ways not matched by other public utilities. More 
importantly, the report explains that RTO costs for administration and
overhead are a small fraction of consumers' total cost of electricity. 
For example, the report notes that these costs were less than one 
percent of a typical New England consumer's electricity costs. This 
fact is significant in evaluating how the Commission can best use its 
limited resources to ensure that consumers are protected from excessive 
costs. 

In any event, I agree with the recommendation that the Commission 
should increase its efforts to review RTO budgets and the 
reasonableness of RTO costs. I have directed the Commission's staff to 
evaluate possible approaches for implementing this recommendation. 

The report also recommends that the Commission "work with RTOs, 
stakeholders, and other experts to develop standardized measures that 
track the performance of RTO operations and markets." Finally, the 
report recommends that the Commission "report the performance results 
to Congress and the public annually, while also providing 
interpretation of (1) what the measures and reported performance 
communicate about the benefits of RTOs and, where appropriate, (2) 
changes that need to be made to address any performance concerns." 

I agree with the recommendation that the Commission work with RTOs and 
others to develop more standardized measures on the performance of 
RTOs. I am still considering appropriate procedures for developing such 
measures but agree with the goal. Also, as the report notes, it may be 
useful to explore whether the same measures should be developed for non-
RTO regions, to provide an appropriate basis for comparison. 

If the Commission's work with RTOs and others results in development of 
appropriate measures, I also agree that results should be transparent 
and could form the basis for continued improvement in RTO operations 
and markets. RTOs currently provide certain types of information in 
their annual reports on the "State of the Markets," and this may be an 
appropriate vehicle for providing additional information to the public 
on RTO performance. While I am not sure that a formal Commission 
evaluation of results and recommendations for changes would be 
feasible, useful and cost-effective on an annual basis, the Commission 
can work with RTOs and others to determine an appropriate interval for 
assessing performance and possible changes. 

Apart from the foregoing, I would like to address two other statements 
in the report. First, the report states that the Commission "approves 
planning decisions the RTO makes about the need for transmission 
infrastructure." While the Commission approves the general procedures 
used by RTOs to plan transmission infrastructure, and the rate recovery 
of facilities built pursuant to such planning processes, the Commission 
does not approve RTO decisions about which projects should get built. 

Second, the report states that RTOs, compared to other public 
utilities, are "in a position of greater public trust." Although it is 
true that RTO public utilities operate large transmission systems in 
the public interest, many non-RTO public utilities operate similarly 
large, often multi-state, transmission systems. For example, based on 
2008 transmission system planning data reported to the Commission, the 
Southern Company forecasts a peak transmission system demand of 49,221 
MW, in excess of ISO-New England's forecast peak transmission system 
demand of 30,768 MW and Southwest Power Pool's forecast peak 
transmission system demand of 43,834 MW. Further, the Southern Company 
reports 9,581 miles of extra-high voltage (230 kV and above) 
transmission lines, compared to ISO-New England's reported 7,708 
circuit miles for its entire (69 kV and above) transmission system. 
Likewise, the Tennessee Valley Authority and Energy Corporation 
forecast 2008 peak transmission system demands of 34,815 MW and 28,134 
MW, and report transmission system circuit mileage of 17,000 and 
15,500, respectively, also comparable in size to these RTOs. 

There is no public policy reason to hold RTOs to a position of greater 
public trust with regard to planning and operating large regional 
transmission systems. All public utilities are in a position of "public 
trust" with regard to their operation of transmission systems and 
administration of electric markets. While the Commission has emphasized 
the need for RTOs to be independent of market participants, the 
Commission generally applies the same ratemaking practices to RTOs as 
it does to all other public utilities. For example, once the Commission 
approves fixed rates for a public utility, the Commission generally 
does not reexamine the rates annually. This is particularly true when 
inflation and other factors are causing costs to increase (as they are 
now), because any changes in the rates are more likely to be increases 
than decreases. Moreover, Commission efforts to treat RTOs differently 
than other public utilities have been rejected by the courts. E.g., 
California Independent System Operator Corp. v. FERC, 372 F.3d 395 
(D.C. Cir. 2004) (rejecting FERC's effort to change CAISO's governing 
board, stating that the "same statutory terms that apply to FERC's 
regulation of CAISO apply to its regulation of all other jurisdictional 
utilities"); Electric Power Supply Ass 'n v. FERC, 391 F.3d 1255 (D.C. 
Cir. 2004) (rejecting FERC's effort to exempt RTO market monitors from 
ex parte restrictions). 

