<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the fiscal year ended December 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from _________ to ___________
Commission File Registrant; State of Incorporation; IRS Employer
Number Address and Telephone Number Identification No.
------ ---------------------------- ------------------
1-11459 PPL Corporation 23-2758192
(Exact name of Registrant as
specified in its charter)
(Pennsylvania)
Two North Ninth Street
Allentown, PA 18101
(610) 774-5151
1-905 PPL Electric Utilities Corporation 23-0959590
(Exact name of Registrant as
specified in its charter)
(Pennsylvania)
Two North Ninth Street
Allentown, PA 18101
(610) 774-5151
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
- ------------------- ------------------------
Common Stock of PPL Corporation New York & Philadelphia
Stock Exchanges
Preferred Stock of PPL Electric Utilities Corporation
4-1/2% New York & Philadelphia Stock Exchanges
3.35% Series Philadelphia Stock Exchange
4.40% Series New York & Philadelphia Stock Exchanges
4.60% Series Philadelphia Stock Exchange
Company-Obligated Mandatorily Redeemable Securities of PPL Electric Utilities
Corporation
8.20% Series ($25 stated value)(a) New York Stock Exchange
8.10% Series ($25 stated value)(b) New York Stock Exchange
(a) Issued by PP&L Capital Trust and guaranteed by PPL Electric Utilities
Corporation
(b) Issued by PP&L Capital Trust II and guaranteed by PPL Electric Utilities
Corporation
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
PPL Corporation [ X ]
PPL Electric Utilities Corporation [ X ]
Indicate by check mark whether the Registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.
PPL Corporation Yes X No _____
-----
PPL Electric Utilities Corporation Yes X No _____
-----
As of January 31, 2000, PPL Corporation had 143,696,625 shares of its $.01 par
value Common Stock outstanding, excluding 30,993,637 shares held as treasury
stock. The aggregate market value of these common shares (based upon the average
of the high and low price of these shares on the New York Stock Exchange on that
date) held by non-affiliates was $3,309,512,895.
PPL Corporation held all 102,230,382 outstanding common shares, no par value, of
PPL Electric Utilities Corporation, excluding 55,070,000 shares held as treasury
stock. The aggregate market value of the voting preferred stock held by non-
affiliates of PPL Electric Utilities Corporation at January 31, 2000 was
$76,378,445.
Documents incorporated by reference:
Registrants have incorporated herein by reference certain sections of PPL
Corporation's 2000 Notice of Annual Meeting and Proxy Statement, and PPL
Electric Utilities Corporation's 2000 Notice of Annual Meeting and Information
Statement, which will be filed with the Securities and Exchange Commission not
later than 120 days after December 31, 1999. Such Statements will provide the
information required by Part III of this Report.
<PAGE>
PPL CORPORATION
PPL ELECTRIC UTILITIES CORPORATION
FORM 10-K ANNUAL REPORT TO
THE SECURITIES AND EXCHANGE COMMISSION
FOR THE YEAR ENDED DECEMBER 31, 1999
------------------------------------
TABLE OF CONTENTS
-----------------
This combined Form 10-K is separately filed by PPL Corporation and PPL
Electric Utilities Corporation. Information contained herein relating to PPL
Electric Utilities Corporation is filed by PPL Corporation and separately by PPL
Electric Utilities Corporation on its own behalf. PPL Electric Utilities
Corporation makes no representation as to information relating to PPL
Corporation or its subsidiaries, except as it may relate to PPL Electric
Utilities Corporation.
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Item Page
PART I
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1. Business............................................................ x
2. Properties.......................................................... x
3. Legal Proceedings................................................... x
4. Submission of Matters to a Vote of Security Holders................. xx
Executive Officers of the Registrants............................... xx
PART II
-------
5. Market for the Registrant's Common Equity and Related Stockholder
Matters............................................................. xx
6. Selected Financial and Operating Data............................... xx
7. Review of the Financial Condition and Results of Operations......... xx
7A. Quantitative and Qualitative Disclosures About Market Risk.......... xx
Report of Independent Accountants................................ xx
Management's Report on Responsibility for Financial Statements... xx
8. Financial Statements and Supplementary Data
Financial Statements:
PPL Corporation
Consolidated Statement of Income for each of the Three Years
Ended December 31, 1999, 1998 and 1997......................... xx
Consolidated Statement of Cash Flows for each of the Three Years
Ended December 31, 1999, 1998 and 1997......................... xx
Consolidated Balance Sheet at December 31, 1999 and 1998......... xx
Consolidated Statement of Shareowners' Common Equity for each
of the Three Years Ended December 31, 1999, 1998 and 1997...... xx
Consolidated Statement of Preferred Stock at December 31, 1999
and 1998....................................................... xx
Consolidated Statement of Company-Obligated Mandatorily
Redeemable Securities at December 31, 1999 and 1998............ xx
Consolidated Statement of Long-Term Debt at December 31, 1999
and 1998....................................................... xx
</TABLE>
<PAGE>
<TABLE>
<S> <C>
PPL Electric Utilities Corporation
Consolidated Statement of Income for each of the Three Years
Ended December 31, 1999, 1998 and 1997......................... xx
Consolidated Statement of Cash Flows for each of the Three Years
Ended December 31, 1999, 1998 and 1997......................... xx
Consolidated Balance Sheet at December 31, 1999 and 1998......... xx
Consolidated Statement of Shareowner's Common Equity for each of
the Three Years Ended December 31, 1999, 1998 and 1997......... xx
Consolidated Statement of Preferred Stock at December 31, 1999
and 1998....................................................... xx
Consolidated Statement of Long-Term Debt at December 31, 1999
and 1998....................................................... xx
Notes to Financial Statements.................................... xx
Supplemental Financial Statement Schedule:
II - Valuation and Qualifying Accounts and Reserves for the
Three Years Ended December 31, 1999......................... xx
Quarterly Financial, Common Stock Price and Dividend Data........... xx
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................ xx
PART III
--------
10. Directors and Executive Officers of the Registrants................. xx
11. Executive Compensation.............................................. xx
12. Security Ownership of Certain Beneficial Owners and Management...... xx
13. Certain Relationships and Related Transactions...................... xxx
PART IV
-------
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.... xxx
Shareowner and Investor Information................................. xxx
Signatures.......................................................... xxx
Exhibit Index....................................................... xxx
Computation of Ratio of Earnings to Fixed Charges................... xxx
</TABLE>
<PAGE>
GLOSSARY OF TERMS AND ABBREVIATIONS
AFUDC (Allowance for Funds Used During Construction) - the cost of equity and
debt funds used to finance construction projects that is capitalized as part of
construction cost.
Aguaytia - Aguaytia Energy, LLC, a consortium of energy companies involved in
the development of gas pipeline and generating units in Peru.
Atlantic - Atlantic City Electric Company.
Bangor Hydro - Bangor Hydro-Electric Company.
BG&E - Baltimore Gas & Electric Company.
BGG - Bolivian Generating Group, LLC, an energy consortium with a 50% interest
in an electric generating company in Bolivia.
Burns Mechanical - Burns Mechanical, Inc., a PPL Spectrum unregulated subsidiary
specializing in mechanical contracting and engineering.
CERCLA - Comprehensive Environmental Response, Compensation and Liability Act.
Clean Air Act (Federal Clean Air Act Amendments of 1990) - legislation enacted
to address certain environmental issues including acid rain, ozone and toxic air
emissions.
CTC - competitive transition charge on customer bills to recover allowable
transition costs under the Customer Choice Act.
Customer Choice Act (Pennsylvania Electricity Generation Customer Choice and
Competition Act) - legislation enacted to restructure the state's electric
utility industry to create retail access to a competitive market for generation
of electricity.
DelSur - Distribuidora Electricidad del Sur S.A., an electric distribution
company in El Salvador, a majority of which is owned by EC.
DEP - Pennsylvania Department of Environmental Protection.
DOE - Department of Energy.
DRIP (Dividend Reinvestment Plan) - program available to shareowners of PPL
common stock and PPL Electric Utilities preferred stock to reinvest dividends in
PPL common stock instead of receiving dividend checks.
DVY - DVY, Incorporated, a mechanical contracting and engineering firm acquired
by Burns Mechanical in October 1999.
EC - Electricidad de Centroamerica, S.A. de C.V, an El Salvadoran holding
company and the majority owner of Del Sur. EC is jointly owned by PPL Global
and Emel.
ECR (Energy Cost Rate) - a tariff applied to PUC-jurisdictional customers to
recover fuel and other energy costs. Effective January 1997, energy costs were
rolled into base rates and the ECR was discontinued.
EGS - electric generation supplier.
EITF (Emerging Issues Task Force) - an organization that aids the FASB in
identifying emerging issues that may require FASB action.
Emel - Empresas Emel, S.A., a Chilean electric distribution holding company.
EMF - electric and magnetic fields.
Energy Act (Energy Policy Act of 1992) - federal legislation passed by Congress
to promote competition in the electric energy market for bulk power.
Energy Marketing Center - business unit within PPL Electric Utilities
responsible for marketing and trading wholesale energy.
EPA - Environmental Protection Agency.
EPS - Earnings per share.
ESOP - Employee Stock Ownership Plan.
FASB (Financial Accounting Standards Board) - a rulemaking organization that
establishes financial accounting and reporting standards.
FERC (Federal Energy Regulatory Commission) - federal agency that regulates
interstate transmission and wholesale sales of electricity and related matters.
FGD - flue gas desulfurization equipment installed at coal-fired power plants to
reduce sulfur dioxide emissions.
H.T. Lyons - H.T. Lyons, Inc., a PPL unregulated subsidiary specializing in
mechanical contracting and engineering.
IBEW - International Brotherhood of Electrical Workers.
ISO - Independent System Operator.
ITC - intangible transition charge on customer bills to recover intangible
transition costs associated with securitizing stranded costs under the Customer
Choice Act.
<PAGE>
ITP - intangible transition property created under the Customer Choice Act,
which represents the right to recover intangible transition costs through the
ITC.
JCP&L - Jersey Central Power & Light Company.
LIBOR - London Interbank Offered Rate.
McCarl's - McCarl's Inc., a PPL unregulated subsidiary specializing in
mechanical contracting.
McClure - McClure Company, a PPL unregulated subsidiary specializing in
mechanical contracting and engineering.
MOU - Memorandum of Understanding.
MSHA - Mine Safety and Health Administration.
NO\x\ - nitrogen oxide.
NPDES - National Pollutant Discharge Elimination System.
NRC (Nuclear Regulatory Commission) - federal agency that regulates operation of
nuclear power facilities.
NUG (Non-Utility Generator) - generating plants not owned by regulated
utilities. If the NUG meets certain criteria, its electrical output must be
purchased by public utilities under PURPA.
OSM - United States Office of Surface Mining.
OTR - Northeast Ozone Transport Region.
PCB (Polychlorinated Biphenyl) - additive to oil used in certain electrical
equipment up to the late-1970s. Now classified as a hazardous chemical.
Penobscot Hydro - Penobscot Hydro Co., Inc., a PPL Global subsidiary which
generates electricity for the New England market.
PJM (PJM Interconnection, LLC) - operates the electric transmission network and
electric energy market in the mid-Atlantic region of the U.S.
PLR - Provider of last resort, referring to PPL Electric Utilities Corporation
providing electricity to retail customers within its delivery territory who have
chosen not to shop for electricity under the Electric Choice Program.
PPL - PPL Corporation, the parent holding company of PPL Electric Utilities, PPL
Global and other subsidiaries.
PPL Capital Funding - PPL Capital Funding, Inc., a PPL financing subsidiary.
PP&L Capital Funding Trust I - a Delaware statutory business trust created to
issue Preferred Securities and Common Trust Securities.
PP&L Capital Trust - a Delaware statutory business trust created to issue
Preferred Securities, whose common stock is held by PPL Electric Utilities.
PP&L Capital Trust II - a Delaware statutory business trust created to issue
Preferred Securities, whose common stock is held by PPL Electric Utilities.
PPL Electric Utilities - PPL Electric Utilities Corporation
PPL Electric Utilities' Mortgage - PPL Electric Utilities Corporations' Mortgage
and Deed of Trust, dated October 1, 1945, as supplemented.
PPL EnergyPlus - PPL EnergyPlus, LLC, a PPL Electric Utilities unregulated
subsidiary which supplies energy and energy services in newly deregulated
markets.
PPL Gas Utilities - PPL Gas Utilities Corporation, a PPL regulated subsidiary
specializing in natural gas distribution, transmission and storage services, and
the sale of propane.
PPL Global - PPL Global, Inc., a PPL unregulated subsidiary which invests in
and develops world-wide power projects.
PPL Montana - PPL Montana Holdings LLC, a PPL subsidiary which generates
electricity for wholesale and retail customers in Montana and the Northwest.
PPL Spectrum - PPL Spectrum, Inc., a PPL unregulated subsidiary which offers
energy-related products and services.
PP&L Transition Bond Company - PP&L Transition Bond Company LLC, a wholly-owned
subsidiary of PPL Electric Utilities formed to issue transition bonds under the
Customer Choice Act.
Preferred Securities - Company-obligated mandatorily redeemable preferred
securities of subsidiary trusts holding solely company debentures (issued by two
Delaware statutory business trusts).
PRP - potentially responsible parties under Superfund.
PUC (Pennsylvania Public Utility Commission) - state agency that regulates
certain ratemaking, services, accounting, and operations of Pennsylvania
utilities.
PUC Final Order - final order issued by the PUC on August 27, 1998, approving
the settlement of PPL Electric Utilities' restructuring proceeding.
<PAGE>
PUHCA - Public Utility Holding Company Act of 1935.
PURPA (Public Utility Regulatory Policies Act of 1978) - legislation passed by
Congress to encourage energy conservation, efficient use of resources, and
equitable rates.
PURTA - Public Utility Realty Tax Act.
SBRCA - Special Base Rate Credit Adjustment.
SCR - selective catalytic reduction.
SEC - Securities and Exchange Commission.
SER - Schuylkill Energy Resources, Inc.
SFAS (Statement of Financial Accounting Standards) - accounting and financial
reporting rules issued by the FASB.
SIP - State Implementation Plan.
SO\2\ - sulfur dioxide.
