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Federal Energy

Regulatory Commission

2001 Annual Report
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FEDERAL ENERGY REGULATORY COMMISSION

2001 ANNUAL REPORT

Photo courtesy of Arizona Public Service.
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TABLE OF CONTENTS

MEMBERS OF THE FEDERAL

ENERGY REGULATORY COMMISSION

Pat Wood, III

Chairman

Linda K. Breathitt

Commissioner

Nora Mead Brownell

Commissioner

William L. Massey

Commissioner

Members of the Federal Energy Regulatory Commission

Letter from the Chairman

Overview

Energy Markets

Energy Projects

Hydroelectric Power Table

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LETTER FROM THE CHAIRMAN

To the Senate and House of Representatives:

I am pleased to submit to the Congress the Federal Energy Regulatory Commission’s annual report, covering the fiscal year from

October 1, 2000, through September 30, 2001.

This is the 81st report issued by the Commission and its predecessor, the Federal Power Commission. As an independent agency,

the Commission oversees key operating functions of the natural

gas, electric utility, hydroelectric power, and oil pipeline transportation industries.

For fiscal year 2001, Congress appropriated $175,200,000 to support Commission activities. Under the authority of the Omnibus

Budget Reconciliation Act of 1986 and other laws, the Commission recovers all of its costs from regulated industries through

fees and annual charges. Revenues generated from these sources

completely offset congressional appropriations and therefore result in a net cost to the treasury of zero dollars. As a result, the

users and beneficiaries of the Commission’s services—not the

general taxpayers—pay its operating costs.

Respectfully,

Pat Wood, III

Chairman
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Near Lost River, West Virginia, FERC and Columbia Gas representatives

hike two miles of a gas pipeline route as part of a compliance inspection.

Federal Energy Regulatory Commission photo.
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OVERVIEW

THE COMMISSION’S REGULATORY

RESPONSIBILITIES

The Commission is a five-member independent regulatory agency, which succeeded to the regulatory responsibilities of the Federal Power Commission in 1977. The Commission’s responsibilities include the licensing of non-federal hydroelectric facilities, the certification of natural gas pipelines, regulating the rates of

natural gas pipelines and pipelines transporting crude oil and oil products, and regulating the rates and other

aspects of electric utility activities.

Hydropower is the oldest area of Commission jurisdiction. The Commission’s predecessor began federal

regulation of non-federal hydroelectric generation in 1920, authorizing the construction of projects in interstate

commerce and overseeing their operation and safety. The Commission now regulates 2,000 dams that generate

over five percent of all electric power in the United States.

Since 1935, the Commission has regulated certain electric utility activities under the Federal Power Act

(FPA). Under FPA Sections 205 and 206, the Commission oversees the rates, terms and conditions of sales for

resale of electric energy and transmission service in interstate commerce by public utilities. The Commission

must ensure that those rates, terms and conditions are just and reasonable, and not unduly discriminatory or

preferential. Under FPA Section 203, the Commission reviews mergers and other asset transfers involving

public utilities. The utilities regulated under FPA sections 203, 205 and 206 are primarily investor-owned

utilities; government-owned utilities (such as the Tennessee Valley Authority [TVA], the federal power marketing agencies, and municipal utilities) and most cooperatively-owned utilities are not subject to the Commission’s

regulation, with certain exceptions.

The Commission may not regulate retail sales or local distribution of electricity. These are matters left to

the states by the FPA. Nor does the Commission have a role in authorizing the construction of new generation

facilities (other than non-federal hydroelectric facilities) or transmission facilities. These too are state or local

responsibilities.

The Commission’s role in the natural gas industry is largely defined by the Natural Gas Act of 1938 (NGA).

Under the NGA, the Commission regulates the construction of new natural gas pipelines and related facilities

and oversees the rates, terms and conditions of sales for resale and transportation of natural gas in interstate

commerce. Pipeline siting and construction is authorized by the Commission if found to be required by the

public convenience and necessity. As with hydropower licensing, the Commission’s actions on pipeline projects

typically require consideration of factors under the National Environmental Policy Act (NEPA), the Endangered Species Act, the Fish and Wildlife Coordination Act, the Coastal Zone Management Act and other such

legislation. The wellhead price of natural gas, which the Commission previously regulated, was gradually

deregulated by Congress beginning with the Natural Gas Policy Act of 1978 (NGPA). All wellhead price controls on natural gas ended on January 1, 1993. Regulation of retail sales and local distribution of natural gas are

matters left to the states.

Finally, the Interstate Commerce Act (ICA) 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.
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OVERVIEW

DIVISION OF

CONGRESSIONAL,

INTERGOVERNMENTAL

AND PUBLIC AFFAIRS

DIVISION OF PRESS

SERVICES

OFFICE OF EXTERNAL

AFFAIRS

COMMISSIONER COMMISSIONER CHAIRMAN COMMISSIONER COMMISSIONER

OFFICE OF

ADMINISTRATIVE LAW

JUDGES

OFFICE OF THE SECRETARY OFFICE OF THE CHIEF

INFORMATION OFFICER

OFFICE OF THE

EXECUTIVE DIRECTOR

2001 FERC ORGANIZATIONAL CHART

FERC REGIONAL

OFFICES: ATLANTA,

PORTLAND, CHICAGO,

NEW YORK, AND SAN

FRANCISCO

GENERAL AND

ADMINISTRATIVE LAW

MARKET OVERSIGHT

AND ENFORCEMENT

ENERGY PROJECTS

MARKETS, TARIFFS

AND RATES

DISPUTE RESOLUTION

SERVICE

SOLICITOR

OFFICE OF THE GENERAL

COUNSEL

DIVISION OF

HYDROPOWER

ADMINISTRATION &

COMPLIANCE

DIVISION OF

PIPELINE

CERTIFICATES

DIVISION OF

ENVIRONMENTAL &

ENGINEERING REVIEW

OFFICE OF

ENERGY PROJECTS

MANAGEMENT AND

OPERATIONS

DIVISION OF

DAM SAFETY AND

INSPECTIONS

DIVISION OF MARKET

INFORMATION

DIVISION OF MARKET

DEVELOPMENT

DIVISION OF ISSUE

IDENTIFICATION AND

RESOLUTION

MANAGEMENT

ASSOCIATE DIRECTOR

OFFICE OF MARKETS,

TARIFFS AND RATES

DIVISION OF TARIFFS

AND RATES–CENTRAL

DIVISION OF TARIFFS

AND RATES–EAST

CHIEF ECONOMIC

ADVISOR

ADMINISTRATIVE

LITIGATION

DIVISION OF POLICY,

INNOVATION &

COMMUNICATION

DIVISION OF

ADMINISTRATION AND

CASE TRACKING

DIVISION OF TARIFFS

AND RATES–WEST

DIVISION OF

LITIGATION

DEPUTY EXECUTIVE

DIRECTOR

HUMAN RESOURCES

MANAGEMENT

DIVISION

ORGANIZATIONAL

MANAGEMENT

DIVISION

MANAGEMENT,

ADMINISTRATIVE

AND PAYROLL

SUPPORT DIVISION

PROCUREMENT

DIVISION

FINANCIAL SERVICES

DIVISION

DEPUTY EXECUTIVE

DIRECTOR & CHIEF

ACCOUNTANT

BUDGET DIVISION

LOGISTICS

MANAGEMENT

DIVISION

REGULATORY

ACCOUNTING POLICY

DIVISION

REGULATORY AUDITS

DIVISION

FINANCIAL POLICY

DIVISION
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LOOKING AHEAD

California was among the first states to open its electric industry to competition, opening a restructured

market in 1998. Until June 2000, California’s electric markets appeared to work well. However, California’s

flawed market rules failed to send generators signals to build new capacity, even while the state experienced

rapid economic growth. The lack of new capacity made the California market vulnerable. In 2000, a series of

other conditions exposed that vulnerability: a severe drought curtailed hydropower; demand-side response was

virtually non-existent, partly because of fixed retail rates; and a hot summer followed a cold winter. The balance between supply and demand tightened, and electric prices rose dramatically.

The Commission acted to mitigate the sharp price increases of electricity and natural gas in the Western

states. These measures provided customers with relief from the most extreme spot market prices. The Commission also removed a series of regulatory obstacles to expedite providing increased energy supplies to the West.

Since June 2001, electric prices have dropped to normal levels and below, throughout the West, and remained

there. Several factors led to this result: reduced demand, relatively mild weather, increased supplies, and the

Commission’s price mitigation. Nonetheless, it is abundantly clear that market crises can erupt quickly, especially in electricity. If not prevented or treated quickly, they can do enormous damage.

Given the experience of Western energy markets, it is now clear that the Commission’s primary emphasis

must be to facilitate a full transition to competitive wholesale energy markets as soon as possible, and to

address crucial issues that arise during the transition. The Commission’s most important responses are:

● A New Sense of Focus and Direction. This is embodied by the Commission’s Strategic Plan.

● An Increased Emphasis on Market Oversight and Investigation. This is embodied in the third of the

Commission’s four key challenges.

FERC’s Strategic Plan lays out challenges, or goals, in four areas:

● Energy Infrastructure

Goal: Promote a Secure, High-quality, Environmentally-responsible Energy Infrastructure Through Consistent Policies. This goal will encourage investment in the infrastructure needed to sustain energy markets by removing roadblocks, providing cost recovery clarity, and welcoming innovative thinking about rates and use of

new technology. By focusing on infrastructure, this goal covers many of the Commission’s important traditional

responsibilities, for example, pipeline certificates, hydropower licenses and preliminary permits, compliance activities, environmental and other licensing conditions, dam safety inspections, and most rate determinations.

● Competitive Markets

Goal: Foster Nationwide Competitive Energy Markets as a Substitute for Traditional Regulation. This goal

focuses on the Commission’s need to complete the transition to competitive energy markets as quickly and

comprehensively as possible. This will require the growth of many new institutions, particularly clearly defined

and independent regional transmission organizations (RTOs), to make electric markets work. The Commission

also needs to establish standardized market designs that will apply in every wholesale electric market, and

encourage continued efforts by industry groups to standardize reliability and business practice standards, promote the use of demand-side participation in energy markets, and establish regional transmission planning.