With these minor clarifications, I find that your report provides a 
useful discussion of issues that have been debated extensively in the 
electricity industry. Your recommendations generally represent 
meaningful measures to enhance public understanding of the performance 
of RTOs and ISOs and the benefits they provide to our Nation's 
electricity consumers. Thank you again for the opportunity to comment 
on your report. 

Sincerely, 

Signed by: 

Joseph T. Kelliher: 
Chairman: 

[End of section] 

Appendix X: GAO Contact and Staff Acknowledgments: 

GAO Contact: 

Mark Gaffigan, (202) 512-3841, gaffiganm@gao.gov: 

Staff Acknowledgments: 

In addition to the individual above Jon Ludwigson, Assistant Director; 
Pedro Almoguera; Dan Egan; Philip Farah; N'Kenge Gibson; Paige 
Gilbreath; Randy Jones; Jennifer Leone; Ying Long; Alison O'Neill; 
Glenn Slocum; Barbara Timmerman; Walter Vance; and George Warnock 
provided significant contributions. 

[End of section] 

Footnotes: 

[1] FERC oversees wholesale electricity sales and interstate 
transmission of electricity by privately owned utilities, among other 
things. 

[2] Consumers often pay a combination of electricity rates and prices. 
Rates are generally approved by regulators and set to recover the cost 
of providing a service plus a rate of return. Transmission and 
distribution expenses, for example, remain regulated and are recovered 
through rates charged to customers. In contrast, prices for generation 
are market-based--determined based on the interaction of supply and 
demand. More specifically, after wholesale restructuring, prices for 
many sales of wholesale electricity began being determined in organized 
markets. These prices are passed on to final consumers, unless the 
state regulatory commission in a nonretail choice state finds a 
wholesale purchase imprudent. (Wholesale sales also occur bilaterally, 
and some utilities generate their own power to sell at retail.) 

[3] In 1996, prior to its RTO policy, FERC called for the creation of 
Independent System Operators (ISO). ISO and RTO characteristics are 
similar, and in many cases, FERC uses the terms interchangeably. 
However, RTOs are intended to cover a large region and, in practice, 
tend to be multistate. In this report, we will use the term "RTO" to 
refer to both RTOs and ISOs. 

[4] FERC has approved four RTOs: ISO New England, Midwest ISO, PJM 
Interconnection (in the Mid-Atlantic and parts of the Midwestern United 
States), and Southwest Power Pool. It has approved two Independent 
System Operators: California ISO and New York ISO, which, as noted 
previously, will be referred to as RTOs in this report. The Electric 
Reliability Council of Texas, an Independent System Operator, is 
primarily regulated by the Public Utility Commission of Texas. 

[5] This authority is granted under Section 205 and 206 of the Federal 
Power Act, 16 U.S.C. §§ 824d-824e. 

[6] RTO financial statements and independent auditors' reports are 
filed on a calendar year basis, which does not correspond with the 
federal fiscal year. 

[7] GAO, Standards for Internal Control in the Federal Government, 
[hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO/AIMD-00-21.3.1] 
(Washington, D.C.: November 1999). 

[8] This authority is granted under Section 205 and 206 of the Federal 
Power Act, 16 U.S.C. §§ 824d -824e. 

[9] With the advent of restructuring, companies began to request 
approval from FERC to charge market-based prices. As a result, FERC 
departed from its historical policy of basing rates upon the cost of 
providing service plus a fair return on invested capital. FERC 
initially began considering proposals for market-based prices on a case-
by-case basis. Over the years, FERC began granting authority to charge 
market-based prices to companies that could demonstrate these market-
based prices were established in a competitive context. See FERC Order 
697, "Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities," June 21, 2007. 