Superfund - federal and state environmental legislation that addresses
remediation of contaminated sites.
SWEB - South Western Electricity plc, a British regional electric utility
company. Following the sale of its supply business in 1999, SWEB was renamed
Western Power Distribution. See WPD, below.
Tolling - an arrangement whereby a third party power marketer supplies fuel to a
power plant and receives the plant's electrical output in return for paying a
pre-established tolling fee.
UGI - UGI Corporation.
U.K. - United Kingdom.
VEBA (Voluntary Employee Benefit Association Trust) - trust accounts for health
and welfare plans for future payments to employees, retirees or their
beneficiaries.
Western Mass. Holdings - Western Massachusetts Holdings, Inc., a PPL unregulated
subsidiary specializing in mechanical contracting and engineering.
WPD - Western Power Distribution, the new name for SWEB's remaining power
distribution business.
Year 2000 - a set of date-related problems that may be experienced by software
systems or applications.
<PAGE>
(THIS PAGE LEFT BLANK INTENTIONALLY.)
<PAGE>
PART I
------
ITEM 1. BUSINESS
----------------
BACKGROUND
On February 14, 2000, PP&L Resources, Inc. (incorporated in 1994) filed
Articles of Amendment with the Pennsylvania Department of State to change its
name to PPL Corporation effective immediately. In addition, several of PPL's
direct and indirect subsidiaries changed their names, effective February 14,
2000, as follows:
. PPL Electric Utilities Corporation, formerly known as PP&L, Inc.
(incorporated in 1920), which provides electricity delivery service in
eastern and central Pennsylvania, and markets wholesale energy in the
United States and Canada;
. PPL Global, Inc., formerly known as PP&L Global, Inc., an
international independent power company which invests in and develops
world-wide power projects;
. PPL EnergyPlus, LLC, formerly known as PP&L EnergyPlus Co., LLC
(currently a subsidiary of PPL Electric Utilities), which sells energy
and energy services to deregulated markets;
. PPL Spectrum, Inc., formerly known as PP&L Spectrum, Inc., which
markets energy-related services and products;
. PPL Gas Utilities Corporation, formerly known as Penn Fuel Gas, Inc.,
which, together with its subsidiaries, provides natural gas
distribution, transmission and storage services and sells propane;
. PPL Energy Funding Corporation, formerly known as CEP Group, Inc.,
which, together with its subsidiaries, engages principally in
financing and cash management activities;
. PPL Montana, LLC, formerly known as PP&L Montana, LLC, which generates
electricity for wholesale and retail customers in Montana and the
Northwest;
. PPL Montana Holdings, LLC, formerly known as PP&L Montana Holdings,
LLC, which holds, through subsidiaries, investments in electricity
generation and related assets in Montana; and
. PPL Capital Funding, Inc., formerly known as PP&L Capital Funding,
Inc., which provides debt funding for PPL and its subsidiaries other
than PPL Electric Utilities.
<PAGE>
Other PPL subsidiaries include:
. PP&L Transition Bond Company (a special purpose subsidiary of PPL
Electric Utilities), formed to issue transition bonds under the
Pennsylvania Customer Choice Act; and
. H.T. Lyons, McClure, McCarl's, Burns Mechanical and Western Mass.
Holdings, which are mechanical contracting and engineering firms.
Other subsidiaries may be formed by PPL to take advantage of new business
opportunities.
The financial condition and results of operations of PPL Electric Utilities
and PPL Global are currently the principal factors affecting PPL's financial
condition and results of operations. PPL Montana is also expected to provide a
significant impact on future results of operations.
The electric utility industry, including PPL Electric Utilities, has
experienced and will continue to experience a significant increase in the level
of competition in the energy supply market. The Energy Act amended the PUHCA to
create a new class of independent power producers, and amended the Federal Power
Act to provide open access to electric transmission systems for wholesale
transactions. In addition, the Customer Choice Act was enacted in Pennsylvania
to restructure the state's electric utility industry in order to create retail
access to a competitive market for the generation of electricity. See "PUC
Restructuring Proceeding" in Note 4 to Financial Statements and "Increasing
Competition" in Review of Financial Condition and Results of Operations for a
discussion of competition-related developments.
PPL Electric Utilities is subject to regulation as a public utility by the
PUC and is subject in certain of its activities to the jurisdiction of the FERC
under Parts I, II and III of the Federal Power Act. PPL Electric Utilities is
not a holding company under PUHCA, and PPL has been exempted by the SEC from the
provisions of PUHCA applicable to it as a holding company.
PPL Electric Utilities is subject to the jurisdiction of the NRC in
connection with the operation of the two nuclear-fueled generating units at PPL
Electric Utilities' Susquehanna station. PPL Electric Utilities owns a 90%
undivided interest in each of the Susquehanna units and Allegheny Electric
Cooperative, Inc. owns a 10% undivided interest in each of those units.
PPL Electric Utilities also is subject to the jurisdiction of certain
federal, regional, state and local regulatory agencies with respect to air and
water quality, land use and other environmental matters. In addition, the
domestic operations of
<PAGE>
PPL are subject to the Occupational Safety and Health Act of 1970.
PPL Electric Utilities provides electricity delivery service to
approximately 1.3 million customers in a 10,000 square mile territory in 29
counties of eastern and central Pennsylvania, with a population of approximately
2.6 million persons. This service area has 129 communities with populations
over 5,000, the largest cities of which are Allentown, Bethlehem, Harrisburg,
Hazleton, Lancaster, Scranton, Wilkes-Barre and Williamsport. In addition to
delivery of its own generation or purchased power, PPL Electric Utilities is
delivering power supplied by licensed EGS' pursuant to the Customer Choice Act.
During 1999, nearly all of PPL Electric Utilities' operating revenue was
derived from energy deliveries and supply, with 24% coming from residential
customers, 21% from commercial customers, 17% from industrial customers, 36%
from wholesale sales and 2% from others.
PPL Electric Utilities operates its generation and transmission facilities
as part of the PJM. The PJM operates the electric transmission network and
electric energy market in the mid-Atlantic region of the United States. Bulk
electricity is transmitted to wholesale users throughout a geographic area
including all or part of Pennsylvania, New Jersey, Maryland, Delaware, Virginia
and the District of Columbia. PPL Electric Utilities is also a party to the
Mid-Atlantic Area Coordination Agreement, which provides for the coordinated
planning of generation and transmission facilities by the companies included in
the PJM.
In November 1997, the FERC ordered the restructuring of the PJM into an
ISO, in order to accommodate greater competition and broader participation in
the power pool. The purpose of the ISO is to separate operation of, and access
to, the transmission grid from the PJM electric utilities' generation interests.
The electric utilities continue to own the transmission assets, but the ISO
directs the control and operation of the transmission facilities.
PPL Electric Utilities has an Energy Marketing Center to take advantage of
opportunities in the competitive wholesale energy marketplace. The group
operates a 24-hour a day trading floor and a marketing effort with
responsibility for all PPL Electric Utilities wholesale power transactions. The
Energy Marketing Center has allowed PPL Electric Utilities to buy and sell
energy at the most competitive prices and to expand these activities beyond PPL
Electric Utilities' traditional service territory.
Pursuant to the Joint Settlement Petition in its PUC restructuring
proceeding, PPL Electric Utilities transferred its retail marketing function to
PPL EnergyPlus. PPL EnergyPlus has
<PAGE>
a PUC license to act as an EGS in Pennsylvania. This license permits PPL
EnergyPlus to offer retail electric and gas supply to customers throughout
Pennsylvania. In 1999, PPL EnergyPlus supplied energy to industrial and
commercial customers in Pennsylvania, New Jersey and Delaware, and is also
licensed to provide energy in Maine and Montana. At this time, PPL EnergyPlus
has decided not to pursue residential customers in the competitive marketplace
based on economic considerations.
Other wholly-owned subsidiaries of PPL Electric Utilities are principally
engaged in oil and gas pipeline operations, cash management and financing.
PPL Global, PPL's second largest subsidiary after PPL Electric Utilities,
is an international independent power company. PPL Global has ownership and
operational interests in companies in the U.K., Chile, Bolivia and El Salvador
that deliver electricity to more than 2 million customers. PPL Global also has
investment interests in Argentina, Peru, Spain, Portugal, Brazil and the U.S.
PPL has established growth in its generation capability, along with
expansion of its energy marketing operations, as a key element of its domestic
and international business strategy. In line with this strategy, PPL Global
completed or announced several acquisitions in 1999.
In May 1999, PPL Global acquired most of Bangor Hydro's generating assets
and certain transmission rights, as well as its interest in an oil-fired
generation facility. The generating assets acquired had a base load capacity of
83 megawatts. In August 1999, PPL Global purchased Bangor Hydro's 50% interest
in the 20-megawatt West Enfield hydroelectric station.
In July 1999, PPL Global reached an agreement with Duke Energy North
America to jointly complete the Griffith Energy Project, a gas-fired, combined-
cycle power plant near Kingman, Arizona. As part of the agreement, PPL Global
transferred a 50% interest in the project to Duke. PPL Global will fund 50% of
the capital cost of the project. The facility, expected to be in service in
2001, would have a nominal base-load capacity of 500 megawatts and a peak
capacity of 600 megawatts.
In 1998, PPL Global signed definitive agreements with the Montana
Power Company ("Montana Power"), Portland General Electric Company ("Portland")
and Puget Sound Energy, Inc. ("Puget") to acquire interests in 13 Montana power
plants, with 2,372 gross megawatts of generating capacity, for a purchase price
of $1.546 billion. The acquisition involves the Colstrip and Corette coal-fired
plants, 11 hydroelectric facilities and a storage reservoir. The Puget and
Portland agreements also provide for the acquisition of related transmission
assets for an additional $126 million, subject to certain conditions.
In December 1999, PPL Global completed the purchase of about 1,315 gross
megawatts of generating assets from Montana Power for $757 million. This
acquisition transferred to PPL Montana the 11 hydroelectric facilities, the
storage reservoir, the Corette plant and Montana Power's ownership interest
in three of the four units of the Colstrip plant, along with other generation-
related assets. PPL Montana is now operating these facilities. PPL Montana also
acquired the energy marketing and trading operation of Montana Power for an
amount that was not significant. The Montana marketing and trading operation,
which is now part of PPL EnergyPlus, is selling electricity in wholesale and
retail markets in Montana and the Northwest.
PPL Global's acquisition of the Colstrip interests of Portland and Puget,
totaling 1,057 additional megawatts, is subject to several conditions, primarily
the receipt of satisfactory regulatory approvals from the state utility
commissions in Oregon and Washington. The Washington Utilities and
Transportation Commission issued a decision in September 1999 with respect to
Puget's 735-megawatt interest in Colstrip, which Puget is disputing in the state
appellate court. On February 29, 2000, the Oregon Public Utility Commission
denied Portland's application to sell its 322-megawatt interest in Colstrip, but
stated that it would be willing to reconsider the decision if Portland could
demonstrate sufficient additional benefits to Oregon ratepayers as a result of
the sale. The interested parties are reviewing the regulatory decisions and
evaluating possible actions to address the decisions. The acquisition agreements
permit each party to terminate the respective agreements if closing does not
occur by April 30, 2000. PPL cannot predict the outcome of these proceedings,
whether the outcome will be satisfactory to the parties, or the effect of these
proceedings on the timing or the ability to complete these acquisitions.
<PAGE>
In the second half of 1999, PPL Global also acquired additional ownership
interests in Emel, a Chilean electric distribution company, increasing its
ownership to 95.4%. Acquisition of the controlling interest in Emel also gave
PPL Global a majority interest in EC, a holding company jointly owned by PPL
Global and Emel. EC is the majority owner of DelSur, an electric distribution
company in El Salvador.
In addition, PPL Global currently has under development a 500 megawatt gas-
fired generating plant in Lower Mt. Bethel, Pennsylvania, which is expected to
be in service in 2002, and a 250 megawatt gas-fired generating plant in
Wallingford, Connecticut, which is also expected to be in service in 2002.
In 1999, PPL subsidiaries also divested certain investments and assets. In
September 1999, PPL Global's U.K. investment, SWEB (subsequently renamed WPD),
sold its electric supply business. In November 1999, PPL Electric Utilities
sold its Sunbury fossil generating station and the related principal assets of
its wholly-owned coal processing subsidiary, Lady Jane Collieries. See "Power
Plant Operations" in Review of Financial Condition and Results of Operation.
In September 1999, the Boards of Directors of PPL and PPL Electric
Utilities approved the initiation of a corporate realignment, in order to better
position PPL and its subsidiaries in the new competitive marketplace. See
"Proposed Corporate Realignment" in the Review of Financial Condition and
Results of Operations for an overview of this initiative.
FINANCIAL CONDITION
See "Earnings" and "Financial Indicators" in the Review of the Financial
Condition and Results of Operations for this information.
CAPITAL EXPENDITURE REQUIREMENTS
See "Financial Condition - Capital Expenditure Requirements" in the Review
of the Financial Condition and Results of Operations for information concerning
PPL Electric Utilities' estimated capital expenditure requirements for the years
2000-2004. See Note 16 to Financial Statements for information
<PAGE>
concerning PPL Electric Utilities' estimate of the cost to comply with various
environmental regulations.
POWER SUPPLY
PPL's system capacity (winter rating) at December 31, 1999 was as follows:
<TABLE>
<CAPTION>
Net
Megawatt
Plant Capacity
----- --------
<S> <C>
PPL Electric Utilities (Pennsylvania)
----------------------
Nuclear-fueled steam station
Susquehanna 1,995 (a)
Coal-fired steam stations
Montour 1,525
Brunner Island 1,469
Martins Creek 300
Keystone 210 (b)
Conemaugh 194 (c)
-----
Total coal-fired 3,698
-----
Gas and oil-fired steam station
Martins Creek 1,640
Combustion turbines and diesels 438
Hydroelectric 146
-----
Total generating capacity 7,917
-----
Firm purchases
Hydroelectric 139 (d)
Qualifying facilities 338
-----
Total firm purchases 477
-----
Total system capacity - PPL Electric Utilities 8,394
-----
PPL Montana (Montana)
-----------
Coal-fired thermal stations
Colstrip Units 1 & 2 308 (e)
Colstrip Unit 3 222 (f)
Coal-fired steam station
Corette 154
-----
Total coal-fired 684
-----
Hydroelectric 474
-----
Total system capacity - PPL Montana 1,158 (g)
-----
PPL Global (through subsidiaries)(Maine)
----------
Oil-fired generating station
Wyman Unit 4 52 (h)
Hydroelectric (Penobscot Hydro
and West Enfield) 41 (i)
-----
Total system capacity - PPL Global 93
-----
Total system capacity - PPL 9,645
=====
</TABLE>
________________________
(a) PPL Electric Utilities' 90% undivided interest.