Along with some traditional work in the area of rate determinations, this goal furthers work on initiatives begun

in the last couple of years such as RTOs and new policies for natural gas.

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● Market Oversight

Goal: Protect Customers and Industry Participants Through Vigilant and Fair Oversight of the Transitioning

Energy Markets. This goal will ensure that competitive energy markets benefit the Nation over the long run.

The Commission plans to establish a new office to coordinate all market oversight and investigative activity.

The Commission needs a much stronger ability to recognize and respond to problems in the markets. At the

systemic level, the Commission needs to recognize problems when–or before–they develop and craft solutions

quickly. The Commission must also be able to police individual behavior in markets much more effectively

than in the past. Work toward this goal also includes more traditional work, such as some aspects of litigation,

dispute resolution, complaints, mergers, and auditing.

● Resource Management

Goal: Efficiently Administer the Agency’s Resources to Accomplish the Agency’s Goals. The Commission

will be unable to meet its programmatic challenges without management support. This includes enhancing the

talents and skills of the staff through recruitment and training, building effective, customer-friendly information technology (IT) services, supporting the Commission with logistics and financial services, and strengthening the Commission’s strategic management processes.

OVERVIEW
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A line mechanic tests a power line to make sure it is not energized prior to performing

maintenance. Photo by Rick Giammaria, courtesy of the Potomac Electric Power Co.
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Control room at Plant Bowen, located in Cartersville,

Georgia. Photo courtesy of Georgia Power.
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GOALS

The Commission’s overall goal for energy markets is to benefit customers by providing a fair, open, and

efficient regulatory foundation for competition. Three objectives related to this goal are to:

● Develop and encourage competitive market institutions

● Increase market pricing efficiency

● Mitigate significant market power.

Three overall strategies apply to all the above objectives. These overall strategies are:

● Observe and monitor energy markets

● Improve and promptly enforce market rules

● Resolve disputes quickly and fairly.

The Commission will develop and encourage competitive market institutions by promoting the development of institutions that ensure fair and efficient markets without the burden of heavy-handed regulation. The

Commission will help these market institutions grow, foster the exchange and sharing of appropriate market

information, and monitor market developments, intervening only where and when necessary. The Commission

will continue to develop rules, such as those in Order No. 2000 and Order No. 637, that increase transmission

system integrity and flexibility through regulatory reform. And the Commission will increase the transparency

of Commission policies and availability of market-related information.

The Commission will work to make markets more efficient through the development of innovative, efficiently priced services that provide reliable transportation systems at the lowest cost to the customer. Utilities

once agreed to regulation in exchange for being the monopoly provider of energy services to customers. Their

rates were based on the prudent costs of providing service and a reasonable return on investment. This approach

gave utilities few incentives to improve operating efficiency or to offer new or different services. Pricing as

many utility services as possible through competitive markets promotes efficient utility operations by introducing a risk/reward dynamic not found in regulated monopolies. Competitive market pricing provides good economic signals for both plant expansion and consumption decisions by customers.

The Commission will act vigorously to mitigate significant market power. Market power–the ability to

raise and maintain prices above a competitive level for a sustained period–distorts price signals, reduces incentives for efficiency, and artificially increases prices to customers.

ACHIEVEMENTS

Outreach

During FY 2001, Commission staff conducted 22 informal outreach meetings with trade associations and

energy, environmental, and consumer organizations to explore issues relating to visions of the future and the

regulatory changes that would be required to meet those visions. In addition, the Commission held a number of

conferences both in Washington and around the nation on a variety of issues, such as post-Order No. 637

affiliate issues, electric utility seams issues, and regional Northwest and California electric power issues. The

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Commission also engaged in an extensive outreach effort with international delegations. During FY 2001,

Commission staff met with over 50 foreign delegations, addressing a variety of topics such as industry restructuring, competition, price regulation, and RTOs. Commission staff also maintained close relationships with a

variety of governmental and other entities with which it interacts, including the Department of Energy (DOE),

the North American Electric Reliability Council, Federal Emergency Management Agency (FEMA), state regulators, and the National Association of Regulatory Utility Commissioners.

Regional Transmission Organizations

During the past year, the Commission continued to push for the development of RTOs throughout the

Eastern and Western Interconnections. RTOs will operate large, regional electric transmission systems on a

non-discriminatory basis and under standardized terms and conditions of service. RTOs are expected to provide

billions of dollars of benefits to customers. During the past year, the Commission has issued orders, and been

heavily involved in collaboration with affected stakeholders, on the development of RTOs. The Commission

expects to institute a rulemaking proceeding in the near future to develop a standardized RTO tariff of general

applicability as well as standardized market rules applicable to the services provided by RTOs.

Market Observation and Monitoring

The success of all aspects of the Commission’s energy markets program depends on being able to respond

to the rapid, continuous evolution of natural gas and electric power markets. The Commission has developed a

monitoring capability that allows it to understand the industries and evolving dynamics of the market, and to

identify market problems and opportunities to extend competitive solutions.

During the past year, the Commission has begun to examine gas and electric markets on a regional and a

national basis using current and historical data. On a daily basis the Commission monitors gas and electric spot

prices at major trading hubs, weather, congestion on the electric grid, generation outages, and pipeline operational flow orders. This information is made available to the Commission and all staff. The Commission also

monitors additions to generation and transmission or pipeline capacity, storage levels by region, futures prices,

reserve levels, hydro levels, market volatility, and releases of gas pipeline capacity above the maximum rate.

Information on these data is issued in a monthly report to the Commission staff. In addition, the staff monitors

for compliance with informational posting requirements of energy websites, and generation outages for separate reports.

Staff has also focused on understanding the underlying dynamics of the markets. They include: the role of

risk management and risk management tools in energy markets, the operation of independent system operators

(ISOs) and RTOs, and the pricing structures in the different markets. The Commission has made major strides

in identifying market structure and development issues of this type. Staff education on these issues occurs

through a variety of vehicles, including a monthly report on energy market issues.

Supply and Demand in the West

In response to the severe energy shortages plaguing California, the Commission implemented a number of

initiatives to bring more economical and reliable energy supplies to the stressed California and Western energy

markets. In addition to immediately streamlining regulatory procedures for wholesale electric power sales and

expediting the certification of natural gas pipeline projects into California and the West, the Commission established a number of economic incentives aimed at ensuring that upgrades to the western transmission grid are

made quickly. Among the incentives were increased rates of return on common equity and shortened depreciation periods for projects that significantly increase transmission on constrained routes.

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Price Mitigation for California and Western Markets

By various orders issued in the spring and summer, the Commission implemented a price mitigation plan

for California and extended such curbs on spot market sales throughout the Western Systems Coordinating

Council (WSCC). The plan, which is to remain effective through September 30, 2002, includes the following

major elements:

● Enhancing the California ISO’s ability to coordinate and control planned outages of generating

units during all hours.

● Requiring all utilities owning non-hydroelectric generation in California and the WSCC to offer all

of their available power to the market place to the extent the output from the facilities is not already

committed.

● Establishing conditions, including refund liability, on public utility sellers’ market-based rate

authority to prevent anticompetitive bidding behavior.

● Establishing a mechanism for price mitigation for all sellers bidding into the California ISO spot

market and other spot market sales in the WSCC. Under this mechanism, the Commission established a

formula (based on gas-fired generation) to be used to establish the real-time market clearing price when

mitigation applies. The price mitigation plan applies to spot market sales in all hours.

Electronic Tariffs

On March 14, 2001, the Commission issued a Notice of Inquiry and Informational Conference (NOI) on

Electronic Tariff Filings. This notice announced the Commission’s intent to move to an electronic format for

oil, gas, and electric tariffs; requested comments on several issues; and scheduled a staff informational conference which was held on April 24, 2001. The goals of this initiative are to make it easier for parties to file and

view tariffs, facilitate tariff research, and to comply with the Office of Management and Budget (OMB) requirement to have an electronic format available for all documents by October 2003. Currently, oil and electric

tariffs are filed on paper and gas tariffs are filed in an outdated electronic format.

In addition to Commission staff, representatives from the oil, gas and electric industries, and other interested parties participated in the informational conference. Numerous comments were received, and a staff team

continues to work out numerous technical issues with the goal of creating a system to electronically collect,

manage, and disseminate oil, gas, and electric tariff information.

Market Power Investigations

By orders issued March 28, 2001, and June 11, 2001, the Commission ordered hearings into allegations of

market power, affiliate abuse and anti-competitive impact on the delivered price of gas and the wholesale

electric market in California associated with three transportation contracts between El Paso Natural Gas Company and El Paso Merchant Energy-Gas, L.P. and El Paso Merchant Energy Company. These proceedings arose

out of a complaint filed by the Public Utilities Commission of the State of California that the El Paso affiliated

companies took improper advantage of their affiliate relationships to exercise market power and to drive up the

cost of natural gas.

On March 28, 2001, the Commission ordered a hearing into three filings made by Transwestern Pipeline

Company of negotiated rate contracts for firm transportation service containing pricing formulas that substanENERGY MARKETS
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tially exceeded recourse rate charges. The hearing will determine if Transwestern was able to contravene Commission regulations and policy by withholding pipeline capacity that would otherwise be available at the recourse rate in order to make that capacity available at substantially higher rates. On September 13, 2001, the

Commission ordered a similar hearing into eight negotiated rate filings made by PG&E Gas Transmission,

Northwest Corporation. Separate hearings were under way in both proceedings.

Refunds in California and the Northwest

On July 25, 2001, the Commission ordered separate evidentiary proceedings to determine the scope and

methodology for calculating refunds in the spot markets operated by the California Independent System Operator Corporation and the California Power Exchange Corporation for the period October 2, 2000, through June

20, 2001, and in the spot markets in the Pacific Northwest for the period December 25, 2000, through June 20,

2001. These proceedings were initiated partly in response to a report by the Chief Administrative Law Judge on

his efforts to achieve a settlement of refund issues between and among buyers and sellers in these spot markets.