[10] These requirements were outlined in FERC's Order 888--"Promoting 
Wholesale Competition through Open Access Non-discriminatory 
Transmission Services by Public Utilities"--issued April 1996. 

[11] Other expected benefits included facilitating the development of 
environmentally preferred generation, increased coordination among 
state regulatory agencies, reduced transaction costs, and the 
facilitation of the success of state retail competition programs. 
Furthermore, RTOs were expected to more effectively manage "parallel 
path flows," a term that refers to the fact that electricity flows over 
all possible transmission lines regardless of who owns the lines and 
what transmission contracts were agreed to. According to FERC, because 
of this engineering reality, many transmission owners found their grids 
overloaded by the actions of others. Since they were unable to 
determine the responsible party, these owners had to curtail their own 
use of their grids. 

[12] As noted in the introduction, throughout this report, we use the 
term "RTO" to refer to RTOs and Independent System Operators--entities 
with similar, though not identical, characteristics and purposes. 

[13] Order 2000 neither required nor prohibited RTO ownership of 
transmission lines. In practice, however, the RTOs developed in the 
United States do not own transmission lines. 

[14] These figures are based on recent estimates from four states: 
Connecticut, Indiana, Illinois, and California. Because the source data 
are from different regions and because utilities in these regions may 
pass through other charges, such as bond repayments, to customers, 
estimates may not total 100 percent. 

[15] The amount of electricity procured in RTO markets varies across 
RTO regions. Electricity may also be self-supplied by utilities that 
continue to own generators or procured through bilateral contracts, 
agreements made directly between parties. According to figures provided 
by five of the six RTOs, between 3 and 55 percent of energy transacted 
in RTO regions is through RTO wholesale markets. Most of the remaining 
45 to 97 percent is transacted through bilateral contracts or is self- 
supplied. 

[16] Capacity represents the maximum amount of power that a given 
system can produce at a particular moment. It reflects the ability to 
produce electricity when needed and is sold separately from electric 
power. Ancillary services are necessary to support the reliable 
operation of the transmission system and provision of electricity at 
appropriate frequency and voltage levels. 

[17] 16 U.S.C. § 824e. 

[18] Numbers in this section for expenses, expenses per MWh, rates and 
investments in property, plant, and equipment are inflation adjusted 
and presented in 2007 dollars. 

[19] FTEs reflect staffing levels at the end of each year reported. As 
a result, average salary and related benefits per FTE may not reflect 
RTO staffing changes throughout the year. 

[20] Depreciation and amortization expense allocates the acquisition 
cost of an asset, less its estimated salvage or residual value, over 
its estimated useful life. This expense reflects the use of the asset 
during specific operating periods to match costs with related revenues 
in measuring income or determining the costs of carrying out program 
activities. RTOs often use depreciation and amortization expenses to 
recover the costs of financing an asset, such as a computer system or 
control center. 

[21] Other expenses include taxes, net interest charges, and expenses 
related to customer accounts and service. 

[22] Total investment in property, plant, and equipment is not adjusted 
for depreciation because accumulated depreciation was not allocated to 
specific asset classes in the independent auditors' reports. 

[23] State regulating authorities are a formal stakeholder group in 
Midwest ISO and vote at the primary committee level. 

[24] California ISO is unique among the six RTOs we reviewed in that it 
does not use a committee structure to solicit input from stakeholders. 
However, California ISO stakeholder meetings and board meetings are 
open to all interested parties. 

[25] In Southwest Power Pool, the finance committee recommends the 
budget to the board and votes by simple majority. The primary committee 
does not vote on the budget. 

[26] In five cases in 2004, FERC's Office of Enforcement conducted 
limited reviews of RTO budgets and expenses during the course of audits 
to determine RTO compliance with governance policies, practices, and 
procedures. 

