Federal Energy 

Regulatory Commission

2007 Annual Report

Federal Energy 

Regulatory Commission

2007 Annual Report

2007 | ANNUAL REPORT

iii

Message froM the ChairMan ........................................................................................................................ 1

seCtion 1. ManageMent suMMary

Organization ........................................................................................................................................................................ 5

Summary ............................................................................................................................................................................... 5

Energy Infrastructure ........................................................................................................................................................................7

Market Regulation ..............................................................................................................................................................................7

Safety .............................................................................................................................................................................................................8

Reliability ....................................................................................................................................................................................................8

Enforcement ............................................................................................................................................................................................9

seCtion 2. energy infrastruCture 

Natural Gas ........................................................................................................................................................................12

Gas Pipelines .........................................................................................................................................................................................12

LNG Facilities .......................................................................................................................................................................................14

Storage Projects .................................................................................................................................................................................15

Environmental Mitigation ..........................................................................................................................................................16

Landowner Issues ..............................................................................................................................................................................17

Electric ..................................................................................................................................................................................20 

Transmission Investment ............................................................................................................................................................20

Transmission Expansion Cost Allocation ........................................................................................................................21

Transmission Line Siting ...............................................................................................................................................................22

Hydropower .......................................................................................................................................................................23

Hydropower Projects .....................................................................................................................................................................23

Hydrokinetic Energy .......................................................................................................................................................................24

Integrated Licensing Process ....................................................................................................................................................25

Environmental Mitigation ..........................................................................................................................................................26

Oil Pipelines .......................................................................................................................................................................26

seCtion 3. Market regulation

Fair and Efficient Competitive Market Rules ......................................................................................................30

Market Rule Changes .....................................................................................................................................................................30

Demand Response ...........................................................................................................................................................................31

Open Access Transmission Tariff Reform .......................................................................................................................32

Long-Term Transmission Rights .............................................................................................................................................33

Reduction of Barriers to Trade ................................................................................................................................................34

Preventing Accumulation and Exercise of Market Power .............................................................................34

Review of Mergers and Acquisitions and Other Corporate Transactions .............................................34

Market Power in Wholesale Power Sales ........................................................................................................................36

Standards of Conduct ...................................................................................................................................................................37

Western Energy Settlements ...................................................................................................................................................37
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Section 4. Safety

Natural Gas ........................................................................................................................................................................39 

Safety at LNG Facilities...................................................................................................................................................................39

Hydropower........................................................................................................................................................................40

Dam Safety..............................................................................................................................................................................................40

Section 5. Reliability

Reliability Standards ......................................................................................................................................................43

Cyber Security ...................................................................................................................................................................44

Section 6. Enforcement

Vigilant Oversight ...........................................................................................................................................................48

Identification and Remedy of Potential Market Problems.................................................................................48

Transparency..........................................................................................................................................................................................49

Market Oversight...............................................................................................................................................................................50

Financial Forms....................................................................................................................................................................................50

Market Monitoring Units.............................................................................................................................................................51

Firm but Fair Enforcement ..........................................................................................................................................52

Clear and Fair Processes ...............................................................................................................................................................52

Investigations and Enforcement ............................................................................................................................................53

Internal Compliance .......................................................................................................................................................................56

Industry Compliance through Audits ...............................................................................................................................57

Appendix A Background information ............................................................................................. 59

Commission Overview ..................................................................................................................................................59

Regulatory Authority .....................................................................................................................................................60

Strategic Plan ....................................................................................................................................................................61

Office Descriptions .........................................................................................................................................................63

Guiding Principles ...........................................................................................................................................................64

Appendix B Settlements and the Alternative Dispute Resolution Process ..................... 66

Appendix C Hydroelectric power Table ........................................................................................... 68

Appendix D List of Acronyms ................................................................................................................ 71
2007 | ANNUAL REPORT

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I am pleased to submit to the Congress the Federal Energy 

Regulatory Commission’s annual report, covering the 

fiscal year from October 1, 2006, through September 

30, 2007. This is the 87th Annual Report issued by the Commission and its predecessor, the Federal Power Commission. 

This year saw the impacts of the dramatic shifts occurring in 

the nation’s natural gas and electricity markets, both in the industries themselves and in the focus and activities of this Commission. These shifts, and the continuing evolution of the energy 

marketplace, create an important backdrop for the work FERC 

performed in Fiscal Year 2007. I am proud of our accomplishments, which are detailed throughout this report. Here, however, I would like to address the context in which this Commission 

conducts its business on behalf of American energy consumers.

The notion of a U.S. natural gas market is behind us; it has 

evolved into a North American market, with reliance upon Canadian imports to meet our needs, to become a truly international regime. North American gas production is inadequate to 

meet North American demand. U.S. gas producers have had 

impressive success in developing reserves in the lower 48 and 

domestic gas production has risen ten percent over the past 

two years. Yet production in some regions is declining. Overall, 

U.S. gas production is expected to remain relatively flat, while 

Canadian imports are projected to fall sharply at the same time 

that U.S. demand continues to increase.

The reality is that liquefied natural gas (LNG) is the fastest growing source of U.S. natural gas supply, and will remain 

so for the foreseeable future. Competition for LNG will be worldwide and vigorous, with European and the Asia-Pacific 

markets vying for LNG to fuel their energy-intensive economies. The U.S. can mitigate some of the volatility and price 

impacts by taking steps such as providing for adequate import capability, certificating sufficient natural gas pipeline 

facilities, and increasing natural gas storage. 

Natural gas costs and supply arising from the changing market also will have a significant impact on U.S. electricity markets. To some extent, there is a growing convergence between natural gas and power markets. Natural gas has 

become the fuel of choice for newly-developed electric generation. Natural gas-fired generation benefits from operational flexibility, relatively short construction periods, lower emissions and, to date, relatively cost-effective fuel.

U.S. electricity markets continue to evolve, moving from localized centers to regional, and in some cases, North 

American trading. This changes how electricity is procured and how it is transmitted. Wholesale power markets—some 

organized, others characterized by bi-lateral contracting among parties—exist across the nation. Transmission, consequently, is moving from the equivalent of farm-to-market roads to superhighways. 
2

FEDERAL ENERGY | FERC REGULATORY COMMISSION

At the same time, the nation faces the challenge of determining how to secure electricity supply at a reasonable 

cost. Electricity demand continues to rise as our economy grows. There are a range of projections, but according to 

some estimates, the U.S. may have to add 230 gigawatts to its generating capacity over the next 15 years. Whether 

and how new generation is developed depends upon a number of factors, not least of which is whether and how the 

nation—or regions—will implement policies to curb greenhouse gas emissions. Demand response and energy efficiency also will play a role in meeting reliability and environmental needs, requiring close integration into the nation’s 

market structures and transmission system. 

Of course, the addition of generation must be accompanied by adequate transmission. Transmission systems in 

parts of the nation suffer from significant constraints. While the U.S. system is extensive, it has suffered from a sustained 

period of inadequate investment. The last sustained period of adequate investment in the U.S. power grid took place 

in the 1970s. However, we may have turned a corner. Transmission investment has nearly doubled in recent years, and 

a number of major backbone transmission projects have been proposed in several regions. 

The above discussion provides the context in which FERC pursued our mission. FERC undertook these activities 

within the role and authorities determined by Congress. The U.S energy regulatory regime is federalist in nature and 

both federal and state regulators have important roles. Within the bounds set for it, FERC’s actions play a significant 

role in implementing national energy policy and in ensuring reliable, reasonably-priced energy. 

In FY 2007, the Commission focused on five core missions: Market Regulation, Energy Infrastructure, Safety, Reliability and Enforcement. Two of these missions—Enforcement and Reliability—are relatively new or expanded. In FY 

2007, the Commission’s implementation of these two missions matured, with significant actions taken in authorizing 

mandatory reliability standards, issuing penalties, and promulgating show cause orders for potential market manipulation. Each of these actions plays an important role in helping the nation meet the challenges ahead by ensuring the 

reliability of electricity supply, protecting consumers from those who would manipulate energy markets, and ensuring 

that players in relevant energy markets operate under the regulations and rules established by this Commission.

FERC continued to pursue other areas: siting and reviewing facilities such as gas pipelines, LNG facilities and hydropower projects; preventing the exercise of market power; assuring just and reasonable rates; refining market rules; and 

assuring safety. These achievements support the infrastructure and market development that will help the U.S. meet 

the challenges ahead. I am proud of the staff here at FERC, and commend them for their knowledge and dedication to 

serving energy consumers in this nation. 

Finally, I would like to recognize my colleagues and the FERC staff, whose efforts helped FERC to achieve one of this 

agency’s most notable years. To them, I convey my thanks and congratulations.

Sincerely,

Joseph T. Kelliher

Chairman
2007 | ANNUAL REPORT

3

SUEDEEN G. KELLY

Commissioner

PHILIP D. MOELLER

Commissioner

MARC SPITZER

Commissioner

JON WELLINGHOFF

Commissioner

2007 | ANNUAL REPORT

5

Management 

Summary

Organization

The Commission is an independent regulatory agency within the U.S. Department of Energy (DOE) whose function is 

to regulate the Nation’s electric, natural gas, hydroelectric 

and oil pipeline industries. It is headed by a bi-partisan, fivemember Commission, comprised of the Chairman and four 

Commissioners who are appointed by the President and 

confirmed by the Senate. The Chairman serves as the chief 

executive officer. In FY 2007, FERC was organized into eight 

functional offices (see table on page 6). In September 2007, 

the Commission signaled the growing importance of the 

Commission’s work on the reliability of the nation’s bulk 

power system by announcing the creation of a new Office 

of Electric Reliability. The Commission’s headquarters are 

in Washington, D.C., and the agency has five regional offices throughout the country dedicated to hydroelectric 

dam safety.

In FY 2007, Congress appropriated $221,901,518 to 

support Commission activities. As of September 30, 2007, 

the Commission had 1,292 staff, including 1,271 permanent staff and 21 temporary staff.

Summary

Fiscal year 2007 was a landmark in Commission history, 

as it took important steps to implement and exercise the 

new authorities granted by the Energy Policy Act of 2005 

(EPAct 2005). Pursuant to the Act, the Commission approved mandatory reliability standards for the bulk power 

system. Beginning in the summer of 2007, compliance with 

reliability standards became mandatory, with the authority 

of the Commission behind them. Pursuant to EPAct 2005, 

the Commission also expanded its enforcement activities, 

and issued its first penalties. To fulfill its market regulation 

mission, the Commission must promulgate regulations, setting the rules under which wholesale competition occurs.

Enforcement activities ensure compliance with these rules, 

and protect consumers from the consequences of market 

participant misconduct.

The Commission also made significant progress on 

other goals, responding to the current and growing demand for electricity and natural gas. It issued regulations 

to encourage fair and effective competition in wholesale 

markets, and to prevent the accumulation and exercise 

of market power. Integrated into these rules were new 

provisions to include demand response in planning and 

to facilitate demand response in organized markets. The 

Commission also established incentives for significant 

transmission development, and issued rules governing 

its limited authority to site transmission facilities. It also 

moved to respond quickly when companies proposed to 
FEDERAL ENERGY | FERC REGULATORY COMMISSION

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Federal Energy Regulatory Commission

Commissioner Commissioner Chairman Commissioner Commissioner 

Office of

Administrative

Law Judges

Office of the 

Executive Director

Office of

Administrative

Litigation

Office of

External Affairs 

Office of the

General Counsel 

Office of

Enforcement 

Office of Energy

Markets and 

Reliability

Office of

Energy Projects

Note: The chart above depicts the Commission on September 30, 2007, the last day of FY 2007. On October 1, 

2007, the Office of Electric Reliability was created. Reliability had previously been a division within the Office of 

Energy Market and Reliability, which was subsequently renamed the Office of Energy Market Regulation.
2007 | ANNUAL REPORT

7

expand or construct needed pipeline and LNG facilities, 

or to license hydroelectric facilities. Notably, new rules 

were proposed for processes and standards for issuing 

and enforcing preliminary permits for hydrokinetic generation facilities. The agency also proposed a new pilot 

license program to allow developers to test technologies 

and sites, and to confirm environmental impacts. Finally, 

the Commission focused closely on its responsibilities to 

oversee the safety of LNG and hydroelectric facilities.

The Commission’s accomplishments in these areas are notable, and summary lists follow. The report 

that follows this summary provides more detail, and is 

divided to reflect its five priorities for the year: Energy 

Infrastructure, Market Regulation, Safety, Reliability and 

Enforcement.

Energy Infrastructure

A robust energy infrastructure can support competitive 

markets and assure reliability of supply. A weak infrastructure can lead to higher prices, greater price volatility, lower 

supply reliability, and less effective competition. A strong 

energy infrastructure is a necessary foundation for competitive markets. In FY 2007, the Commission took the following 

significant actions: 

 The Commission continued to certificate new storage facilities and new pipeline projects, including 

the Rockies Express West Pipeline, which consists of 

nearly 800 miles of new pipeline.

 The Commission certificated a major new Millennium 

pipeline project to bring gas from the Great Lakes 

area to the Northeast and several new west-to-east 

pipelines in Oklahoma, Arkansas, Texas and Louisiana 

to move shale gas into existing major hubs and systems serving Midwest and Northeast gas markets. 

 The Commission certified the Algonquin and Maritimes & Northeast expansions to accommodate 

revaporized Liquefied Natural Gas (LNG) from Canada and offshore New England.

 The Commission implemented the LNG pre-filing 

mandates of EPAct 2005 and ensured ample stakeholder input into discussions of new energy infrastructure.

 The Commission approved three new LNG projects 

(Bayou Casotte, Gulf LNG and Calhoun) and a major 

expansion at the Elba Island LNG terminal.

 The Commission issued original licenses and relicenses 

for approximately 3,200 megawatts of non-federal 

hydropower. 

 The Commission issued rules to implement section 

1221 of EPAct 2005, which is a new section 216 of 

the Federal Power Act, authorizing the Commission 

to issue construction permits for the siting and construction of electric transmission facilities in certain 

circumstances. 

Market Regulation

A primary focus of the Commission is guarding the 

consumer from exploitation and ensuring that wholesale 

power markets produce just and reasonable rates. In FY 2007, 

the Commission took the following actions to discharge 

this duty:

 The Commission issued a final rule designed to 

strengthen the pro forma open-access transmission 

tariff to ensure that it achieves its original purpose 

of preventing undue discrimination or preference. 

The rule provides greater specificity to reduce opportunities for undue discrimination, facilitates the 

Commission’s enforcement regarding regional transmission planning, and increases transparency in the 

rules and use of the transmission system.

 The Commission issued a final rule to reform its 

market-based rate program and prevent market 

power abuses. 

 The Commission proposed a package of important 

regulatory reforms designed to enhance effective 

competition in organized wholesale power markets. 
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The proposed reforms promote more effective demand response in organized markets, strengthen 

the independence of market monitoring, encourage long-term contracting, and assure the responsiveness of regional transmission organizations and 

independent system operators to customers and 

other stakeholders. The Commission initiated these 

proposals after conducting three technical conferences with stakeholders on competition in these 

markets. These reforms are intended to strengthen 

competitive markets and better protect consumers. 

 The Commission advanced the case for greater use 

of demand response in electric markets through a 

collaborative effort with the National Association 

of Regulatory Utility Commissioners and the publication of its second report on demand response 

activities, which also addressed advanced metering 

infrastructure.

 The Commission encouraged the development of 

wind and other renewable energy facilities through 

approval of an innovative interconnection proposal 

by the California Independent System Operator. 

Commission orders over this period recognized that demand response, environmental issues, competitive wholesale 

electricity markets, and reliability have become increasingly 

interrelated. The complexity and interdependence among 

these elements resulted in the September 2007 announcement of the creation of the Energy Innovations Sector 

within the Office of Energy Market Regulation, formerly 

the Office of Energy Markets and Reliability. 

Safety

The Commission is responsible for the safety of on-shore 

LNG and non-federal hydropower facilities throughout the 

entire life cycle of a project: design review, construction and 

operation. In FY 2007, the Commission took the following 

significant actions:

 The Commission reviewed and approved the final 

engineering design and safety aspects of the Freeport, Sabine Pass, Cameron and Golden Pass LNG 

projects.

 The Commission conducted biennial operational 

inspections at six LNG peak-shaving facilities and 

annual operational inspections at five LNG import 

terminals.

 Along with its continual and thorough review of existing dams, the Commission also took several steps 

to address safety at existing facilities: it rectified safety concerns at the Swinging Bridge Dam Project and 

addressed the 2005 dam breach at the Taum Sauk 

Pumped Storage Project to ensure the safety of the 

replacement of the upper dam. 

 The Commission also cooperated with a large number of federal and state agencies to ensure and 

promote dam safety and, more recently, homeland 

security. 

Reliability

The Commission has made tremendous progress on reliability over the past two years. The Commission issued 

rules underpinning the reliability program and certified an 

Electric Reliability Organization. In FY 2007, the Commission 

took the following significant actions:

 The Commission conducted a critical assessment of 

proposed reliability standards, approved standards 

that it determined would protect reliability, and acted to assure that reliability standards are improved 

over time. 

 In Order No. 693, the Commission approved 83 of 

107 electric reliability standards proposed by the 

North American Electric Reliability Corporation 

(NERC). The Commission also directed improvements to 56 of the approved standards. Notable 

among the directed improvements were requirements to include an explicit provision recognizing 

that demand-side management may be used as a 

resource for contingency reserves. 
2007 | ANNUAL REPORT

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 The Commission initiated rulemaking proceedings 

to consider public comment on two additional sets 

of reliability standards proposed by NERC in regard 

to system operating limits and cyber-security. 

 The Commission approved delegation agreements 

to provide for regional enforcement of approved reliability standards, and continued to work closely with 

the regional entities to strengthen enforcement. 

 The Commission set an ambitious target of having 

mandatory standards in place by the summer of 

2007, earlier than the schedule envisioned by Congress. The Commission met that target, and the 

summer of 2007 was the first summer in which the 

interstate power grid was governed by mandatory 

and enforceable reliability standards. 

 Going forward, on September 20, 2007, the Commission announced the creation of the Office of Electric Reliability, formerly a division within the Office 

of Energy Markets and Reliability. The Office was 

formally established on October 1, 2007 and it will 

continue to focus on the development and implementation of mandatory and enforceable reliability 

standards for the users, owners and operators of the 

nation’s bulk power system.

Enforcement

Shortly after enactment of the EPAct 2005, the Commission 

issued a Policy Statement on Enforcement that explained 

how the Commission would exercise its new enforcement 

authority. The Enforcement Policy Statement was modeled on the best enforcement practices of other agencies, 

including the Securities and Exchange Commission, the U.S. 

Department of Justice, and the Commodity Futures Trading Commission. The Policy Statement made plain that the 

Commission’s purpose is firm but fair enforcement. Beginning in January 2007, the Commission began to carefully 

exercise its newly-delegated penalty authority. The Commission’s enforcement authority has protected consumers 

and encouraged regulated companies to develop a culture 

of compliance. In FY 2007, the Commission took the following actions:

 The Commission approved 10 settlements of enforcement actions providing for a total of $32.5 million in civil penalties.

 The Commission issued two show cause orders in 

cases of alleged market manipulation in which it 

proposed civil penalties totaling $458 million. 

Commission Open Meeting.

2007 | ANNUAL REPORT

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Energy

Infrastructure 

The Commission is responsible for authorizing LNG facilities, certificating interstate natural gas pipelines 

and storage projects, permitting electric transmission facilities in interstate commerce (under certain 

circumstances), and licensing non-federal hydropower projects. Throughout all of these application 

processes, the Commission’s goal is to apply its standard of review in a consistent manner, honor its responsibilities for 

environmental protection and public participation, while reducing the time it takes to act on projects. 

The Commission also promotes, and sometimes requires, 

the use of the pre-filing process, which involves completing a substantial portion of the environmental review and 

identifying significant non-environmental issues prior to 

the filing of an application. The pre-filing process addresses 

issues early in the application process and involves stakeholders from the beginning. This process was embraced by 

Congress in EPAct 2005, and the Commission continues 

to pursue this method as a way to stimulate infrastructure 

development.