The Chief Judge also recommended a methodology to be used to calculate refunds. On September 24, 2001, the

presiding administrative law judge in the Pacific Northwest proceeding recommended that the Commission not

require any refunds in the Pacific Northwest. The Commission asked for comments on the judge’s recommendations.

Index of Customers Notice of Proposed Rulemaking (NOPR)

On July 26, 2001, the Commission issued a NOPR, proposing a quarterly electronic report that would

increase the accessibility and usefulness of key electric power data. The proposed Index of Customers Report

would contain information on contracts in service and transaction information for power sales during the previous calendar quarter. The Commission proposes that each public utility under the FPA would no longer file

conforming service agreements: short-term or long-term service agreements for market-based sales of electric

energy; service agreements for those generally applicable services, such as point-to-point transmission service,

for which the public utility has an approved standard form of agreement under its tariff; and Quarterly Transaction Reports summarizing its short-term sales and purchases of power at market-based rates. The new electronic format would make the information standard, complete and easier to use. Numerous comments were

received by the Commission. Work on a final rule and the development of an information system to collect,

manage and disseminate the report data will continue in FY 2002.

Electronic Format for Forms 2, 2-A and 6

In the Commission’s continuing effort to improve the ease and accuracy of filing and processing data

collections, it implemented a new, mandatory electronic version of the FERC Form 6, Annual Report of Pipeline Companies, and offered an optional revised electronic format for the FERC Form 2, Annual Report of

Major Natural Gas Companies, and Form 2-A, Annual Report of Non-major Natural Gas Companies. The

Commission issued Order 620 on December 13, 2000, revising the Form 6 filing requirements and mandating

electronic filing over the Internet using software provided at no cost by FERC. The software is very similar in

format to the successful Form 1 system. The Form 6 was previously filed only on paper. Similar software was

developed to collect Form 2 and 2-A data over the Internet for the year 2000 filings, submitted in April 2001.

These forms were previously submitted on paper and diskette, and required substantial manual intervention to

produce, process and verify. The new software is much easier for respondents to use, loads into the FERC Form

2 database automatically, and contains edit checks which significantly reduce staff processing time.

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Standards of Conduct for Affiliates

In September 2001, the Commission proposed a rulemaking that would adopt a uniform set of standards of

conduct to govern the relationship between regulated gas and electric transmission providers and their energy

affiliates. The new standards are intended to reflect the significant changes in the electric and gas industries that

have occurred since separate sets of standards were implemented for each industry.

Increased Infrastructure Security

Immediately following the September 11, 2001, terrorist attacks, the Commission assured its regulated

companies that it will approve applications proposing the recovery of prudently incurred costs necessary to

safeguard the nation’s energy infrastructure. The Commission is committed to expedite the processing on a

priority basis of any application that would recover costs of security from wholesale customers. The Commission views the safety and reliability of the nation’s energy supply infrastructure as being critical to the nation’s

economic well-being.

Informal Procedures

The Commission encourages parties to resolve disputes quickly and informally, whenever possible. The

Commission encourages parties to use the Enforcement Hotline (for quick advice and resolution), or the Dispute Resolution Service (DRS) (for facilitation, mediation, or other alternative dispute resolution [ADR] services) before filing a case with the Commission. After they file a case, the Commission may address the issues

based on the filing or through a technical conference, refer the matter to the DRS, use a settlement judge, or

begin other ADR processes to help parties resolve the matter informally.

Targeted Litigation

Situations will always arise where the Commission needs formal investigations or hearings. The Commission will be selective, setting only appropriate disputes for full investigation and hearing. Approaches developed in FY 2000 will continue to cut by up to one fourth the time taken to decide litigated cases.

Electric Utility Mergers

Recognizing that dramatic changes in the electric utility industry were giving rise to increased public

utility mergers in addition to more innovative utility combinations, the Commission has taken steps to update

and clarify the procedures and policies concerning public utility mergers. On November 8, 2000, the Commission issued Order No. 642, which established streamlined filing requirements for merger applications. Designed to facilitate the review process, the rule:

● Revises filing requirements to reflect existing merger policy based on the Commission’s 1996

Merger Policy Guidelines

● Provides more detail for the industry in developing competitive market analyses

● Continues the existing screening process for mergers with potential horizontal competitive

concerns and establishes informational requirements for vertical competitive analyses

● Streamlines filing requirements for transactions that do not raise competitive concerns

● Reduces the industry’s regulatory burden by eliminating outdated filing requirements.

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During the year, the Commission also acted on seven merger applications. They were:

EC00-106-000 Entergy Power Marketing Corp./ Koch Energy Trading, Inc.

EC01-13-000 Bangor-Hydro Electric Company/ Emera Inc.

EC01-22-000 FirstEnergy Corporation/ GPU, Inc.

EC01-25-000 The AES Corporation/ IPALCO Enterprises, Inc.

EC01-63-000 Niagara Mohawk Holdings, Inc./ National Grid USA

EC01-97-000 Energy East Corp./ RGS Energy Group

EC01-101-000 Potomac Electric Power Company/ Conectiv.

The Commission continues to experience a marked increase in the number of corporate applications pertaining to disposition of public utility property, consolidation or purchase of securities (Section 203 filings).

Many of these applications involve the divestiture of transmission assets related to sale of generation assets and

corporate reorganizations. These ongoing changes in the electric industry are occurring in large part as a result

of continuing restructuring in the industry. With these changes, and with Commission initiatives such as Order

No. 2000, Section 203 corporate applications are expected to remain an important part of the Commission's

regulatory mission.

Natural Gas Wellhead Determinations

The Commission received approximately 2,000 wellhead determinations under the procedures established

in Order No. 616 which reinstated wellhead determinations under Section 503 of the NGPA. The determinations establish eligibility for a tax credit under Section 29 of the Internal Revenue Code. The determination

procedures apply to coal seam gas, Devonian shale gas, and tight formation gas produced through recompletions

commenced after 1992 in wells drilled after 1980 and before 1993, or through wells commenced after 1980 and

before 1993.

Oil Pipeline Pricing Index

On December 14, 2000, the Commission issued an order concluding its initial five-year review of the oil

pipeline pricing index first established in Order No. 561. In Order No. 561 the Commission established an

index for pricing oil pipeline transmission rates equal to the Producer Price Index for Finished Goods (PPI)

minus 1 percent. The index, when applied to established base rates, would act as a measure of actual cost

changes in the oil pipeline industry. The initial review undertaken during 2000 found that the index has remained an accurate measure for tracking oil pipeline costs.

ENERGY MARKETS
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Changes in Gas Pipeline Regulation

During FY 2001, the Commission continued the implementation compliance process for gas pipelines

under Order No. 637. In Order No. 637, the Commission, among other things, revised its regulations relating to

scheduling procedures, capacity segmentation, and pipeline penalties in order to improve the competitiveness

and efficiency of the interstate pipeline grid.

The Final Rule, Order No. 637:

● Temporarily removes price ceilings for certain short-term transactions

● Permits peak/off-peak and seasonal rates

● Revises transaction procedures, such as scheduling

● Narrows the right of first refusal

● Improves reporting requirements to provide more transparent pricing information.

These changes are expected to create greater transactional liquidity and more competition. To ensure they

do, the Commission will obtain and make available better information about availability and price, enabling

shippers to make more informed decisions. The implementation compliance process for this order should be

substantially complete by the end of the next fiscal year.

ENERGY MARKETS

Gas pipeline installation in Greenland, New Hampshire.

Photo courtesy of Foster’s Daily Democrat/Dave Lane.
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Tower construction near Baxley, Georgia. Photo courtesy of Georgia Power.
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GOALS

The Commission’s challenge is to promote a secure, high-quality, environmentally-responsible energy

infrastructure through consistent policies. The objectives for meeting these challenges include:

● Removing roadblocks impeding market investment; and

● Proactively addressing landowner, safety, and environmental concerns.

Natural Gas Pipeline Infrastructure

The expeditious processing of certificate applications, while ensuring due process for those affected by

natural gas projects, remains an ongoing goal for the Commission. Early involvement helps the Commission

accomplish this goal. The Commission encourages applicants to address stakeholder concerns before the certification process formally begins, while using collaboration with affected parties to the greatest extent possible.

The Commission seeks to foster early involvement in its process by using such tools as enhanced pre-filing

opportunities and its gas outreach program.

The gas pipeline industry continues to expand into new markets. Pipelines are proposing to serve markets

already served by other pipelines. Competing pipelines, and landowners who question the need for the new

projects, vigorously contest many of these proposals. Parties with environmental concerns also question the

need. Processing contested proposals requires significant resources, and the Commission remains fully committed to ensuring that multiple competing interests and timeliness issues are not only addressed, but that any

decision authorizing the construction and operation of facilities balances these concerns.

Increasing availability of Canadian supplies, new deep-water production in the Gulf of Mexico, and the

growing market for natural gas in the Northeast will continue to result in large construction projects. The

Commission also expects that Canadian gas and oil suppliers will seek additional markets for their products in

the United States, and that producers will explore options to export gas to Canadian and Mexican markets,

which may require pipeline construction. Pre-filing conferences and meetings are taking place to explore the

utilization of Alaskan gas reserves for the lower 48 states. Increased competition in markets and customers'

desires for multiple, competing sources of supply will generate more NGA Section 3 filings and related requests for Presidential permits for importing and exporting gas and oil. The Commission will also continue to

see projects related to the extensive exploration effort on the offshore outer continental shelf and construction

of pipelines to reach significant new gas supplies.

The Commission expects to receive applications for storage development for peaking capacity and supply

flexibility, since customers will continue to be responsible for their own gas supply acquisition. Anticipated

storage facilities include depleted gas fields, new leached-salt caverns, and liquefied natural gas (LNG) tanks.