(b) PPL Electric Utilities' 12.34% undivided interest.
(c) PPL Electric Utilities' 11.39% undivided interest.
(d) From Safe Harbor Water Power Corporation.
(e) PPL Montana's 50% undivided interest acquired December 1999.
(f) PPL Montana's 30% undivided interest acquired December 1999.
(g) Represents PPL Montana's net capacity. Gross capacity equals 1,315 mWh.
(h) PPL Global's 8.33% undivided interest acquired May 1999.
(i) Includes PPL Global's 50% interest in the West Enfield Station.
<PAGE>
The capacity of generating units is based upon a number of factors,
including the operating experience and physical condition of the units, and may
be revised from time to time to reflect changed circumstances.
The system capacity shown in the preceding tabulation does not reflect two-
party sales and purchases, contractual bulk power sales to JCP&L and BG&E (as
described in Note 7 to Financial Statements), or installed capacity credit sales
and purchases with other utilities. The net effect of these transactions is to
reduce PPL Electric Utilities' system capacity by 558,000 kilowatts at the end
of December 1999, to 7,836,000 kilowatts. The net effect of Penobscot Hydro's
committed sales to Bangor Hydro is to reduce PPL Global's system capacity by
41,000 kilowatts, to 52,000 kilowatts. The West Enfield facility's output will
be sold to Bangor Hydro through the year 2024. The output from Penobscot
Hydro's other hydroelectric stations will be sold to Bangor Hydro through March
2000. It has not yet been determined whether Bangor Hydro will purchase the
output after this date.
PPL Montana has two transition agreements to supply wholesale electricity
to the Montana Power Company. One agreement provides for the sale of 200,000
kilowatts from PPL Montana's interest in Colstrip Unit 3 for two years. The
other agreement covers Montana Power's remaining native load commitments and
lasts until the remaining load is zero, but in no event later than June 2002.
During 1999, PPL Electric Utilities generated about 39.5 billion kWh in
plants it owned, with 57% of the energy generated by coal-fired stations, 38%
from nuclear operations at the Susquehanna station, 4% from the Martins Creek
gas and oil-fired station and 1% from hydroelectric stations. PPL Electric
Utilities also purchased 26.9 billion kWh and had 29.6 billion kWh in non-system
energy sales.
For the six months ended December 1999, PPL Global (through subsidiaries)
generated about 215 million kWh. Of this total, about 126 million kWh was from
hydroelectric generation, with the balance from PPL Global's interest in the
oil-fired Wyman Unit 4.
The maximum one-hour demand recorded on PPL Electric Utilities' system was
6,939,000 kilowatts, which occurred on January 17, 2000. The maximum recorded
one-hour summer demand was 6,387,000 kilowatts, which occurred on July 19, 1999.
These peak demands do not include energy sold to BG&E or JCP&L.
PPL Electric Utilities purchases energy from and sells energy to other
utilities and FERC-certified power marketers at market-based rates under power
purchase and sales agreements. PPL Electric Utilities enters into these
transactions on an hourly, daily, weekly, monthly or longer-term basis.
<PAGE>
PPL Electric Utilities has FERC authorization to sell electric energy,
capacity and ancillary services at market-based rates to wholesale customers
located both inside and outside the PJM control area. As of the end of 1999,
one hundred utilities and power marketers had signed service and power sales
agreements under this tariff. Transactions under these agreements allow PPL
Electric Utilities to make more efficient use of its generating resources and
are intended to provide benefits to both PPL Electric Utilities and the other
parties. Under the market-based tariff, PPL Electric Utilities may also sell
power purchased from third parties.
PPL Electric Utilities also has a FERC short-term capacity and/or energy
sales tariff enabling PPL Electric Utilities to sell to other utilities and
marketers at cost-based rates. Seventy parties have signed service agreements
under this tariff.
PPL Electric Utilities has an export license to sell capacity and/or energy
to electric utilities in Canada. This export license allows PPL Electric
Utilities to sell either its own capacity and energy not required to serve
domestic obligations or power purchased from other utilities.
In addition to the 338,000 kilowatts of qualifying facility generation
included in the total system capacity table above, PPL Electric Utilities is
purchasing about 57,600 kilowatts of output from various other non-utility
generating companies.
In an effort to reduce operating costs and position itself for the
competitive marketplace, PPL Electric Utilities closed its Holtwood coal-fired
generating station in April 1999. The adjacent hydroelectric plant continues to
operate. In addition, PPL Electric Utilities sold its Sunbury coal-fired
generating station in November 1999.
See "Proposed Corporate Realignment" in the Review of Financial Condition
and Results of Operations concerning PPL Electric Utilities' proposal to
transfer all of its generating assets to affiliates.
FUEL SUPPLY
Coal - PPL Electric Utilities
-----------------------------
During 1999, about 65% of the coal delivered to PPL Electric Utilities'
generating stations was purchased under long-term contracts and 35% was obtained
through open market purchases. These contracts provided PPL Electric Utilities
with about 4.6 million tons of coal in 1999 and are expected to provide about
4.1 million tons in 2000. PPL Electric Utilities' requirements for additional
coal are expected to be obtained by contracts and open market purchases.
<PAGE>
The amount of coal carried in inventory at PPL Electric Utilities'
generating stations varies from time to time depending on market conditions and
plant operations. At December 31, 1999, PPL Electric Utilities' coal supply was
sufficient for at least 39 days of operations.
The coal burned in PPL Electric Utilities' generating stations contains
both organic and pyritic sulfur. Mechanical cleaning processes are utilized to
reduce the pyritic sulfur content of the coal. The reduction of the pyritic
sulfur content by either mechanical cleaning or blending has lowered the total
sulfur content of the coal burned to levels which permit compliance with current
sulfur dioxide emission regulations established by the DEP.
PPL Electric Utilities owns a 12.34% undivided interest in the Keystone
station and an 11.39% undivided interest in the Conemaugh station, both of which
are generating stations located in western Pennsylvania. The owners of the
Keystone station have a long-term contract with a coal supplier that provided at
least two-thirds of that station's requirements through 1999 and declining
amounts thereafter until the contract expires at the end of 2004. The balance
of the Keystone station requirements are purchased in the open market. The coal
supply requirements for the Conemaugh station are being met from several sources
through a blend of long-term and short-term contracts and spot market purchases.
Coal - PPL Montana
- ------------------
PPL Montana has a 50% interest in Colstrip Units 1 & 2 and a 30% ownership
interest in Colstrip Unit 3. The owners of the units have a contract to purchase
sub-bituminous coal with defined quality characteristics and specifications.
The contract for units 1 & 2 is in effect through December 31, 2009. The
contract for unit 3 is in effect through December 31, 2019.
PPL Montana also owns the JE Corette Steam Generation Plant. The plant has
a one-year contract to purchase low sulfur coal with defined quality
characteristics and specifications.
Oil and Natural Gas
- -------------------
PPL Electric Utilities' Martins Creek generating station units 3 and 4 burn
both oil and natural gas. During 1999, 100% of the oil requirements for the
Martins Creek units was purchased on the spot market. At December 31, 1999, PPL
Electric Utilities had no long-term agreements for these requirements.
During 1999, all of the natural gas consumed at Martins Creek was purchased
under short-term agreements. PPL Electric Utilities has no long-term agreements
to purchase gas.
<PAGE>
PPL Electric Utilities' oil and natural gas purchasing and sales functions
are now performed by the Energy Marketing Center. The addition of oil and gas
to the Energy Marketing Center's electricity marketing is intended to enhance
wholesale and retail marketing opportunities and to provide a diversified energy
portfolio to customers. Additionally, the new marketing and supply activities
help PPL Electric Utilities to optimize electric generation efficiency and
minimize fuel costs.
Nuclear
-------
PPL Electric Utilities has executed uranium supply and conversion
agreements that satisfy 65% of the uranium requirements for the Susquehanna
units in 2000, approximately 35% of the requirements for the period 2001-2002
and, including options, an additional 25% of the requirements for the period
2002-2005. Deliveries under these agreements are expected to provide sufficient
uranium to permit Unit 1 to operate into the first quarter of 2002 and Unit 2 to
operate into the first quarter of 2001.
PPL Electric Utilities has executed an agreement that satisfies all of its
enrichment requirements through 2004. Assuming that the other uranium
components of the nuclear fuel cycle are satisfied, deliveries under this
agreement are expected to provide sufficient enrichment to permit Unit 1 to
operate into the first quarter of 2006 and Unit 2 to operate into the first
quarter of 2007.
PPL Electric Utilities has entered into an agreement that, including
options, satisfies all of its fabrication requirements through 2006. Assuming
that the uranium and other components of the nuclear fuel cycle are satisfied,
deliveries under this agreement are expected to provide sufficient fabrication
to permit Unit 1 to operate into the first quarter of 2008 and Unit 2 to operate
into the first quarter of 2007.
Federal law requires the federal government to provide for the permanent
disposal of commercial spent nuclear fuel. Under the Nuclear Waste Policy Act
the DOE initiated an analysis of a site in Nevada for a permanent nuclear waste
repository. Progress on a proposed disposal facility has been slow, and the
repository is not expected to be operational before 2010. Thus, expansion of
Susquehanna's on-site spent fuel storage capacity was necessary. To support this
expansion, PPL Electric Utilities contracted for the design and construction of
a spent fuel storage facility employing dry cask fuel storage technology. The
facility is modular, so that additional storage capacity can be added as needed.
The new facility began receiving spent nuclear fuel in October 1999. PPL
Electric Utilities estimates that there is sufficient storage capacity in the
spent nuclear fuel pools and the on-site dry spent fuel storage facility at
Susquehanna to accommodate discharged fuel through the life of the plant, if
necessary.
<PAGE>
Federal law also provides that generators of spent fuel are responsible for
certain costs of disposal. In January 1997, PPL Electric Utilities joined over
30 other utilities in a lawsuit in the U.S. Court of Appeals for the District of
Columbia Circuit seeking assurance of the DOE's performance of its contractual
obligation to accept spent nuclear fuel and suspension of payment to that agency
pending such performance. In November 1997, the Court denied the utilities'
requested relief and held that the contracts between the utilities and the DOE
provide a potentially adequate remedy if the DOE failed to begin disposal of
spent nuclear fuel by January 31, 1998. However, the Court also precluded the
DOE from arguing that its delay in contract performance was "unavoidable".
The U.S. Congress is currently considering amendments to the Nuclear Waste
Policy Act to address certain of the issues which have arisen between the DOE
and the nuclear power industry regarding disposal of spent nuclear fuel as well
as the ongoing litigation against DOE. PPL Electric Utilities is unable to
predict the ultimate outcome of this proposed legislation or litigation.
YEAR 2000
See "Year 2000" in the Review of the Financial Condition and Results of
Operations for information.
ENVIRONMENTAL MATTERS
Certain PPL subsidiaries, including PPL Electric Utilities, are subject to
certain present and developing federal, regional, state and local laws and
regulations with respect to air and water quality, land use and other
environmental matters. See "Financial Condition - Capital Expenditure
Requirements" in the Review of the Financial Condition and Results of Operations
for information concerning environmental expenditures during 1999 and PPL's
estimate of those expenditures during the years 2000-2004. PPL believes that its
subsidiaries are in substantial compliance with applicable environmental laws
and regulations.
See "Environmental Matters" in Note 16 to Financial Statements for
information concerning federal clean air legislation enacted in 1990,
groundwater degradation and waste water control at facilities owned by PPL's
subsidiaries, state solid waste disposal regulations, and PPL Electric
Utilities' and PPL Gas Utilities' agreements with the DEP concerning remediation
at certain sites. Other environmental laws, regulations and developments that
may have a substantial impact on PPL's subsidiaries are discussed below.
<PAGE>
Air
---
The Clean Air Act includes, among other things, provisions that: (a)
require the prevention of significant deterioration of existing air quality in
regions where air quality is better than applicable ambient standards; (b)
restrict the construction of and revise the performance standards for new coal-
fired and oil-fired generating stations; and (c) authorize the EPA to impose
substantial noncompliance penalties of up to $25,000 per day of violation for
each facility found to be in violation of the requirements of an applicable
state implementation plan. The state agencies administer the EPA's air quality
regulations through the state implementation plans and have concurrent authority
to impose penalties for noncompliance.
In December 1997, international negotiators reached agreement in Kyoto,
Japan to strengthen the 1992 United Nations Global Climate Change Treaty by
adding legally-binding greenhouse gas emission limits. This Agreement -
formally called the Kyoto Protocol - if ratified by the U.S. Senate and
implemented, would require the United States to reduce its greenhouse gas
emissions to 7% below 1990 levels by 2008 - 2012. Compliance under the
Agreement, if implemented, could result in increased capital and operating
expenses for PPL Electric Utilities and PPL Montana in amounts which are not now
determinable but which could be significant.
Water
-----
To implement the requirements of the Federal Water Pollution Control Act of
1972, as amended by the Clean Water Act of 1977 and the Water Quality Act of
1987, the EPA has adopted regulations on effluent standards for steam electric
stations. The states administer the EPA's effluent standards through state laws
and regulations relating, among other things, to effluent discharges and water
quality. The standards adopted by the EPA pursuant to the Clean Water Act may
have a significant impact on existing facilities of certain PPL subsidiaries,
including PPL Electric Utilities, depending on the states' interpretation and
future amendments to regulations.
Pursuant to the Surface Mining and Reclamation Act of 1977, the OSM has
adopted effluent guidelines which are applicable to PPL subsidiaries as a result
of their past coal mining and coal processing activities. The EPA and the OSM
limitations, guidelines and standards also are enforced through the issuance of
NPDES permits. In accordance with the provisions of the Clean Water Act and the
Reclamation Act of 1977, the EPA and the OSM have authorized the states to
implement the NPDES program. Compliance with applicable water quality standards
is assured by state review of NPDES permit conditions.