The Commission also stimulates infrastructure development by applying pricing policies that encourage 

investment and establishing and consistently applying policies that permit timely cost recovery. The Commission’s 

rate policies, when consistently applied to infrastructure 

projects, must give investors confidence that they will 

have an opportunity to recover their investments as well 

as provide certainty to customers. Without such assurances, investors will face greater risks, companies will find 

it more difficult to obtain financing for jurisdictional facilities, and fewer energy projects will be constructed than 

the Nation needs. That, in turn, will undermine the provision of adequate and reliable energy service. The Commission encourages rate designs that support competitive 

wholesale markets for electric power and natural gas and 

provide incentives for companies to build and efficiently 

operate key new projects. Wholesale electric customers 

and gas and oil pipeline ratepayers need regulatory certainty about (1) the transportation costs they can expect 

to face, (2) the fairness of these costs, (3) continued access 

to nondiscriminatory transportation services, and (4) adequate transportation capacity. The Commission works 

to ensure that terms and conditions of service provide 

reliable access to service for all customers. 
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Natural Gas

Gas Pipelines 

The United States has a robust delivery system for natural 

gas, with approximately 220,000 miles of interstate pipelines. 

However, to meet the growing demand for natural gas, the 

Commission must continue to respond quickly when companies propose expansions or new construction for needed 

pipelines and related facilities. In FY 2007, the Commission 

took several steps to expedite the certification of natural 

gas pipelines. For example, Commission staff participated 

actively in more than 25 projects that used the pre-filing 

process to engage stakeholders in the identification and 

resolution of stakeholder concerns prior to filing a certificate 

application with the Commission. The staff’s participation 

and initiative in these efforts will allow companies to file 

better certificate applications, enabling more efficient and 

expeditious consideration by the Commission. 

Overall in FY 2007, the Commission approved 2,868 

miles of new natural gas pipeline in the United States. This 

demonstrates the Commission’s ability to approve pipeline projects quickly in response to changing patterns of 

domestic gas production. Specifically, the Commission authorized the following major natural gas pipeline projects:

 In December 2006, the Commission approved a 

natural gas pipeline project proposed by the Millennium Pipeline Co. LLC, Columbia Gas Transmission 

Corp., Empire State Pipeline and Empire Pipeline Inc., 

Algonquin Gas Transmission LLC, and Iroquois Gas 

Transmission System LP that will provide more than 

525,400 Dekatherm per day (Dth/d) of Canadian 

and domestic gas to meet rising energy demand in 

New York. The companies proposed to construct 

and operate more than 260 miles of new pipeline to 

transport natural gas from the U.S.-Canada border 

to the New York City metropolitan region. 

 In February 2007, the Commission authorized Maritimes & Northeast Pipeline, L.L.C. to construct, own 

and operate certain pipeline facilities to increase its 

mainline design capacity by approximately 418,000 

Dth/d to accommodate the importation of regasified LNG from Canada. 

 In February 2007, the Commission authorized Northern Natural Gas Company to construct, modify and 

operate pipeline, compression and town border station facilities in Minnesota and Iowa. The project will 

enable it to provide approximately 374,000 Dth/d of 

incremental winter peak day firm service to meet residential, commercial and industrial customer market 

growth commencing with the 2008 heating season.

 In March 2007, the Commission authorized Algonquin Gas Transmission, LLC to construct, install, 

own and operate a 16.4-mile subsea pipeline that 

will provide a direct connection between the offshore LNG port proposed by Northeast Gateway 

Energy Bridge, L.L.C. (Northeast Gateway) in federal 

waters in Massachusetts Bay and Algonquin’s existing HubLine offshore system in Massachusetts Bay. 

Natural gas pipeline.
2007 | ANNUAL REPORT

13

Algonquin proposed the new facilities to provide up 

to 800,000 Dth/d of firm transportation service for 

Northeast Gateway’s affiliate, Excelerate Energy Limited Partnership. 

 In April 2007, the Commission approved the Rockies Express West interstate pipeline project intended 

to transport more than 1.5 million Dth/d of Rocky 

Mountain natural gas to supply growing energy 

demand in markets east of the Rockies. The entire 

project will consist of nearly 800 miles of new pipeline that will span portions of Colorado, Wyoming, 

Nebraska, Kansas, Missouri and New Mexico.

 In April 2007, the Commission authorized Questar 

Pipeline Company to construct and operate its 

Southern System Expansion Project II, a 53.9-mile, 

24-inch diameter extension of ML 104 in Utah to 

transport Rocky Mountain gas to end-use markets. 

The project will result in an increase of 175,000 

Dth/d of incremental capacity. 

 In September 2007, the Commission authorized 

Southeast Supply Header, LLC and Southern Natural 

Gas Company to construct and operate 269 miles 

of new natural gas transmission facilities beginning 

near the Perryville Hub in Louisiana and terminating 

in Alabama. The project is capable of transporting up 

to approximately 1.14 million Dth/d of natural gas.

 In September 2007, the Commission authorized Gulf 

South Pipeline Company to construct and operate 

its proposed Southeast Expansion Project, which 

consists of approximately 111 miles of pipeline in 

Mississippi and Louisiana. 

In FY 2007, the Commission took the following industrywide actions to provide greater regulatory certainty and 

facilitate the expansion and construction of needed pipelines and related facilities:

 In October 2006, the Commission approved a final 

rule expanding the scope of blanket certificate eligibility for natural gas infrastructure projects and 

raising the limits for project costs. The final rule 

extended blanket certificate eligibility to mainlines, 

storage field facilities, and facilities transporting 

revaporized liquefied natural gas or synthetic or 

natural gas. The rule also raised the cost limits that 

apply to eligible blanket certificate projects from 

$8.2 to $9.6 million for automatic authorizations and 

from $22.7 to $27.4 million for prior-notice projects. 

The rule also clarified that a natural gas company is 

not necessarily engaged in an unduly discriminatory 

practice if it charges different customers different 

rates for the same service based on the date customers commit to service.

 In October 2006, the Commission finalized a rulemaking that implements provisions of EPAct 2005 

requiring the Commission to coordinate the environmental review and the issuance of all federal authorizations for natural gas infrastructure proposals with 

other federal and state agencies, and to maintain 

a consolidated federal record for judicial appeal and 

review. Under the final rule, the Commission will act 

as lead agency for environmental review and will establish a schedule by which federal agencies, as well 

as state agencies acting under federally delegated authority, will reach final regulatory decisions necessary 

The United States has a robust 

delivery system for natural gas, 

with approximately 220,000 miles

 of interstate pipelines. 
FEDERAL ENERGY | FERC REGULATORY COMMISSION

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for the approval of natural gas infrastructure projects 

under section 3 or 7 of the Natural Gas Act. 

 In October 2006, the Commission concluded that the 

return on equity for rates charged for the interstate 

natural gas transportation services provided by Kern 

River Gas Transmission Co. should be 11.2 percent. The 

order reversed an administrative law judge’s March 2, 

2006, initial decision recommending the Commission 

adopt a 9.34 percent return on equity. The Commission concluded the initial decision should have excluded two companies from the proxy group the judge 

relied upon in calculating the lower rate of return.

 In April 2007, the Commission determined that it will 

not accept requests from interstate natural gas pipelines to compensate customers or other downstream 

entities for costs they may incur in using gas supplies 

that include revaporized LNG that meets approved 

standards for gas quality and interchangeability. The 

Commission announced the new policy in a case involving a complaint filed by AES Ocean Express LLC 

against Florida Gas Transmission Company. 

 In June 2007, the Commission proposed to amend 

its regulations to modify the landowner notification 

requirements and require a noise survey following 

the completion of projects involving compressor 

facilities undertaken pursuant to blanket certificate 

authority. The proposed regulatory revisions should 

enhance public participation in the Commission’s 

consideration of proposed projects.

 In July 2007, the Commission proposed to modify its 

standards to allow the use of master limited partnerships in the composition of proxy groups used 

to determine the returns on equity in rates charged 

by interstate natural gas and oil pipeline companies. 

The Commission’s proposed Policy Statement seeks 

public comment on proposed modifications to its 

calculation of rates of return on equity that address 

myriad changes in the natural gas and oil pipeline 

industries, since these businesses increasingly are organized as master limited partnerships.

LNG Facilities

There is significant concern about the adequacy of natural gas supply, overall price levels, and price volatility in 

the United States. Importation of LNG is key to offsetting 

shortfalls in North American natural gas production and 

reducing energy price volatility during peak demand periods. The demand for natural gas in the United States has 

been exceeding domestic supply for most of the decade. 

In fact, natural gas usage is increasing while United States 

production is expected to remain roughly flat. As a result, 

LNG is now the fastest growing source of U.S. natural gas 

supply. LNG is economically viable at today’s market price, 

based on supply contracts and on netback pricing. In FY 

2007, following a thorough safety review, the Commission 

authorized, with conditions, the construction and operation 

of the following three new LNG import terminals:

 Bayou Casotte Energy LLC to site, construct and 

operate a new LNG import terminal in Pascagoula, 

Mississippi. The terminal project proposed by Chevron would enable its affiliates to import and deliver 

up to a peak volume of 1.6 billion cubic feet (Bcf) of 

regasified LNG per day and the vaporized LNG will 

reach the interstate grid through interconnections 

with five interstate pipelines.

 Gulf LNG Energy, LLC and Gulf LNG, Pipeline LLC to 

site, construct and operate a new LNG import terminal in Pascagoula, Mississippi. The terminal would 

include four LNG storage tanks that would have the 

capability to store up to 13 Bcf of natural gas and have 

a send-out capability of an average of 3.3 Bcf per day.

 Calhoun LNG, L.P. to site, construct, and operate a 

new LNG import terminal and associated facilities at 

the Port of Port Lavaca-Point Comfort in Calhoun 

County, Texas. The project will be designed for an 

installed gas send-out capacity of 1.0 Bcf per day. 

In FY 2007, the Commission also authorized three expansions of existing LNG terminals:

 Cheniere Creole Trail LNG’s project to construct 

and operate an additional 18.1 miles of 42-inch pipeline in Cameron Parish, Louisiana that will connect 
2007 | ANNUAL REPORT

15

Importation of LNG is key to

 offsetting shortfalls in North American

 natural gas production and reducing energy price 

volatility during peak demand periods.

with another recently-approved project proposed 

by Cheniere Sabine Pass Pipeline LP. The amended 

proposal would extend Cheniere Trail’s 116.8 mile 

certificated pipeline system to interconnect with 

the terminus of the Sabine Pass pipeline system in 

order to access and transport up to 2.0 Bcf per day 

of previously authorized regasified LNG originating 

from the Sabine Pass LNG terminal. 

Cameron LNG, LLC to amend its previous authorization to increase the send-out rate of the LNG terminal from the equivalent of 1.5 Bcf of natural gas to 

1.8 Bcf per day on an interim basis and, ultimately, 

to 2.65 Bcf per day. The terminal is currently under 

construction near Hackberry, Louisiana.

Southern LNG to expand the storage capacity of 

its Elba Island LNG import terminal by 8.44 Bcf and 

its vaporization capacity by 900 MMcf per day. The 

proposal will allow the LNG terminal in Elba Island, 

Georgia to interconnect with Transcontinental Gas 

Pipe Line Corporation. 

Storage Projects 

There is great concern about natural gas price volatility and 

its impact on captive customers. One of the best ways to 

hedge against volatility is by increasing gas storage capacity. The Commission is acting to encourage expansion of 

gas storage capacity, and has adopted pricing reforms to 

that end. Underground natural gas storage can be used to 

balance a variable market with a nearly constant supply of 

natural gas provided by the pipeline system. Storage fields 

are, in effect, warehouses with a ready supply of natural gas 

that can serve a market with high peak demands in warm 

or cold weather. In FY 2007, the Commission continued to 

certificate projects to increase the storage capacity in the 

United States. Specifically, the Commission certificated the 

following major storage projects:

In December 2006, the Commission authorized the 

construction of the MoBay Gas Storage Project in 

South Mobile Bay County, Alabama. The project will 

include nearly 83 Bcf of total storage capacity and 50 

Bcf of working gas storage capacity from the three 

fully-developed reservoirs. The storage facility will 

be capable of receiving and delivering natural gas at 

a maximum rate of 1.0 Bcf/d.

In February 2007, the Commission authorized the 

construction of a new salt dome natural gas storage facility and related pipeline facilities proposed by 

Mississippi Hub LLC. The Mississippi Hub Gas Storage 

LNG Tank.
FEDERAL ENERGY | FERC REGULATORY COMMISSION

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Project will be located in Simpson and Jefferson Davis 

counties, Mississippi, and will be designed to provide 

storage for up to a total of 17.34 Bcf of gas. Each cavern will have a working capacity of 6 Bcf with deliverability of up to 1.2 Bcf/d and will be able to receive 

injection gas at a rate of an estimated 0.6 Bcf/d.

 In September 2007, the Commission authorized Tres 

Palacios Gas Storage LLC to construct and operate a 

salt dome natural gas storage facility in Matagorda 

County, Texas. The facility will be capable of storing approximately 53.99 Bcf of natural gas, of which 36.04 Bcf 

will be working gas and 17.95 Bcf will be cushion gas. 

In June 2006, the Commission issued a final rule intended 

to mitigate natural gas price volatility by encouraging the 

development of new natural gas storage capacity. The rule 

provided further incentives for the development of new 

natural gas storage capacity and ensures access to storage services at just and reasonable rates, while at the same 

time ensuring that adequate storage capacity will be available to meet anticipated market demand. The rule set up 

two ways for developers of natural gas storage facilities to 

seek authorization to charge market-based rates. The first 

approach includes a broadened definition of the relevant 

product market for storage. The second approach implements EPAct 2005 provisions that would allow applicants 

to request authority to charge market-based rates even if 

a lack of market power has not been demonstrated, under 

certain circumstances where market-based rates are in the 

public interest and necessary to encourage the construction 

of storage capacity in the area needing storage service, and 

customers are adequately protected. 

In November 2006, the Commission approved for 

the first time an interstate natural gas storage operator’s 

request to charge market-based rates under the second 

approach adopted in the June 2006 rule. The Commission concluded that Northern Natural Gas Company 

would qualify for market-based rates for storage from its 

to-be-proposed expansion of its Redfield Storage facility 

because it met the criteria, which included protection 

from market power for existing customers and those 

that signed precedent agreements.

Environmental Mitigation

In FY 2007, the Commission promoted the use of the thirdparty compliance monitoring program for environmental 

compliance in natural gas projects. The program established 

a full-time on-site presence during the construction and 

restoration of major projects, giving the Commission staff 

immediate access to information regarding field conditions 

and the ability to respond quickly to requests from landowners and construction contractors. The program also 

gives the industry more flexibility to react to changing or 

unanticipated construction conditions. 

During FY 2007, the Commission staff completed the 

environmental review of 29 gas pipeline and LNG filings, 

including 17 environmental assessments (EAs) and 12 Environmental Impact Statements (EISs). Concurrently, the 

Commission staff continued work on 21 additional EAs 

and 20 additional EISs, primarily for new gas pipelines. Because of the effective use of the Commission’s pre-filing 

process, the average time for the staff’s completion of 

the EISs was about nine months.

Recommendations from the environmental review 

of pipeline and LNG applications are frequently included as conditions in the certificate orders. For example, 

the Commission included 56 environmental conditions 

in the order approving the Millennium Pipeline project 

and 42 environmental conditions in the order approving the Rockies Express West pipeline. These conditions 

were necessary to ensure that the pipelines would be 

constructed in an environmentally conscious manner to 

prevent or mitigate adverse impacts. For LNG applications, safety conditions are imposed in addition to environmental conditions. For example, the Commission 

imposed 79 conditions when issuing a certificate for the 

Calhoun LNG Project, including several conditions relating to the safety and security of the proposed facility.
2007 | ANNUAL REPORT

17

Over the last year, FERC staff has held public 

hearings in 43 cities, towns and villages, 

addressing 18 projects. Every week, 20 percent 

of FERC’s siting staff were somewhere in the 

country meeting with state or local stakeholders.

Landowner Issues

FERC is committed to ensuring that landowners have ample opportunity to have their issues and concerns heard. 

FERC notifies property owners of a proposal, convenes 

public hearings and provides assistance for landowners 

seeking to become involved in the pre-filing or filing phases 

of proposal review. 

Hearings are typically held in a number of venues 

along a project. Over the last year, FERC staff has held 

public hearings in 43 cities, towns and villages, addressing 

18 projects. Every week, 20 percent of FERC’s siting staff 

were somewhere in the country meeting with state or 

local stakeholders.

For long transmission projects, such hearings will 

occur at a number of sites along the proposed routes. 

Hearings are held during the day, in the evening, and 

on weekends. These hearings play an important role 

in Commission decisions. Frequently, public concerns 

raised in these hearings result in changes reflected in FERC’s 

final orders. These hearings give the public a convenient 

FERC scoping meeting.
FEDERAL ENERGY | FERC REGULATORY COMMISSION

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opportunity to provide information or comments that 

will be included in the formal record for the proceeding. 

Landowners are encouraged to participate in the prefiling process convened by FERC staff, which is designed 

to work with cooperating stakeholders to evaluate routes 

and issues presented by a proposal. FERC has a record of 

changing routes for projects to avoid problems with individual landowners’ homes or businesses. Landowners are 

also encouraged to submit their comments directly into 

the record developed on the proposed project. 

FERC staff will investigate landowner complaints 

about developers’ tactics and operations before and 

during construction of electric transmission facilities. 

During project development, this may be done by staff 

from FERC’s Office of Energy Projects. Others may be addressed by FERC’s Enforcement Hotline.

During FY 2007, FERC’s Enforcement Hotline received 

112 calls regarding landowner matters related to natural gas 

interstate pipeline construction. These calls varied in purpose and scope and included matters such as allegations 

of, among other things, improper landowner notification 

prior to commencement of construction, disturbances 

and/or damage caused to property by pipeline construction, inadequate post-construction restoration of property, 

or trespassing on landowners’ property (such as when 

pipeline construction crews strayed beyond the pipeline’s 

right-of-way). 

FERC Staff Meeting with public.

For example, the proposed route of the Southeast Supply 

Header Project pipeline would have crossed the property of an 

elderly couple. The landowners participated in the Commission 

proceeding, protesting the proposed route, which would have crossed 

through their yard. The husband had hand-built their “dream home” 

with timber he cut himself on the property. The husband had a serious

 illness, and he attended the Commission community meeting with IV ports 

in his arms from a recent hospitalization. Intercession by Commission 

staff and an environmental condition in the order encouraged the 

pipeline to settle on a route off the property, avoiding treasured 

wet meadows and stands of mature trees. 
2007 | ANNUAL REPORT

19

For example, a Hotline caller complained that pipeline 

construction activities had resulted in, among other things, changes 

to the gradation of his land such that his fields had become 

subject to flooding and his crops had been destroyed. Hotline staff, 

with the assistance of Commission technical/environmental staff, 

determined through an on-site analysis that the pipeline construction 

had indeed changed the gradation of the land as the landowner 

had described, and ensured that the pipeline 

company properly restored the property. 

Hotline staff helps landowners understand the pipeline construction process and their rights under the Commission’s rules and regulations. Hotline staff also explains 

the constructing pipeline company’s obligations to the 

landowner(s) as well as any pertinent requirements established in the certificate that the Commission issued to the 

pipeline company authorizing the construction. When 

warranted, Hotline staff contacts the pipeline company 

to resolve these issues and coordinates with Commission 

technical staff overseeing the pipeline construction project to determine the appropriate resolution of the matter. 

Under certain circumstances, Commission technical staff 

will conduct an inspection of the pipeline construction 

to determine the extent of any problems arising from the 

pipeline construction. 

To make this information as accessible as possible to 

the public, FERC maintains pertinent information on its 

website, www.FERC.gov. This includes projects in various 

areas of the country, information on how to get involved, 

and guides to gas facilities, LNG, electric transmission siting, hydropower licensing, and the pre-filing process.