These projects, many of which will be located near market areas, are likely to generate significant public

interest regarding competition, need, and environmental impact.

The Commission also anticipates many applications for replacement facilities. Replacement and upgrading

of pipeline facilities continues because of the aging of the national pipeline grid.

Regardless of whether the gas certificate applications involve new greenfield projects, expansions of existing facilities, or simply the replacement of aging infrastructure, the Commission continues to ensure the responsible development of transportation capacity with large public interest benefits.

ENERGY PROJECTS
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Optimizing Hydroelectric Projects

Electricity generated from the power of falling water is economical, renewable, available for peak demand,

and free of emissions and is a significant component of the nation's energy mix. But because hydropower

projects use and affect a variety of important natural resources, they must adjust to increasing concern for the

environment and shared jurisdictional authorities, while competing in rapidly changing energy markets.

Public concern about the environmental effects of hydropower operations continues to increase. This heightened concern, reflected in a host of environmental laws, results in many additional requirements in new licenses.

While the Commission's responsibility under the FPA gives equal consideration to the many competing

power and non-power interests, various statutory requirements give other agencies a powerful role in the licensing of projects. The Commission shares its license conditioning authority with numerous state and federal

agencies. Shared jurisdiction poses unique challenges to the Commission in issuing timely and balanced licenses. In FY 2001, the Commission reported to Congress on the results of an Interagency Task Force formed

in 1998. The Task Force developed seven key reports containing many recommendations to improve, streamline, and enhance the licensing process.

Over the next eight years, more than 180 project licenses will expire. Many of these projects significantly

affect important environmental resources, and as such, have a high potential for conflicts. The Commission

mitigates this potential by: (1) involving every integral stakeholder (local citizen groups, power users, Native

Americans, environmental organizations, fish and wildlife agencies, and the hydropower companies) early in

the licensing/relicensing process; and (2) promoting better communication among stakeholders. By encouraging participation early in the collaborative processes, the Commission's authorizations more thoroughly address the needs of the stakeholders affected by the hydropower facilities. Environmental terms and conditions

are developed after providing numerous opportunities for input from all stakeholders and carefully considering

all associated issues and concerns.

Hydropower Project Safety

The Commission's internationally recognized dam safety program ensures that the dams under its jurisdiction are properly constructed, operated and maintained. Because of the increasing number of older dams under

the Commission's jurisdiction, continued vigilance is necessary. As engineering technology, tools, and procedures improve, the Commission conscientiously facilitates sharing of knowledge, and it works with licensees,

the engineering community, and federal and state agencies to maintain its acclaimed dam safety record.

ENERGY PROJECTS
23

ACHIEVEMENTS

NATURAL GAS PIPELINES

Expedited Approval Process

President Bush’s National Energy Policy (NEP) asks agencies to continue their efforts to expedite natural

gas pipeline permitting in an environmentally-sound manner and to look for ways to improve the regulatory

process governing approval of interstate pipeline projects. Accordingly, the Commission reviewed its pipeline

certification program. New approaches, such as enhanced pre-filing cooperation with applicants, have allowed

the Commission to respond to urgent energy needs.

When the serious need for gas in California and the West demanded a quick response, the Commission's

staff expeditiously processed those certificate applications involving additional deliverability into western markets. Another immediate step the Commission took was to temporarily increase cost limitations on

blanket certificates and prior notices for projects located in the WSCC, which were scheduled to be in

service by April 30, 2002. Blanket certificates and prior notices allow the applicant to automatically construct facilities using authority granted outside of the traditional review process.

Major Facilities Construction

In 2001, the Commission authorized the construction and operation of a significant number of pipeline

facilities to provide service to all regions of the country. Major projects include:

The Gulfstream Project, which was authorized in February, 2001, involves the construction and operation of 744 miles of pipe and 120,000 horsepower of compression at an estimated cost of $1.65 billion. The

pipeline will transport 1,130 million cubic feet per day (MMcfd) of natural gas from Mississippi to Florida,

crossing the Gulf of Mexico in the process. Wyoming Interstate’s Medicine Bow Lateral Expansion, which

was authorized in May, provides for the transportation of 675 MMcfd of gas over 155 miles of pipe in

Wyoming and Colorado, using 7,170 horsepower of compression at a cost of $156 million. Pacific Gas and

Electric was authorized in July to construct and operate 21 miles of pipe and 97,500 horsepower of compression in order to transport 207 MMcfd of natural gas from Canada. The project is estimated to cost about $122

million. Florida Gas Transmission’s Phase V Expansion, which was also authorized in July, comprises 231

miles of pipe and 89,765 horsepower of compression in Alabama, Mississippi and Florida at a cost of approximately $427 million. This project increases the transportation capacity of Florida Gas’ system by almost 270 MMcfd.

In addition to the above authorizations, the Commission also made preliminary determinations on nonenvironmental issues on several major projects. Iroquois Gas Transmission's Eastchester Extension would provide 230 MMcfd of deliverability and would require the construction of 32.8 miles of pipe and 54,300 horsepower of compression in New York at a cost of about $174 million. Maritimes and Northeast Pipeline's Phase

III Project proposes to transport 360 MMcfd of gas to Massachusetts using 25 miles of pipe at an estimated cost

of $134 million. Algonquin Gas Transmission Company's Hubline Project would deliver 230 MMcfd of gas

into Massachusetts using 35 miles of new pipe at a cost of about $160 million. North Baja Pipeline proposes to

provide 500 MMcfd of transportation via the construction of about 80 miles of pipe and 7,200 horsepower of

compression in Arizona and California. Colorado Interstate Gas Company plans to construct 119 miles of pipe

and 4,450 horsepower of compression in Colorado at a cost of about $72 million to transport 272 MMcfd of

gas. Tuscarora Gas Transmission Company would transport 95.9 MMcfd of gas in California and Nevada by

constructing 14.2 miles of pipe and 24,000 horsepower of compression at an estimated cost of $57.8 million.

ENERGY PROJECTS
24

In 2001, the Commission also authorized two major storage projects and three LNG projects. Central New

York Oil and Gas Company’s Stage Coach Storage project, which was authorized in February, provides storage

for up to 13.6 billion cubic feet (Bcf) of natural gas, using 25,000 horsepower of compression. Egan Hub was

authorized in June to construct and operate 19,130 horsepower of compression in order to store 5.5 Bcf of

natural gas in Louisiana. Distrigas of Massachusetts was authorized in January to increase by 600 MMcfd its

deliverability of regassified LNG from its Boston import terminal by constructing about $35 million of LNGrelated facilities. Trunkline LNG was authorized in March to provide 300 MMcfd of deliverability at its LNG

plant in Louisiana. The cost of this project is estimated to be $1.3 million. Finally, Southern LNG was authorized in July to deliver 135 MMcfd of regassified LNG from its import terminal in Georgia using facilities

costing $14.2 million.

The following table provides a summary of the major natural gas facilities authorized by the Commission

in FY 2001:

Information Availability and Outreach

The Commission remained vigilant in ensuring that pipeline companies notify affected landowners of

proposed route locations according to the Landowner Notification Rule. The ongoing success of this program

has proved useful in providing an opportunity for early landowner participation in the Commission's process.

Early participation can allow the parties to identify and resolve disputes before filing with the Commission and

come up with significant new issues and alternatives.

ENERGY PROJECTS

TYPE OF PROJECT FACILITIES / ADDED CAPACITY COST ($ MILLION)

New Pipeline 2449 miles; 6,644

804,592 horsepower;

6.63 Bcfd capacity

New Storage 19.1 billion cubic feet storage; N/A

44,130 horsepower;

500 MMcfd deliverability

Expanded Liquefied Natural Gas 1.04 Bcfd deliverability 50.5

Preliminary Determinations 305.9 miles 742.8

89,950 horsepower

1.7 Bcfd capacity
25

The Commission also continued its outreach program to collect and disseminate information on ways for

applicants, state and other federal agencies, and citizens to identify and resolve disputes before filing with the

Commission. Commission staff initiated a series of Interstate Natural Gas Facility Planning Seminars. Seminars

were held in Albany, New York; Chicago, Illinois; Tampa, Florida; and Seattle, Washington. These seminars were

designed to bring the parties together to explore new strategies for participatory project design and for developing

solutions to environmental issues during the pre-filing planning process.

Based on feedback from the seminars, Commission staff developed and issued a report entitled Ideas for

Better Stakeholder Involvement in the Interstate Natural Gas Pipeline Planning Pre-Filing Process.

Alaskan Gas

In response to interest in Alaskan gas, in January 2001, staff submitted to the U.S. Senate Committee on

Energy and Natural Resources a report on the Alaskan Natural Gas Transportation Act of 1976 (ANGTA)

requirements for constructing a pipeline from Alaska to the lower 48 states. The report discusses Commission

proceedings in the 1970s under ANGTA and the issues the Commission would face to finish considering these

applications today.

As part of the President’s NEP, Commission staff are also participating in a DOE working group on

Alaskan natural gas.

HYDROPOWER LICENSING,

ADMINISTRATION, COMPLIANCE AND SAFETY

LICENSING

Increased Collaborative Efforts

The Commission continues to promote collaborative efforts by encouraging participation in the Alternative

Licensing Process (ALP). The ALP is a voluntary process designed to improve communication among interested parties, and allows the Commission’s staff to provide requested assistance to participants early in the

licensing process. The process is flexible and tailored to the facts and circumstances of the particular project.

Other efforts to promote collaboration include interagency hydropower workshops, stakeholder consultation

meetings, and outreach meetings.

Resource Standards and Adaptive Management Provisions

With the resource standards approach (performance-based measures), the Commission imposes the desired

result and allows the licensee to decide the best way to achieve that result. Under the adaptive management

approach, the Commission issues licenses with terms that allow the Commission to react to changes over time.

The joint use of resource standards and adaptive management provides a more flexible approach, allowing

stakeholders to decide cooperatively the best and most cost-effective way to meet license objectives. The Commission has already initiated the use of these approaches in recent relicensing orders. During relicensing proceedings, Commission staff will examine license objectives to decide how to apply the resource standards and

adaptive management approaches. In addition, Commission staff will institute monitoring procedures to determine their effectiveness in achieving the desired results.