<PAGE>
Solid and Hazardous Waste
-------------------------
The provisions of Superfund authorize the EPA to require past and present
owners of contaminated sites and generators of any hazardous substance found at
a site to clean-up the site or pay the EPA or the state for the costs of clean-
up. The generators and past owners can be liable even if the generator
contributed only a minute portion of the hazardous substances at the site.
Present owners can be liable even if they contributed no hazardous substances to
the site.
State laws such as the Pennsylvania Superfund law also give state agencies
broad authority to identify hazardous or contaminated sites and to order owners
or responsible parties to clean-up the sites. If responsible parties cannot or
will not perform the clean-up, the agency can hire contractors to clean-up the
sites and then require reimbursement from the responsible parties after the
clean-up is completed.
Certain federal and state statutes, including Superfund and the
Pennsylvania Hazardous Sites Cleanup Act, empower certain governmental agencies,
such as the EPA and the DEP, to seek compensation from the responsible parties
for the lost value of damaged natural resources. The EPA and the DEP may file
such compensation claims against the parties held responsible for cleanup of
such sites. Such natural resource damage claims could result in material
additional liabilities for PPL subsidiaries.
Low-Level Radioactive Waste
---------------------------
Under federal law, each state is responsible for the disposal of low-level
radioactive waste generated in that state. States may join in regional compacts
to jointly fulfill their responsibilities. The states of Pennsylvania,
Maryland, Delaware and West Virginia are members of the Appalachian States Low-
Level Radioactive Waste Compact. Efforts to develop a regional disposal
facility in Pennsylvania were suspended by the DEP in 1998. The Commonwealth
retains the legal authority to resume the siting process should it be necessary.
Low-level radioactive waste resulting from the operation of Susquehanna are
currently being sent to Barnwell, South Carolina for disposal. In the event
that this disposal option becomes unavailable or no longer cost-effective, the
low-level radioactive waste will be stored on-site at Susquehanna. PPL Electric
Utilities cannot predict the future availability of low-level waste disposal
facilities or the cost of such disposal.
General
-------
Concerns have been expressed by some members of the scientific community
and others regarding the potential health effects of EMFs. These fields are
emitted by all devices carrying electricity, including electric transmission and
distribution lines and substation equipment. Federal, state and
<PAGE>
local officials have focused attention on this issue. PPL Electric Utilities
supports the current efforts to determine whether EMFs cause any human health
problems and is taking low cost or no cost steps to reduce EMFs, where
practical, in the design of new transmission and distribution facilities. PPL
Electric Utilities is unable to predict what effect, if any, the EMF issue might
have on PPL Electric Utilities' operations and facilities and the associated
cost, or what, if any, liabilities PPL Electric Utilities might incur related to
the EMF issue.
PPL and its subsidiaries are unable to predict the ultimate effect of
evolving environmental laws and regulations upon its existing and proposed
facilities and operations. In complying with statutes, regulations and actions
by regulatory bodies involving environmental matters, including the areas of
water and air quality, hazardous and solid waste handling and disposal and toxic
substances, PPL may be required to modify, replace or cease operating certain of
its facilities. PPL may also incur significant capital expenditures and
operating expenses in amounts which are not now determinable.
FRANCHISES AND LICENSES
PPL Electric Utilities is authorized to provide electric public utility
service throughout its service area as a result of grants by the Commonwealth of
Pennsylvania in corporate charters to PPL Electric Utilities and companies to
which it has succeeded and as a result of certification by the PUC. PPL Electric
Utilities is granted the right to enter the streets and highways by the
Commonwealth subject to certain conditions. In general, such conditions have
been met by ordinance, resolution, permit, acquiescence or other action by an
appropriate local political subdivision or agency of the Commonwealth. PPL
Electric Utilities also has an export license from the DOE to sell capacity
and/or energy to electric utilities in Canada.
PPL Electric Utilities operates Susquehanna Unit 1 and Unit 2 pursuant to
NRC operating licenses, which expire in 2022 and 2024, respectively. It operates
two hydroelectric projects pursuant to licenses renewed by the FERC in 1980:
Wallenpaupack (44,000 kilowatts capacity) and Holtwood (102,000 kilowatts
capacity). The Wallenpaupack license expires in 2004 and the Holtwood license
expires in 2014. As part of the regulatory applications in the pending corporate
realignment, PPL Electric Utilities has proposed to transfer these licenses to
the respective affiliated generating companies.
PPL Electric Utilities owns one-third of the capital stock of Safe Harbor
Water Power Corporation (Safe Harbor), which holds a project license which
extends the operation of its hydroelectric plant until 2030. The total capacity
of the Safe Harbor plant is 417,500 kilowatts, and PPL Electric Utilities is
entitled by contract to one-third of the total capacity (139,000
<PAGE>
kilowatts). As part of the regulatory applications in the pending corporate
realignment, PPL Electric Utilities has proposed that its interest in Safe
Harbor be transferred to a new generating company affiliate.
The eleven hydroelectric facilities and one storage reservoir recently
purchased from the Montana Power Company are licensed by FERC under licenses
which expire on varying dates through 2035. Prior to the December 1999
acquisition, the Montana Power Company had been in the process of the normal
relicensing nine of the hydroelectric facilities and the storage reservoir,
collectively known as Project 2188. A final FERC license order on Project 2188
is expected in the first quarter of 2000. The licenses for the other two
hydroelectric facilities expire in 2009 and 2025.
EMPLOYEE RELATIONS
As of December 31, 1999, PPL and its subsidiaries had 9,166 employees,
including 6,314 full-time PPL Electric Utilities employees and 470 full-time PPL
Montana employees. Approximately 62 percent of PPL Electric Utilities' full-
time employees are represented by the IBEW. Approximately 68 percent of PPL
Montana employees are represented by the IBEW. PPL Electric Utilities reached a
new labor agreement with the IBEW in 1998. This agreement expires in May 2002.
PPL Montana's contract with the IBEW expires in 2001.
<PAGE>
ITEM 2. PROPERTIES
------------------
Refer to the "Utility Plant" section of Note 1 to Financial Statements and
"Power Plant Operations" in the Review of the Financial Condition and Results of
Operations for information concerning investments in property, plant and
equipment. Substantially all of PPL Electric Utilities' electric utility plant
is subject to the lien of PPL Electric Utilities' Mortgage. PPL Electric
Utilities' generating facilities to be transferred to affiliates in the pending
corporate realignment will be released from this Mortgage. In addition, PPL
Electric Utilities has electric transmission and distribution lines in public
streets and highways pursuant to franchises and on rights-of-way secured from
property owners. For a description of PPL Electric Utilities' service territory
and properties, see Item 1, "BUSINESS - Background," "BUSINESS - Power Supply"
and "BUSINESS - Fuel Supply." See these same sections for discussions of PPL
Global's investments and the property of PPL Montana.
ITEM 3. LEGAL PROCEEDINGS
-------------------------
See Item 1 "BUSINESS - Fuel Supply" for information concerning a lawsuit
against the DOE for failure of that agency to perform certain contractual
obligations.
See "Proposed Corporate Realignment" in Review of Financial Condition and
Results of Operation for information on pending regulatory proceedings related
to the proposed corporate realignment.
Pursuant to changes in the Pennsylvania Public Utility Realty Tax Act
("PURTA") enacted in 1999, PPL Electric Utilities has filed a number of tax
assessment appeals in various counties throughout its service territory. These
appeals challenge existing local tax assessments, which now furnish the basis
for payment of the PURTA tax on PPL Electric Utilities properties. Also, as of
January 1, 2000, generation facilities are no longer taxed under PURTA, and
these local assessments will be used directly to determine local real estate tax
liability for PPL Electric Utilities' power plants. PPL Electric Utilities has
filed retroactive appeals for tax years 1998 and 1999, as permitted by the new
law, as well as prospective appeals for 2000, as permitted under normal
assessment procedures.
Hearings on the appeals were held by the boards of assessment appeals in
each county, and decisions have now been rendered by most counties. To the
extent the appeals were denied or PPL Electric Utilities was not otherwise
satisfied with the results, PPL Electric Utilities has filed further appeals
from the board decisions with the appropriate county Courts of Common Pleas.
<PAGE>
Of all the pending proceedings, the most significant appeal concerns the
assessed value of the Susquehanna nuclear station. The current county
assessment of the Susquehanna station indicates a market value of $3.9 billion.
However, based on Pennsylvania assessment law, PPL Electric Utilities contends
that machinery and equipment used at the Susquehanna station are not part of the
real estate subject to taxation. PPL Electric Utilities has estimated that the
market value should be approximately $60 million.
PPL Electric Utilities' appeal of the Susquehanna station assessment is
currently pending in the Luzerne County Court of Common Pleas, and a trial date
has been set for August 2000. As a result of these proceedings and potential
appeals, a final determination of market value and the associated tax liability
may not occur for several years.
Based on the county market valuation of $3.9 billion, the Berwick Area
School District (where the Susquehanna station is located) has issued a tax bill
to PPL Electric Utilities for just under $25 million for the first six months of
2000. Within the next two months, PPL Electric Utilities expects to receive a
joint tax bill from the county and municipality for another $20 million, which
will cover the entire year. On the basis of PPL Electric Utilities' estimated
valuation, the School District would be entitled to receive about $770,000 in
local taxes annually ($385,000 for the first six months of 2000), and the county
and township combined would receive about $350,000 annually.
In the other assessment appeals pending in county courts, the local
authorities have assessed PPL Electric Utilities' generating plants at an
aggregate amount of about $330 million for tax year 2000, for a total tax
liability of about $6.8 million. PPL Electric Utilities has estimated the
aggregate market value of these plants at about $26 million for tax year 2000,
for a total tax liability of about $454,000. As at the Susquehanna station, the
school districts involved in these proceedings have issued interim tax bills at
levels which are disputed by PPL Electric Utilities. Final determinations of
market value and associated tax liability may not occur for several years.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
-----------------------------------------------------------
There were no matters submitted to a vote of security holders, through the
solicitation of proxies or otherwise, during the fourth quarter of 1999.
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANTS
-------------------------------------
Officers of PPL and PPL Electric Utilities are elected annually by their
Boards of Directors to serve at the pleasure of the respective Boards. There
are no family relationships among any of the executive officers, or any
arrangement or understanding between any executive officer and any other person
pursuant to which the officer was selected.
There have been no events under any bankruptcy act, no criminal proceedings
and no judgments or injunctions material to the evaluation of the ability and
integrity of any executive officer during the past five years.
Listed below are the executive officers as of December 31, 1999:
PPL Corporation:
Effective Date of
Election to
Name Age Position Present Position
---- --- -------- ----------------
William F. Hecht 56 Chairman, President and
Chief Executive Officer February 24, 1995
Frank A. Long 59 Executive Vice President February 24, 1995
Robert G. Byram* 54 Senior Vice President
and Chief Nuclear
Officer-PPL Electric
Utilities April 1, 1997
John R. Biggar 55 Senior Vice President
and Chief Financial
Officer November 1, 1998
Paul T. Champagne* 41 President-PPL Global, Inc. May 24, 1999
Robert J. Grey 49 Senior Vice President,
General Counsel and
Secretary March 1, 1996
Terry H. Hunt 51 Senior Vice President-
Strategic Planning October 1, 1998
Joseph J. McCabe 49 Vice President and
Controller August 1, 1995
James E. Abel 48 Vice President-Finance
and Treasurer June 1, 1999
* Mr. Byram and Mr. Champagne have been designated executive officers of PPL
by virtue of their respective positions at PPL subsidiaries.
<PAGE>
PPL Electric Utilities Corporation:
Effective Date of
Election to
Name Age Position Present Position
---- --- -------- ----------------
William F. Hecht 56 Chairman, President and
Chief Executive Officer January 1, 1993
Frank A. Long 59 Executive Vice President
and Chief Operating
Officer January 1, 1993
Robert G. Byram 54 Senior Vice President
and Chief Nuclear
Officer April 1, 1997
John R. Biggar 55 Senior Vice President
and Chief Financial
Officer November 1, 1998
Robert J. Grey 49 Senior Vice President,
General Counsel and
Secretary March 1, 1996
Terry H. Hunt 51 Senior Vice President-
Strategic Planning October 1, 1998
Joseph J. McCabe 49 Vice President and
Controller August 1, 1995
James E. Abel 48 Vice President-Finance
and Treasurer June 1, 1999
Each of the above officers, with the exception of Messrs. Champagne, Grey,
and Hunt, has been employed by PPL Electric Utilities for more than five years
as of December 31, 1999. Mr. Champagne joined PPL Global in January 1995. Prior
to that time, he was Regional Manager - Business Development - Midwest at
Mission Energy Company. Mr. Grey joined PPL Electric Utilities in March 1995. He
had been General Counsel of Long Island Lighting Company since 1992. Mr. Hunt
joined PPL Electric Utilities in October 1998. He had been President and CEO of
PPL Gas Utilities.
Prior to their election to the positions shown above, the following
executive officers held other positions within PPL Electric Utilities since
January 1, 1995: Mr. Byram was Senior Vice President - Nuclear and Senior Vice
President - Generation and Chief Nuclear Officer; Mr. Biggar was Vice President-
Finance, Vice President - Finance and Treasurer and Senior Vice President-
Financial; Mr. Grey was Vice President, General Counsel and Secretary; Mr.
McCabe was Controller; and Mr. Abel was Manager - Treasury, Manager - Auditing,
and Treasurer.
<PAGE>
PART II
-------
ITEM 5. MARKET FOR THE REGISTRANT'S
COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
-------------------
Additional information for this item is set forth in the sections entitled
"Quarterly Financial, Common Stock Price and Dividend Data" and "Shareowner and
Investor Information" of this report. The number of common shareowners is set
forth in the section entitled "Selected Financial and Operating Data" in Item 6.