FERC scoping meetings.
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Electric

The transmission grid is the interstate highway system for 

wholesale power markets. A robust grid is necessary to assure 

reliability and support competitive markets. The grid no longer consists of a multitude of local systems. Rather, the U.S. 

transmission system is regional in nature, with some systems 

extending into Canada and part of Mexico. Transmission 

investment has roughly doubled since 2002, after suffering 

from a sustained period of underinvestment. In response 

to the broad recognition of the national importance of a 

robust transmission grid, EPAct 2005 gave the Commission 

significant new regulatory authority to strengthen the grid, 

such as the reliability, transmission incentives, and federal 

siting provisions.

Transmission Investment 

EPAct 2005 added a new section 219 to the FPA, which 

directed the Commission to develop incentive-based rate 

treatments for transmission of electric energy in interstate 

commerce. In response, the Commission issued a pricing 

reform rule that seeks to bolster investment in the Nation’s transmission infrastructure, and to promote electric 

power reliability and lower costs for consumers by reducing 

transmission congestion. In FY 2007, the Commission approved several incentive proposals to encourage transmission investment:

 In October 2006, the Commission authorized a return on equity for the owners of the ISO New England transmission grid that included an incentive 

rate to encourage transmission expansion needed to 

ensure grid reliability in the New England region. The 

Commission approved returns on equity of 11.7 percent covering the period from February 1, 2005, until 

the date of the order, and 12.4 percent subsequently.

 In February 2007, the Commission conditionally 

granted Duquesne Light Company’s petition for 

transmission rate incentives in connection with a 

proposed $184 million transmission expansion project in Western Pennsylvania.

 In May 2007, the Commission conditionally granted 

United Illuminating Company’s petition for transmission rate incentives in connection with a proposed 

transmission construction project from Middletown 

to Norwalk, Connecticut.

 In May 2007, the Commission conditionally accepted Trans-Allegheny Interstate Line Company’s 

(TrAILCo) filing to implement a transmission cost 

of service formula rate for TrAILCo and an incentive 

rate authorization for a previously-qualified facility, 

the Trans-Allegheny Interstate Line Project (TrAIL 

Project). The TrAIL Project is a proposed 500 kilovolt, 

244-mile transmission line that is to be constructed 

from southwestern Pennsylvania to West Virginia to 

Northern Virginia, within the PJM Interconnection 

(PJM) region, at an expected cost of $1.8 billion.

 In July 2007, the Commission accepted Baltimore 

Gas & Electric’s proposed return on equity adder 

for continuing membership in PJM and for two 

Electric Wholesale Transmission.
2007 | ANNUAL REPORT

21

proposed transmission expansion projects. The 

Commission also initiated a technical conference to 

investigate whether to grant a return on equity adder for certain other upgrades.

The Commission has taken additional and novel steps to 

encourage transmission projects. Recognizing the unique 

characteristics of location-constrained resources, the Commission in April 2007 approved a proposal by the California 

Independent System Operator for financing facilities to 

interconnect location-constrained renewable resources. 

The Commission determined that this proposal represented 

a reasonable balance addressing the barriers impeding the 

development of location-constrained resources, such as 

wind facilities, while including appropriate ratepayer protections to ensure that rates are just and reasonable and not 

unduly discriminatory. To strengthen regional grid planning 

in the Pacific Northwest, in April 2007 the Commission accepted Columbia Grid’s proposal to coordinate transmission 

planning and expansion in the region. This proposal should 

help ensure reliability and support competitive power markets in the Pacific Northwest.

Transmission Expansion 

Cost Allocation

In FY 2007, the Commission reviewed proposed transmission cost allocation plans in organized markets to ensure 

that they result in just and reasonable rates that are not 

unduly discriminatory or preferential. In looking at these 

cost allocation plans, the Commission approved several 

orders establishing new methodologies for allocating costs 

in the future. For example:

 In November 2006, the Commission accepted the 

Midwest Independent Transmission System Operator’s (Midwest ISO) proposed methodology for 

allocating 20 percent of the costs of high-voltage 

baseline reliability network upgrades on a systemwide basis and allocating the remaining 80 percent 

to affected transmission owners based on the outcome of load flow analysis. The order reaffirmed a 

February 2006 order that had conditionally accepted the proposed cost sharing methodology pending 

the outcome of a technical conference. 

 In December 2006, the Commission held a technical 

conference to discuss proposals to allocate between 

the Midwest ISO and PJM the cost responsibility 

for constructing facilities that benefit both regional 

transmission organizations (RTOs).

 In March 2007, the Commission issued two orders 

on cost allocation in the Midwest ISO region. In the 

first order, the Commission reaffirmed the previously 

mentioned November 2006 decision to accept the 

proposed cost sharing for baseline reliability projects. 

In the second decision, the Commission conditionally accepted Midwest ISO’s proposal to allocate 20 

percent of the costs of regionally beneficial projects 

(e.g., new economic projects) on a system-wide basis 

and allocate the remaining eighty percent of costs 

among the three geographic sub-regions based on 

a “beneficiary pays” approach. 

 In April 2007, the Commission accepted a plan for 

allocating transmission costs among PJM’s transmission service customers. The Commission reaffirmed 

The transmission grid is 

the interstate highway system

 for wholesale power markets.
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PJM’s current “license plate” rate design for allocating the cost of existing facilities and new owner-initiated facilities. Under a license plate rate design, each 

utility pays for transmission service based on the 

costs of transmission facilities located in the same, 

sub-regional zone in which the utility is located. The 

Commission also determined that the costs of all 

new, centrally-planned, high-voltage facilities in PJM 

should be shared on a region-wide basis.

The Commission also continues to work to facilitate merchant transmission projects. For example, in April 2007 the 

Commission approved Linden VFT, LLC’s request to sell 

transmission rights at negotiated rates from its proposed 

merchant transmission project. Linden’s merchant transmission project differed from the merchant transmission 

projects previously addressed by the Commission in that, as 

a part of its project, Linden proposed to increase the capacity on an existing transmission line and to charge negotiated 

rates for the incremental capacity. 

Transmission Line Siting

Section 1221 of EPAct 2005 added a new section 216 to 

the Federal Power Act that authorizes the Commission to 

issue construction permits for the siting and construction 

of electric transmission facilities in certain circumstances. 

The siting authority entrusted to the Commission is limited 

in scope. Congress took a very different approach with respect to federal transmission siting than it took with federal 

siting of interstate natural gas pipelines. When Congress 

provided for federal siting of interstate natural gas pipelines, 

it provided for exclusive and preemptive federal siting. By 

contrast, federal transmission siting is not exclusive. Federal 

transmission siting supplements state siting, instead of supplanting state siting. 

In November 2006, the Commission approved a final rule, effective January 30, 2007, governing the filing 

requirements and procedures for entities asking the 

Commission to exercise its supplemental authority to 

site interstate transmission facilities under EPAct 2005. 

The final rule reflects the Commission’s extensive experience in licensing transmission for hydroelectric generation facilities and issuing certificates for interstate natural 

gas pipelines, and it applies this knowledge and experience to the electric transmission construction permit 

program.

In February and March 2007, Commission staff held 

a series of workshops on the transmission siting final rule. 

The workshops were designed to assist stakeholders in 

understanding the implementation of the rule. Commission staff also created a brochure entitled “A Guide to the 

FERC Electric Transmission Facilities Permit Process” to 

educate the public and stakeholders on this process. The 

Commission received no applications for Federal siting 

under the new law during FY 2007.

The Commission has taken

 additional and novel steps to 

encourage transmission projects. 
2007 | ANNUAL REPORT

23

Hydropower

Hydropower Projects

Hydropower remains an important component of the Nation’s energy portfolio and supports efficient, competitive 

electric markets by providing low-cost energy reserves and 

ancillary services. In FY 2007, the Commission authorized 56 

megawatts (MW) of additional capacity at existing licensed 

hydropower projects. The Commission also granted an increasingly large number of preliminary permits authorizing 

feasibility studies for more than 7,870 MW of capacity for 

new projects. 

During FY 2007, the Commission acted on a total 

of 16 hydropower applications, which included a total 

of 14 relicense applications and two 5-MW exemption 

applications. These applications represented an installed 

capacity of over 3,424 MW. The Commission also initiated the processing of 10 relicense applications, five of 

which have an installed capacity in excess of 100 MW.

Several new hydropower projects were licensed or issued 5-MW exemptions, contributing to an increase in overcall capacity. The following actions took place in FY 2007:

 In February 2007, the Commission approved a comprehensive settlement and issued a new license allowing the continued operation of the School Street 

Hydro Project in upstate New York. The license for 

the 38.8-MW project, located on the Mohawk River 

in Albany and Saratoga counties in upstate New 

York, includes provisions for 11 MW of increased 

power generation, a fish passage and aesthetic flows 

to protect the scenic quality of Cohoes Falls. 

 In March 2007, the Commission issued a new license 

for the 2,755-MW Niagara Hydroelectric Project on 

the Niagara River in New York, ensuring that a valuable source of low-cost power for the region will 

continue operating with improved environmental 

protections and recreational benefits. 

 In March 2007, the Commission issued a new license 

for Ameren’s Osage Hydroelectric Project, a 176-MW 

project on the Osage River in Missouri. The new license assures the continued operation of a reliable 

power source in the region while minimizing downstream erosion and protecting water quality, fisheries, wetlands, recreation and historical resources at 

the project.

 In May 2007, the Commission issued a new license 

for the continued operation and maintenance of 

the 29.9-MW Merrimack River Project located on 

the Merrimack River in Merrimack and Hillsborough 

Counties, New Hampshire. 

 In July 2007, the Commission issued a new license for 

the 312.33-MW Pit 3, 4, 5 Hydroelectric Project located on the Pit River in Shasta County, California. 

Saluda Dam reconstruction.
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 In July 2007, the Commission issued a new license

to continue operation and maintenance of the 7.54-

MW Blue Lake Project located on Sawmill Creek in 

the Borough of Sitka, Alaska.

 In August 2007, the Commission approved a settlement and issued a new license to continue operation and maintenance of the 19.38-MW Cooper 

Lake Hydroelectric Project located on Cooper Lake, 

Cooper Creek and Kenai Lake, near the community 

of Cooper Landing in south-central Alaska.

 In August 2007, the Commission issued a new license to operate and maintain the 4-MW Boulder 

Creek Hydroelectric Project, located in south-central Utah, in Garfield County. 

The additional electric generation that results at a downstream project from regulation of the flow of the river by 

an upstream headwater project is referred to as headwater 

benefits. These benefits are usually attributable to increasing 

or decreasing the release of water from a storage reservoir. 

Pursuant to section 10(f) of the Federal Power Act, in FY 

2007 the Commission assessed $6,266,000 in headwater benefits in 24 river basins covering 83 hydroelectric projects for 

energy benefits provided by federal headwater storage facilities. Headwater benefit assessments are returned to the U.S. 

Treasury to offset headwater project construction costs.

Hydrokinetic Energy

Hydrokinetic energy is hydroelectric generation from ocean 

waves, tides, and currents and from free-flowing rivers. In 

the past, efficient and reliable conversion of kinetic energy 

from water has proven elusive, but with recent advances 

in technology, rising fuel cost, and a growing demand for 

renewable energy, the potential for hydropower using new 

technologies is on the rise. The development of this new 

source of hydropower has the potential to add a substantial amount of power to the nation’s generation capacity, 

particularly in the area of renewable energy. Some experts 

predict that ocean-based hydropower using new technologies could double hydropower production. At present, however, the development and commercialization of 

the new technologies are just beginning. The Commission 

took a number of important steps in FY 2007 to promote 

development of hydrokinetic technologies.

In FY 2007, the Commission issued 44 preliminary 

permits for hydrokinetic energy projects. The purpose of 

a preliminary permit is to maintain priority of application for a license for three years while the permit holder 

conducts investigations and secures data necessary to 

determine the feasibility of a new project and prepares 

an application to develop it. 

The Commission also took several steps towards 

issuing the first hydrokinetic energy license:

 In November 2006, the Commission received the 

first license application for a wave energy hydropower project, the Makah Bay Offshore Wave Energy Project. In May 2007, the Commission issued 

an environmental assessment for the project, to be 

located in Makah Bay in Clallam County, Washington that would generate up to 1 MW.

 Commission staff has been working with Verdant Power to develop a license application for the Roosevelt 

Tidal Energy Hydropower Project, which would be located in the East River in Queens County, New York.

 Commission staff has been working with Reedsport 

OPT Wave Park and other stakeholders as they prepare a license application for a proposed wave energy 

project in Douglas County, Oregon, which could 

generate up to 50 MW.

In December 2006, the Commission held a technical conference to examine new hydroelectric technologies. The purpose of the technical conference was to learn more about 
2007 | ANNUAL REPORT

25

these new technologies and to develop prudent “next steps” 

in the regulation of this nascent industry. In response to the 

technical conference, in February 2007, the Commission issued a Notice of Inquiry announcing an interim policy and 

seeking public comment on how to process preliminary permit applications for wave, current and instream hydropower 

technologies and how it should enforce permits once they 

are issued. In the interim policy, the Commission proposed 

to grant the preliminary permit applications that meet the 

Commission’s rules, but subject to strict scrutiny. Under the 

interim policy, if the Commission determines that a permit 

holder is not actively pursuing project exploration, and is 

not preparing for a license application, the Commission may 

cancel the preliminary permit. 

In July 2007, the Commission announced the creation of the staff proposal for a Pilot License program. 

The goal was to allow developers to: test new technologies, determine appropriate sites, and confirm environmental effects while connected to the grid; complete the 

full project licensing process in as few as six months; and 

provide for Commission oversight and input from affected states and other federal agencies. The process would 

be available for projects that are 5 MW or smaller, removable or able to shut down on relatively short notice, and 

located in waters that have no sensitive designations. The 

Commission will convene a technical conference on this 

pilot program in the beginning of FY 2008.

To eliminate redundancy for the benefit of the applicants, other stakeholders, and the two agencies, the 

Commission has developed a Memorandum of Understanding with the Minerals Management Service (MMS) 

of the U.S. Department of the Interior to weave the MMS 

and Commission processes together.

Integrated Licensing Process

In an effort to increase the efficiency of the licensing process, which involves a multitude of stakeholders including 

citizen groups, environmental organizations, tribal interests, 

and local, state and federal resource agencies, the Commission developed the Integrated Licensing Process (ILP). The 

ILP’s ultimate goal is to establish an efficient, predictable and 

timely licensing process that develops a record sufficient for 

the Commission to take final action. 

In FY 2007, the number of hydropower projects using 

the ILP increased from 17 to 28. The first three relicense 

applications prepared using the ILP, PPL Montana’s Mystic Project No. 2301, Georgia Power Co.’s Morgan Falls 

Project No. 2237, and Public Service Company of New 

Hampshire’s Canaan Project No. 7528, are currently 

pending at the Commission. These projects are being 

processed expeditiously and are expected to be ready for 

final Commission action within the target time frame for 

the ILP (16 to 18 months from filing).

Hydrokinetic energy 

is hydroelectric generation 

from ocean waves, tides, and currents 

and from free-flowing rivers.
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Throughout FY 2007, the Commission also undertook numerous outreach efforts to educate the industry, 

resource agencies, tribes, nongovernmental organizations, citizen groups and other stakeholder groups on 

the ILP. Staff made presentations and led discussions 

on the ILP at several national hydropower meetings. In 

addition, regional conferences and intensive projectspecific meetings with multiple stakeholder groups were 

held to educate participants on the ILP. 

Environmental Mitigation

Hydropower licenses include requirements that are designed to protect, mitigate and enhance the environmental 

resources of project areas. The Commission safeguards the 

environment by requiring that all hydropower applicants 

communicate with affected federal and state natural resources agencies, tribes and state water quality agencies 

prior to submitting an application to the Commission. 

The Commission continues to receive an increasing 

number of land and water use development applications 

that involve contested, complex issues related to water 

quality, navigation hazards, aesthetics and erosion around 

licensed lakes and reservoirs. The Commission expects this 

trend to continue, as public leisure demands continue to 

grow on lakes and reservoirs. The Commission has issued a guidance manual for shoreline management, and 

will hold land resources management and development 

workshops in the affected regions of the country. 

In FY 2007, Commission staff completed the environmental review of 21 hydroelectric license and exemption 

applications, including 13 EAs and seven EISs. Concurrently, Commission staff continued work on three draft EAs 

and three draft EISs. Environmental recommendations are 

also incorporated into the hydroelectric licenses the Commission issues. For example, in FY 2007, the Osage Project 

contained 30 special conditions and 28 standard conditions for a total of 58 conditions. There were also additional requirements in the State of Missouri’s Water Quality 

Certificate that were included as part of the license.

In FY 2007, the Commission continued to monitor 

compliance through its environmental inspection program to ensure that resource protection measures, designed to maintain environmental quality at hydropower 

projects, are constructed and implemented according 

to license requirements. The Commission’s compliance 

assistance program, comprised of environmental inspections, building partnerships, collaborative problem solving, and guidance, will ensure effective license compliance 

and resource protection.

Oil Pipelines

The United States has approximately 175,000 miles of oil 

and oil products pipelines, with ten companies accounting 

for over 40% of the total miles. There are about 200 interstate pipelines, comprised of a few large players and many 

small pipelines.

In FY 2007, the Commission encouraged and supported the building of expanded petroleum product 

lines through its orders on pipeline petitions for declaratory orders. In these orders, the Commission approved 

certain flexible rate methodologies and granted other 

rate assurances prior to construction in order to reduce 

the uncertainty and risk inherent with these large infrastructure projects. Specifically, the Commission took the 

following major actions:

 In May 2007, the Commission denied rehearing of 

an order that granted in part Colonial Pipeline Co.’s 

(Colonial) petition for declaratory order and approved 

certain rate methodologies applicable to Colonial’s 

proposed $1 billion pipeline expansion between Baton 
2007 | ANNUAL REPORT

27

Rouge, Louisiana, and Atlanta, Georgia. On rehearing, 

the Commission rejected arguments that the Commission erred by approving Colonial’s proposal for a 

uniform rate component surcharge rather than requiring the surcharge to be based on the length of haul, or 

requiring that expansion costs be recovered through 

a revision of Colonial’s existing grandfathered rates.

 In July 2007, the Commission approved a rate plan 

that would allow Calnev Pipe Line LLC (Calnev) to 

begin a four-year, $400 million expansion of its 248-

mile petroleum products pipeline system to meet 

growing demand for fuel in Las Vegas. Calnev’s refined petroleum products pipeline system serves 

consumer and military installations in Southern 

California and Southern Nevada. It consists of two 

parallel 248-mile pipelines, one 14 inches in diameter 

and one that is eight inches in diameter. The Commission approved Calnev’s proposal to establish a 

uniform rate charge to recover its expansion costs 

while continuing to recover the cost of its existing 

facilities under grandfathered rates. 

Oil Pipeline.

2007 | ANNUAL REPORT

29

Market 

Regulation

I n FY 2007, the Commission continued to develop rules that encourage fair and effective competitive markets and prevent the accumulation and exercise of market power. The Commission’s regulatory approach is flexible and can react effectively to changes in energy markets caused by new technology and market forces. 

This flexibility allows the Commission to find the best possible mix of regulation and competition to encourage fair and 

effective competitive markets and prevent the accumulation and exercise of market power. 

The Commission is charged by statute with ensuring that 

prices in jurisdictional energy markets remain just and reasonable and are not unduly discriminatory or preferential. 

The Commission does this by preserving and expanding 

the transparency of information and operations in energy 

markets, and by having effective rules that encourage fair 

and efficient competitive markets. The Commission accomplishes this primarily through:

 Its rate, merger and corporate review jurisdiction 

under sections 205, 206 and 203 of the Federal 

Power Act.

 Its rate jurisdiction under sections 4 and 5 of the 

Natural Gas Act and section 311 of the Natural Gas 

Policy Act of 1978. 

 EPAct 2005 amendments to the Federal Power Act 

and Natural Gas Act related to market operations, 

including anti-manipulation provisions.

In FY 2007, the Commission actively took steps to encourage fair and effective competitive markets. The Commission 

issued a final rule reforming the decade-old Open Access 

Transmission Tariff and made significant changes to the 

market-based rate program, while codifying for the first time 

the rules for obtaining market-based rate authority. The 

Commission also convened a series of public conferences 

to evaluate the state of competition in wholesale power 

markets. The Commission has a duty to ensure that jurisdictional services provided in wholesale markets are just and 

reasonable and not unduly discriminatory, and these public 

conferences helped discharge this important responsibility. 