ENERGY PROJECTS
26

Settlements

The Commission encourages stakeholders, particularly when using the ALP, to resolve issues in the form

of settlement agreements. The following are examples of settlement agreements reached in FY 2001.

FPL Energy Maine Hydro LLC reached a settlement agreement with stakeholders for the relicensing of

Maine’s largest hydro plant, the 88-megawatt (MW) Indian Pond Project, also known as Harris Station. The

agreement stems from talks that began in 1999, after the project was purchased by FPL Energy from Central

Maine Power Co. The agreement would more than double the existing minimum flow from 140 to 300 cfs. It

also would provide habitat restoration funding, angler access, and suitable flows for fishing. FPL Energy Maine

is to donate 1,300 acres for conservation purposes and to attempt to protect lands along Kennebec Gorge.

On June 21, 2001, PacifiCorp filed a settlement agreement on behalf of itself and seven federal and state

agencies to resolve issues associated with the relicensing proceeding for its 185.5-MW North Umpqua Project

in Douglas County, Oregon. The project is adjacent to and just upstream of the 34-mile-long North Umpqua

Wild and Scenic River, considered by many the nation’s premier steelhead trout resource. The settlement agreement is the product of over five years of discussions among the signatories and Commission staff participation

during the year.

ENERGY PROJECTS

2002

2003

2004

2005

2006

2007

2008

2009

2010

1000

2000

3000

4000

5000

6000

7000

0

TOTAL MEGAWATTS AT HYDRO

PROJECTS UP FOR RELICENSING

FISCAL YEAR

MEGAWATTS

500

1500

2500

3500

4500

5500

6500

7500
27

Interagency Cooperation

In May 2000, the Commission and the Departments of Interior, Commerce, and Agriculture signed a statement of commitment to make the hydropower licensing process more efficient and effective. A Joint Settlement

of Commitment outlines the administrative reforms developed by an interagency task force that these agencies

created to improve the hydropower licensing process. In December 2000, the task force released seven reports

that included agreements pertaining to: noticing procedures; NEPA processes; endangered species consultation; studies process; mandatory terms and conditions; trackable and enforceable license conditions; and collaborative processes. Beginning in January 2001, an interagency outreach team presented the task force reports

to over 150 Commission and resource agency personnel in eight cities.

To monitor the success of interagency agreements aimed at improving the licensing process and to create a

lasting forum for discussion of issues among agencies involved in the licensing process, the task force created

the Interagency Hydropower Committee (IHC).

To help in defining the Commission’s and U.S. Fish and Wildlife Service’s responsibilities and opportunities to protect migratory birds, the Commission is participating along with other agencies in the preparation of

a memorandum of understanding (MOU) to implement Executive Order 13186, “Responsibilities of Federal

Agencies to Protect Migratory Birds.”

COMPLIANCE AND ADMINISTRATION

Preliminary Permits

During FY 2001, the Commission processed 169 applications for preliminary permits. Over 200 applications were filed, a 97 percent increase from FY 2000, and the great majority of sites proposed for study are

located in the western United States. The purpose of a preliminary permit is to maintain priority of application

for a license during the three-year term of the permit while the permittee conducts investigations and secures

data necessary to determine the feasibility of the proposed project and prepares an acceptable development

application.

Non-Power License

The Commission has issued its first non-power license to Wisconsin Electric Power Co. for the 800-kW

Sturgeon Project. The non-power license permits temporary operation of the project for several years while the

reservoir is drained, the reservoir bed is stabilized, and the project works are removed. When that is completed,

the Commission intends to accept WEPCO’s application to surrender its license. The Commission approved an

agreement in early 2001 that included relicensing eight WEPCO projects in the Upper Menominee River Basin

and the surrender of the Sturgeon license.

License Transfers

During FY 2001, the Commission acted on 39 applications for the transfer of a license. When a licensee

wishes to transfer its license, it must seek Commission approval. A transfer application is jointly filed by the

transferor and transferee and is publicly noticed. Since the issuance of the Commission's Decommissioning

Policy Statement in 1994, Commission staff has scrutinized license transfers to ensure that a transferor with a

poor compliance record is not trying to escape that record and give a transferee an advantage in relicensing, or

handing off an increasingly marginal project to a new licensee that lacks the financial resources to maintain the

project. A determination is made concerning the proposed transferee's fitness under the FPA.

ENERGY PROJECTS
28

Outreach

The Commission continues to make outreach a part of its day-to-day operations. Commission staff provides assistance and guidance to interested parties working toward mutually acceptable solutions to post-licensing matters.

For example, in October 2000, Commission staff met in Taftsville, Vermont, to discuss the relocation of

two historic substations at the Taftsville Project. At the meeting, the group discussed alternatives and agreed to

look at various options.

Staff encouraged the licensee and the group to develop a scoping document to look at the feasibility of

relocating the two substations. The group has filed progress reports and is working toward a solution.

At the request of the licensee for the Smith Mountain Project in central Virginia, Commission staff participated in a meeting with the licensee and waterfront home developers interested in the application process for

non-project uses. Staff assisted the licensee in explaining this process and discussed the licensee’s ongoing

efforts to prepare a shoreline management plan for the project. Staff also met with the steering committee at

Smith Mountain Lake to discuss the development of their shoreline management plan.

Commission staff participated in an outreach meeting concerning water-borne debris on the lower

Susquehanna River near Harrisburg, Pennsylvania. In response to a recent high-flow event on the river, the

meeting allowed parties to review the debris management measures taken at the Conowingo Hydroelectric

Project.

Commission staff also attended a meeting in Missoula, Montana, with multiple agencies to discuss Flathead Lake. A public session was held to provide information to the public regarding the operation of the project

during summer low flow and drought conditions.

Since February 2001, Commission staff has met regularly with the licensee of the Toledo Bend Project and

a group of interested stakeholders to assist the group in a collaborative effort to reach a mutually acceptable

agreement on reservoir operating levels at the project, which is located on the Sabine River in Texas and

Louisiana. Commission staff continues to assist and guide the collaborative work group as it works toward

resolving these issues.

Civil Penalties

In FY 2001, the Commission, for the first time in a decade, did not impose any civil penalties; however,

several noncompliance cases were addressed and resolved. In one case, Commission staff worked over several

years and visited a project site numerous times to facilitate its sale. In another case that had public safety

implications, the Commission was granted injunctive relief and a District Court ordered a licensee to make

necessary repairs by a specified date, or face contempt or daily fines until the repair work was completed. This

matter was also resolved in FY 2001, when a company with hydro experience purchased the project and agreed

to make the needed repairs. The Commission also reached an agreement with a municipality that had allegedly

violated its license requirement concerning flushing flows. Negotiations with the municipality revealed a differing interpretation of the requirement and after further discussions about environmental impacts, the licensee

agreed to implement the flushing flows sought by the Commission and revisit the issue by submitting an

application to amend the license.

ENERGY PROJECTS
29

Shoreline Management

The Commission recognized the need for a guidance document to address the Commission’s legal authorities and regulatory role with regard to shoreline management, planning, and monitoring. Therefore, in April

2001, the Commission issued a shoreline management guidance booklet.

In recent years, the Commission has seen an increasing number of applications filed for shoreline development activities (specifically for non-project uses and occupancies of project lands and waters). In response to

the growing involvement of homeowners and users of recreational facilities in the public review process, Commission staff has been actively searching for ways to work with licensees and concerned stakeholders. Through

the Shoreline Management Guidance Handbook, the Commission hopes to minimize the environmental effects

of these uses of project resources while continuing to allow for public enjoyment of project resources.

Compliance Plans and Reports

Licenses issued today include conditions that will protect and enhance environmental resources. These

conditions require licensees to prepare and file plans or reports with the Commission. These plans and reports

may deal with project operation, development of recreational resources, improvements to fishery habitat, water

quality protection, wildlife benefits, wetlands and vegetation improvements, and cultural resources protection.

Prepared after the license is issued, the licensees typically develop the plans and reports in consultation with

identified agencies and groups, and file them as applications with the Commission. In FY 2001, the Commission approved over 900 applications.

Environmental Compliance Reviews

To ensure that licensees comply with the terms and conditions of their licenses, the Commission will

continue to pursue reported incidences of environmental non-compliance. If an incident is reported, the Commission directs the licensee to explain the circumstances surrounding the incident and, if necessary, provide

additional information. In FY 2001, the Commission completed over 200 reviews of reports on non-compliance incidents related to environmental requirements. Many of the incidents were received by the Commission

as self-reports made by the hydropower licensees while others were allegations received from private citizens

and resource agencies. All of the reports required review by the Commission staff with many of the incidents

corrected immediately by the licensee or corrected after staff took follow-up actions.

ENERGY PROJECTS

BETWEEN THE YEARS 2002 AND 2010,

MORE THAN 180 PROJECT LICENSES WILL EXPIRE.

THESE PROJECTS REPRESENT ABOUT 21 GIGAWATTS,

OR 32 PERCENT, OF THE TOTAL GENERATING

CAPACITY OF ALL LICENSED PROJECTS.
30

Effectiveness of Environmental Measures

Most hydropower licenses include requirements to develop plans to monitor the environmental resource

protection conditions implemented at the project. In FY 2001, the Commission reviewed the results of these

monitoring efforts to evaluate whether the environmental measures were providing appropriate levels of protection, mitigation, and enhancement for environmental resources. Stakeholders with an interest in a particular

environmental measure being examined were provided an opportunity to participate in the evaluation process.

Through outreach meetings and workshops, the Commission distributed information for licensees and potential licensees to use in developing their environmental resource protection plans. Outreach meetings and workshops addressed such topics as shoreline management programs, water quality protection, fish passage, and

recreation management plans. The evaluations resulting from the review and analysis of these monitoring

results will allow for improvements to the environmental measures included in future licenses and, consequently, to the hydropower program objective of improving the environmental performance of hydropower

projects.