<PAGE>
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
<TABLE>
<CAPTION>
1999 (a) 1998 (a) 1997 (a) 1996 1995 (a)
PPL Corporation
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Income Items -- millions
Operating revenues..................................... $ 4,590 $ 3,786 $ 3,077 $ 2,926 $ 2,752
Operating income (f)................................... 872 827 800 810 836
Net Income (Loss)...................................... 432 (569) 296 329 323
Balance Sheet Items -- millions (b)
Property, plant and equipment, net..................... 5,644 4,480 6,820 6,960 6,970
Recoverable transition costs........................... 2,647 2,819
Total assets........................................... 11,174 9,607 9,485 9,670 9,492
Long-term debt......................................... 4,157 2,984 2,735 2,832 2,859
Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts
holding solely company debentures.................... 250 250 250
Preferred stock
With sinking fund requirements....................... 47 47 47 295 295
Without sinking fund requirements.................... 50 50 50 171 171
Common equity.......................................... 1,613 1,790 2,809 2,745 2,597
Short-term debt........................................ 857 636 135 144 89
Total capital provided by investors.................... 6,974 5,757 6,026 6,187 6,011
Capital lease obligations.............................. 125 168 171 247 220
Financial Ratios
Return on average common equity -- % (e)............... 16.89 10.98 11.69 12.30 11.23
Embedded cost rates (b)
Long-term debt -- %.................................. 6.95 7.40 7.88 7.89 7.95
Preferred stock -- %................................. 5.87 5.87 5.85 6.09 6.09
Preferred securities -- %............................ 8.43 8.43 8.43
Times interest earned before income taxes (e).......... 3.04 3.28 3.59 3.55 3.17
Ratio of earnings to fixed charges -- total
enterprise basis (c), (e)............................ 2.86 3.10 3.40 3.45 3.08
Ratio of earnings to fixed charges and
dividends on preferred stock
--total enterprise basis (c), (e)................... 2.61 2.78 3.02 2.90 2.51
Common Stock Data
Number of shares outstanding -- thousands
Year-end............................................. 143,697 157,412 166,248 162,665 159,403
Average.............................................. 152,287 164,651 164,550 161,060 157,649
Number of record shareowners (b)....................... 91,553 100,458 117,293 123,290 128,075
Earnings (loss) per share - reported................... $ 2.84 ($3.46) $ 1.80 $ 2.05 $ 2.05
Earnings per share excluding one-time
adjustments (e)...................................... $ 2.35 $ 1.87 $ 2.00 $ 2.05 $ 1.79
Dividends declared per share........................... $ 1.00 $ 1.335 $ 1.67 $ 1.67 $ 1.67
Book value per share (b)............................... $ 11.23 $ 11.37 $ 16.90 $ 16.87 $ 16.29
Market price per share (b)............................. $ 22.875 $ 27.875 $ 23.938 $ 23 $ 25
Dividend payout rate -- % (e).......................... 43 71 84 81 93
Dividend yield -- % (d)................................ 4.37 4.79 6.98 7.26 6.68
Price earnings ratio (e)............................... 9.73 14.91 11.97 11.22 13.97
</TABLE>
(a) The earnings for each year, except for 1996, were affected by one-time
adjustments. These adjustments affected net income and certain items under
Financial Ratios and Common Stock Data.
See "Earnings" in Review of Financial Condition and Results of Operations
for a description of one-time adjustments in 1999, 1998 and 1997.
(b) At year-end.
(c) Computed using earnings and fixed charges of PPL and its subsidiaries.
Fixed charges consist of interest on short- and long-term debt, other
interest charges, interest on capital lease obligations and the estimated
interest component of other rentals.
(d) Based on year-end market prices.
(e) Based on earnings excluding one-time adjustments.
(f) Operating income of 1997 and earlier years restated to conform to the
current presentation.
<PAGE>
SELECTED FINANCIAL AND OPERATING DATA
<TABLE>
<CAPTION>
1999 (a) 1998 (a) 1997 (a) 1996 1995 (a)
PPL Electric Utilities Corporation
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Income Items -- millions
Operating revenues..................................... $ 3,952 $ 3,643 $ 3,049 $ 2,911 $ 2,752
Operating income (e)................................... 749 801 790 809 836
Earnings (loss) available to PPL....................... 398 (587) 308 329 324
Balance Sheet Items -- millions (b)
Property, plant and equipment, net..................... 4,345 4,331 6,820 6,960 6,970
Recoverable transition costs........................... 2,647 2,819
Total assets........................................... 9,092 8,838 9,472 9,405 9,424
Long-term debt......................................... 3,505 2,569 2,633 2,832 2,859
Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts holding
solely company debentures............................ 250 250 250
Preferred stock
With sinking fund requirements....................... 47 295 295 295 295
Without sinking fund requirements.................... 50 171 171 171 171
Common equity.......................................... 1,296 1,730 2,612 2,617 2,528
Short-term debt........................................ 183 91 45 10 89
Total capital provided by investors.................... 5,331 5,106 6,006 5,925 5,942
Capital lease obligations.............................. 125 168 171 247 220
Financial Ratios
Return on average common equity -- % (d)............... 17.90 11.45 11.91 12.95 11.65
Embedded cost rates (b)
Long-term debt -- %.................................. 6.97 7.56 7.91 7.89 7.95
Preferred stock -- %................................. 5.87 6.09 6.90 6.09 6.09
Preferred securities -- %............................ 8.43 8.43 8.43
Times interest earned before income taxes (d).......... 3.44 3.77 3.67 3.62 3.41
Ratio of earnings to fixed charges -- total
enterprise basis (c), (d)............................ 3.09 3.52 3.47 3.50 3.09
Ratio of earnings to fixed charges and
dividends on preferred stock
--total enterprise basis (c), (d)................... 2.62 2.77 2.77 2.93 2.52
Sales Data
Customers (thousands)(b)............................... 1,270 1,257 1,247 1,236 1,226
Electric energy sales delivered -- millions of kWh
Residential.......................................... 11,704 11,156 11,434 11,849 11,300
Commercial........................................... 11,002 10,597 10,309 10,288 9,948
Industrial........................................... 10,179 10,227 10,078 10,016 9,845
Other................................................ 160 164 143 154 188
-------- -------- -------- -------- --------
Service area sales ................................ 33,045 32,144 31,964 32,307 31,281
Wholesale energy sales ............................ 31,683 36,706 21,454 14,341 11,424
-------- -------- -------- -------- --------
Total electric energy sales delivered.............. 64,728 68,850 53,418 46,648 42,705
-------- -------- -------- -------- --------
Number of Full-Time Employees (b)........................ 6,314 6,344 6,343 6,428 6,661
</TABLE>
(a) The earnings for each year, except for 1996, were affected by one-time
adjustments.
These adjustments affected earnings available to PPL and certain items in
Financial Ratios.
See "Earnings" in Review of Financial Condition and Results of Operations
for a description of one-time adjustments in 1999, 1998 and 1997.
(b) At year-end.
(c) Computed using earnings and fixed charges of PPL Electric Utilities and its
subsidiaries. Fixed charges consist of interest on short- and long-term
debt, other interest charges, interest on capital lease obligations and the
estimated interest component of other rentals.
(d) Based on earnings excluding one-time adjustments.
(e) Operating income of 1997 and earlier years restated to conform to the
current presentation.
<PAGE>
ITEM 7. REVIEW OF THE FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF PPL
CORPORATION AND PPL ELECTRIC UTILITIES CORPORATION
PPL is a holding company with headquarters in Allentown, PA. See Item 1
"BUSINESS - Background" for descriptions of PPL's major subsidiaries. Other
subsidiaries may be formed by PPL to take advantage of new business
opportunities.
The financial condition and results of operations of PPL Electric Utilities
and PPL Global are currently the principal factors affecting the financial
condition and results of operations of PPL. All fluctuations, unless
specifically noted, are primarily due to activities of PPL Electric Utilities
and PPL Global.
Terms and abbreviations appearing in the Review of the Financial Condition
and Results of Operations are explained in the glossary.
Forward-looking Information
Certain statements contained in this Form 10-K concerning expectations,
beliefs, plans, objectives, goals, strategies, future events or performance and
underlying assumptions and other statements which are other than statements of
historical facts are "forward-looking statements" within the meaning of the
federal securities laws. Although PPL and PPL Electric Utilities believe that
the expectations and assumptions reflected in these statements are reasonable,
there can be no assurance that these expectations will prove to have been
correct. These forward-looking statements involve a number of risks and
uncertainties, and actual results may differ materially from the results
discussed in the forward-looking statements. In addition to the specific
factors discussed in this Review of Financial Condition and Results of
Operations, the following are among the important factors that could cause
actual results to differ materially from the forward-looking statements: state
and federal regulatory developments; new state or federal legislation; national
or regional economic conditions; market demand and prices for energy, capacity
and fuel; weather variations affecting customer energy usage; competition in
retail and wholesale power markets; the effect of any business or industry
restructuring; PPL's and PPL Electric Utilities' profitability and liquidity;
new accounting requirements or new interpretations or applications of existing
requirements; operating performance of plants and other facilities;
environmental conditions and requirements; system conditions and operating
costs; performance of new ventures; political, regulatory or economic conditions
in foreign countries where PPL Global makes investments; foreign exchange rates;
and PPL's and PPL Electric Utilities' commitments and liabilities. Any such
forward-looking statements should be considered in light of such important
factors and in conjunction with PPL's and PPL Electric Utilities' other
documents on file with the SEC.
New factors that could cause actual results to differ materially from those
described in forward-looking statements emerge from time to time, and it is not
possible for PPL or PPL Electric Utilities to predict all of such factors, or
the extent to which any such factor or combination of factors may cause actual
results to differ from those
<PAGE>
contained in any forward-looking statement. Any forward-looking statement speaks
only as of the date on which such statement is made, and neither PPL nor PPL
Electric Utilities undertakes any obligation to update the information contained
in such statement to reflect subsequent developments or information.
Results of Operations
---------------------
Earnings
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Earnings per share - excluding
one-time adjustments $2.35 $1.87 $2.00
One-time adjustments:
Sale of Sunbury plant and related
assets (Note 12) .28
Sale of SWEB supply business (Note 12) .42
Securitization (Note 5) .13
Write-down carrying value of
investments (Note 12) (.34)
PUC restructuring charge (Note 6) (5.56)
FERC municipalities settlement
(Note 6) (0.19)
Windfall profits tax (.23)
SER settlement .11
U.K. tax rate reduction .06 .06
PPL Gas Utilities acquisition costs .03 (.03)
Other impacts of restructuring .22
----- ------ -----
Earnings (loss) per share - actual $2.84 $(3.46) $1.80
===== ====== =====
</TABLE>
The earnings of PPL for 1999, 1998 and 1997 were impacted by several one-
time adjustments. Refer to specific Notes to Financial Statements for
discussion of certain of these one-time adjustments. The one-time adjustments
without note references are discussed in "Other Income and (Deductions)." In
addition, the PUC restructuring adjustments provided a favorable impact of about
22 cents per share on earnings in the second half of 1998. These adjustments
included lower depreciation on impaired generation assets, reduced accruals for
taxes other than income and a regulatory adjustment to unbilled revenues. These
favorable impacts were partially offset by the immediate expensing of computer
software costs identified as impaired in restructuring accounting adjustments.
Excluding the effects of these one-time adjustments, 1999 earnings were
$2.35 compared with adjusted earnings of $1.87 for 1998. (In 1999, PPL
discontinued including the impact of weather in calculating adjusted earnings
per share.) The adjusted earnings for 1999 represents a 48 cents per share
improvement, or about 26%, compared with 1998. The earnings improvement was
primarily due to higher margins on wholesale energy and marketing activities, an
increase in electricity supplied to commercial and industrial customers, lower
taxes, lower depreciation on generation assets, and increased earnings from
unregulated operations. The earnings per share for 1999 also reflects the
benefit of fewer common shares outstanding, resulting from stock repurchase
programs. In addition,
<PAGE>
1998 earnings were adversely impacted by the unusually mild winter weather.
These earnings improvements in 1999 were partially offset by a four percent rate
reduction for electric delivery customers in Pennsylvania and by the loss of
customers who shopped for alternate electric generation suppliers. In addition,
1998 earnings benefited from certain regulatory treatments that did not carry
over to 1999.
The adjusted earnings of 1998 were 13 cents per share, or 7%, lower than
the similarly adjusted earnings in 1997. Mild winter weather in 1998 adversely
affected earnings by about 20 cents per share. On a weather-adjusted basis, PPL
Electric Utilities' electric delivery sales were 2.9% higher in 1998 than 1997.
Earnings in 1998 were also favorably impacted by higher wholesale electricity
revenues. These earnings improvements were partially offset by higher operating
expenses in 1998 from 1997. This includes higher costs associated with computer
information systems, and additional payroll, consultant services and other
expenses to meet the requirements of retail competition. Increased firm
transmission costs related to the Energy Marketing Center activities and a
higher provision for uncollectible customer accounts also increased operating
expenses.
Electric Energy Sales
PPL Electric Utilities' electricity sales for 1999, 1998 and 1997 were as
follows:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
(Millions of kWh)
<S> <C> <C> <C>
Electricity delivered to
retail customers by PPL Electric
Utilities (a) 33,045 32,144 31,964
Less: Electricity supplied
by others 9,621 1,999 65
------ ------ ------
Electricity supplied to retail
customers by PPL Electric
Utilities 23,424 30,145 31,899
Electricity supplied to retail
customers by PPL EnergyPlus 10,271 1,506
------ ------ ------
Total electricity supplied
to retail customers (a) 33,695 31,651 31,899
Wholesale electricity sales 31,683 36,708 21,454
</TABLE>
(a) kWh for customers residing in PPL Electric Utilities' service territory who
are receiving energy from PPL Electric Utilities or PPL EnergyPlus will be
reflected in both of these categories.
In 1998, there was a pilot of the Electric Choice Program under the
Customer Choice Act. Beginning on January 1, 1999, customers were allowed to
choose their electricity supplier. Customers making this choice continue to
have their electricity delivered by the utility that serves their territory.
<PAGE>
Electricity delivered to retail customers increased by 901 million kWh, or
2.8%, in 1999 over 1998. This increase was primarily due to the mild winter in
1998. If normal weather had been experienced in both 1999 and 1998, deliveries
would have increased by 0.6%. Industrial sales showed no growth in 1999.
Electricity delivered in 1998 increased by 180 million kWh, or 0.6%, from 1997.