As a result of these conferences, the Commission issued an 

advanced notice of proposed rulemaking, which addressed 

a number of issues in wholesale electric markets.

The agency’s efforts to promote competitive markets take place at a time when the cost of natural gas 

and primary fuels used to generate electricity are rising, 

resulting both in higher gas and power prices. In particular, the wholesale spot price of natural gas has more 

than doubled in the five years since 2002. That increase 

is being borne by natural gas consumers. It is also borne 

by electricity consumers, since increasing fuel costs put 

upward pressure on power prices. To some extent, increasing electricity prices may be the unavoidable result 

of rising fuel costs. 
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However, movements in retail prices are not a correct measure of the success of competition in wholesale 

power markets. The truest measure of that success is 

what electricity prices would have been in the absence of 

competition, based on total reliance on regulation, recognizing the imperfections of cost-of-service regulation. This 

measurement, however, is impossible to quantify with any 

satisfactory precision.

The better course is to compare the elements of 

competitive wholesale power and gas markets with the 

elements of perfect or textbook competition. Success 

can be measured by the extent to which wholesale markets manifest these characteristics. The elements of perfect competition include the following:

 Adequacy of electricity and natural gas supply

 Entry by generators and gas producers

 Market access

 Robust infrastructure—both electric transmission 

and gas pipelines

 Fair access to grid and pipelines

 Continued infrastructure investment

 Contract certainty

 Regulatory stability

 Good market rules

 Market transparency

 Elasticity of demand—effective demand response

 Effective enforcement

 Absence of market manipulation and market power 

exercise.

It should be recognized that perfect competition may not 

exist outside a textbook. For that reason, the goal should 

perhaps be workable competition to assure that wholesale 

power and gas markets have as many elements of perfect 

competition as possible. The Commission is making continued progress towards that goal. 

Fair and Efficient 

Competitive Market Rules

The Commission ensures that open access transmission 

service is available at reasonable prices on a nondiscriminatory basis. This provides the foundation for fair and efficient 

wholesale energy markets for electricity and natural gas. 

In exercising its jurisdiction over wholesale markets and 

transportation in interstate commerce, the Commission 

strives to reduce barriers in both gas and electric markets. 

Furthermore, the Commission seeks to adopt approaches 

that are complementary to those of the states in their regulation of retail markets. 

The Commission continues to make progress towards strengthening competitive wholesale power and 

gas markets. In particular, it has proposed a number of 

reforms and adopted orders that make continued progress towards more perfect competition. In FY 2007, the 

Commission took steps to improve access to the transmission grid, improve market rules, assure continued entry by generators through adoption of forward capacity 

markets, and improve market transparency. 

Market Rule Changes

In FY 2007, the Commission addressed issues in wholesale 

competitive markets by taking the following actions:

 In October 2006, the Commission finalized a rulemaking modifying the mandatory power purchase 

obligation for electric utilities under the Public Utility Regulatory Policies Act of 1978. The final rule 

does not terminate the purchase obligation of any 

utility, but instead allows electric utilities to file applications for relief. Qualifying facilities in the markets the Commission identified may, under the rule, 

be able to rebut the presumption of access to markets because of operational characteristics or transmission constraints. In June 2007, the Commission 

issued a rehearing order affirming the final rule.

 In November 2006, the Commission took final action to establish a Forward Capacity Market to 

address deficiencies in New England’s generation 
2007 | ANNUAL REPORT

31

capacity markets. The Commission reiterated that 

it relied upon a relevant and substantial record in 

reviewing the settlement. The agreement was the 

product of a series of more than 30 formal settlement conferences over a four-month period.

 In December 2006, the Commission approved, with 

conditions, a settlement agreement concerning PJM’s 

Reliability Pricing Model intended to secure sufficient resources to meet PJM’s reliability requirements 

at just and reasonable rates. The settlement will allow 

utilities to provide capacity through a combination 

of generation, transmission and demand response.

 In January 2007, the Commission authorized the 

Southwest Power Pool to initiate its proposed energy imbalance market. SPP’s energy imbalance 

market employs least-cost bid-based security-constrained economic dispatch and locational marginal 

pricing of energy to settle all energy imbalances in 

its footprint.

 In February 2007, the Commission adopted a final 

rule reforming its decade-old open-access electric 

transmission tariff. As described more fully below, 

the reform will better ensure that transmission service is provided on a basis that is just and reasonable 

and not unduly discriminatory. It also provides for 

more effective regulation and transparency in the 

operation of the transmission grid.

 In April 2007, the Commission largely reaffirmed a 

prior order approving planned power market reforms in California, reiterating the Commission’s 

view that the reforms are necessary to help prevent 

a recurrence of the Western energy crisis. The Commission granted in part and denied in part petitions 

for clarification and rehearing of its September 2006 

order approving a filing by the CAISO to implement 

its proposed Market Redesign and Technology Upgrade (MRTU) tariff.

 In June 2007, the Commission issued an Advanced 

Notice of Proposed Rulemaking seeking public comment on potential reforms to improve operations in 

organized wholesale power markets. The proposal 

will help the Commission identify challenges facing 

competitive wholesale power markets in RTOs and 

ISOs and propose workable solutions in those areas 

in which the Commission has jurisdiction. Specifically, the Commission sought comments on (1) the 

role of demand response in organized markets, (2) 

facilitation of opportunities for long-term power 

contracts, (3) strengthened market monitoring, and 

(4) the responsiveness of RTOs and ISOs to customers and other stakeholders.

The Commission also has encouraged the development of 

business rules and practices that maximize market efficiency, 

ease market entry, and reduce transaction costs, relying in 

the first instance on such organizations as the North American Energy Standards Board (NAESB), RTOs and ISOs, where 

appropriate. For example, in June 2007, the Commission 

amended its open access regulations governing standards 

for business practices and electronic communications with 

interstate natural gas pipelines and public utilities. The Commission incorporated by reference certain standards promulgated by the Wholesale Gas Quadrant and the Wholesale 

Electric Quadrant of NAESB. Through this rulemaking, the 

Commission sought to improve coordination between the 

gas and electric industries in order to improve communications about scheduling of gas-fired generators.

Demand Response

A well-functioning competitive wholesale electric market 

should reflect current supply and demand conditions. The 

Commission’s policy is to facilitate the participation of demand response in organized markets because demand response helps to hold down wholesale power prices, reduces 

price volatility, increases awareness of energy usage, provides 

for more efficient operation of markets, mitigates market power and enhances reliability. In FY 2007, the Commission took 

several steps to help facilitate demand response programs:

 In November 2006, the Commission initiated a Collaborative Dialogue on Demand Response with the 

National Association of Regulatory Utility Commissioners to explore state/federal coordination of efforts to 
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promote and integrate demand response into retail 

and wholesale markets and planning. The purpose of 

the Collaborative Dialogue is to address the coordination of federal and state demand response policies 

concerning issues such as the regulatory barriers to 

increased customer participation in demand response 

programs identified in the 2006 Report to Congress: 

Demand Response & Advanced Metering.

 In April 2007, the Commission conducted a technical conference on integrating demand response 

in wholesale power markets. The Commission also 

explored the technical feasibility and capability of 

demand resources to be cost-effectively integrated 

into the transmission planning process. 

 In June 2007, the Commission issued an Advanced 

Notice of Proposed Rulemaking on competition in 

wholesale markets, which included proposals to encourage greater demand response in RTOs and independent system operators (ISOs) by (1) allowing 

demand resources to provide certain ancillary services in their markets unless not permitted by state 

law, (2) modifying tariffs to let demand resources 

provide spinning and supplemental reserves without being required to sell into the energy market, (3) 

modifying RTO and ISO tariffs to eliminate certain 

charges for purchasing less energy in real time than 

in the day-ahead market during a system emergency, 

(4) amending market rules to permit an entity that 

aggregates the demand responses of individual retail 

consumers to bid the aggregate demand reduction 

directly into an RTO or ISO energy market, unless 

not permitted by state law, and (5) modifying market power mitigation rules to allow pricing during an 

emergency to elicit more demand response.

 In September 2007, Commission staff issued its annual report pursuant to EPAct 2005 that charts 

progress in the number of demand response programs, the number of states introducing opportunities for demand response, and the key role that 

demand response is playing in organized wholesale 

power markets. Demand response and advanced 

metering programs have grown significantly over 

the past year, according to the report. 

Open Access Transmission 

Tariff Reform

The primary task of the Commission in the area of electric regulation is to guard the consumer from rates that are not just 

and reasonable. The primary goal of the Open Access Transmission Tariff reform final rule is to prevent undue discrimination and preference in transmission service, thus allowing 

wholesale customers to access lower-cost power supplies.

In the final rule issued in February 2007, the Commission concluded that the existing Open Access Transmission Tariff provides an opportunity to engage in undue 

discrimination and preference in transmission service. 

The final rule limits undue discrimination and preference 

by increasing the transparency of Open Access Transmission Tariff administration. The final rule also limits undue 

discrimination by requiring an open, transparent and coordinated transmission planning process that will consider the needs of native load customers and transmission 

customers, as well as transmission providers. Specifically, 

the final rule was issued to:

 Increase non-discriminatory access to the grid by 

eliminating the wide discretion that transmission providers had in calculating available transfer capability.

 Improve the ability of customers to access new generating resources by requiring an open, transparent 

and coordinated transmission planning process.

 Promote efficient utilization of transmission by eliminating artificial barriers to access to the grid. 

 Facilitate the use of and access to intermittent energy resources.

 Further acknowledge the role of demand resources 

in transmission planning and in ancillary services. 

 Strengthen compliance and enforcement efforts.
2007 | ANNUAL REPORT

33

The final rule applies to all public utility transmission providers, including RTOs and ISOs. Each public utility is required 

to file revisions to its Open Access Transmission Tariff to 

conform to this rule. Since February 2007, the Commission 

has taken several steps to implement the provisions of the 

Open Access Transmission Tariff final rule and to offer guidance to the industry:

 In June 2007, Commission staff convened technical 

conferences in four locations around the country to 

review and discuss the “strawman” proposals regarding processes for transmission planning required by 

the final rule. 

 In July 2007, Commission staff convened a technical conference to consider (1) the minimum leadtime for undesignating network resources in order 

to make firm third-party sales and (2) the eligibility 

of on-system sellers’ choice and system sales to be 

designated as network resources.

 In August 2007, due to requests by transmission 

providers and stakeholders for guidance during the 

transmission planning conferences, the Commission 

staff released a white paper regarding the compliance filings for transmission planning and scheduled 

follow-up technical conferences for October 2007 

to discuss transmission providers’ draft proposals 

regarding transmission planning.

Long-Term Transmission Rights

In July 2006, the Commission issued a rule that required 

RTOs and ISOs to make long-term firm transmission rights 

available to all transmission customers. The availability of 

such rights will provide financial certainty to load-serving 

entities that wish to enter into long-term power supply arrangements. In FY 2007, the Commission took the following 

actions on filings made by RTOs and ISOs:

 In November 2006, the Commission accepted PJM’s 

proposal to establish a Long-Term Transmission 

Rights product intended to allow load serving entities to hedge their energy market positions on a 

long-term basis by providing price certainty over the 

relevant period. 

 In May 2007, the Commission generally affirmed its 

earlier holding that PJM’s Long-Term Transmission 

Rights proposal was consistent with the rule. 

 In May 2007, the Commission accepted the Midwest 

ISO long-term firm transmission rights proposal, 

subject to modification.

 In July 2007, the Commission conditionally accepted, 

subject to modification, proposed revisions to the 

California MRTU Tariff to implement long-term firm 

transmission rights.

 In August 2007, the Commission held a technical 

conference to address issues raised by the New York 

Independent System Operator’s Long-Term Transmission Rights proposal.

Differences in market rules and designs, 

operating and scheduling protocols, and other control-area 

practices can inhibit or preclude the ability to execute 

transactions that cross regional boundaries 

and thus create inefficiencies.
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Reduction of Barriers to Trade 

Differences in market rules and designs, operating and scheduling protocols, and other control-area practices can inhibit 

or preclude the ability to execute transactions that cross 

regional boundaries and thus create inefficiencies. Significant differences in power products, pricing and rules among 

markets can reduce competition among suppliers across the 

regions. Resolving these differences (referred to as “seams”) 

could lower transaction costs, permit greater utilization of 

resources and, ultimately, lower costs to customers. 

The Commission has facilitated discussions between 

industry and the states to address and resolve seams issues. 

In FY 2007, the Commission took the following actions:

 In November 2006, the Commission accepted for 

filing a proposed Seams Operating Agreement between the Midwest ISO and Manitoba Hydro.

 In December 2006, the Commission held a technical conference to examine concerns about seams issues stemming from the CAISO’s implementation of 

MRTU. While MRTU does not introduce seams into 

Western electricity markets, certain seams issues 

already existed between organized and bilateral markets in the West, and the Commission determined 

that a technical conference would be appropriate 

to address these concerns. The Commission also 

required the CAISO to file quarterly reports, jointly 

with neighboring control areas, on progress toward 

reducing seams in the West.

 In March 2007, the Commission held a technical conference on seams issues in the Eastern Interconnection. The goal of the conference was to identify the 

market seams in the Eastern Interconnection that 

create the greatest barriers to trade and cost shifts.

Preventing Accumulation 

and Exercise of Market 

Power

Commission rules encourage fair and efficient competitive 

markets by preventing the accumulation and exercise of 

market power and promoting transparency of competitive 

electric and gas markets. 

Most industries that make the transition to increased 

competition experience considerable restructuring, including consolidations of companies within individual 

segments of the industry. Mergers and other dispositions 

or acquisitions can bring efficiencies from economies of 

scale and can represent the success of competition when 

more effective business models grow. However, they also 

can eliminate competitors and lead to markets that are 

too concentrated and not fully competitive. 

The Commission safeguards the customer from 

consolidations of energy assets that reduce competition, 

and ensures that rates customers pay for electricity and 

transmission services in wholesale markets are just and 

reasonable.

The Federal Power Act and the Natural Gas Act 

enable the Commission to identify and disallow from 

jurisdictional rates any imprudently-incurred, unjust or 

unreasonable or unduly discriminatory or preferential 

costs from affiliate transactions among companies in the 

same holding company system.

Review of Mergers and Acquisitions 

and Other Corporate Transactions

The Commission is responsible for determining whether 

certain mergers and acquisitions in the electric industry 

are consistent with the public interest. In making its determination, the Commission examines a transaction’s effect 

on competition, rates and regulation, and the potential for 

cross-subsidization. The Commission’s approach to mergers 

analyzes horizontal and vertical competitive concerns, and 

establishes filing requirements and conditions for mergers 

that raise market power concerns. 
2007 | ANNUAL REPORT

35

In FY 2007, the Commission held several technical 

conferences to evaluate the merger and acquisition review process. In response to these technical conferences, 

in July 2007 the Commission issued the following package of orders designed to provide greater clarity and 

guidance on its merger and acquisition review policies 

while protecting customers from inappropriate crosssubsidization between regulated utilities and their unregulated affiliates:

 In a Supplemental Policy Statement, the Commission provided guidance regarding future implementation of section 203 of the Federal Power Act. This 

guidance was based on the Commission’s experience 

amending its Federal Power Act section 203 regulations to implement EPAct 2005 as well as enacting 

new regulations under the Public Utility Holding 

Company Act of 2005.

 In a proposed rule, the Commission sought to codify 

cross-subsidy pricing restrictions on power and nonpower goods and services transactions between 

franchised public utilities with captive customers 

and their market-regulated power sales affiliates or 

non-utility affiliates.

 In a separate proposed rule, the Commission asked 

for comment on a proposal to grant an additional 

limited blanket authorization for certain dispositions of voting securities by public utilities to public 

utility holding companies.

In its review of mergers and other corporate transactions, 

the Commission uses its authority under section 203 of the 

Federal Power Act to prevent the accumulation of market 

power. A merger could potentially increase market power 

by eliminating a competitor or overly concentrating those 

markets where the merging parties have overlapping generation resources. In such a case, the Commission would either 

reject the merger, or impose conditions or accept applicant 

commitments to ensure that competition is not harmed. 

For example, in October, 2006, the Commission 

authorized the merger of National Grid and KeySpan 

Corporation, subject to restrictions on certain sales by 

the merged company. The analysis of the effect of the 

merger on competition in the relevant markets showed 

that combining National Grid’s electric generating resources in upstate New York with KeySpan’s generating 

resources in New York City and Long Island would increase market concentration in New York City and Long 

Island, and therefore potentially result in an increase in 

market power in those markets. The Commission’s concern about any increase in market power was addressed 

by the applicants’ commitment to seek prior Commission authorization before making sales from upstate 

generating resources into New York City or Long Island 

submarkets, and therefore the Commission relied on that 

commitment in authorizing the merger. The Commission 

also required applicants to revise their market-based rates 

tariffs to show the limitation on those sales. 

Commission rules encourage fair and efficient 

competitive markets by preventing

 the accumulation and exercise of market

 power and promoting transparency

 of competitive electric and gas markets.
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Overall, the Commission approved the following significant mergers and acquisitions in FY 2007:

 In October 2006, the Commission approved the 

merger of KeySpan Corp. and National Grid. The 

Commission determined that the $7.3 billion merger 

would not adversely affect wholesale power rates, 

noting that the companies had stated their commitment to hold ratepayers harmless from transactionrelated costs in excess of transaction-related savings 

for five years.

 In October 2006, the Commission approved the 

acquisition of NorthWestern Corp. by Babcock & 

Brown Infrastructure Ltd for $2.2 billion. The Commission noted that the acquisition would not result 

in any new combination of generating assets that 

would compete in the same geographic markets.

 In December 2006, the Commission approved the 

acquisition of Duquesne Light Holdings Inc. by an investment consortium led by Macquarie Infrastructure Partners. Under the terms of the agreement, 

the consortium would acquire all of the outstanding 

shares of Duquesne Light Holdings Inc. in a transaction valued at approximately $1.59 billion.

 In December 2006, the Commission approved the 

$9.2 billion merger between Peoples Energy and 

WPS Resources. In approving the merger, the Commission noted that the applicants had offered “hold 

harmless” provisions for jurisdictional ratepayers and 

had provided sufficient assurances that their merger 

would not result, at the time of consummation or in 

the future, in cross-subsidization.

 In September 2007, the Commission authorized the 

transfer of jurisdictional assets owned by Oncor 

Electric Delivery and TXU Wholesale through the 

acquisition of their parent company, TXU Corp., by 

Texas Holdings. The transaction was valued at approximately $32 billion.

Market Power in 

Wholesale Power Sales

The Commission has been granting market-based rate authority to qualified applicants since 1988. The Commission’s 

policy has evolved based on its experience on a case-bycase basis. This program first requires a seller seeking marketbased rate authorization to demonstrate that neither it nor 

its affiliates have market power in generation or transmission 

(or that any such market power is sufficiently mitigated). If 

such demonstration is made, the grant of market-based 

rate authorization is conditioned on adherence to a code 

of conduct, the quarterly filing of transaction information 

through the Electric Quarterly Reports, and the filing of any 

change in status affecting market power. 

In June 2007, the Commission issued Order No. 

697, its final rule on the proposed amendments to its 

market-based rate policy. The rule reflects the Commission’s fundamental responsibilities to oversee wholesale 

power markets and protect consumers from exploitation 

in those markets. The rule was designed to reform and 

codify the existing standards to protect customers and 

provide greater certainty to sellers seeking market-based 

rate authority. The rule became effective in September 

2007 and has the following major elements:

 The rule includes a two-part test covering horizontal (generation) and vertical (transmission and other 

barriers to market entry) market power. 

 Restrictions on affiliate abuse must be satisfied as a 

condition of obtaining and retaining market-based 

rate authority.