SAFETY

Project Inspections

Inspections verify the structural integrity of dams and compliance with engineering, environmental, and

public safety conditions and regulations. They also identify necessary maintenance and remedial modifications. The Commission is responsible for inspecting about 2,600 dams and related water retention structures. It

conducts periodic inspections starting from the receipt of an application for a proposed jurisdictional project,

throughout the term of a license. The Commission's five regional offices conduct the inspections.

Inspections during project construction ensure that the constructed project complies with the approved

design. They also ensure that project construction complies with all applicable federal and state environmental

regulations and includes appropriate environmental protection measures, such as erosion control plans and

flow monitoring systems. Construction inspections can uncover unexpected conditions (such as unknown foundation features) and any need for design changes.

When the project begins operation, focus shifts to ensuring safe operation and maintenance of the dams.

Periodic, on-site operation inspections ensure the long-term structural integrity of the project works. They also

ensure that licensees comply with license provisions. These inspections safeguard the continued operation of

projects, as well as downstream lives, property, and environment.

Special inspections occur when special issues arise. These may involve potential dam safety problems,

unauthorized projects, complaints about the construction or operation of projects, public safety concerns, or

compliance issues.

ENERGY PROJECTS
31

Engineering Analyses

To provide guidance to its engineering staff, dam owners, their consultants, and the rest of the dam safety

community, the Commission publishes Engineering Guidelines for the Evaluation of Hydropower Projects.

These guidelines specify the criteria, analytical methods, engineering parameters, and other engineering aspects related to the design, construction, monitoring, and operation of safe dams. The dam safety community

widely requests and relies on these guidelines. The Commission updates and expands the guidelines as necessary to ensure consistency with state-of-the-art technology.

As dams age and undergo various stress conditions, such as floods and earthquakes, the Commission increases its monitoring and use of instrumentation data to decide whether the condition of the dams and their

appurtenant facilities are changing. This procedure is the key to detecting potential problems before they become serious and deciding whether new remediation is necessary. With monitoring data available, the Commission will require licensees and their consultants to continually evaluate the condition and performance of their

dams.

Safety Reviews

The Commission's dam safety program must ensure consistently high safety standards at high and significant hazard potential dams to maintain the lowest probability of failure. In addition to its own periodic visual

inspections and evaluations, the Commission requires periodic independent consultant inspections of dams

with high hazard potential. These inspections include a complete engineering assessment and inspection of the

project works, with a detailed review of the project design and a thorough inspection of project structures. For

quality control, Commission dam safety experts approve qualifications of independent consultants. They also

thoroughly review all independent consultant inspection reports for validity of the analysis and conclusions and

the need for additional studies or remedial measures.

In FY 2001, the Commission developed and held independent consultants workshops in Portland, Oregon,

and Washington, D.C. These workshops accomplished the objective of promoting communication and a common understanding of the Commission’s Independent Consultant Inspection Program by the licensees, independent consultants, and Commission staff. The workshops resulted in opening up new lines of communication, specifically a web-based system that provides for the free flow of dam safety-related information, policy

updates, and collaboration on developing dam safety initiatives.

Ensuring Safe Projects: Aging Hydraulic Components

The proper functioning of the hydraulic components of dams is critical to ensuring dam safety. Without

proper functioning of the hydraulic machinery, penstocks, conduits, gates, and spillways, the necessary control

of reservoirs can be lost, resulting in dam failure. While the Commission’s role and responsibility regarding

dam safety are quite different from those of other agencies, such as the Corps of Engineers, the Bureau of

Reclamation, and FEMA, all have common technical dam safety concerns. In addition, the rest of the dam

safety community, including dam owners, state dam safety agencies, and engineering consultants, has expertise

and a vested interest in technical dam safety issues. The Commission is coordinating and focusing the dam

safety community on hydraulic component safety problems. The goal is to develop the proper technical approach to assure the safety and adequacy of aging hydraulic components of dams.

ENERGY PROJECTS
32

ENERGY PROJECTS

Performance Monitoring

Applying instrumentation to dams and related water-retaining structures, to monitor otherwise-undetectable changes in these structures, is a critical component of the Commission’s dam safety program. By applying

the correct technology and instrumentation to each unique situation for early detection and evaluation of deficiencies, serious problems are identified, evaluated, and corrected before they fully develop. In FY 2001, the

Commission initiated development of an important aspect of its performance monitoring program — potential

failure modes analysis. In conducting these analyses, the focus is to determine: (1) the most likely failure mode

of a dam; and (2) how to ensure that conditions leading to it will be corrected before they become dam safety

problems. Establishing site-specific potential failure modes for dams will increase the efficiency and effectiveness of the performance monitoring program.

State Safety Programs

Congress established the National Dam Safety Program Review Board (NDSPRB) to advise the Director of

FEMA on implementation of the National Dam Safety Program. The Commission's dam safety expertise was

influential in the Board's accomplishments in FY 2001. Accomplishments included grant distribution to all 50

states, and dam safety program improvements made in every state. Also during FY 2001, the National Dam

Safety Program Training Subcommittee, which the Commission chairs, facilitated several beneficial training

opportunities for state programs. The State of Alaska requested that the Commission share its expertise in

emergency action planning to help improve the state’s dam safety program. Commission staff held a training

course in Anchorage, Alaska, on the testing of Emergency Action Plans (EAPs) for state-regulated dam owners

and Commission-regulated licensees.

Seismicity in the East

In FY 2001, the Commission staff worked with several licensees to develop new information on several

site-specific seismicity studies and seismic stability analyses for projects in the southeastern part of the United

States. The impact of earthquakes on the safety and stability of Commission-licensed dams is an area of concern and requires detailed engineering evaluations. Current studies have focused on earth dams constructed in

the 1930’s, sometimes over loose foundation materials, or constructed with techniques that produced a loose

embankment dam susceptible to drastic strength reductions during seismic shaking. These evaluations indicate

significant modifications are required at several projects. Commission staff has guided the remedial designs to

develop effective, least-cost solutions.

Seismicity in the Northwest

In FY 2001, engineering consultants to the Commission completed several studies in the Northwest assessing the seismic influence a major rupture along the Cascadia Subduction Zone and the Juan de Fuca Plate

would have on several high hazard potential dams. The Commission’s Engineering Guidelines require that high

hazard potential dams withstand the Maximum Credible Earthquake (MCE). Study results are enabling Commission staff to establish new or revised MCE loads in the Pacific Northwest region. Currently, several licensees are reviewing the seismic stability of their dams using the seismic loadings developed from the above

studies. In addition, the Commission is requiring dam owners to have their independent consultants perform

site-specific seismic evaluations and revise dam stability analyses when loading conditions change significantly, or when previous methods of analysis are no longer acceptable.
33

Emergency Action Planning

The Commission continues to make improvements to its EAP program. The Commission is recognized as

a national leader in EAPs. EAPs specify actions that owners must take, in coordination with federal, state and

local preparedness agencies, in case of emergencies. During FY 2001, the “International Workshop for Emergency Preparedness at Dams” was planned. Interest from throughout the U.S. and from several foreign countries was generated. Security at dams is an important topic at all Commission emergency action planning

workshops. In FY 2001, Commission staff continued to improve its EAP program by incorporating emergency

management personnel into the course, and providing more assistance to state dam safety programs. The primary objective of the course is to help Commission licensees better prepare for the testing of their emergency

action planning process. To achieve the maximum benefit of exercising the EAP, participation of all key players

involved in the plan is needed. Commission staff emphasizes the importance of emergency management personnel working closely with the dam owner to complete the EAP plan test.

ENERGY PROJECTS
34

Hydro Quebec’s Robert-Bourassa dam, completed in 1979, has a nominal capacity of 5,328 megawatts.

Canada is an important supplier of energy to the United States. Photo courtesy of Hydro Quebec.
35

HYDROELECTRIC POWER TABLE

 (PROJECTS FOR WHICH LICENSES WILL EXPIRE BETWEEN JANUARY 1, 2001, AND DECEMBER 31, 2007)

LICENSE FERC FACILITIES PERIOD

EXPIRATION PROJECT INSTALLATION UNDER OF SUBJ.

DATE OWNER NO. STATE COUNTY RIVER (KW) LICENSE (YEARS) FED.