[27] According to FERC, the rate-setting process involves extensive 
examination of expenses, interventions by customers and other 
stakeholders, and months of testimony and cross-examination before an 
administrative law judge. It can be an expensive and time-consuming 
process and may take years to complete. FERC's rates for RTOs tend to 
remain in place for years. 

[28] In 2004, FERC did review Midwest ISO's rate for recovering 
expenses associated with operating its financial transmission rights 
and energy market. However, it has not reviewed Midwest ISO's tariff 
administration and reliability expenses since 2001. 

[29] According to FERC officials, through their attendance at Midwest 
ISO Advisory Committee meetings, they would most likely be aware of 
these and other stakeholder issues. 

[30] FERC's 2004 work was presented in "Staff Report on Cost Ranges for 
the Development and Operation of a Day One Regional Transmission 
Organization." October 2004. 

[31] According to an ISO New England representative, nonprofit RTOs 
must comply with Internal Revenue Service standards governing the 
reasonableness of compensation for executives, including base salaries. 
Executive compensation must fall within a range of competitive 
practices for total compensation paid by similarly situated 
organizations, both taxable and tax-exempt, for functionally comparable 
positions. To ensure compliance with these procedures, ISO New England 
has engaged a nationally recognized, independent consulting firm to 
evaluate compensation offered by similarly situated entities. 

[32] Rate-setting proceedings at FERC involving proposed rates are 
generally conducted under authority granted in Section 205 of the 
Federal Power Act and are commonly referred to as Section 205 hearings. 
The authority of FERC to receive complaints that existing rates are not 
just and reasonable is generally under Section 206 of the Federal Power 
Act and are commonly referred to as Section 206 complaints. 

[33] Lowering the cost of electricity production can result in lower 
electricity prices, higher profits for generators and others that sell 
electric power, or a combination of both effects. 

[34] See appendix I for a more complete description of our methodology. 
Our analysis was based on state-level data that we obtained from the 
Energy Information Administration on electric power retail sales and 
electric revenues. We divided the states into four geographic groups. 
Over the time period analyzed, California's electricity industry went 
through turbulent changes that would unduly influence any grouping in 
which it would otherwise fall; therefore, we included California in a 
category by itself. We did not include Texas in our analysis, because 
its market is largely unregulated by FERC. A listing of states in each 
category is in appendix I. 

[35] We found similar relationships by examining indexes of prices, 
relative to the national average, which are reflected in appendix VII. 

[36] Various studies have used economic techniques to isolate the 
impacts of restructuring and RTOs from other factors that influence 
electricity prices. These studies reach different conclusions, as shown 
in appendix VIII. 

[37] Transmission congestion refers to instances in which a 
transmission line has insufficient capacity to transfer the electricity 
needed to satisfy demand in a particular area. An area that does not 
have sufficient transmission capacity may have to rely on local power 
plants whose production costs may be higher than those for electricity 
supplies from other locations. Inability to import lower-cost supplies 
may cause electricity prices in the transmission-constrained area to be 
higher than would be the case without congestion. 

[38] FERC, Wholesale Competition in Regions with Organized Electric 
Markets, Docket RM07-19-000 and AD07-7-000, February 22, 2008. 

[39] FERC's estimate was based on a model developed by ICF Inc. 

[40] We adjusted FERC's estimate of natural gas prices and the actual 
prices to 2007 dollars to facilitate comparison. 

[41] These include, among other things, data on load, prices, outage 
rates, net revenue, imports and exports, and generation by fuel type. 

[42] FERC annually produces the "State of the Markets Report," which 
contains broad information on the electricity and natural gas 
industries. 

[43] GAO, Managing for Results: Enhancing Agency Use of Performance 
Information for Management Decision Making, [hyperlink, 
http://www.gao.gov/cgi-bin/getrpt?GAO-05-927] (Washington D.C.: Sept. 
9, 2005). 

[44] Data collected by the Energy Information Administration reflect 
average revenue per kilowatt-hour of electricity sold to customers and 
represent a proxy for prices. 

[End of section] 

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