 The rule eliminates the section 35.27 exemption 

from market power screens of all generation built after July 9, 1996. Now all sellers seeking market-based 

rate authority, or filing updated market power analyses, on or after the effective date of the rule must 

provide a horizontal market power analysis for the 

generation they own or control, including generation, built after July 1996. 
2007 | ANNUAL REPORT

37

 It allows a seller to use the entire RTO/ISO geographic footprint as the default relevant geographic 

market if the RTO/ISO has sufficient market structure and a single energy market with Commissionapproved market monitoring and mitigation. But if 

the Commission determines there is a submarket 

within an RTO/ISO, the submarket becomes the default relevant geographic market.

 The rule provides that the Commission will determine appropriate mitigation on a case-specific basis, including whether a “must offer” requirement is 

necessary to mitigate market power for those sellers 

that do not demonstrate a lack of market power.

 Finally, the rule allows mitigated sellers to make market-based rate sales at the boundary of the mitigated market if that seller provides assurance that the 

power will leave the control area and that it will not 

sell the power back into the control area through 

an affiliate. The rule imposes a record retention requirement on mitigated sellers making such sales 

and requires the seller to include tariff language in 

its market-based rate tariff to allow for such sales.

Standards of Conduct

On November 17, 2006, the United States Court of Appeals 

for the District of Columbia vacated Order No. 2004, which 

adopted Standards of Conduct for transmission providers, 

as it applies to the relationship between natural gas pipelines and their non-marketing affiliates in National Fuel Gas 

Supply Corp. v. FERC, 486 F.3d 831 (D.C.Cir. 2006). The Commission acted promptly to respond to the court decision 

and to clarify the Standards of Conduct. In January 2007, 

the Commission issued an interim rule that addressed deficiencies identified by the court by revising the Standards of 

Conduct so they did not apply to non-marketing affiliates of 

natural gas pipelines. Concurrently, the Commission issued 

a proposed rule to make permanent the revisions contained 

in the interim rule. In the proposed rule, the Commission 

sought comment on the applicability of the Standards of 

Conduct to non-marketing affiliates of electric utilities. The 

Commission also proposed changes to the Standards of 

Conduct to improve the consideration of transmission in 

electric utilities’ integrated resource planning and procurement subject to certain restrictions designed to protect 

against affiliate abuse. The Commission received comments 

and intends to act promptly in these proceedings.

Western Energy Settlements

The Commission continues to pursue resolution of the 

remaining disputes arising from the 2000–2001 Western 

energy crisis. While litigation continues in various appeals 

and Commission proceedings, the Commission approved 

several additional settlements in refund proceedings for 

companies involved in the Western energy markets crisis 

in FY 2007. This represents continued progress towards 

resolution of the Western energy crisis.

Date Settling Parties Payment

March 1, 2007 APX, Inc. and approximately 30 other entities $53 million 

March 17, 2007 Portland General Electric Company $65.4 million

June 21, 2007 PacifiCorp $27.9 million

June 21, 2007 El Paso Marketing LP $56 million

July 6, 2007 BP Energy Company $18 million

2007 | ANNUAL REPORT

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Safety 

T

The Commission reviews and approves the final engineering 

design of authorized LNG projects, inspects these facilities 

during construction to ensure compliance with the safety 

and reliability requirements of Commission orders, and conducts the annual and biennial safety and reliability inspections of the existing jurisdictional LNG peak shaving and 

marine import terminals for the life of these facilities. The 

Commission has taken steps to ensure that the review of 

new facilities does not conflict with the ongoing obligation 

of the Commission to ensure the safe and reliable operation 

of existing facilities.

Natural gas projects and hydropower projects have 

environmental impacts that can be mitigated with appropriate measures. The Commission is committed to 

satisfying environmental concerns through cost-effective 

mitigation of environmental impacts, while also seeking 

he Commission is responsible for the safety of onshore LNG and non-federal hydropower facilities 

throughout the entire life cycle of a project: design review, construction and operation. 

to avoid construction delays. Commission licenses include terms and conditions that are designed to mitigate 

possible environmental impacts of project construction 

and operation, and to provide opportunities to enhance 

the public’s use of available resources. The Commission 

monitors these terms and conditions for compliance 

throughout the term of the license. 

Natural Gas

Safety at LNG Facilities 

Consideration of public safety is the Commission’s highest 

priority when fulfilling its Congressional mandate under 

the Natural Gas Act to regulate facilities for importation 

of natural gas. The Commission has been proactive in addressing safety concerns and rigorously applies high safety 

standards to these projects. When projects meet the Commission’s safety standards and are found to be in the public 

interest, they are approved. Projects that fall short of these 

standards are rejected. 
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The siting and oversight of LNG facilities are governed 

by a comprehensive scheme of federal regulation that 

guarantees that the Commission and other federal agencies work together to ensure public safety. The Commission works with the U.S. Department of Transportation 

(DOT), which is responsible for safety of gas pipelines once 

operational, and the U.S. Coast Guard to ensure the safe 

siting, operations and reliability of facilities. This process 

ensures that approved LNG terminals and associated LNG 

vessel traffic meet safety and environmental requirements 

during construction and operation. For each project, the 

Commission, in coordination with DOT and the U.S. Coast 

Guard, conducts an engineering and siting review geared 

toward assuring that a facility will operate safely and securely in an environmentally sound manner. In FY 2007, 

the Commission reviewed 16 LNG applications to ensure 

that safety concerns are appropriately addressed. 

Hydropower

Dam Safety 

The Commission administers the largest dam safety program in the United States. The Commission cooperates 

with a large number of federal and state agencies to ensure 

and promote dam safety and, more recently, homeland 

security. More than 2,500 FERC-licensed dams are in the 

program. Two-thirds of these dams are more than 50 years 

old. As dams age, concern over their safety and integrity 

grows, and oversight and a regular inspection program are 

extremely important.

In addition to implementing an effective dam safety 

program, FERC continues to make significant contributions to ensure and improve the safety of dams in the 

United States as a member of the National Dam Safety 

Review Board. The Board, as authorized by Congress, 

directs and facilitates federal funding and technology 

transfer to the 50 state dam safety offices to ensure and 

improve the safety of more than 70,000 non-federal dams 

in the United States

The Commission dam safety program, recognized 

both nationally and internationally as a leading expert 

in Emergency Action Planning, conducts biennial open 

training workshops for federal, state and local dam safety 

and emergency response agencies for emergency action 

planning and exercising. The Commission also developed 

and implemented an innovation in dam safety evaluations entitled the Potential Failure Mode Analysis. The 

Commission provides training to federal and state dam 

safety agencies in this analysis, which identifies the possible failure modes for specific dams and determines necessary actions before a problem occurs, thereby ensuring 

the safety of dams and preventing failure emergencies. 

The entire United States dam safety community has embraced the value Potential Failure Mode Analysis brings 

to ensuring dam safety. 

Commission staff also has assumed a leadership role 

in many of the important technical advancements in the 

areas of dam safety research, training, dam safety program 

design, and the importance of coordinating Emergency 

Action Plans with the local first responder agencies. 

During FY 2007, Commission staff: (1) conducted 

three workshops on dam site security and emergency action planning; and (2) convened a technical workshop for 

all Commission pump storage operators, the U.S. Army 

Corps of Engineers, and the Bureau of Reclamation to develop guidelines for the operation, instrumentation and 

monitoring, and inspection of pumped storage projects.

Commission staff also has assumed a leadership role 

in many of the important technical advancements in the 

areas of dam safety research, training, dam safety program design and the importance of coordinating emergency action plans with the local first responder agencies. 

Among the activities in FY 2007 were: 

 Three workshops on dam site security and emergency action planning.

 Significant contributions to the Department of 

Homeland Security (DHS) on dam security and criticality of dams.

 Continuing work with DHS and the Federal Bureau 

of Investigation to coordinate a national security 

response at dams.
2007 | ANNUAL REPORT

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 Leading interagency coordination on federal infrastructure security at dams.

 Continuing coordination efforts between Commission-regulated dam owners and law enforcement 

and emergency management agencies.

 Coordination with various federal and state dam 

safety agencies, Federal Emergency Management 

Agency and DHS, and providing industry guidance 

on the format and content of disaster recovery plans 

for hydropower projects.

The Commission also took additional steps to address safety 

concerns at specific dam locations. In October 2006, the 

Commission approved a settlement addressing the December 14, 2005, breach of the upper reservoir of the Taum 

Sauk hydroelectric project in Reynolds County, Missouri. 

AmerenUE agreed to pay a $10 million civil penalty, to fund 

$5 million in improvements in the vicinity of the Taum Sauk 

project, and to adopt a comprehensive safety program for 

AmerenUE’s hydroelectric facilities. The $10 million civil 

penalty is the largest the Commission has ever imposed 

in a hydroelectric matter. The penalty, plus the $5 million 

in improvements, are over and above the costs AmerenUE 

will incur in remediating the environmental and property 

damage caused by the breach. The approved enhancements 

include computer system improvements for an enhanced 

911 emergency system, construction of a new emergency 

operations center, installation of an emergency power generator for the municipal drinking water supply, purchase of 

a CT scanner for the local medical center, and structural 

improvements to Lesterville High School. The enhancements are scheduled for completion by July 2008.

Commission staff also focused on safety issues involving a sinkhole discovered in the crest of the Swinging 

Bridge Dam on the Mongaup River in Sullivan County, 

New York. The Commission conducted an investigative 

program to assess the condition of the dam, to determine the cause of the sinkhole, and to determine what 

actions may be necessary to correct the problem. In July 

2007, the Commission approved the reopening of the 

recreation facilities at the Swinging Bridge Reservoir. The 

recreation areas at the Mongaup Falls and Rio Projects 

will remain closed until further notice. Prior to reopening 

the reservoir, the Commission required the licensee to 

notify the public of any water and boating safety cautions that they must exercise while the reservoir is refilling. In addition, the Commission required the licensee to 

install signage at all access points notifying the public of 

the safety cautions and of the rules and regulations for 

use of the reservoir. 

FERC Staff inspect Taum Sauk Project. Inspection of Taum Sauk Project.

2007 | ANNUAL REPORT

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Reliability 

T

Historically, while the Commission regulated access to the 

transmission grid, it had no role in the approval or enforcement of reliability standards. Prior to 1965, reliability of the 

interconnected electric grid was managed by individual 

electric utilities, or groups of interconnected utilities, which 

were, to varying degrees, accountable to state and local 

regulators. Following the Northeast Blackout of 1965, regional reliability organizations and, later, the predecessor to 

NERC, were formed to develop voluntary reliability rules and 

to encourage reliable operating practices. Over time, the 

voluntary regime proved insufficient. The primary causes 

of the August 2003 blackout were violations of voluntary 

reliability standards. Indeed, a common cause of all previous 

major bulk power system failures was violation of voluntary 

reliability standards.

he security, safety, and economic well-being of our citizens depend upon the reliability of our Nation’s 

bulk power system. It is therefore critical for the industry to be regulated by clear, unambiguous, mandatory and enforceable reliability standards and secure communications and control technology. 

Reliability Standards

In EPAct 2005 Congress granted the Commission authority 

to establish mandatory reliability standards, and ultimately 

enforce those standards by adding to the Federal Power Act 

a new section 215 on reliability. It directed the Commission 

to promulgate new rules addressing establishment of an 

Electric Reliability Organization (ERO) and development of 

mandatory electric reliability standards and enforcement 

procedures. On June 18, 2007, reliability standards became 

mandatory for the wholesale electricity grid. 

During FY 2007, the Commission took a number of 

important steps to implement section 215 of the FPA 

and to ensure that the reliability standards could become 

effective for the summer season:

 In March 2007, the Commission acted to assure the 

reliability of the nation’s bulk power system by approving reliability standards proposed by the North 

American Electric Reliability Corporation (NERC), the 

Commission-certified ERO. The final rule approved 83 

of 107 proposed reliability standards, which apply to 

users, owners and operators of the bulk power system 

designated by NERC through its compliance registry 

procedures, and simultaneously directed the ERO to 

modify 56 of the approved reliability standards to address issues identified by the Commission. 
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 In April 2007, the Commission approved NERC’s 

pro forma Delegation Agreement, which serves as 

the blueprint for the contractual relationship between NERC and eight regional reliability entities. 

The agreement includes a compliance monitoring 

and enforcement program to be used by NERC and 

regional entities to monitor, assess and enforce compliance with Commission-approved mandatory reliability standards.

 In May 2007, the Commission issued a final rule to 

ensure that qualifying facilities are subject to mandatory reliability rules. The final rule clarified that 

qualifying facilities are not, as a class, exempt from 

compliance with mandatory reliability standards. 

 In May 2007, the Commission approved the assignment of more than 700 Violation Risk Factors for 

NERC’s Reliability Standards. A Violation Risk Factor links the violation of a Requirement of a Reliability Standard with its potential reliability impact 

on the Bulk-Power System. Violation Risk Factors 

are an important part of the ERO’s compliance and 

enforcement program that will be used in the determination of monetary penalties for violations of 

reliability standards.

 In June 2007, the Commission approved eight regional reliability standards for the Western Interconnection. The proposed regional reliability standards 

would allow the continuation of certain reliability 

practices that are currently in effect in the Western 

Interconnection.

 In July 2007, the Commission issued the Small Entity Compliance Guide to assist small entities—small 

businesses, small organizations and small governmental entities—to comply with the Commission’s 

mandatory reliability standards. 

 In August 2007, the Commission proposed to approve three reliability standards that set requirements for the development of system operating 

limits of the wholesale electricity grid for use in the 

planning and operation horizons.

 In September 2007, the Commission held a technical 

conference to explore issues associated with cost recovery of penalties for reliability standard violations 

assessed against ISOs and RTOs.

CYBER SECURITY

The Commission has also begun to analyze and facilitate 

the industry’s work in cyber and physical security and information exchange within the industry. In July 2007, the 

Commission issued a proposed rule to approve a set of reliability standards and, immediately after their approval, to 

direct modifications to them in order to help safeguard the 

nation’s bulk electric power supply system against potential 

disruptions from cyber attacks. The proposed standards 

require certain users, owners and operators of the grid to 

establish plans, protocols and controls to safeguard physical 

and electronic access to systems, to train personnel on security matters, to report security incidents, and to be prepared 

to recover information. The proposed rule follows a Commission Staff Assessment of Critical Infrastructure Protection Standards, which was issued in December 2006. 

Electric Reliability Standards Approved in FY 2007

Reliability 

Standard Title

BAL-001-0 Real Power Balancing Control Performance

BAL-002-0 Disturbance Control Performance

BAL-003-0 Frequency Response and Bias

BAL-004-0 Time Error Correction

Reliability 

Standard Title

BAL-005-0 Automatic Generation Control

BAL-006-1 Inadvertent Interchange

CIP-001-1 Sabotage Reporting

COM-001-1 Telecommunications
2007 | ANNUAL REPORT

45

Reliability 

Standard Title

COM-002-2 Communications and Coordination

EOP-001-0 Emergency Operations Planning

EOP-002-2 Capacity and Energy Emergencies

EOP-003-1 Load Shedding Plans

EOP-004-1 Disturbance Reporting

EOP-005-1 System Restoration Plans

EOP-006-1 Reliability Coordination – System Restoration

EOP-008-0 Plans for Loss of Control Center Functionality

EOP-009-0 Documentation of Blackstart Generating 

Unit Test Results

FAC-001-0 Facility Connection Requirements

FAC-002-0 Coordination of Plans for New Facilities

FAC-003-1 Transmission Vegetation Management Program

FAC-008-1 Facility Ratings Methodology

FAC-009-1 Establish and Communicate Facility Ratings

FAC-013-1 Establish and Communicate Transfer Capabilities

INT-001-2 Interchange Transaction Tagging

INT-003-2 Interchange Transaction Implementation

INT-004-1 Interchange Transaction Modifications

INT-005-1 Interchange Authority Distributes 

Arranged Interchange

INT-006-1 Response to Interchange Authority

INT-007-1 Interchange Confirmation

INT-008-1 Interchange Authority Distributes Status

INT-009-1 Implementation of Interchange

INT-010-1 Interchange Coordination Exceptions

IRO-001-1 Reliability Coordination – Responsibilities 

and Authorities

IRO-002-1 Reliability Coordination – Facilities

IRO-003-2 Reliability Coordination – Wide Area View

IRO-004-1 Reliability Coordination – Operations Planning

IRO-005-1 Reliability Coordination – Current Day Operations

IRO-006-3 Reliability Coordination – Transmission 

Loading Relief

IRO-014-1 Procedures, Processes, or Plans to Support 

Coordination Between Reliability Coordinators

IRO-015-1 Notifications and Information Exchange 

Between Reliability Coordinators

IRO-016-1 Coordination of Real-time Activities 

Between Reliability Coordinators

MOD-006-0 Procedures for Use of CBM Values

MOD-007-0 Documentation of the Use of CBM

MOD-010-0 Steady-State Data for Transmission 

System Modeling and Simulation

MOD-012-0 Dynamics Data for Transmission System 

Modeling and Simulation

MOD-016-1 Actual and Forecast Demands, Net Energy 

for Load, Controllable DSM

MOD-017-0 Aggregated Actual and Forecast Demands 

and Net Energy for Load

MOD-018-0 Reports of Actual and Forecast Demand Data

MOD-019-0 Forecasts of Interruptible Demands 

and DCLM Data

MOD-020-0 Providing Interruptible Demands and DCLM Data

MOD-021-0 Accounting Methodology for Effects 

of Controllable DSM in Forecasts

PER-001-0 Operating Personnel Responsibility and Authority

PER-002-0 Operating Personnel Training

Reliability 

Standard Title

PER-003-0 Operating Personnel Credentials

PER-004-1 Reliability Coordination – Staffing

PRC-001-1 System Protection Coordination

PRC-004-1 Analysis and Mitigation of Transmission and 

Generation Protection System Misoperations

PRC-005-1 Transmission and Generation Protection System 

Maintenance and Testing

PRC-007-0 Assuring Consistency with Regional UFLS Program

PRC-008-0 Underfrequency Load Shedding Equipment 

Maintenance Programs

PRC-009-0 UFLS Performance Following 

an Underfrequency Event

PRC-010-0 Assessment of the Design and Effectiveness 

of UVLS Program

PRC-011-0 UVLS System Maintenance and Testing

PRC-015-0 Special Protection System Data 

and Documentation

PRC-016-0 Special Protection System Misoperations

PRC-017-0 Special Protection System Maintenance 

and Testing

PRC-018-1 Disturbance Monitoring Equipment Installation 

and Data Reporting

PRC-021-1 Under-Voltage Load Shedding Program Data

PRC-022-1 Under-Voltage Load Shedding Program Performance

TOP-001-1 Reliability Responsibilities and Authorities

TOP-002-2 Normal Operations Planning

TOP-003-0 Planned Outage Coordination

TOP-004-1 Transmission Operations

TOP-005-1 Operational Reliability Information

TOP-006-1 Monitoring System Conditions

TOP-007-0 Reporting SOL and IROL Violations

TOP-008-1 Response to Transmission Limit Violations

TPL-001-0 System Performance Under Normal Conditions

TPL-002-0 System Performance Following Loss of a Single 

BES Element

TPL-003-0 System Performance Following Loss of Two or 

More BES Elements

TPL-004-0 System Performance Following Extreme BES Events

VAR-001-1 Voltage and Reactive Control

VAR-002-1 Generator Operations for Maintaining Network 

Voltage Schedules

Glossary Glossary of Terms Used in Reliability Standards

WECC-BALSTD-002-0 Operating Reserves

WECC-IROSTD-006-0 Qualified Path Unscheduled Flow Relief

WECC-PRCSTD-001-1Certification of Protective Relay Applications 

and Settings

WECC-PRCSTD-003-1Protective Relay and Remedial 

Action Scheme Misoperation

WECC-PRCSTD-005-1 Transmission Maintenance

WECC-TOPSTD-007-0 Operating Transfer Capability

WECC-VARSTD-002a-1 Automatic Voltage Regulators

WECC-VARSTD-002b-1 Power System Stabilizers

2007 | ANNUAL REPORT

47

Enforcement

Competitive energy markets can succeed only when competition is tempered by effective regulation. The Commission has adjusted its regulatory policies to meet the dramatic changes that have occurred in both the natural gas and electricity industries. While the core legal duties of the Commission have not changed—that is, to guard the consumer from market power abuse—the means of discharging this 

duty have evolved over time. 