20010125 S D WARREN CO 2942 ME CUMBERLAND PRESUMPSCOT RIVER 2400 DM PH 20 N

20010125 S D WARREN CO 2931 ME CUMBERLAND PRESUMPSCOT RIVER 1900 DM PH 21 N

20010125 S D WARREN CO 2932 ME CUMBERLAND PRESUMPSCOT RIVER 800 DM PH 21 N

20010125 S D WARREN CO 2941 ME CUMBERLAND PRESUMPSCOT RIVER 1000 DM PH 21 N

20010125 S D WARREN CO 2897 ME CUMBERLAND PRESUMPSCOT RIVER 1350 DM PH 22 Y

20010131 CONNECTICUT LIGHT & POWER CO 2597 CT LITCHFIELD HOUSATONIC RIVER 9000 DM PH 20 N

20010131 NEKOOSA PACKAGING CORP 2901 VA AMHERST JAMES RIVER 1875 DM PH 20 Y

20010131 LYNDONVILLE VILLAGE OF 3090 VT CALEDONIA PASSUMPSIC RIVER 350 DM PH 20 N

20010131 VIRGINIA ELECTRIC & POWER CO 2009 NC HALIFAX ROANOKE RIVER 278000 DM PH 50 Y

20010131 ERIE BOULEVARD HYDROPOWER, L.P 2060 NY COLTON TOWN OF COLTON 0 RS 50 Y

20010228 ANTRIM COUNTY 3030 MI ANTRIM ELK RIVER 700 DM PH 20 N

20010228 DAIRYLAND POWER COOP 1960 WI RUSK FLAMBEAU RIVER 15000 DM PH 50 Y

20010330 CONSUMERS ENERGY CO 2566 MI IONIA GRAND RIVER 3250 DM PH 20 Y

20010430 PACIFICORP 2071 WA CLARK LEWIS 134000 DM PH 50 Y

20010731 MARQUETTE CITY OF 2589 MI MARQUETTE DEAD RIVER 3900 DM PH 20 Y

20010731 USGEN NEW ENGLAND, INC. 2077 NH GRAFTON CONNECTICUT RIVER 291360 DM PH 50 Y

20010830 BLACK RIVER FALLS CITY OF 3052 WI JACKSON BLACK RIVER 920 DM PH 20 N

20010831 PACIFICORP 2652 MT FLATHEAD SWAN RIVER 4150 DM PH 25 Y

20010831 GREEN MOUNTAIN POWER CORP 2090 VT WASHINGTON WATERBURY RIVER 5520 DM PH 47 Y

20010901 INTERNATIONAL PAPER CO 2631 MA HAMPDEN WESTFIELD RIVER 2690 DM PH 20 Y

20010930 HAMILTON CITY OF 2724 OH BUTLER MIAMI RIVER 1500 DM PH 20 N

20010930 ENTERPRISE MILL, LLC 2935 GA RICHMOND AUGUSTA CANAL 1200 DM PH 20 N

20010930 AQUENERGY SYSTEMS INC 2416 SC GREENWOOD SALUDA RIVER 6200 DM PH 25 Y

20010930 NANTAHALA POWER & LIGHT CO 2694 NC MACON QUEENS CREEK 1440 DM PH 25 N

20011001 PACIFICORP 472 ID FRANKLIN BEAR RIVER 30000 DM PH 20 Y

20011001 CONNECTICUT LIGHT & POWER CO 2576 CT FAIRFIELD HOUSATONIC RIVER 105900 DM PH 20 N

20011001 PACIFICORP 20 ID CARIBOU BEAR RIVER 14000 DM PH 23 Y

20011001 PACIFICORP 2401 ID CARIBOU BEAR RIVER 40500 DM PH 25 Y

20011031 WISCONSIN ELECTRIC POWER CO 2131 MI DICKINSON MENOMINEE RIVER 7200 DM PH 22 Y

20011031 WISCONSIN ELECTRIC POWER CO 2073 MI IRON MICHIGAMME RIVER 9600 DM PH 50 Y

20011031 WISCONSIN ELECTRIC POWER CO 2074 MI IRON MICHIGAMME RIVER 2800 DM PH 50 Y

20011130 METRO. WATER RECLAMATION 2866 IL WILL CHICAGO SANITARY 13500 DM PH 20 Y

20011130 NORTH CENTRAL POWER CO INC 2064 WI SAWYER CHIPPEWA RIVER 600 DM PH 50 Y

20011231 WISCONSIN ELECTRIC POWER CO 1759 MI IRON MICHIGAMME RIVER 19944 DM PH 27 Y

20011231 CENTRAL MAINE POWER CO 2142 ME SOMERSET KENNEBEC RIVER 76400 DM PH 47 Y

20011231 TACOMA, CITY OF 2016 WA LEWIS COWLITZ RIVER 460000 DM PH 50 Y

20011231 PORTLAND GENERAL ELECTRIC CO 2030 OR JEFFERSON DESCHUTES RIVER 416100 DM PH 50 Y

20011231 WISCONSIN ELECTRIC POWER CO 2072 MI IRON PAINT RIVER 100 DM PH 50 Y

20020131 PUD NO 1 OF PEND OREILLE CNTY 2042 WA PEND OREILLE PEND OREILLE 60000 DM PH 50 N

20020131 ERIE BOULEVARD HYDROPOWER L.P. 2084 NY ST LAWRENCE RAQUETTE RIVER 101250 DM PH 50 Y

20020223 EL DORADO IRRIGATION DISTRICT 184 CA EL DORADO SOUTH FORK AMERICAN 20000 DM PH 22 Y

20020331 FORT JAMES OPERATING COMPANY 2312 ME PENOBSCOT PENOBSCOT RIVER 7655 DM PH 39 Y

20020731 COMINCO AMERICAN INC 2103 WA PEND O’REILLE CEDAR CREEK 0 RS 50 N

20020903 SPRINGVILLE, CITY OF 2031 UT UTAH BARTHOLOMEW CR 2000 DM PH 50 N

20020930 HART, CITY OF 3516 MI OCEANA PENTWATER RIVER 352 DM PH 20 N

20021012 SITHE PENNSYLVANIA HOLDINGS 309 PA CLARION CLARION RIVER 28800 DM PH 23 Y

20021031 HYDRO DEVELOPMENT GROUP INC 6059 NY ST LAWRENCE OSWEGATCHIE RIVER 900 DM PH 20 N

20021101 TRINITY CONSERVANCY INC 719 WA CHELAN PHELPS CREEK 240 DM PH 23 N

20021201 NEW YORK STATE ELEC & GAS CORP 2835 NY CLINTON AUSABLE RIVER 2640 DM PH 20 Y

20021231 HYDRO DEVELOPMENT GROUP INC 6058 NY ST LAWRENCE OSWEGATCHIE RIVER 1490 DM PH 20 N

20030131 WOODS LAKE HYDRO CO 3410 CO EAGLE LIME CREEK 45 DM PH 20 N

20030228 NEW YORK STATE ELEC & GAS CORP 2852 NY STEUBEN MUD CREEK 2000 DM PH 20 Y

20030228 ENTERGY, ARKANSAS, INC. 271 AR HOT SPRINGS OUACHITA 65300 DM PH 23 Y

20030331 AVONDALE MILLS INC 5044 GA RICHMOND AUGUSTA CANAL 2475 DM PH 20 N

20030426 SOUTHERN CALIFORNIA EDISON CO 344 CA BERNARDINO SAN GORGONIO RIVER 2250 DM PH 20 Y
36

HYDROELECTRIC POWER TABLE

20030430 PAROWAN CITY CORP 2782 UT IRON RED CREEK 500 DM PH 25 N

20030606 FORD MOTOR CO 362 MN RAMSEY MISSISSIPPI RIVER 17920 DM PH 23 Y

20030630 PCA HYDRO INC 2180 WI LINCOLN WISCONSIN RIVER 3000 DM PH 26 Y

20030731 BURFORD, JUDITH A 6418 CO EAGLE EAST BRUSH CREEK 11 DM PH 20 N

20030824 MINNESOTA POWER & LIGHT CO 346 MN MORRISON MISSISSIPPI RIVER 18000 DM PH 23 Y

20030831 SOUTHERN CALIFORNIA EDISON CO 2086 CA FRESNO MONO CREEK 0 RS 50 N

20030918 INDIANA MICHIGAN POWER CO 401 MI ST. JOSEPH ST JOSEPH RIVER 1750 DM PH 25 Y

20030930 CHARTER TOWNSHIP OF YPSILANTI 5334 MI WASHTENAW HURON RIVER 3413 DM PH 20 N

20030930 PACIFIC GAS & ELECTRIC CO 2107 CA BUTTE FEATHER RIVER 142830 DM PH 50 N

20031031 PACIFIC GAS & ELECTRIC CO 233 CA SHASTA PIT RIVER 317000 DM PH 22 Y

20031031 MINNESOTA POWER & LIGHT CO 469 MN LAKE KAWISHIWI 4000 DM PH 22 Y

20031031 NEW YORK POWER AUTHORITY 2000 NY ST LAWRENCE ST LAWRENCE RIVER 912000 DM PH 50 N

20031231 POTOMAC EDISON CO 2516 WV BERKELY POTOMAC RIVER 1900 DM PH 27 N

20031231 POTOMAC EDISON CO 2517 WV BERKELY POTOMAC RIVER 1210 DM PH 27 N

20040131 NEWTON FALLS INC. 7000 NY ST LAWRENCE OSWEGATCHIE RIVER 2220 DM PH 20 Y

20040331 S D WARREN CO 2984 ME CUMBERLAND PRESUMPSCOT 1800 DM PH 20 Y

20040331 PUD NO 1 OF CHELAN COUNTY 637 WA CHELAN CHELAN RIVER 48000 DM PH 30 Y

20040410 MIDWEST HYDRO, INC 287 IL LASALLE FOX RIVER 3680 DM PH 24 Y

20040430 MADISON PAPER INDUSTRIES 2364 ME SOMERSET KENNEBEC RIVER 16977 DM PH 40 Y

20040430 MADISON PAPER INDUSTRIES 2365 ME SOMERSET KENNEBEC RIVER 9000 DM PH 40 Y

20040430 MERIMIL LTD PARTNERSHIP 2574 ME KENNEBEC KENNEBEC RIVER 6770 DM PH 40 Y

20040430 UNITED WATER CONSERVATION DIST 2153 CA VENTURA PIRU CREEK 1420 DM PH 50 Y

20040630 WISCONSIN PUBLIC SERVICE CORP 1979 WI LINCOLN WISCONSIN RIVER 4200 DM PH 30 Y

20040731 NORWAY, CITY OF 2720 MI DICKINSON MENOMINEE RIVER 5636 DM PH 20 Y

20040731 IDAHO POWER CO 2726 ID GOODING BIG WOOD RIVER 21770 DM PH 25 Y