However, if normal weather had been experienced in these years, deliveries would
have increased by 2.9%. This increase reflected strong third and fourth quarter
deliveries to all customer classes.
Electricity supplied to retail customers increased by 2,044 million kWh, or
6.5%, in 1999 as compared to 1998. This increase was due to sales by PPL
EnergyPlus in the competitive market, and the impact of mild winter weather in
1998. The slight decrease in electricity supplied in 1998 compared to 1997 was
due to the impact of weather and the pilot Electric Choice Program.
Wholesale electricity sales, which includes sales to other utilities and
energy marketers through contracts, spot market transactions or power pool
arrangements, decreased by 5,025 million kWh in 1999 when compared to 1998.
This was primarily the result of decreased activity of the Energy Marketing
Center in the electricity wholesale market, because of increased retail market
needs and the decline of contract sales. See the following section for more
information.
Operating Revenues
Electric
- --------
The increase (decrease) in revenues from electric operations was
attributable to the following:
<TABLE>
<CAPTION>
1999 vs. 1998 1998 vs. 1997
------------- -------------
(Millions of Dollars)
<S> <C> <C>
Retail Electric Revenue
PPL Electric Utilities - electric
delivery and PLR load $(338) $ 7
PPL EnergyPlus - electric
generation supply 415
PPL Global - Emel/EC - electric
delivery 245
Other 26 6
----- -----
$ 348 $ 13
===== =====
</TABLE>
Operating revenues from retail electric operations increased by $348
million in 1999 over 1998. PPL Electric Utilities and PPL EnergyPlus revenues
increased by $77 million, or 3.3%, for the same period. This increase, in part,
reflects the unfavorable impact of mild winter weather on 1998 sales. Also, PPL
Electric Utilities and PPL EnergyPlus provided 6.5% more electricity to retail
customers during 1999 as compared with 1998. These revenue gains were partially
offset by a one-year 4% reduction in PPL Electric Utilities' regulated rates,
effective January 1, 1999, in connection with the PUC Final Order in PPL
Electric Utilities' restructuring proceeding.
<PAGE>
PPL Global consolidated the financial results of Emel and EC in the third
quarter of 1999, effective from January 1, 1999. Accordingly, "Electric
Operating Revenues" includes Emel and EC revenues from delivering electricity to
their customers in Central America. See Note 1 to Financial Statements for
additional information.
Operating revenues for electric operations increased by $13 million in 1998
from 1997. PPL Electric Utilities' electricity deliveries increased by 2.9%,
contributing to this revenue increase. Also, PPL Electric Utilities' revenues
increased due to a change in the regulatory treatment of energy costs. These
revenue gains were substantially offset by mild winter weather in 1998.
Gas and Propane
- ---------------
PPL acquired PPL Gas Utilities in August 1998. The results of PPL Gas
Utilities, including revenues and the associated costs from gas and propane
operations, have been recorded subsequent to acquisition.
Wholesale Energy Marketing and Trading
- --------------------------------------
The increase (decrease) in revenues from wholesale energy marketing and
trading activities was attributable to the following:
<TABLE>
<CAPTION>
1999 vs. 1998 1998 vs. 1997
------------- -------------
<S> <C> <C>
(Millions of Dollars)
Electric
Bilaterial Sales $ 62 $496
PJM 63
Cost-based contracts (69) (45)
Oil & gas sales 229 62
Other 1 (3)
---- ----
$223 $573
==== ====
</TABLE>
Operating revenues from wholesale energy marketing and trading increased by
$223 million in 1999 over 1998. This increase was predominately due to
wholesale gas revenues, which increased nearly four-fold. This increase was, in
part, due to a need for more supply to meet the greater demand for gas-fired
generation and an increase in retail gas marketing activities. The decrease in
revenues from cost-based contracts reflects the phase down of the capacity and
energy agreement with JCP&L by 189,000 MW from 1998. The contract expired on
December 31, 1999.
Revenues in 1998 increased by $573 million over 1997, despite the phase-
down of the capacity and energy agreement with JCP&L and the end of the capacity
and energy agreement with Atlantic. The overall revenue increase reflected PPL
Electric Utilities' continued emphasis on competing in wholesale markets and
support of PPL EnergyPlus requirements. Energy purchases also increased to meet
these increased sales. Refer to "Energy Purchases" for more information.
<PAGE>
PUC Restructuring Proceeding
Refer to Note 4 to Financial Statements for information regarding the PUC
restructuring proceeding.
Energy-Related Businesses
Energy-related businesses (see Note 1 to Financial Statements) contributed
$60 million to the 1999 operating income of PPL, which was an increase of $35
million from 1998. The improvement reflected PPL Global's higher equity
earnings from its additional investment in WPD and additional operating income
provided by the mechanical contracting and engineering subsidiaries. Energy-
related businesses are expected to provide an increasing share of PPL's future
earnings.
Energy-related business provided an additional $16 million to operating
income in 1998 compared with 1997. This was primarily due to PPL Global's
higher equity earnings from its additional investments in Emel, EC and WPD.
With respect to PPL Global's investment in WPD, PPL Corporation is required
to file audited financial statements of WPD, as an amendment to this 10-K , when
such statements become available. WPD's fiscal year ends at March 31, 2000, and
it is expected that such financial statements will become available on or prior
to June 30, 2000.
Electric Fuel Costs
Electric fuel costs decreased by $44 million in 1999 when compared to 1998.
The decrease resulted from lower generation by PPL Electric Utilities' coal-
fired and oil/gas fired units, as well as lower fuel prices for coal. The lower
coal-fired generation resulted from units being dispatched less during off-peak
periods, as a result of NOx allowances affecting the unit costs from May to
September of 1999. The Holtwood plant closing and the Sunbury plant sale (See
"Power Plant Operations" discussion) also contributed to the decrease in
generation. In addition, PPL Electric Utilities entered into a rail contract
which lowered coal freight prices effective June 1999. These decreases were
partially offset by higher fuel prices for nuclear and oil/gas fired stations.
Electric fuel expense increased by $14 million in 1998 when compared to
1997. This increase reflects higher generation at the coal and oil/gas fired
stations. These units, particularly Martins Creek, were needed as a result of
increased wholesale energy marketing and trading by the Energy Marketing Center.
This increase was partially offset by lower fuel prices for all units,
especially oil/gas fired stations.
Energy Purchases
Excluding the purchases made by Emel and EC, which were consolidated by PPL
Global effective January 1, 1999, energy purchases increased by $316 million in
1999 when compared to 1998. The increase was primarily due to increased gas
purchases by the Energy Marketing Center, additional wholesale purchases to
support PPL EnergyPlus, and higher wholesale prices for electricity. These
increases were partially offset by a decrease in the volume of electricity
purchases and the reduction of the liability for above-market NUG purchases.
<PAGE>
Energy purchases increased by $556 million in 1998 when compared to 1997.
The increase was primarily due to greater quantities of energy purchased to meet
the increased wholesale energy marketing and trading by the Energy Marketing
Center, which includes increased purchases of natural gas and electric capacity
for resale. The related sales are included in wholesale energy sales. In
addition, the overall market price of purchased power was higher during 1998
compared to 1997 due to market volatility.
Other Operation Expenses
Other operation expenses increased by $91 million from 1998 to 1999.
Operating expenses of acquired companies and certain regulatory impacts caused a
substantial portion of this increase. These included:
. PPL Global's consolidation of Emel and EC, effective January 1, 1999,
which added about $25 million in operation expenses. PPL Global's
acquisition of Penobscot Hydro in 1999 added another $4 million of
operation expenses.
. About $23 million of additional operation expenses of PPL Gas
Utilities recorded in 1999 compared to 1998. PPL Gas Utilities was
acquired in August 1998.
. About $46 million of regulatory credits recorded in 1998. These
credits were for the loss of revenue as a result of the pilot Electric
Choice Program and the deferral of undercollected energy costs. No
similar items were reflected in 1999, as the pilot program was
completed and energy costs were no longer recoverable through the ECR.
Eliminating the effects of the above amounts, the other operation expenses
of PPL decreased by $7 million in 1999 compared with 1998. This decrease was
primarily due to PPL Electric Utilities' cost-cutting initiatives to increase
shareowner value, gains on the sale of emission allowances and decreased load
dispatching activities for system control. These decreases were partially
offset by additional expenses associated with customer choice, and additional
marketing expenses by PPL EnergyPlus. Also, wages and employee benefits were
higher in 1999 than 1998.
Other operation expenses increased by $92 million from 1997 to 1998. This
increase reflected higher costs associated with computer information systems,
and additional payroll, consultant services and other expenses to meet the
requirements of retail competition. This increase was also due to increased
firm transmission costs related to the Energy Marketing Center activities, and
higher provisions for uncollectible customer accounts. Operation costs of PPL
Gas Utilities, which was acquired in 1998, also added to the increase. The
increases in 1998 were partially offset by credits recorded in connection with
the pilot Electric Choice Program.
<PAGE>
Maintenance Expenses
Maintenance expenses increased by $33 million in 1999 from 1998. About
half of the increase was due to the consolidation of Emel effective January 1,
1999 and the acquisition of PPL Gas Utilities in August 1998. The other half of
this increase was due to higher costs of outage-related and other maintenance at
PPL Electric Utilities' fossil and nuclear power plants, and additional expenses
to maintain transmission and distribution facilities.
Power Plant Operations
In April 1999, PPL Electric Utilities closed its Holtwood coal-fired
generating station. The closing was part of an effort to reduce operating costs
and position PPL Electric Utilities for the competitive marketplace. The
adjacent hydroelectric plant continues to operate.
In November 1999, PPL Electric Utilities sold its Sunbury plant and the
principal assets of its wholly-owned coal processing subsidiary, Lady Jane
Collieries, to Sunbury Holdings, LLC. PPL Electric Utilities received cash
proceeds of $107 million for the assets, including coal inventory, which
resulted in a one-time contribution to earnings of about 28 cents per share.
Depreciation and Amortization
Depreciation and amortization expenses decreased by $81 million from 1998
to 1999. This decrease was mainly due to the write-down of generation-related
assets in connection with the restructuring adjustments recorded in June 1998.
The decrease was partially offset by depreciation associated with the
acquisition of PPL Gas Utilities in August 1998 and the consolidation of Emel
effective January 1, 1999.
Depreciation and amortization expenses decreased by $47 million from 1997
to 1998. This decrease also reflected the write-down of impaired generation-
related assets.
Other Income and (Deductions)
Other income of PPL increased by $31 million from 1998 to 1999. PPL
Global's earnings for 1999 reflected a pre-U.S. tax gain of $78 million from the
sale of SWEB's electricity supply business. Also, PPL Electric Utilities sold
its Sunbury plant and the principal assets of its wholly owned subsidiary, Lady
Jane Collieries, recognizing a $66 million pre-tax gain. These increases in
1999 were partially offset by a $51 million write-down of certain of PPL
Global's international investments: WPD, Aguaytia and BGG. Other income in
1998 also included several favorable one-time adjustments: a $30 million
recovery from SER to settle a suit over disputed purchase prices, a $9 million
credit for a reduction in U.K. corporate tax rates, and a $6 million credit to
earnings to reverse the prior expensing of PPL Gas Utilities acquisition costs.
<PAGE>
Other income in 1998 increased by $94 million from 1997. This increase was
primarily due to the favorable one-time adjustments recorded in 1998, as noted
above, and a windfall profits tax incurred by PPL Global in 1997. In July 1997,
the U.K. imposed a windfall profits tax on privatized utilities. SWEB's tax was
about $148 million, of which PPL Global's proportionate share was $37 million.
Financing Costs
PPL experienced higher financing costs associated with long-term debt
during the past few years, primarily associated with the issuance of $2.42
billion of transition bonds by PP&L Transition Bond Company and the issuance of
medium-term notes by PPL Capital Funding. Refer to "Financing Activities" for
more information. Interest on long-term debt and dividends on preferred stock
increased from $235 million in 1996 to $259 million in 1999, for a total
increase of $24 million. Interest on short-term debt, net of capitalized
interest and AFUDC borrowed funds, increased from $13 million in 1996 to $44
million in 1999. This increase reflects PPL Capital Funding's commercial paper
program initiated in 1998, which added short-term debt.
Income Taxes
Income tax expense decreased by $85 million in 1999 from 1998. This was
primarily due to deferred income taxes no longer required due to securitization.
Income tax expense in 1998 increased by $22 million from 1997. This was
primarily due to a $106 million increase in pre-tax book income.
Financial Condition
-------------------
Energy Marketing and Trading Activities
PPL Electric Utilities purchases and sells wholesale electric capacity and
energy under its FERC market-based tariff. PPL Electric Utilities has entered
into agreements to sell firm capacity or energy under its market-based tariff to
certain entities located inside and beyond the PJM power pool. PPL Electric
Utilities enters into these agreements to market available energy and capacity
from its generating assets and to profit from market price fluctuations. If PPL
Electric Utilities were unable to deliver firm capacity and energy under these
agreements, under certain circumstances it would be required to pay damages.
These damages would be based on the difference between the market price to
acquire replacement capacity or energy, and the contract price of the
undelivered capacity or energy. Depending on price volatility in the wholesale
energy markets, such damages could be significant. Extreme weather conditions,
unplanned generating plant outages, transmission disruptions, non-performance by
counterparties (or their counterparties) with which it has power contracts and
other factors could affect PPL Electric Utilities' ability to meet its firm
capacity or energy obligations, or cause significant increases in the market
price of replacement capacity and energy. Although PPL Electric Utilities
attempts to mitigate these risks, there can be no assurance that it will be able
to fully meet
<PAGE>
its firm obligations, that it will not be required to pay damages for failure to
perform, or that it will not experience counterparty non-performance in the
future.
PPL Electric Utilities attempts to mitigate risks associated with open
contract positions by holding back generation capacity to deliver electricity to
satisfy its net firm sales contracts and by purchasing firm transmission
service. In addition, PPL Electric Utilities' Energy Marketing Center adheres
to the Company's risk management policy and programs, including established
credit policies to evaluate counterparty credit risk. To date, PPL Electric
Utilities has not experienced any significant losses due to non-performance by
counterparties.