The Commission permits market-based rates and increasingly sets rules of general applicability that govern market 

participants and, where applicable, an entire market. As a 

result of this regulatory approach, it is even more important for the Commission to promote compliance with, and 

enforce, the statutes it is responsible for implementing and 

the regulations it issues under those statutes.

The Commission seeks to detect violations quickly; 

penalize those who violate orders, rules, and regulations; seek disgorgement of unjust profits or other remedies; publicize misconduct where appropriate; and take 

prompt action to prevent future misconduct. 

It is important that the Commission understand 

market dynamics, detect problems or issues in energy 

markets early, prevent violations of its rules, and enforce 

compliance with the laws under its jurisdiction. Perhaps 

most importantly, the Commission needs to ensure that 

utilities subject to its jurisdiction have effective internal 

monitoring and compliance programs in place to assure 

that they are following established Commission rules 

and regulations. Commission oversight must then provide an independent and external check to ensure that 

the compliance programs of each jurisdictional utility 

are adequate, and periodically to audit utility compliance with Commission’s rules, regulations and statutory 

requirements. 
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The Commission’s enforcement tools were greatly 

reinforced when EPAct 2005 conferred expanded authority, which provided for the first time civil penalty 

authority for violations of the Natural Gas Act and Part 

II of the Federal Power Act. This expanded penalty authority also applied to any entity (not just companies traditionally subject to the Commission’s jurisdiction) that 

manipulates wholesale gas or electric markets by engaging in fraud or deceit in connection with jurisdictional 

transactions. Armed with this expanded authority, the 

Commission has created an even stronger and more effective compliance and enforcement program to protect 

the public interest.

Within the Office of Enforcement, the Division of Energy Market Oversight monitors markets on a daily basis 

and maintains regular contact with the market monitors 

in the Commission-approved RTOs and ISOs. The Division of Investigations conducts non-public investigations 

of violations of Commission orders, rules or regulations, 

and the Division of Audits conducts operating and financial audits of regulated entities’ practices.

Vigilant Oversight

Energy markets are complex and change rapidly. A key part 

of the Commission’s market-oriented approach to its oversight of the natural gas and electric power industries is the 

ability to identify potential problems quickly and to address 

them before they become severe. Transparency of market 

operations is key to market oversight.

Identification and Remedy of 

Potential Market Problems 

In FY 2007, the Commission continued to enhance its comprehensive energy market oversight program. This program 

reviews all key markets daily to detect both anomalous 

behavior by individual market participants and problems 

with market rules or operations that affect outcomes significantly. The program uses a real-time information capability 

to address rapidly developing situations and emergencies. 

The Commission’s Market Monitoring Center (MMC) provides analysts with data from numerous sources of market 

information. The information includes data on prices from 

sources such as RTOs and the trade press, on physical flows 

on the pipeline and electric transmission systems (largely 

from data aggregators), on the operating status of some 

generating units (for example, operational information on 

nuclear plants from the Nuclear Regulatory Commission) 

and on some aspects of individual transactions from some 

trading platforms. It acts as a nerve center where analysts 

can quickly examine market conditions, exchange insights 

and develop shared understanding of the information observed. Through daily fact-finding meetings attended by 

Commission staff, followed by briefings if warranted, the 

market oversight program helps keep key decision makers 

updated on market activities.

The MMC, where Commission staff can access most 

of the real-time and other data obtained from information providers, is a hub of data-collection and analysis for 

Commission research staff and a “must-visit” for foreign 

and domestic visitors engaged in or contemplating monitoring their energy markets. In FY 2007, more than 48 

groups were briefed on MMC functions and operations 

by Commission staff; these groups included more than 

380 individuals from 32 foreign country delegations. Staff 

from the U.S. Congress, state commissions, federal agencies, and other energy-related agencies/organizations 

also toured the MMC in conjunction with appropriate 

briefings. 

The market oversight program focuses on wholesale 

physical markets for natural gas and electric power and 

associated transmission markets. The Commission’s market oversight program examines detailed interactions 

between the two industries to detect any possible problems as soon as possible after their occurrence.

Because many other markets affect the operation of 

the physical electric power and natural gas markets, the 

market oversight program also reviews related markets 

every day, including: financial markets for electric power 

and natural gas, markets for generation fuels and emissions credits, and international markets.
2007 | ANNUAL REPORT

49

The Commission also supports state efforts to monitor power and gas markets. To that end, in FY 2007 the 

Commission established the Research in Market Oversight (RIMO) program. Under this program, representatives from state agencies come to the Commission for a 

week to research an energy market issue of importance 

to the state in partnership with the Commission’s Market Oversight staff. The first RIMO project in April 2007 

saw five representatives from Wyoming (including three 

aides to the Governor) study the effect of natural gas 

pipelines on prices paid to producers in Wyoming. In 

June 2007, two separate RIMO projects occurred. First, 

a staff member of the California Public Utilities Commission studied episodes of high prices in various RTOs. 

Second, three staff members of the Public Utilities Commission of Ohio improved modeling techniques they use 

to analyze electric markets in Ohio. The Commission 

anticipates performing at least four projects a year with 

states in the future.

The RIMO program complements an ongoing program in which the Commission makes available to state 

and federal energy agencies the opportunity to discuss information on energy markets, including: natural 

gas supplies and prices of electric power, LNG facilities 

planned and under construction, coal market fundamentals, weather implications and an analysis of observed 

changes over the month. The program provides for 

monthly regional phone discussions with representatives 

of various agencies that have requested participation, 

using information as posted on the Market Oversight 

web site and other energy issues the agencies may wish 

to discuss. This outreach program began modestly and 

has now grown to more than 38 participating state and 

federal energy agencies, four regional state entities and 

British Columbia. 

Complementing the market oversight program is 

the long-established Enforcement Hotline program. The 

Hotline provides a way for market participants and the 

public to contact the Commission’s enforcement staff 

on a confidential basis by telephone or email on matters affecting prices and wholesale utility service, including bidding anomalies, price spikes, inappropriate use of 

financial instruments, changes in available capacity on 

electric transmission systems or natural gas pipelines, 

undue discrimination in access to interstate transmission 

or transportation services, or violations of the Commission’s Standards of Conduct or other improper affiliate 

transactions. The Hotline also is available to landowners 

to raise concerns regarding pipeline construction and remediation that affects their property. Matters brought to 

the attention of the Hotline may result in investigations 

by the Commission’s enforcement staff.

Transparency 

Sections 316 and 1281 of EPAct 2005 added section 23 to 

the Natural Gas Act and section 220 to the Federal Power 

Act. These sections provide that the Commission may act 

to facilitate price transparency in wholesale natural gas and 

electricity markets and authorize the Commission to adopt 

such rules as may be necessary to assure the timely dissemination of information about the availability and prices of 

natural gas, electric energy and transmission service in such 

The market oversight program

 focuses on wholesale physical markets

 for natural gas and electric power

 and associated transmission markets.
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markets. In FY 2007, the Commission took several actions 

to improve market transparency:

 In October 2006, the Commission held a transparency technical conference designed to (1) review the 

current structure of energy markets with a particular 

emphasis on the transparency of price development, 

(2) assess the quality of existing transparency mechanisms, (3) examine developing price transparency 

mechanisms, and (4) identify any opportunities for 

Commission action under EPAct 2005 authority to 

improve transparency in these markets.

 In October 2006, the Commission adopted new accounting rules for service companies and holding 

companies to allow for greater accounting transparency and to protect ratepayers from paying for improper service company costs.

 In April 2007, to address concerns regarding transparency in natural gas markets, the Commission 

proposed new rules to facilitate price transparency 

in markets for the sale and transportation of natural gas in interstate commerce. The proposed rule 

would establish (a) a daily requirement for intrastate pipelines to post the capacities and volumes 

of natural gas flowing through their major receipt 

and delivery points and mainline segments, and (b) 

an annual requirement for certain buyers and sellers 

of natural gas to report the numbers and volumes of 

relevant transactions for the previous calendar year.

 In July 2007, the Commission held a transparency 

workshop to discuss various implementation and 

other technical issues associated with the proposals 

set forth in the transparency proposed rule.

Market Oversight

During FY 2007, Commission staff continuously examined 

the seasonal events affecting natural gas and electricity 

prices. The goal was to provide information for Commission staff and to help Congress, state officials and citizens to 

understand the factors affecting energy supply and demand, 

and natural gas and electricity prices. At several Commission meetings, staff presented the Commission and the 

public detailed information relating to current market prices 

and analyses explaining those prices and their effect on 

supply and demand in the various regions of the Nation. 

In February 2007, the Commission issued the 2006 State of 

the Markets Report.

In January 2007, the Commission announced an addition to its website to allow greater access to information 

on jurisdictional and related electric and natural gas markets. The site serves as a repository for Commission analytic work as well as regular updates of market data. This 

initiative allows stakeholders, regulators and the public to 

get better access to Commission staff’s market observations through the website. Specifically, the webpage:

 Collects and organizes staff’s analytical work, such 

as the State of the Markets Report; and the Winter 

and Summer Assessments.

 Presents regional information on electric and gas 

markets, including supply, demand, capacity and 

price information.

 Updates monthly more than 50 graphs on market 

indices such as electric and gas prices, generated 

and delivered electric power and gas pipeline and 

storage volumes. 

Financial Forms

Uniform accounting and financial forms provide information 

that is essential to the Commission’s oversight authority, 

namely, financial data covering a company’s past performance. The financial statements are prepared in accordance 

with the Commission’s Uniform Systems of Accounts and 
2007 | ANNUAL REPORT

51

related regulations. The statements provide data that enable the Commission to develop and monitor cost-based 

rates, analyze costs of different services and classes of assets, 

and compare costs across lines of business. In addition, the 

financial forms are relied upon by electric utilities, interstate 

natural gas pipeline and oil pipelines, state commissions, and 

trade associations to develop and monitor rates. In FY 2007, 

the Commission took the following actions to improve accounting and reporting of financial information:

 In October 2006, the Commission amended its regulations to provide for electronic filing of the FERC 

Form 60 (annual reporting by centralized service 

companies in holding companies). In connection 

with this initiative, the Commission developed and 

made available to filers electronic submission software, thereby reducing the cost of data entry and 

the overall burden on filers.

 Also in October 2006, Commission staff met informally with both filers and users of Forms 1 and 

2 (annual reporting by Public Utilities and Natural 

Gas companies) to reexamine the type of data collected by the forms and to determine the need for 

clarifications, corrections, deletions or additional 

information.

 In February 2007, the Commission initiated a rulemaking proceeding to assess whether its financial 

forms collect relevant financial information critical 

to the Commission’s jurisdictional activities. 

 Simultaneously, the Commission ordered 14 companies to explain why they failed to file required financial 

forms, and eliminated the capability to mark data as 

“privileged” in electronic submissions of financial forms. 

 In March and May of 2007, the Commission provided guidance to industry on how companies should 

implement new accounting standards in the areas 

of employee post-retirement benefits and income 

taxes for Commission accounting and reporting 

purposes. The new standards and guidance will improve financial reporting and ensure that all companies account for and report these transactions to 

the Commission in a uniform manner. 

 In July 2007, the Commission held a staff workshop 

to address the need for changes or revisions to the 

Commission’s reporting requirements in the FERC 

Form No. 6 (annual reporting by Oil Pipelines). By 

addressing these issues, Commission staff provided an informal forum for market participants and 

stakeholders in the oil industry to explore ways to 

improve the quality and usefulness of information 

contained in this form.

 In September 2007, the Commission proposed to 

amend the financial forms, statements, and reports 

for natural gas companies, making up FERC Form 

Nos. 2, 2-A and 3-Q. The proposed revisions reflect 

the fact that in the present regulatory environment, 

in which interstate natural gas pipelines are no longer required to file a triennial restatement of rates, 

and the number of filed rate cases has declined 

sharply, FERC Form Nos. 2, 2-A, and 3-Q may need 

to be expanded and otherwise revised in order for 

the Commission and the public to have sufficient 

information to assess the justness and reasonableness of pipeline rates. 

Market Monitoring Units

Market monitors have played an integral role in the organized electric markets, providing valuable reporting and 

analysis services not only to the Commission, but also to 

the RTOs and ISOs, to market participants, and to state 

commissions. In light of their importance, the Commission 

has required that all RTOs and ISOs incorporate a market 

monitoring function. Market monitoring units (MMUs) 

take different forms and perform a diverse set of market 

functions, depending on the individual tariffs of their respective RTOs or ISOs. The span of years over which market 
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monitors have been in existence has given the Commission 

and others in the industry a track record upon which to 

evaluate the appropriate roles MMUs should play and the 

procedures that might be adopted to assist them in performing those roles. 

In April 2007, the Commission held a technical conference to review its market monitoring policies. At the 

conference, the Commissioners heard from interested 

parties on the development of the concept and functions of market monitoring, the MMUs’ role with respect 

to the Commission, the MMUs’ role with respect to ISOs 

and RTOs, and the MMUs’ role with respect to the various stakeholders such as states, generators, transmission 

providers and customers. 

In June 2007, the Commission issued a proposal, 

which sought comment on the following proposals regarding MMUs:

 Remove the market monitoring unit from RTO/ISO 

operations.

 Require that the MMU advise the Commission and 

other stakeholders of any design flaws and report to 

the Commission any tariff violations it believes may 

have been committed by the RTO or ISO.

 Hold regular conference calls among the market monitor, interested state commissions and FERC staff.

 Release offer and bid data, with a lag period, but 

mask market participants’ identities.

 Subject to certain limitations, allow state commissions within an RTO or ISO to request and receive 

information from the RTO’s or ISO’s MMU.

 Develop a pro forma tariff provision to address all 

sections relating to market monitoring.

In May 2007, in response to complaints filed against PJM 

alleging interference with the independence of PJM’s MMU, 

the Commission issued data requests to both PJM and the 

MMU to determine whether, in fact, there had been any 

tariff violations or interference with the MMU by PJM, and 

whether any such interference was ongoing. In September 

2007, the Commission issued an order on the complaints. 

While the Commission concluded that PJM had not committed any tariff violations, the Commission initiated settlement procedures for the parties to address the details of the 

relationship between PJM and the MMU.

Firm but Fair 

Enforcement

In EPAct 2005, Congress substantially enhanced the Commission’s enforcement authority. First, the new law expanded the Commission’s authority to assess civil penalties to 

include all of the Natural Gas Act and Part II of the Federal 

Power Act, and set the maximum civil penalty authority for 

the Natural Gas Act, Part II of the Federal Power Act, and 

the Natural Gas Policy Act of 1978 at $1 million per violation 

per day. Second, EPAct 2005 amended the Natural Gas Act 

and Federal Power Act to prohibit the use of manipulative 

or deceptive devices or contrivances by any entity in connection with the purchase or sale of electric energy, natural 

gas, or transmission or transportation services subject to the 

jurisdiction of the Commission.

In light of the new authorities granted the Commission by EPAct 2005, the Commission has taken a number 

of steps to craft a cohesive approach to enforcement, 

built around the central theme that Commission enforcement actions will be firm but fair. The Commission 

uses the full range of remedies available—civil penalties, 

disgorgement of unjust profits, or conditioning, revocation, or suspension of authorizations—but exercises 

discretion to apply such penalties and remedies in a fair, 

reasonable and appropriate manner.

Clear and Fair Processes 

In FY 2007, the Commission took additional steps to establish clear and fair processes to protect energy customers. 

Specifically, the Commission took the following actions:

 In October 2006, the Commission modified its 

“no-action” letter process, which allows entities to 

request and obtain informal staff advice on certain 
2007 | ANNUAL REPORT

53

matters. The Commission clarified that the no-action letter process could be used to obtain advice 

as to whether Staff will recommend that the Commission take no enforcement action with respect to 

specific proposed transactions, practices or situations that may raise issues under the Commission’s 

regulations relating to the Standards of Conduct for 

Transmission Providers, Market Behavior Rules, the 

Prohibition of Energy Market Manipulation Rules, 

and the codes of conduct. 

 In December 2006, the Commission outlined its 

policy for processing and assessing civil penalties 

administratively. The Statement of Administrative 

Policy explains how the Commission will assess civil 

penalties and the procedural safeguards provided 

when it takes enforcement actions under Parts I and 

II of the Federal Power Act, the Natural Gas Act and 

the Natural Gas Policy Act of 1978.

 In May 2007, the Commission approved the assignment of over 700 violation risk factors for NERC 

reliability standards. The Commission reviewed the 

proposed violation risk factor assignments to determine whether they appropriately indicate the potential or expected impact to the reliability of the 

bulk-power system.

Investigations and Enforcement

In competitive markets, participants constantly seek new 

profit opportunities, but some participants may violate rules 

or manipulate markets to reap unjust profits. In FY 2007, 

the Commission actively monitored electric and natural 

gas markets to determine whether price movements are 

the result of market manipulation or market fundamentals. 

The Commission’s market oversight and investigations staff 

continually reviewed market activity for any possible manipulation of prices. In close coordination with investigations staff, market oversight staff performs a detailed review 

of wholesale electric and natural gas prices and market 

activity on a daily basis with the intent of identifying areas 

of possible manipulation. If Commission staff identify price 

anomalies that are not explained by market fundamentals 

it will investigate the matter.

The Commission’s enforcement investigations in FY 

2007 focused on possible market manipulation, undue 

discrimination or affiliate abuses, violations of Standards 

of Conduct requirements, compliance with hydropower 

requirements, violations of the terms and conditions of 

tariffs, referrals from market monitors in organized markets, and violations related to Commission rules and regulations. Enforcement investigations arise from a variety 

of sources, including referrals from the Commission, Enforcement Hotline calls, direct contact with enforcement 

staff, observations of markets, market monitors in RTOs 

and ISOs, and anonymous tips. 

In light of the new authorities granted the Commission by 

EPAct 2005, the Commission has taken a number of steps

 to craft a cohesive approach to enforcement, 

built around the central theme that Commission 

enforcement actions will be firm but fair.
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In FY 2007, the Commission continued to use the 

Enforcement Hotline, a mechanism whereby industry 

participants provide information to the Commission, 

to identify other potential investigations. In addition 

to identifying possible investigations, the Enforcement 

Hotline was used by the Commission to encourage selfpolicing and reporting of violations. 

Where the Commission identified violations, it applied remedies to mitigate the effects of market power, 

required disgorgement of unjust profits where appropriate, imposed civil penalties or other sanctions when 

available under existing laws, and required compliance 

plans to prevent future violations. 

In many cases enforcement proceedings result in settlements. Settlements allow the Commission to stretch 

out enforcement resources and conduct investigations 

across a wider field. They also benefit consumers by delivering benefits such as disgorgement of profits sooner 

than would be possible under litigation. In FY 2007, the 

Commission approved the following settlements of enforcement matters:

 In October 2006, the Commission completed action 

on an investigation concerning the breach of the upper reservoir of the Taum Sauk hydroelectric project 

in Missouri. The Commission approved a record hydropower settlement of $15 million, including a $10 

million civil penalty and a $5 million fund to provide 

enhancements to the project area over and above 

remediation of the damages from the breach.

 In January 2007, SCANA Corporation agreed to 

pay a $9 million civil penalty and to disgorge $1.4 

million in profits to resolve an investigation into 

violations of the utility’s Open Access Transmission 

Tariff (OATT). The company further agreed to credit 

$400,000 in foregone point-to-point transmission 

revenues to retail customers, and to undertake a 

compliance program including quarterly filings to 

allow the Commission to ascertain the company’s 

continuing compliance with the network service 

provisions of its OATT. Specifically, staff identified 

1,109 transactions during a four-year period in which 

South Carolina Electric & Gas, a SCANA subsidiary, 

improperly used network transmission to facilitate 

off-system wholesale power sales in violation of its 

Open Access Transmission Tariff.

 In January 2007, PacifiCorp agreed to pay a $10 million civil penalty to settle violations of the utility’s 

Open Access Transmission Tariff (OATT) and Standards of Conduct. Staff’s investigation found that 

PacifiCorp engaged in hundreds of OATT violations 

granting undue preference to its merchant power 

function, and engaged in numerous and significant 

Standards of Conduct violations. The investigation 

began when PacifiCorp self-reported, following its 

acquisition by MidAmerican Energy Co., having 

used network transmission service for transactions 

that should have employed point-to-point transmission service. Staff identified 1,096 violations since 

April 2003, representing 174,639 MW of total transmission service.