20040930 BARTON VILLAGE INC 7725 VT ORLEANS CLYDE RIVER 1300 DM PH 20 N

20040930 PPL HOLTWOOD, LLC 487 PA WAYNE LACKAWAXEN RIVER 40000 DM PH 30 Y

20041031 BUFFALO HYDRO L.C. 1413 ID FREMONT BUFFALO RIVER 250 DM PH 25 N

20041031 PACIFIC GAS & ELECTRIC CO 2105 CA PLUMAS FEATHER RIVER 342628 DM PH 50 Y

20041112 PETERSBURG, CITY OF 201 AK WRANGELL CRYSTAL CREEK 2000 DM PH 30 Y

20041116 PORTLAND GENERAL ELECTRIC CO 477 OR CLACKAMAS SANDY RIVER 21000 DM PH 25 Y

20041130 INTERNATIONAL PAPER CO 4914 WI BROWN FOX RIVER 1078 DM PH 20 N

20041230 PAROWAN CITY CORP 1273 UT IRON CENTER CREEK 600 DM PH 30 N

20041231 MOSINEE PAPER CORP 2207 WI MARATHON WISCONSIN RIVER 3050 DM PH 30 Y

20041231 MONTANA POWER CO 2543 MT MISSOULA CLARK FORK 3200 DM PH 40 Y

20041231 OAKDALE & SAN JOAQUIN IRR DIST 2005 CA TUOLUMNE STANISLAUS 63990 DM PH 50 Y

20041231 OAKDALE & SAN JOAQUIN IRR DIST 2067 CA TUOLUMNE STANISLAUS 17100 DM PH 50 Y

20041231 PACIFIC GAS & ELECTRIC CO 2130 CA TUOLUMNE STANISLAUS 87900 DM PH 50 Y

20041231 GEORGIA POWER CO 2177 GA HARRIS CHATTAHOOCHEE 115600 DM PH 50 Y

20041231 PORTLAND GENERAL ELECTRIC CO 2233 OR CLACKAMAS WILLAMETTE 16800 DM PH 50 Y

20050228 SOUTHERN CALIF EDISON CO 382 CA KERN KERN 12000 DM PH 25 Y

20050228 TAPOCO INC 2169 TN MONROE LITTLE TENNESSEE 326500 DM PH 50 Y

20050331 WISCONSIN ELECTRIC POWER 2697 WI DUNN RED CEDAR 6000 DM PH 25 Y

20050331 SOUTHERN CALIF EDISON CO 2174 CA FRESNO RANCHERIA CR,BIG CR 10800 DM PH 50 Y

20050331 WISCONSIN ELECTRIC POWER 2181 WI DUNN RED CEDAR 5400 DM PH 50 Y

20050430 PACIFIC GAS & ELECTRIC CO 178 CA KERN KERN 11500 DM PH 25 Y

20050430 ALABAMA ELECTRIC COOP INC 2586 AL CRENSHAW CONECUH 8250 DM PH 25 N

20050531 MARSHALL, CITY OF 6514 MI CALHOUN KALAMAZOO 319 DM PH 20 N

20050531 GRAND RIVER DAM AUTH 2183 OK MAYES NEOSHO 100000 DM PH 50 Y

20050630 N. E. W. HYDRO INC ET AL 7264 WI OUTAGAMIE FOX 1390 DM PH 20 Y

20050630 PACIFICORP 2630 OR JACKSON N FK ROGUE 36760 DM PH 25 Y

20050630 FPL ENERGY MAINE HYDRO LLC 2194 ME YORK SACO 4000 DM PH 50 Y

20050730 NANTAHALA PWR AND LT CO 2601 NC SWAIN OCONALUFTEE 980 DM PH 25 Y

20050730 NANTAHALA PWR AND LT CO 2602 NC JACKSON TUCKASEGEE 225 DM PH 25 Y

20050730 NANTAHALA PWR AND LT CO 2603 NC MACON LITTLE TENNESSEE 1040 DM PH 25 Y

20050731 NANTAHALA PWR AND LT CO 2619 NC CLAY HIWASSEE 1800 DM PH 25 Y

LICENSE FERC FACILITIES PERIOD

EXPIRATION PROJECT INSTALLATION UNDER OF SUBJ.

DATE OWNER NO. STATE COUNTY RIVER (KW) LICENSE (YEARS) FED.
37

HYDROELECTRIC POWER TABLE

20050731 IDAHO POWER CO 1971 OR BAKER SNAKE 1166500 DM PH 50 Y

20051004 NORQUEST SEAFOOD INC. 620 AK CHIGNIK INDIAN CREEK 60 PH 26 N

20051031 PUD GRANT CTY, WASHINGTON 2114 WA GRANT COLUMBIA 1755000 DM PH 50 Y

20051031 ERIE BOULEVARD HYDRO, LP 7387 NY FRANKLIN RAQUETTE 2700 DM PH 20 Y

20051110 LOUISVILLE GAS & ELECTRIC CO 289 KY JEFFERSON OHIO RIVER 80230 DM PH 24 Y

20060131 NANTAHALA PWR AND LT CO 2698 NC JACKSON TUCKASEGEE RIVER 26175 DM PH 25 N

20060131 NANTAHALA PWR AND LT CO 2686 NC JACKSON TUCKASEGEE RIVER 24600 DM PH 25 N

20060214 MONROE CITY CORPORATION 632 UT SEVIER MONROE CREEK 250 DM PH 28 N

20060228 PACIFICORP 2082 CA SISKIYOU KLAMATH RIVER 151000 DM PH 52 N

20060228 NANTAHALA PWR AND LT CO 2692 NC CLAY NANTAHALA RIVER 43200 DM PH 25 N

20060228 UNION ELECTRIC CO 459 MO BENTON OSAGE 176200 DM PH 25 Y

20060331 SOUTH CAROLINA PUBLIC AUTHORITY 199 SC BERKELEY SANTEE RIVER 134520 DM PH 27 N

20060412 N Y ST ELEC & GAS CORP 2738 NY CLINTON SARANAC RIVER 38950 DM PH 26 N

20060430 PUGET SOUND PWR AND LT CO 2150 WA SKAGIT BAKER RIVER 162400 DM PH 50 N

20060430 PACIFICORP 2111 WA CLARK LEWIS RIVER 240000 DM PH 50 N

20060430 COWLITZ CO PUD NO 1 2213 WA COWLITZ LEWIS RIVER 70000 DM PH 50 N

20060430 PACIFICORP 935 WA CLARK LEWIS RIVER 135000 DM PH 23 N

20060630 CHELAN CO PUD 1 2145 WA DOUGLAS COLUMBIA R 1236600 DM PH 50 N

20060831 PORTLAND GENERAL ELEC CO 2195 OR CLACKAMAS CLACKAMAS RIVER 91900 DM PH 50 N

20060831 PORTLAND GENERAL ELEC CO 135 OR CLACKAMAS OAK GROVE FOR 40825 DM PH 26 Y

20061130 ERIE BOULEVARD HYDROPOWER, L.P. 7321 NY FRANKLIN SALMON RIVER 1000 DM PH 20 N

20061231 CITY & COUNTY OF DENVER 2204 CO GRAND WILLIAMS FORK RIVER 3000 DM PH 43 N

20061231 MONTANA POWER CO 2543 MT MISSOULA CLARK FORK 3200 DM PH 38 N

20070131 SACRAMENTO M U D 2100 CA EL DORADO TELLS CREEK 762850 DM PH 50 Y

20070228 CITY OF HOLYOKE, MA 7758 MA HAMPDEN HOLYOKE CNL 760 PH 20 N

20070327 PACIFIC GAS AND ELECTRIC 606 CA SHASTA SOUTH COW CREEK 4400 DM PH 23 Y

20070331 FLAMBEAU HYDRO, LLC 9185 WI BURNETT CLAM 1200 DM PH 20 N

20070430 CHUGACH ELEC ASSN INC 2170 AK SEWARD COOPER CREEK 15000 DM PH 40 Y

20070430 GARKANE POWER ASSN INC 2219 UT GARFIELD W FK BOULDER CREEK 43000 DM H 40 Y

20070609 FLAMBEAU HYDRO, LLC 9184 WI BURNETT YELLOW 1076 DM PH 20 N

20070731 ALABAMA POWER CO 82 AL CHILTON COOSA 170000 DM PH 32 Y

20070731 PACIFIC GAS & ELECTRIC CO 2155 CA EL DORADO S FK AMERICAN RIVER 7000 DM PH 45 Y

20070731 SACRAMENTO M U D 2101 CA EL DORADO S FK AMERICAN RIVER 640950 DM PH 40 Y

20070731 ALABAMA POWER CO 618 AL ELMORE COOSA 170000 DM PH 27 Y

20070731 ALABAMA POWER CO 2146 GA ELMORE COOSA 690900 DM PH 40 Y

20070829 ALASKA POWER AND TELEPHONE CO 1051 AK SKAGWAY DEWEY 943 DM PH 27 N

20070831 RESOURCES WEST ENERGY CORP 2545 ID LINCOLN SPOKANE 1366000 DM PH 35 Y

20070831 ALABAMA POWER CO 2165 AL TUSCALOOSA BLACK WARRIOR 203250 DM PH 40 Y

20070831 NEW YORK POWER AUTHORITY 2216 NY NIAGARA NIAGARA 27555000 DM PH 50 Y

20070831 SOUTH CAROLINA GAS AND ELECTRIC 516 SC NEWBERRY SALUDA 207300 DM PH 27 Y

20071130 SOUTHERN CALIFORNIA EDISON CO 2085 CA FRESNO SAN JOAQUIN 180937 DM PH 40 Y

20071130 WOLVERINE HYDROELECTRIC CORP 2785 MI MIDLAND TITTABAWASSEE 3300 DM PH 20 Y

*INCLUDES TYPES OF FACILITIES AT EACH PROJECT, BUT NOT TOTAL NUMBER OF EACH TYPE (E.G. A PROJECT MAY CONSIST OF MULTIPLE POWERHOUSES OR

DAMS.). DM DAM, RS RESERVOIR, CL CANAL, TU TUNNEL, FM FLUME, PI PIPELINE, PK PENSTOCK, PH POWERHOUSE, TR TURBINE, GN GENERATOR(S), TC

TAILRACE, TL TRANSMISSION LINE OR CONNECTION THERETO.

LICENSE FERC FACILITIES PERIOD

EXPIRATION PROJECT INSTALLATION UNDER OF SUBJ.

DATE OWNER NO. STATE COUNTY RIVER (KW) LICENSE (YEARS) FED.
38

For Additional Information, Contact:

 Federal Energy Regulatory Commission

Office of External Affairs

888 First Street, NE

Washington, DC 20426

202/208-0004

Printed 2002
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