During 1999, PPL Electric Utilities entered into commodity forward and
option contracts for the physical purchase and sale of energy, as well as energy
related contracts that could be settled financially. On January 1, 1999, PPL
Electric Utilities adopted mark-to-market accounting for energy contracts
executed for trading purposes, in accordance with EITF 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities." Under
mark-to-market accounting, gains and losses from changes in market prices on
contracts executed for trading purposes are reflected in current earnings. The
earnings effect of mark-to-market accounting was not significant in 1999. Under
EITF 98-10, energy trading activities refer to energy contracts executed with
the objective of generating profits on, or from exposure to, shifts or changes
in market prices. Risk management activities refer to energy contracts that are
designated as (and effective as) hedges of non-trading activities (i.e.,
marketing available capacity and energy and purchasing fuel for consumption).
PPL Electric Utilities will continue to use accrual accounting for energy
contracts that are designated as non-trading activities until it adopts SFAS
133, "Accounting for Derivative Instruments and Hedging Activities," which is
effective January 1, 2001. SFAS 133, which expands the definition of a
derivative to possibly include commodity contracts that require physical
delivery, requires that an entity recognize all derivatives in the statement of
financial position at fair value. The accounting for changes in the fair value
of a derivative will depend on the intended use of the derivative and the
resulting designation.
PPL Electric Utilities has entered into an agreement to provide wholesale
energy marketing, trading and energy portfolio management services for an energy
cooperative organization that provides energy-related services to public power
entities. The market risk associated with this type of activity is not
significant. PPL Electric Utilities will terminate this agreement early in
2000. PPL Electric Utilities expects to expand its activities by entering into
similar agreements with other counterparties.
<PAGE>
Market Risk Sensitive Instruments
Quantitative and Qualitative Disclosures About Market Risk
----------------------------------------------------------
PPL actively manages the market risk inherent in its commodity, debt,
foreign currency and equity positions. The Board of Directors of PPL has
adopted a risk management policy to manage the risk exposures related to energy
prices, interest rates and foreign currency exchange rates. The policy
establishes a Risk Management Committee comprised of certain executive officers
which oversees the risk management function. Nonetheless, adverse changes in
commodity prices, interest rates, foreign currency exchange rates and equity
prices may result in losses in earnings, cash flows and/or fair values. The
forward-looking information presented below only provides estimates of what may
occur in the future, assuming certain adverse market conditions, due to reliance
on model assumptions. As a result, actual future results may differ materially
from those presented. These disclosures are not precise indicators of expected
future losses, but only indicators of reasonably possible losses.
See Note 10 to the Financial Statements for a discussion of forward
starting interest rate swaps and treasury locks to hedge debt issuances and
retirements during 1999. Note 10 also describes hedge positions at December 31,
1999 to manage exposures to interest rate risk for anticipated debt issuance in
the first quarter of 2000.
Commodity Price Risk - Energy Marketing Center
----------------------------------------------
PPL Electric Utilities' risk management program is designed to manage the
risks associated with market fluctuations in the price of electricity, natural
gas, oil and emission allowances. The Company's risk management policy and
programs include risk identification and risk limits management, with
measurement and controls for real time risk monitoring. In 1999, PPL Electric
Utilities entered into fixed-price forward and option contracts that required
physical delivery of the commodity, exchange-for-physical transactions and over-
the-counter contracts (such as swap agreements where settlement is generally
based on the difference between a fixed and index-based price for the underlying
commodity). PPL Electric Utilities expects to continue using such contracts in
2000 as well as tolling agreements or other contractual arrangements.
PPL Electric Utilities enters into contracts to hedge the impact of market
fluctuations on its energy-related assets, liabilities and other contractual
arrangements. In addition, as defined by EITF 98-10, it enters into these
contracts for trading purposes to take advantage of market opportunities. PPL
Electric Utilities may at times create a net open position in its portfolio that
could result in significant losses if prices do not move in the manner or
direction anticipated.
PPL Electric Utilities uses various methodologies to simulate forward price
curves in the energy markets to estimate the size and probability of changes in
market value resulting from commodity price movements. The methodologies require
several key assumptions,
<PAGE>
including selection of confidence levels, the holding period of the commodity
positions, and the depth and applicability to future periods of historical
commodity price information. At December 31, 1999, PPL Electric Utilities
estimated that a 10% adverse movement in market prices across all geographic
areas and time periods could have decreased the value of PPL Electric Utilities'
trading portfolio by approximately $1 million, as compared to a $16 million
decrease at December 31, 1998. For PPL Electric Utilities' non-trading
portfolio, a 10% adverse movement in market prices across all geographic areas
and time periods could have decreased the value of PPL Electric Utilities' non-
trading portfolio by approximately $11 million at December 31, 1999, as compared
to a $17 million decrease at December 31, 1998. However, this effect would have
been offset by the change in the value of the underlying commodity, i.e., the
electricity generated. In addition to commodity price risk, PPL Electric
Utilities' commodity positions are also subject to operational and event risks
including, among others, increases in load demand and forced outages at
generating plants.
Commodity Price Risk - PPL EnergyPlus
-------------------------------------
During 1999, PPL EnergyPlus entered into various arrangements with retail
customers who elected to shop for an energy provider. These contracts committed
PPL EnergyPlus to the sale of electricity or natural gas without a specified
firm volume. The sale contracts ranged in duration from five months to three
years. To hedge the price risk of these transactions, PPL EnergyPlus has the
ability to supply the electricity through a one-year option contract with the
Energy Marketing Center. Therefore, the potential for short-term losses
associated with PPL EnergyPlus' commodity position is not significant.
PPL EnergyPlus also provides for the transportation and sale of excess
electricity generated by PPL Montana. Changes in the prices of this commodity
can affect PPL Montana's financial results. PPL EnergyPlus manages this
exposure, in part, by using financial derivatives and physical instruments in
hedged transactions to reduce earnings volatility and stabilize cash flows. PPL
EnergyPlus may enter into derivative financial instruments from time to time for
trading purposes.
At December 31, 1999, PPL EnergyPlus estimated that a 10% adverse movement
in market prices across all geographic areas and time periods would not have a
significant impact on the financial statements. At December 31, 1999 PPL
EnergyPlus had no trading transactions as defined under EITF 98-10.
Interest Rate Risk
------------------
PPL and PPL Electric Utilities have issued debt to finance their
operations. Also, PPL has issued debt to provide funds for unregulated energy
investments, which also increases interest rate risk. PPL and PPL Electric
Utilities manage their interest rate risk by using financial derivative products
to adjust the mix of fixed and floating-rate interest rates in their debt
portfolios, adjusting the duration of their debt portfolios and locking in U.S.
treasury rates
<PAGE>
(and interest rate spreads over treasuries) in anticipation of future financing,
when appropriate. Risk limits are designed to balance risk exposure to
volatility in interest expense and losses in the fair value of PPL's and PPL
Electric Utilities' debt portfolio due to changes in the absolute level of
interest rates. See Note 10 to Financial Statements for a discussion of
financial derivative instruments outstanding at December 31, 1999.
PPL's potential annual exposure to increased interest expense due to a 10%
increase in interest rates was estimated at a $4.9 million at December 31, 1999,
and $6.3 million at December 31, 1998.
PPL is also exposed to changes in the fair value of its debt portfolio. At
December 31, 1999, PPL estimated that its potential exposure to a change in the
fair value of its debt portfolio through a 10% adverse movement in interest
rates was $61.3 million, compared with $118.8 million at December 31, 1998.
PPL utilizes various risk management instruments to reduce its exposure to
adverse interest rate movements for future anticipated financings. While PPL is
exposed to changes in the fair value of these instruments, they are designed
such that any economic loss in value should be offset by interest rate savings
at the time the future anticipated financing is completed. At December 31, 1999,
PPL estimated its potential exposure to a change in the fair value of these
instruments through a 10% adverse movement in interest rates at $46.3 million.
At December 31, 1998 PPL had no financial derivative instruments outstanding.
Market events that are inconsistent with historical trends could cause
actual results to exceed estimated levels.
Foreign Operations Risk
-----------------------
At December 31, 1999 and 1998, PPL Global had investments of $810 million
and $671 million, respectively, the majority of which were international
investments in energy-related distribution facilities. PPL Global is exposed to
foreign currency risk primarily through investments in affiliates in Latin
America and Europe.
PPL has adopted a foreign currency risk management program designed to
limit or hedge future cross-border cash flows for firm transactions and
commitments, and to hedge economic exposures such as anticipated dividends and
projected asset sales or acquisitions when there is a high degree of certainty
that the exposure will be realized. As of December 31, 1999 and 1998, PPL did
not have any outstanding significant foreign currency-based financing.
<PAGE>
Nuclear Decommissioning Fund - Securities Price Risk
----------------------------------------------------
PPL Electric Utilities maintains trust funds, as required by the NRC, to
fund certain costs of decommissioning Susquehanna. At December 31, 1999, these
funds were invested primarily in domestic equity securities and fixed rate,
fixed income securities and are reflected at fair value on the Consolidated
Balance Sheet. The mix of securities is designed to provide returns to be used
to fund Susquehanna's decommissioning and to compensate for inflationary
increases in decommissioning costs. However, the equity securities included in
the trusts are exposed to price fluctuation in equity markets, and the value of
fixed rate, fixed income securities are exposed to changes in interest rates.
PPL Electric Utilities actively monitors the investment performance and
periodically reviews asset allocation in accordance with PPL Electric Utilities'
nuclear decommissioning trust policy statement. A hypothetical 10% increase in
interest rates and 10% decrease in equity prices would result in an $18.6
million reduction in the fair value of the trust assets at December 31, 1999, as
compared to a $13.7 million reduction at December 31, 1998.
PPL Electric Utilities' restructuring settlement agreement provides for the
collection of authorized nuclear decommissioning costs through the CTC.
Additionally, PPL Electric Utilities is permitted to seek recovery from
customers of up to 96% of any increases in these costs. Therefore, PPL Electric
Utilities' securities price risk is expected to remain insignificant.
Capital Expenditure Requirements
The schedule below shows PPL Electric Utilities' current capital
expenditure projections for the years 2000-2004 and actual spending for the year
1999.
PPL Electric Utilities' Capital Expenditure Requirements
<TABLE>
<CAPTION>
Actual -----------Projected-----------
1999 2000 2001 2002 2003 2004
(Millions of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Construction expenditures
Generating facilities $ 91 $ 69 $ 69 $ 123 $ 95 $ 61
Transmission and
distribution facilities 111 115 114 119 119 123
Environmental 47 98 29 5 23 21
Other 15 22 18 18 16 16
----- ----- ----- ----- ---- ----
Total Construction
Expenditures 264 304 230 265 253 221
Nuclear fuel owned and
leased 42 50 55 56 56 59
Operating leases 38 28 28 28 28 28
----- ----- ----- ----- ---- ----
Total Capital
Expenditures $ 344 $ 382 $ 313 $ 349 $337 $308
===== ===== ===== ===== ==== ====
</TABLE>
<PAGE>
Construction expenditures include AFUDC and Capitalized Interest which are
expected to be less than $19 million in each of the years 2000-2004.
PPL Electric Utilities' capital expenditure projections for the years 2000-
2004 total about $1.7 billion. Capital expenditure plans are revised from time
to time to reflect changes in conditions.
Acquisitions and Divestitures
Refer to Note 12 to the Financial Statements for information regarding
Acquisitions and Divestitures.
At December 31, 1999, PPL Global had investments in foreign and domestic
facilities, including investments in Emel, DelSur, and Penobscot Hydro (that are
consolidated in PPL Global's financial statements), but excluding PPL Montana.
PPL Global continues to pursue opportunities to develop and acquire electric
generation, transmission and distribution facilities in the U.S. and abroad.
Financing and Liquidity
Cash and cash equivalents decreased by $207 million more during the twelve
months ended December 31, 1999, compared with the same period in 1998. The
reasons for this change were:
. A $7 million increase in cash provided by operating activities.
. A $694 million increase in cash used in investing activities,
primarily due to the acquisition of the Montana generating assets,
partially offset by the sale of the Sunbury generating and related
assets and the sale of SWEB's supply business.
. A $480 million increase in cash provided by financing activities. This
increase was due to a net increase in long-term debt and a decrease in
payments of common dividends. These financing inflows were partially
offset by lower funds from issuing common stock, and a smaller
increase in short-term debt balances.
From 1997 through 1999, PPL issued $3.2 billion of long-term debt
(including $2.42 billion of securitized debt issued by PP&L Transition Bond
Company). For the same period, PPL issued $146 million of common stock,
excluding stock issued in conjunction with the PPL Gas Utilities acquisition.
From 1997 through 1999, PPL retired $2.1 billion of long-term debt and purchased
$836 million of common shares. During the years 1997 through 1999, PPL Electric
Utilities also incurred $185 million of obligations under capital leases.
Refer to Note 11 to the Financial Statements for additional information on
credit arrangements and financing activities in 1999.
<PAGE>
In February 2000, PPL Capital Funding issued $500 million of medium-term
notes in the form of 7.75% series due 2005. This issuance used $500 million of
the $1.2 billion SEC shelf registration filed in September 1999. (See Note 11 to
the Financial Statements.) At the time of issuance, PPL also settled a number of
forward-starting swaps that had been entered into in a lower interest rate
environment as a means to lock-in interest rates and limit exposure to
increasing interest rates, all pursuant to PPL's interest rate risk management
program. PPL received net proceeds of $15.8 million from the settlement of these
contracts, which will be deferred on the balance sheet and subsequently
amortized over the life of the medium-term notes. The effective interest rate on
the medium-term notes was reduced by approximately 75 basis points as a result
of this hedging activity. Also, in conjunction with this transaction, PPL
swapped $350 million notional amount of these notes from fixed to floating-rate
instruments, with an initial average rate of three-months LIBOR plus 45 basis
points, to adjust the amount of floating-rate debt carried in its liability
portfolio.
In the first quarter of 2000, PPL Electric Utilities intends to call for
redemption its remaining $28 million of First Mortgage Bonds, 9-1/4% Series due
2019, through the maintenance and replacement fund provisions of its mortgage.
On February 25, 2000, the PPL Board of Directors declared a quarterly
common stock dividend of $.265 per share, payable April 1, 2000 to shareowners
of record on March 10, 2000. The amount of the April 1, 2000 dividend represents
an increase of 6% from the amount of the quarterly dividend ($.25 per share)
that had been paid since October 1, 1998. Future dividends, declared at the
discretion of the Board of Directors, will be dependent upon future earnings,
financial requirements and other factors.