Settlements allow the Commission to 

stretch out enforcement resources and conduct 

investigations across a wider field. They also benefit 

consumers by delivering benefits such as disgorgement 

of profits sooner than would be possible under litigation.
2007 | ANNUAL REPORT

55

 In January 2007, Entergy agreed to pay a $2 million 

civil penalty and to contribute $1 million to a hurricane relief fund to settle three separate self-reported 

matters: (1) employees of Entergy lost, in violation 

of the Federal Power Act, all hourly Available Flowgate Capability (AFC) data files from the start of the 

AFC system in April 2004 through January 2005; (2) 

Entergy’s AFC system responded in error to nearly 

2,000 requests for transmission service between 

April 2004 and January 2006; and (3) Entergy on 

multiple occasions failed to post information on its 

open-access same-time information system (OASIS) 

in violation of the Commission’s OASIS posting requirements.

 In January 2007, Northwestern Energy agreed to 

pay a $1 million civil penalty to settle 83 instances 

in which the utility violated its Open Access Transmission Tariff, including failure to act on requests for 

firm monthly and yearly point-to-point transmission 

service within 30 days, as required by the Commission’s Business Practice Standards. Thirty-nine of the 

violations occurred after August 8, 2005, the date of 

EPAct 2005’s enactment.

 In January 2007, NRG Energy agreed to pay a 

$500,000 civil penalty to settle violations of Commission Market Behavior Rules that resulted from 

the misrepresentation of a reliability-must-run generation facility in ISO-New England. Staff found that 

NRG intentionally misrepresented that the generating plant was available, when it was not. The misrepresentation resulted from the actions of a single 

employee and did not involve NRG Energy senior 

management, the staff investigation concluded. 

NRG Energy took immediate corrective action, including reporting the incident to the Commission 

and ISO-New England. 

 In March 2007, Bangor Gas Co. agreed to pay a civil 

penalty of $1 million and take other actions to resolve self-reported violations of the Commission’s 

“shipper-must-have-title” requirements. Bangor Gas 

Co. did not hold title to the gas it transported for 

nine customers on a natural gas pipeline located in 

Maine.

 In May 2007, a Calpine Corporation affiliate, Calpine 

Energy Services, L.P. (CES), agreed to allow a $4.5 million civil penalty claim in its bankruptcy proceeding 

to resolve self-reported violations of the Commission’s “shipper-must-have-title” requirements. The 

Commission found that CES violated Commission 

requirements when the company failed to hold title 

to 156.5 Bcf of gas that CES transported on eight 

natural gas pipelines. CES’s violations of the “shipper-must-have-title” requirement numbered in the 

thousands and varied in type, including the misuse 

of capacity held by Calpine affiliates to serve other 

affiliates, and improper movement of gas to storage 

and delivery of gas to other pipelines and markets.

 In May 2007, Columbia Gulf Transmission Company 

(Columbia Gulf) agreed to pay a civil penalty of $2 

million to resolve an investigation into whether Columbia Gulf violated Commission orders by failing to 

allow Tennessee Gas Pipeline Company to construct 

a receipt point interconnection on a natural gas 

complex in Egan, Louisiana. Under the Stipulation 

and Consent Agreement, Columbia Gulf may not recover the civil penalty amount from its ratepayers.

 In June 2007, Cleco Power, LLC, (Cleco), agreed to 

pay a civil penalty of $2 million to resolve an investigation into whether it violated its code of conduct 

and a 2003 Commission-approved settlement agreement. Following a self-report by Cleco, a staff investigation found that Cleco’s regulated electric utility 

and its exempt wholesale generators violated the 

2003 Settlement Agreement and their code of conduct by sharing six operating personnel and market 

information from the summer of 2003 to as late as 

the winter of 2005. The investigation also found that 

Cleco failed to disclose those violations to the Commission’s Office of Enforcement, as required under 

the 2003 Settlement Agreement.
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 In August 2007, the Commission approved a settlement with Gexa Energy, L.L.C. (Gexa) stemming 

from its failure to file for merger authorization in 

advance of indirect transfer of Gexa’s jurisdictional 

assets to FPL Energy (FPLE) in a transaction in which 

FPLE purchased all the equity of Gexa’s parent company. Pursuant to the Settlement, Gexa will pay a 

$500,000 civil penalty and disgorge nearly $12,500 in 

profits with interest.

Not all enforcement actions result in settlements. Congress 

gave the Commission the authority to prevent manipulation to protect both consumers and the integrity of these 

markets on which our economy depends. When manipulation is detected and proven, violators will be punished 

severely.

In July 2007, for the first time, the Commission used 

its new enforcement authority to prosecute market manipulation when it issued show cause orders that made 

preliminary findings of market manipulation and proposed civil penalties and disgorgement totaling $458 

million in two investigations involving traders’ actions in 

natural gas markets. Specifically, the Commission took 

the following actions with respect to preliminary findings of market manipulation:

 The Commission directed Amaranth and two traders to show cause why they should not be assessed 

civil penalties and disgorge profits totaling $291 

million for manipulating the price of Commissionjurisdictional transactions by trading in the NYMEX 

Natural Gas Futures Contract in February, March 

and April 2006.

 The Commission directed Energy Transfer Partners, 

L.P. to show cause that it did not violate the Commission’s then-applicable market behavior rule by 

manipulating the wholesale natural gas market at 

Houston Ship Channel on certain dates in 2003, 

2004 and 2005. The Commission proposed more 

than $167 million in total penalties and disgorgement of unjust profits.

Internal Compliance

Self-reports began immediately after the issuance of the Policy Statement on Enforcement. In FY 2007, the Commission 

received 40 self-reports of violations of various Commission 

orders, rules or regulations. In many cases companies took 

self-corrective action before making the self-report. During 

FY 2007, 16 self-reports involving less serious matters were 

closed without further action by the Commission, upon a 

showing by the company that it was now in compliance. 

Elsewhere, the Commission has imposed civil penalties for 

more serious violations that were self-reported, but in doing 

so gave significant credit in determining the penalty amount 

to the company for having self-reported. The Commission 

encourages companies to instill a strong culture of compliance in their organizations, and to self-report violations 

promptly and fully.

It is incumbent upon the Commission to ensure that 

its market, reliability and other regulatory rules are clear, 

enforceable and fully understood by the jurisdictional 

entities that we regulate. Yet the obligation to comply 

with those regulations, rules and standards lies with the 

regulated entity. Therefore, it is important that regulated 

entities have a rigorous internal compliance program that 

provides the tools, processes and high-level management 

support to identify problems or areas of non-compliance 

and to report such problems to the Commission. The 
2007 | ANNUAL REPORT

57

Commission intends to work with its regulated entities 

to help them develop and maintain good compliance 

procedures such that any necessary enforcement actions 

by the Commission (including penalties or sanctions) are 

a regulatory tool of last resort—invoked only when the 

compliance process has failed.

Industry Compliance 

through Audits

Audits are a crucial part of the Commission’s strategy to 

prevent the accumulation and exercise of market power. 

The Commission staff conducts audits on a regular but 

unscheduled basis to ensure that jurisdictional companies 

comply with the Commission regulations, orders and policies in four major program areas: Open Access Transmission 

Tariff; market-based rate program; market-based-rate storage program; and price transparency. Audits in these major 

program areas are performed to ensure that jurisdictional 

companies are following appropriate Commission precedent 

when providing and obtaining transmission service, making 

power sales in wholesale power markets, pricing storage and 

storage services at market prices, and reporting trade data 

to price index publishers. In FY 2007, the Commission has 

completed major audits in these program areas to improve 

jurisdictional companies’ compliance with Commission 

precedent. Corrective actions resulting from these audits 

included structural, process and procedural changes, as well 

as remedies to improve market transparency.

In FY 2007, the Commission completed 68 audits of 

jurisdictional companies, including natural gas pipelines 

and electric utilities. The 68 audits consisted of 29 operational audits and 39 financial audits. The jurisdictional 

companies implemented corrective actions to comply 

with all of the 98 recommendations issued by the Commission. The Commission conducted these audits proactively on a regular but unscheduled basis to ensure 

compliance with various Commission requirements. 

The audits resulted in stringent compliance plans 

requiring the creation of robust compliance programs. 

Among them were requirements for the company to 

conduct periodic internal audits related to the areas 

of noncompliance, to make refunds, to make correcting accounting entries, and to file tariff revisions. These 

compliance plans required the creation of organizational, 

procedural and process remedies. For example, the Commission auditors monitored a public utility’s successful 

completion of a new construction project costing $25 

million to alleviate congestion on the transmission system. This increased transmission capacity benefited 

many entities in the Midwest, including a number of municipal electricity providers. Moreover, two Commission 

audits resulted in a public utility (1) paying $1 million in 

refunds for fuel costs improperly recovered from wholesale energy customers in fuel adjustment clause billings 

and (2) paying $125,000 in refunds for engaging in affiliated transactions without Commission authorization. 

Transparency of 

market operations is key

 to market oversight.

2007 | ANNUAL REPORT

59

Appendix A

Background Information

Commission Overview

The Federal Energy Regulatory Commission (FERC or the 

Commission) is an independent agency that regulates aspects of the electric, natural gas and oil pipeline industries. 

FERC also reviews proposals to build liquefied natural gas 

(LNG) terminals, certificates interstate natural gas pipelines 

and licenses hydroelectric power projects. The Energy Policy 

Act of 2005 (EPAct 2005) gave FERC additional responsibilities for overseeing the reliability of the nation’s electric grid, 

and additional enforcement:

 Regulating the transmission and sale of natural gas 

for resale in interstate commerce. 

 Regulating the transportation services of interstate 

oil pipelines.

 Regulating the transmission and wholesale sales of 

electricity in interstate commerce.

 Reviewing mergers, acquisitions, asset sales, and certain security transactions in the electric industry.

 Licensing and inspecting private, municipal, and 

state hydroelectric projects. 

 Approving the siting and abandonment of interstate 

natural gas facilities, including pipelines, storage facilities, and liquefied natural gas facilities. 

 Approving the siting of electric transmission facilities in national interest electric transmission corridors if certain conditions are met.

 Overseeing the establishment and enforcement of 

reliability standards for the bulk power system.

 Monitoring wholesale energy markets and investigating violations of Commission orders, rules, and 

regulations.

 Enforcing compliance with FERC rules, through audits, the use of civil penalties, and other means.

 Overseeing environmental matters related to natural gas pipelines and hydroelectric projects. 

 Administering accounting and financial reporting 

regulations applicable to regulated companies. 

 Assuring the safety of licensed hydroelectric projects and liquefied natural gas facilities.

The combination of the Commission’s vision, mission, organizational structure, resources and goals, as described in 

this section will help it achieve its regulatory responsibilities, 

including those added by EPAct 2005.
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Regulatory Authority

The Commission is an independent regulatory agency within 

the U.S. Department of Energy (DOE).

The Commission was created through the Department of Energy Organization Act on October 1, 1977. 

At that time, the Federal Power Commission (FPC), the 

Commission’s predecessor that was established in 1920, 

was abolished and the Commission inherited most of the 

FPC’s regulatory mission.

The Commission has five members who are appointed by the President of the United States with the advice 

and consent of the Senate to five-year staggered terms. 

Each Commissioner has an equal vote on regulatory matters and no more than three Commissioners may belong 

to the same political party. One member is designated by 

the President to serve as Chairman and is the Commission’s chief executive officer.

Hydropower regulation, the oldest area of the Commission’s jurisdiction, began with the FPC’s regulation of 

non-federal hydroelectric generation in 1920 and includes 

authorizing the construction of projects in interstate 

commerce and overseeing their operation and safety.

Since 1935, the Commission has regulated certain 

electric industry activities under the Federal Power Act. 

Under Federal Power Act sections 205 and 206, the Commission ensures that the rates, terms and conditions of 

sales for resale of electric energy and transmission service in interstate commerce by public utilities are just, 

reasonable and not unduly discriminatory or preferential. 

Under Federal Power Act section 203, as amended by 

EPAct 2005, the Commission reviews mergers and certain corporate transactions involving public utilities and 

public utility holding companies. Under Federal Power 

Act sections 203, 205 and 206, the Commission primarily 

regulates investor-owned utilities. Government-owned 

utilities (e.g., Tennessee Valley Authority, federal power 

marketing agencies, and municipal utilities) and most cooperatively owned utilities are not, in large part, subject 

to Commission regulation (with certain exceptions).

Regulation of retail sales and local distribution of 

electricity are matters left to the states. The Commission 

does not have a role in authorizing the construction of 

new generation facilities (other than non-federal hydroelectric facilities) as regulation of such construction is the 

responsibility of state and local governments. EPAct 2005 

gave the Commission authority to permit the construction or modification of transmission facilities in national 

interest electric transmission corridors designated by the 

Secretary of Energy, if certain conditions are met.

A major new area of Commission regulation as a result 

of EPAct 2005 is oversight of the Electric Reliability Organization (ERO). The ERO will develop and enforce mandatory reliability standards for the nation’s bulk power system, 

subject to Commission approval pursuant to new section 

215 authority under the FPA. On July 20, 2006, the ComMission

Regulate and oversee energy industries in the economic, 

environmental, and safety interests of the American public.

Vision

Abundant, reliable energy in a fair competitive market.
2007 | ANNUAL REPORT

61

mission conditionally certified the North American Electric 

Reliability Corporation (NERC) as the ERO. On March 15, 

2007, the Commission acted to protect the reliability of the 

nation’s bulk power system by approving 83 reliability standards proposed by the Commission-certified ERO. On June 

18, 2007, all owners, users and operators of the bulk power 

system became subject to mandatory reliability standards 

approved by the Commission.

The Commission’s role in regulating the natural gas 

industry is largely defined by the Natural Gas Act. Under 

sections 3 and 7 of the Natural Gas Act, the Commission 

regulates the construction of new on-shore LNG import 

terminals and natural gas pipelines and related facilities. 

Under sections 4 and 5 of the Natural Gas Act, it oversees the rates, terms and conditions of sales for resale and 

transportation of natural gas in interstate commerce. The 

Commission’s jurisdiction over wholesale sales of natural 

gas, however, is limited by the Natural Gas Policy Act of 

1978 and the Wellhead Decontrol Act of 1989. Pipeline 

siting and construction is authorized by the Commission if found to be required by public convenience and 

necessity. As with hydropower licensing, the Commission’s actions on LNG and pipeline projects typically 

require consideration of factors under the National Environmental Policy Act of 1969, the Endangered Species 

Act, the Coastal Zone Management Act and other such 

statutes. Regulation of the production and gathering of 

natural gas, as well as retail sales and local distribution 

of natural gas, are matters left to the states.

Finally, the Interstate Commerce Act gives the Commission jurisdiction over the rates, terms and conditions 

of transportation services provided by interstate oil pipelines. The Commission has no authority over the construction of new oil pipelines, or over other aspects of 

the industry such as production, refining or wholesale or 

retail sales of oil.

Strategic Plan

Federal Energy Regulatory 

Commission

Strategic Plan Framework

FY 2006 – FY 2011

Mission

Regulate and oversee energy industries in the economic, 

environmental, and safety interests of the American public.

Vision

Abundant, reliable energy in a fair competitive market.

Guiding Principles that Strengthen 

the Commission’s Overall Performance

To fulfill its Mission, the Federal Energy Regulatory Commission commits to:

Organizational Excellence

Use resources efficiently and effectively to achieve its 

strategic priorities.

Due Process and Transparency

Complete regulatory proceedings in an open and fair 

manner, consistent with established regulations.

Regulatory Certainty

Provide regulatory certainty through consistent Commission approaches and actions.

Stakeholder Involvement

Ensure that interested parties are informed and provided 

an appropriate opportunity to participate in Commission 

proceedings.

Timeliness

Act on regulatory matters in an expeditious manner.
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Goal 1: Energy Infrastructure

Promote the Development of a Strong Energy 

Infrastructure

Objective A: Stimulate Appropriate Infrastructure 

Development

 Resolve regulatory and other challenges to needed 

development

 Encourage investment and effect timely cost recovery

Objective B: Maintain a Reliable and Safe 

Infrastructure

 Assure reliability of the interstate transmission grid

 Protect safety at LNG and hydropower facilities

 Incorporate environmental considerations into Commission decisions

Goal 2: Competitive Markets

Support Competitive Markets

Objective A: Develop Rules that Encourage Fair 

and Efficient Competitive Markets

 Employ best practices in market rules

 Reduce barriers to trade between markets and among 

regions

Objective B: Prevent Accumulation and Exercise 

of Market Power

 Assure proposed mergers and acquisitions are in the 

public interest

 Address market power in jurisdictional wholesale 

markets

Goal 3: Enforcement

Prevent Market Manipulation

Objective A: Provide Vigilant Oversight

 Identify and remedy problems with structure and 

operations in energy markets

Objective B: Provide Firm but Fair Enforcement

 Establish clear and fair processes

 Conduct investigations promptly and impose penalties where appropriate

 Encourage self-policing and reporting of violations
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Office Descriptions

Offices Descriptions

Office of Administrative Law Judges

Resolves contested cases as directed by the Commission effectively, efficiently 

and expeditiously, either through impartial hearing and decision or through 

negotiated settlement, ensuring that the rights of all parties are preserved.

Office of Administrative Litigation

Represents the public interest and seeks to litigate or settle cases set for hearing in a timely, efficient and equitable manner while ensuring the outcomes 

are consistent with Commission policy.

Office of External Affairs Handles all external communications with the public, press, Congress, 

and the states for the Commission.

Office of the Executive Director

Provides administrative support services to the Commission including human 

resources, procurement, information technology, organizational management, 

financial, logistics and others.

Office of Energy Projects

Strengthens our energy infrastructure through the approval and oversight of 

hydroelectric and natural gas energy projects that are in the public interest 

and assures the safety of hydroelectric and LNG facilities.

Office of the General Counsel

Provides legal services to the Commission. OGC represents the Commission 

before the courts and Congress, and is responsible for the legal phases of the 

Commission’s activities.

Office of Enforcement

Ensures effective regulation and protection of consumers by monitoring the 

operation of energy markets, identifying and remedying market problems in 

a timely manner, and enforcing Commission orders, rules and regulation.

Office of Energy Markets and Reliability

Establishes and maintains rules for fair and competitive markets and prevents 

the exercise of market power and undue discrimination and preference by 

establishing market rules, terms and conditions of service. Reviews proposed 

electric reliability standards; oversees enforcement of Commission approved 

standards, reviews/conducts special reliability studies and assessments and 

considers cost recovery filings pursuant to reliability expenditures.
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Guiding Principles

Five principles guide the Commission as it exercises its 

jurisdiction under its governing statutes. Whether the 

Commission is adjudicating a rate filing, ruling on a permit 

application, or developing a new policy, it strives to meet 

these criteria as a means of ensuring that each of its actions 

is consistent with the public interest.

Organizational Excellence. Above all, the Commission strives to use its resources efficiently and effectively 

to achieve its strategic priorities. This includes its human 

resources. The Commission performs targeted recruiting 

and hiring and has developed a markets-oriented training 

curriculum for entry-level and experienced staff and a retention and mentoring program for new employees. The 

Commission also makes efficient use of its information 

technology to receive filings, produce reports and orders, 

and maintain data repositories. The Commission tracks 

the activities of its staff to ensure that they are directed at 

meeting the Commission’s strategic goals and objectives.

Due Process and Transparency. Paramount in all 

of its proceedings is the Commission’s determination to 

be open and fair to all participants. All significant initial filings submitted to the Commission are announced by way 

of public notice published in the Federal Register. Material 

issues of fact are litigated in public hearings governed by 

due process rules. Many of the Commission’s major decisions are discussed and announced at open meetings that 

are webcast at no charge on its website. Significant items 

are posted on the Commission’s website and beginning in 

July 2007 summaries of items from Commission meetings 

were immediately posted following the meeting.

Regulatory Certainty. In each of the thousands of 

orders, opinions and reports issued by the Commission 

each year, the Commission strives to provide regulatory 

certainty through consistent approaches and actions. 

Without an assurance that the Commission’s policies will 

be internally consistent and applied consistently, investors 

may be unwilling to bear the risks associated with investing in critical energy infrastructure. Where appropriate, 

the Commission provides generic direction to industry 

participants in the form of guidance orders, policy statements or rulemakings, to avoid the uncertainty present 

in case-by-case adjudications. The Commission also has 

codified market power rules designed to help prevent the 

exercise of market power and market abuse to provide a 

more stable marketplace and create an environment that 

will attract needed investment capital.

Stakeholder Involvement. The Commission conducts regular outreach to ensure that interested parties 

have an appropriate opportunity to contribute to the 

performance of the Commission’s responsibilities. The 

Commission also organizes technical conferences and 

workshops designed to explain and explore issues related 

to the development and implementation of its policies. 

Throughout FY 2007, the Commission met with state and 

federal regulators, industry officials and the public to discuss significant energy issues. Specifically, the Commission 

held the significant technical conferences and workshops; 

shown on the table on page 65.

The Commission also held regional conferences to 

identify infrastructure conditions, needs and investment, 

as well as environmental and landowner concerns. Finally, 

in processing hydropower and gas-related permit applications, the Commission conducts an extensive collaborative 

pre-filing process, during which it receives input from a 

multitude of stakeholders including citizen groups, environmental organizations, tribal interests, and local, state 

and federal resource agencies. 

Timeliness. The Commission’s goal is to reach an 

appropriate resolution of each proceeding in an expeditious 

manner. Toward that end, the Commission has steadily 

reduced the time it takes to act on projects, such as LNG 

import terminals, gas storage facilities, and interstate natural gas pipelines. It has done so without compromising 

its environmental protection and public participation responsibilities. The Commission also sets and tracks compliance with goals for timely resolution of filings for cost 

recovery, new services or changes to existing services, as 

well as on opinions resolving initial decisions, complaints, 

and FPA section 203 applications. 
2007 | ANNUAL REPORT

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Date Subject Location

October 12 Technical Conference regarding Preventing Undue Discrimination and Preference 

in Transmission Service

DC

October 13 Technical conference on Price Transparency DC

December 5 Technical Conference to discuss proposals to allocate between Midwest ISO and PJM cost 

responsibility for constructing facilities that benefit both RTOs

DC

December 6 Technical conference on Hydroelectric Infrastructure DC

December 7 Technical Conference on Public Utilities Holding Company Act of 2005 and Federal Power 

Act Section 203 Issues

DC

December 14

December 15

Technical Conference to address issues related to the CAISO electric tariff, which reflects 

the Market Redesign and Technology Upgrade

Phoenix

February 13

March 6

March 7

March 20

March 21

Workshop on Electric Transmission Siting Chicago

Boston

Atlanta

Portland 

Phoenix

February 27

May 8

Conference on Competition In Wholesale Power Markets DC

March 8 Technical Conference on the Commission’s Merger and Acquisition Review Standards 

under FPA Section 203

DC

March 29 Technical conference on Seams Issues for RTOs and ISOs in the Eastern Interconnection DC

April 5 Technical conference to review the Commission’s general policies regarding market monitoring DC

April 23 Technical Conference on Demand Response in Wholesale Markets DC

May 8 Quarterly Trilateral Electric Reliability Conference with Canadian and Mexican energy 

and reliability regulators

DC

June 4–7

June 13

June 26

June 28–29

Technical conference on “strawman” proposals regarding transmission planning under 

Order No. 890

Little Rock

Park City

Phoenix

Pittsburgh

July 18 Workshop on Adequacy of FERC Financial Forms DC

July 24 Informal staff workshop on the transparency provisions of the Natural Gas Act and the 

Energy Policy Act of 2005

DC

July 30 Technical conference on Preventing Undue Discrimination and Preference in Transmission Service DC

August 22 Technical conference on E-filing DC

September 13 Quarterly Trilateral Electric Reliability Conference with Canadian and Mexican energy 

and reliability regulators

Montreal

September 18 Technical conference on Reliability Standard Compliance and Enforcement in Regions 

with ISOs and RTOs

DC
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Appendix B

Settlements and the Alternative 

Dispute Resolution Process

The Commission encourages parties to resolve disputes in the form of settlements. Settlements offer 

a means of asserting control over the outcome that is more certain and predictable than the risk of 

litigation. To this end, the Commission encourages the use of alternative dispute resolution (ADR) 

whenever appropriate to resolve conflicts. The Commission has been actively involved in efforts to improve the use of 

alternative dispute resolution and conflict resolution on a government-wide basis. The Commission submitted extensive information on its programs in the following reports:

 In December 2006, the Commission issued its first annual report to Office of Management and Budget and 

the Council of Environmental Quality per a joint policy 

memo directing agencies to increase the effective use 

of and build institutional capacity for Environmental 

Conflict Resolution (ECR). ECR is third-party assisted 

conflict resolution and collaborative problem-solving.

ECR is used for hydropower licensing and re-licensing 

applications; natural gas facility certificate applications; LNG facility applications; and electric transmission permit applications. 

 In April 2007, the U.S. Attorney General submitted 

to the President the Report for the President on the 

Use and Results of Alternative Dispute Resolution 

in the Executive Branch of the Federal Government.

The Commission’s efforts to encourage and apply 

ADR are highlighted throughout the report and 

demonstrate the Commission’s leadership among 

federal agencies to encourage settlements and alternative approaches to conflict resolution.

Since litigation can be costly and time-consuming, 

the Commission requires litigants to conform to specified 

time limits, depending upon the complexity of the issues. 

Thus, the Commission’s litigation staff and its administrative law judges guide the efficient handling of the unique, 

complex issues that arise in today’s energy markets, and 

speed their resolution. The Commission’s administrative 

law judges frequently serve as settlement judges or mediators, thereby offering the parties greater access to the 

means of settlement which, in turn, allows them to exercise greater control over the outcomes. Overall, settlements certified in FY 2007 cases set for hearing produced 

over $129 million in immediate refunds and over $724 

million in future annual savings to ratepayers.

Below are examples of benefits obtained though uncontested settlements certified in FY 2007:

 Moratoria (e.g., three-year) in several cases preclude new rate increases and/or complaints, thereby increasing rate certainty. Several settlements 

contained “come-back” provisions requiring the 

regulated entity to make a rate filing within a set period, thus ensuring that rates will continue to reflect 

current costs.
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 Settlements improved transparency of gas pipeline 

billings, especially relating to pass through of fuel 

costs.

 Several settlements implemented audit, discovery, 

dispute resolution, complaint and subject-to-refund 

provisions to ensure that companies will bear the 

burden of justifying all of the costs they seek to pass 

through their formula rates, and to protect customers by affording them procedures through which 

they can determine the accuracy of the costs being 

flowed-through.

 Settlements protected wholesale ratepayers, and ultimately retail ratepayers, from the adverse effects of 

affiliate abuse and code of conduct violations.

 Settlements of many reactive power and reliability 

must-run cases have helped to ensure the stability 

of the transmission grid and reduce administrative 

burdens on RTOs.

 Several settlements resulted in updated, clarified, 

and improved interconnection service agreements.

 Several settlements obtained rollover rights balanced with system reliability needs.

 Settlements resolved significant rate and other issues to allow development of Cove Point LNG facility to move forward.

 Several settlements resolved issues related to who 

pays for network upgrades, and how much.

 Settlements preserved incentives for merchant 

transmission investment by maintaining the incremental financial transmission rights that are produced when transmission facilities are installed.

 Settlements have mitigated adverse effects of code 

of conduct violations thereby protecting the development of competitive markets.

 Contracts among affiliate entities have been modified through settlements to mitigate the potential 

for affiliate abuse thereby assuring compliance with 

the Commission’s standards for affiliate transactions.

 Issues relating to cost-based rates instituted in lieu 

of market-based rates have been settled thereby ensuring that the potential for the exercise of market 

power by some entities has been eliminated.

The Commission’s litigation staff 

and its administrative law judges guide the 

efficient handling of the unique, complex issues

 that arise in today’s energy markets, 

and speed their resolution.
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Appendix C

Hydroelectric Power Table

Hydroelectric Power Table

Project For Which Licenses Will Expire Between January 1, 2007 and December 31, 2012

# Project No. Project Name Licensee Waterway State

Authorized 

Capacity 

(KW) Expiration Date

 1 02100 FEATHER RIVER

CALIFORNIA DEPT-WTR 

RESOURCES (CA) FEATHER RIVER CA 762850 1/31/2007

 2 00606

KILARC-COW 

CREEK

PACIFIC GAS AND ELECTRIC CO 

(CA) SOUTH COW CREEK CA 4440 3/27/2007

 3 09185 CLAM RIVER FLAMBEAU HYDRO LLC. (WI) CLAM RIVER WI 1200 3/31/2007

 4 00082 MITCHELL ALABAMA POWER CO (AL) COOSA RIVER AL 170000 7/31/2007

 5 00618 JORDAN DAM ALABAMA POWER CO (AL) COOSA RIVER AL 100000 7/31/2007

 6 02101

UPPER 

AMERICAN RIVER

SACRAMENTO MUNICIPAL 

UTIL DIST (CA)

SOUTH FORK 

AMERICAN RIVER CA 640950 7/31/2007

 7 02146 COOSA RIVER ALABAMA POWER CO (AL) COOSA RIVER GA 690900 7/31/2007

 8 02155 CHILI BAR

PACIFIC GAS AND ELECTRIC CO 

(CA)

SOUTH FORK 

AMERICAN RIVER CA 7000 7/31/2007

 9 02545 SPOKANE RIVER AVISTA CORPORATION (WA) SPOKANE RIVER WA 136600 7/31/2007

10 02165 WARRIOR RIVER ALABAMA POWER CO (AL) SIPSEY FORK AL 203250 8/31/2007

11 02085

MAMMOTH 

POOL

SOUTHERN CALIFORNIA 

EDISON CO (CA) SAN JOAQUIN RIVER CA 150938 11/30/2007

12 02785 SANFORD BOYCE HYDRO POWER, LLC (MI). TITTABAWASSEE MI 3300 11/30/2007

13 00925 OTTUMWA OTTUMWA CITY OF (IA) DES MOINES RIVER IA 3250 4/30/2008

14 00946 HYRUM HYRUM CITY CORP (UT)

BLACKSMITH 

FORK RIVER UT 400 4/30/2008

15 02197 YADKIN

ALCOA POWER 

GENERATING INC. (NC) YADKIN RIVER NC 216380 4/30/2008

16 02206 YADKIN-PEE DEE

PROGRESS ENERGY 

CAROLINAS, INC. (NC) PEE DEE RIVER NC 108600 4/30/2008

17 00906 CUSHAW

VIRGINIA ELECTRIC 

& POWER CO (VA) JAMES RIVER VA 7500 6/15/2008

18 00659

LAKE 

BLACKSHEAR CRISP COUNTY POWER COMM (GA) FLINT RIVER GA 15200 8/9/2008

19 02232

CATAWBAWATEREE DUKE ENERGY CAROLINAS, LLC (SC) WATEREE RIVER SC 804940 8/31/2008

20 02225

SULLIVAN LAKE 

(STORAGE)

PUD NO 1 OF PEND 

OREILLE CNTY (WA) SULLIVAN CREEK WA 0 9/30/2008

21 02242 CARMEN-SMITH CITY OF EUGENE (OR) MCKENZIE RIVER OR 120500 11/30/2008

22 00067

BIG CREEK NOS 2A, 

8 & EASTWOOD

SOUTHERN CALIFORNIA 

EDISON CO (CA)

SOUTH FORK 

SAN JOAQUIN RIVER CA 373320 2/28/2009

23 00120 BIG CREEK NO 3

SOUTHERN CALIFORNIA 

EDISON CO (CA) SAN JOAQUIN RIVER CA 165375 2/28/2009

24 02175

BIG CREEK 

NO.1 & NO.2

SOUTHERN CALIFORNIA 

EDISON CO (CA) SAN JOAQUIN RIVER CA 150150 2/28/2009

25 02237 MORGAN FALLS GEORGIA POWER CO (GA)

CHATTAHOOCHEE 

RIVER GA 16800 2/28/2009
2007 | ANNUAL REPORT

69

# Project No. Project Name Licensee Waterway State

Authorized 

Capacity 

(KW) Expiration Date

26 02655

EAGLE & 

PHOENIX MILLS

EAGLE & PHENIX HYDRO 

CO INC (SC)

CHATTAHOOCHEE 

RIVER GA 27660 2/28/2009

27 02088

SOUTH FEATHER 

POWER

SOUTH FEATHER WATER 

AND POWER AGENCY (CA)

SOUTH FORK 

FEATHER RIVER CA 104100 3/31/2009

28 02281

WOODLEAF 

KANAKA T. L.

PACIFIC GAS AND ELECTRIC CO 

(CA) BUTTE CO CA 0 3/31/2009

29 04851 SLY CREEK T. L.

PACIFIC GAS AND ELECTRIC CO 

(CA) CA 0 3/31/2009

30 09988

JOHN P. KING 

MILL AUGUSTA CANAL AUTHORITY (GA) SAVANAH RIVER GA 2050 5/31/2009

31 02261

LOLO-IMNAHA 

T. L. AVISTA CORPORATION (OR) OR 0 7/22/2009

32 07528 CANAAN PUBLIC SERVICE CO OF NH (NH) DEUBERT VT 1100 7/31/2009

33 01005

BOULDER 

CANYON BOULDER CITY OF (CO)

MIDDLE 

BOULDER CREEK CO 20000 8/31/2009

34 00803

DESABLACENTERVILLEPACIFIC GAS AND ELECTRIC CO 

(CA)

WEST BRANCH 

FEATHER RIVER CA 26650 10/11/2009

35 02801 GLENDALE LITTLEVILLE POWER CO INC (MA) SUM MA 1140 10/31/2009

36 02301 MYSTIC LAKE PP&L MONTANA, LLC (MT)

WEST 

ROSEBUD CREEK MT 10000 12/31/2009

37 06885

CINNAMON 

RANCH MOSS RICHARD (CA) MIDDLE CREEK CA 175 12/31/2009

38 02543 MILLTOWN

CLARK FORK AND BLACKFOOT, 

LLC (MT). CLARK FORK MT 3200 12/31/2009

39 02244

PACKWOOD 

LAKE ENERGY NORTHWEST (WA) LAKE CREEK WA 26125 2/28/2010

40 02210

SMITH 

MOUNTAIN APPALACHIAN POWER CO (VA)

ROANOKE 

(STAUNTON) RIVER VA 636000 3/31/2010

41 00785 CALKINS BRIDGE CONSUMERS ENERGY CO (MI) KALAMAZOO RIVER MI 2550 4/10/2010

42 00733 OURAY JACOBSON ERIC R (CO)

UNCOMPAHGRE 

RIVER CO 700 4/12/2010

43 01992 FIRE MOUNTAIN WILLIS KEN (CA) FERN SPRINGS CREEK CA 15 4/30/2010

44 00400 TACOMA-AMES

PUBLIC SERVICE CO 

OF COLORADO (CO) SAN MIGUEL RIVER CO 11500 6/30/2010

45 00503 SWAN FALLS IDAHO POWER CO (ID) SNAKE RIVER ID 25000 6/30/2010

46 02277 TAUM SAUK UNION ELECTRIC CO (MO)

EAST FORK 

BLACK RIVER MO 408000 6/30/2010

47 02677 BADGER-RAPIDE KAUKAUNA CITY OF (WI) FOX RIVER WI 8000 8/11/2010

48 00516 SALUDA

SOUTH CAROLINA ELECTRIC & GAS 

CO (SC) SALUDA RIVER SC 207300 8/31/2010

49 03041 HETTINGER MACKAY BAR CORP (ID) SMITH CREEK ID 12 10/31/2010

50 00013 GREEN ISLAND

GREEN ISLAND POWER 

AUTHORITY (NY) HUDSON RIVER NY 6000 3/2/2011

continued on following page...
FEDERAL ENERGY | FERC REGULATORY COMMISSION

70

...continued

# Project No. Project Name Licensee Waterway State

Authorized 

Capacity 

(KW) Expiration Date

51 02211 MARKLAND DUKE ENERGY INDIANA, LLC. (IN) OHIO RIVER IN 64800 4/30/2011

52 02985 WILLOW MILL MEAD PAPER CORP (MA) ZAVESKY MA 100 4/30/2011

53 02157

HENRY M JACKSON (SULTAN) EVERETT, CITY OF (WA) SULTAN RIVER WA 111800 5/31/2011

54 00739 CLAYTOR APPALACHIAN POWER CO (VA) NEW RIVER VA 75000 6/30/2011

55 02106 MCCLOUD-PIT

PACIFIC GAS AND ELECTRIC CO 

(CA) PIT RIVER CA 340500 7/31/2011

56 02144 BOUNDARY SEATTLE CITY OF (WA) PEND OREILLE RIVER WA 1024000 9/30/2011

57 02594 LAKE CREEK NORTHERN LIGHTS INC (ID) LAKE CREEK MT 4500 11/30/2011

58 02621 PACOLET LOCKHART POWER CO (SC) PACOLET RIVER SC 800 1/31/2012

59 02558 OTTER CREEK OMYA, INC. (VT) OTTER CREEK VT 18130 3/31/2012

60 02615 BRASSUA

BRASSUA HYDROELECTRIC 

LTD PART (ME) MOOSE RIVER ME 4180 3/31/2012

61 02851 NATURAL DAM CELLU TISSUE CORPORATION (NY) ST. LAWRENCE RIVER NY 1020 3/31/2012

62 02149 WELLS

PUD NO 1 OF DOUGLAS 

COUNTY (WA) COLUMBIA RIVER WA 774250 5/31/2012

63 02850 EMERYVILLE HAMPSHIRE PAPER CO INC (NY) ST. LAWRENCE RIVER NY 3481 5/31/2012

64 02662 SCOTLAND

FIRSTLIGHT HYDRO 

GENERATING CO. (CT) SHETUCKET RIVER CT 2000 8/31/2012

65 04362 RIVERDALE

RIVERDALE DEVELOPMENT 

VENTURE, LLC. (SC) ENOREE RIVER SC 1240 8/31/2012

66 02713

OSWEGATCHIE 

RIVER

ERIE BOULEVARD 

HYDROPOWER, L.P. (NY) PUGLESE NY 28471 12/31/2012
2007 | ANNUAL REPORT

71

Appendix D

List of Acronyms

Acronyms and Abbreviations 

Midwest ISO Midwest Independent Transmission 

 System Operator Inc. 

MMC Market Monitoring Center 

MOU memorandum of understanding

MW megawatts

NAESB North American Energy Standards Board

NERC North American Electric Reliability Corp. 

NEPA National Environmental Policy 

 Act of 1969 

NGA Natural Gas Act 

NGPA Natural Gas Policy Act of 1978 

NRC Nuclear Regulatory Commission

OASIS Open Access Same Time 

 Information System 

PJM PJM Interconnection 

PURPA Public Utility Regulatory Policies 

 Act of 1978 

RTO regional transmission organization

SPP Southwest Power Pool Inc.

WECC Western Electric Coordinating Council

ADR alternative dispute resolution

ATC available transmission capability 

Bcf billion cubic feet 

CAISO California Independent System 

 Operator Inc.

Commission Federal Energy Regulatory Commission

DOE U.S. Department of Energy 

Dth dekatherm

EA Environmental Assessment

EIS Environmental Impact Statement

Entergy Entergy Services Inc.

 EPAct 2005 Energy Policy Act of 2005 

ERO Electric Reliability Organization 

FERC Federal Energy Regulatory Commission

FPA Federal Power Act 

FPC Federal Power Commission 

ILP Integrated Licensing Process 

ISO independent system operator

kV kilovolt 

LNG Liquefied Natural Gas 


Federal Energy 

Regulatory Commission

888 First Street, NE, Washington, DC 20426

202-502-6088 • 1-866-208-3372 (toll free) • 202-502-8371 (TTY)

http://www.ferc.gov