Financial Indicators
Earnings for 1999, 1998 and 1997 were impacted by one-time adjustments.
(See "Earnings" for additional information.) The following financial indicators
for PPL reflect the elimination of these impacts from earnings, and provide an
additional measure of the underlying earnings performance of PPL and its
subsidiaries.
<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Earnings per share, as adjusted $ 2.35 $ 1.87 $ 2.00
Return on average common equity 16.89% 10.98% 11.69%
Ratio of pre-tax income to
interest charges 3.04 3.28 3.59
Dividends declared per share $ 1.00 $1.335 $ 1.67
</TABLE>
See Item 6 "Selected Financial and Operating Data" for additional financial
indicators.
<PAGE>
Environmental Matters
See Note 16 to Financial Statements for a discussion of environmental
matters.
Increasing Competition
The electric utility industry has experienced, and will continue to
experience, a significant increase in the level of competition in the energy
supply market at both the state and federal level.
State Activities
----------------
Refer to Note 4 to the Financial Statements for a discussion of PPL
Electric Utilities' PUC restructuring proceeding under the Customer Choice Act.
Also refer to Note 4 regarding PPL Electric Utilities' transfer of its
retail electric marketing function to PPL EnergyPlus. PPL EnergyPlus has a PUC
license to act as a Pennsylvania EGS. This license permits PPL EnergyPlus to
offer retail electric supply to participating customers in the service territory
of PPL Electric Utilities and in the service territories of other Pennsylvania
utilities. In 1999, PPL EnergyPlus served industrial and commercial customers
in Pennsylvania, New Jersey and Delaware, and is also licensed to sell energy in
Maine and Montana.
Federal Activities
------------------
PPL Electric Utilities and PPL EnergyPlus have authority from the FERC to
sell specified ancillary services at market-based rates in the following
markets: the New England power pool, the New York power pool, the market
administered by the California ISO, and the PJM.
PPL Electric Utilities and PPL EnergyPlus have authority from the FERC to
sell electric energy and capacity at market-based rates and to sell, assign or
transfer transmission rights and associated ancillary services. PPL Electric
Utilities has a FERC-filed code of conduct governing its relationship with such
affiliates that engage in the sale and/or transmission of electric energy.
Proposed Corporate Realignment
In September 1999, the Boards of Directors of PPL and PPL Electric
Utilities approved the initiation of a corporate realignment, in order to better
position PPL and its subsidiaries in the new competitive marketplace. This
realignment includes the following key features:
. The transfer of all of PPL Electric Utilities' electric generating
facilities and related assets to new generating subsidiaries of PPL,
under a new unregulated generation company. In order to effect this
transfer,
<PAGE>
these assets will be released from PPL Electric Utilities' Mortgage.
. The transfer of PPL Electric Utilities' wholesale energy marketing
business, to PPL EnergyPlus, which will be the wholesale and retail
energy marketing subsidiary of PPL and will no longer be a subsidiary
of PPL Electric Utilities.
. The transfer of the U.S. electric generation subsidiaries of PPL
Global to the new generating company.
Upon completion of this corporate realignment, PPL Electric Utilities'
principal business will be the transmission and distribution of electricity to
serve retail customers in its franchised territory in eastern and central
Pennsylvania. PPL Global's principal business will be the acquisition or
development of both U.S. and international energy projects and the ownership of
international energy projects. Other existing subsidiaries of PPL and PPL
Electric Utilities will generally be aligned in the new corporate structure
according to their principal business functions.
The proposed corporate realignment is subject to approval from the PUC, the
FERC and the NRC, as well as certain third-party consents. In December 1999,
the company filed applications for these regulatory approvals. Several protests
and petitions to intervene have been filed in these proceedings, raising a
variety of issues associated with the corporate realignment. PPL currently
expects to complete the corporate realignment in mid-2000.
Year 2000
PPL successfully addressed the Year 2000 issue. The Year 2000 issue was
the result of computer programs written using two digits rather than four to
define the applicable year and other programming techniques which limited date
calculations or assigned special meanings to some dates. All of PPL Electric
Utilities' computer systems that had date-sensitive software or microprocessors
could have recognized a date using "00" as the year 1900 rather than the year
2000. This could have resulted in a system failure or miscalculations causing
disruptions of operations, including among other things, a temporary inability
to measure usage, read meters, process transactions, send bills, receive
payments, distribute electricity or operate electric generation stations. In
addition, the Year 2000 issue could have affected the ability of customers to
receive bills sent by PPL Electric Utilities or to make payments on these bills.
PPL Electric Utilities has not experienced any significant problems in this
regard.
Based upon present assessments, PPL Electric Utilities estimates that it
incurred approximately $13 million in Year 2000 remediation costs. These costs
have been expensed as incurred.
Other PPL domestic and international affiliates successfully completed the
Year 2000 rollover with no significant problems. PPL's electricity distribution
companies in the U.K., Chile, Bolivia, and El Salvador
<PAGE>
all reported fewer than normal outages, which were unrelated to Year 2000. In
addition, PPL Gas Utilities and generating facilities in Montana and Maine also
successfully made the Year 2000 transition without incident.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to "Quantitative and Qualitative Disclosures About Market
Risk," in Review of Financial Condition and Results of Operations, and Note 1 to
the Financial Statements.
<PAGE>
(Address and phone number appears here)
Thirty South Seventeenth Street
Philadelphia, PA 19103-4094
Telephone 215 575 5000
(PricewaterhouseCoopers LLP logo appears here)
Report of Independent Accountants
- ---------------------------------
To the Shareowners and Board of Directors of
PPL Corporation and to the Shareowner and
Board of Directors of PPL Electric Utilities Corporation
In our opinion, the accompanying consolidated financial statements listed in the
index appearing under Item 14(a)(1) present fairly, in all material respects,
the consolidated financial position of PPL Corporation and its subsidiaries
("PPL") at December 31, 1999 and 1998, and the consolidated results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999 and the consolidated financial position of PPL Electric
Utilities Corporation and its subsidiaries ("PPL Electric Utilities") at
December 31, 1999 and 1998 and the consolidated results of their operations and
their cash flows for each of the three years in the period ended December 31,
1999, in conformity with accounting principles generally accepted in the United
States. These financial statements are the responsibility of management of PPL
and PPL Electric Utilities; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
January 31, 2000
<PAGE>
(THIS PAGE LEFT BLANK INTENTIONALLY.)
<PAGE>
PPL Corporation
---------------
Management's Report on Responsibility for Financial Statements
--------------------------------------------------------------
The management of PPL Corporation is responsible for the preparation,
integrity and objectivity of the consolidated financial statements and all other
sections of this annual report. The financial statements were prepared in
accordance with generally accepted accounting principles and the Uniform System
of Accounts prescribed by the Federal Energy Regulatory Commission. In
preparing the financial statements, management makes informed estimates and
judgments of the expected effects of events and transactions based upon
currently available facts and circumstances. Management believes that the
financial statements are free of material misstatement and present fairly the
financial position, results of operations and cash flows of PPL.
PPL's consolidated financial statements have been audited by
PricewaterhouseCoopers LLP (PricewaterhouseCoopers), independent certified
public accountants. PricewaterhouseCoopers' appointment as auditors was
previously ratified by the shareowners. Management has made available to
PricewaterhouseCoopers all PPL's financial records and related data, as well as
the minutes of shareowners' and directors' meetings. Management believes that
all representations made to PricewaterhouseCoopers during its audit were valid
and appropriate.
PPL maintains a system of internal control designed to provide reasonable,
but not absolute, assurance as to the integrity and reliability of the financial
statements, the protection of assets from unauthorized use or disposition and
the prevention and detection of fraudulent financial reporting. The concept of
reasonable assurance recognizes that the cost of a system of internal control
should not exceed the benefits derived and that there are inherent limitations
in the effectiveness of any system of internal control.
Fundamental to the control system is the selection and training of
qualified personnel, an organizational structure that provides appropriate
segregation of duties, the utilization of written policies and procedures and
the continual monitoring of the system for compliance. In addition, PPL
maintains an internal auditing program to evaluate PPL's system of internal
control for adequacy, application and compliance. Management considers the
internal auditors' and PricewaterhouseCoopers' recommendations concerning its
system of internal control and has taken actions which are believed to be cost-
effective in the circumstances to respond appropriately to these
recommendations. Management believes that PPL's system of internal control is
adequate to accomplish the objectives discussed in this report.
The Board of Directors, acting through its Audit Committee, oversees
management's responsibilities in the preparation of the financial statements.
In performing this function, the Audit Committee, which is composed of four
independent directors, meets periodically with management, the internal auditors
and the independent certified public accountants to review the work of each.
The independent certified public accountants and the internal auditors have free
access to the Audit Committee and to the Board of Directors, without management
present, to discuss internal accounting control, auditing and financial
reporting matters.
Management also recognizes its responsibility for fostering a strong
ethical climate so that PPL's affairs are conducted according to the highest
standards of personal and corporate conduct. This responsibility is
characterized and reflected in the business policies and guidelines of PPL's
operating subsidiaries. These policies and guidelines address: the necessity of
ensuring open communication within PPL; potential conflicts of interest; proper
procurement activities; compliance with all applicable laws, including those
relating to financial disclosure; and the confidentiality of proprietary
information.
William F. Hecht
Chairman, President and Chief Executive Officer
John R. Biggar
Senior Vice President and Chief Financial Officer
<PAGE>
PPL Electric Utilities Corporation
----------------------------------
Management's Report on Responsibility for Financial Statements
--------------------------------------------------------------
The management of PPL Electric Utilities Corporation is responsible for the
preparation, integrity and objectivity of the consolidated financial statements
and all other sections of this annual report. The financial statements were
prepared in accordance with generally accepted accounting principles and the
Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission. In preparing the financial statements, management makes informed
estimates and judgments of the expected effects of events and transactions based
upon currently available facts and circumstances. Management believes that the
financial statements are free of material misstatement and present fairly the
financial position, results of operations and cash flows of PPL Electric
Utilities.
PPL Electric Utilities' consolidated financial statements have been audited
by PricewaterhouseCoopers LLP (PricewaterhouseCoopers) independent certified
public accountants. PricewaterhouseCoopers' appointment as auditors was
previously ratified by the shareowners of PPL. Management has made available to
PricewaterhouseCoopers all PPL Electric Utilities' financial records and related
data, as well as the minutes of shareowners' and directors' meetings.
Management believes that all representations made to PricewaterhouseCoopers
during its audit were valid and appropriate.
PPL Electric Utilities maintains a system of internal control designed to
provide reasonable, but not absolute, assurance as to the integrity and
reliability of the financial statements, the protection of assets from
unauthorized use or disposition and the prevention and detection of fraudulent
financial reporting. The concept of reasonable assurance recognizes that the
cost of a system of internal control should not exceed the benefits derived and
that there are inherent limitations in the effectiveness of any system of
internal control.
Fundamental to the control system is the selection and training of
qualified personnel, an organizational structure that provides appropriate
segregation of duties, the utilization of written policies and procedures and
the continual monitoring of the system for compliance. In addition, PPL
Electric Utilities maintains an internal auditing program to evaluate PPL
Electric Utilities' system of internal control for adequacy, application and
compliance. Management considers the internal auditors' and
PricewaterhouseCoopers' recommendations concerning its system of internal
control and has taken actions which are believed to be cost-effective in the
circumstances to respond appropriately to these recommendations. Management
believes that PPL Electric Utilities' system of internal control is adequate to
accomplish the objectives discussed in this report.
The Board of Directors, acting through PPL Corporation's Audit Committee,
oversees management's responsibilities in the preparation of the financial
statements. In performing this function, the Audit Committee, which is composed
of four independent directors, meets periodically with management, the internal
auditors and the independent certified public accountants to review the work of
each. The independent certified public accountants and the internal auditors
have free access to PPL Corporation's Audit Committee and to the Board of
Directors, without management present, to discuss internal accounting control,
auditing and financial reporting matters.
Management also recognizes its responsibility for fostering a strong
ethical climate so that PPL Electric Utilities' affairs are conducted according
to the highest standards of personal and corporate conduct. This responsibility
is characterized and reflected in PPL Electric Utilities' business policies and
guidelines. These policies and guidelines address: the necessity of ensuring
open communication within PPL Electric Utilities; potential conflicts of
interest; proper procurement activities; compliance with all applicable laws,
including those relating to financial disclosure; and the confidentiality of
proprietary information.
William F. Hecht
Chairman, President and Chief Executive Officer
John R. Biggar
Senior Vice President and Chief Financial Officer
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONSOLIDATED STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, except per share data)
<TABLE>
<CAPTION>
1999 1998 1997
<S> <C> <C> <C>
Operating Revenues
Electric.............................................................. $ 2,758 $ 2,410 $ 2,397
Natural gas and propane............................................... 109 35
Wholesale energy marketing and trading................................ 1,446 1,223 650
Energy related businesses............................................. 277 118 30
-------- -------- --------
Total................................................................. 4,590 3,786 3,077
-------- -------- --------
Operating Expenses
Operation
Electric fuel....................................................... 446 490 476
Natural gas and propane............................................. 46 13
Energy purchases for retail load and wholesale...................... 1,518 1,060 504
Other............................................................... 686 595 503
Amortization of recoverable transition costs........................ 172
Maintenance........................................................... 215 182 184
Depreciation and amortization (Note 1)................................ 257 338 385
Taxes, other than income (Note 8)..................................... 161 188 204
Energy related businesses............................................. 217 93 21
-------- -------- --------
Total................................................................. 3,718 2,959 2,277
-------- -------- --------
Operating Income........................................................ 872 827 800
-------- -------- --------
Other Income and (Deductions)........................................... 97 66 (28)
-------- -------- --------
Income Before Interest, Income Taxes and Minority Interest.............. 969 893 772
Interest Expense........................................................ 277 230 215
-------- -------- --------
Income Before Income Taxes, Minority Interest and
Extraordinary Items..................................................... 692 663 557
Income Taxes (Note 8)................................................... 174 259 237
Minority Interest (Note 1).............................................. 14
-------- -------- --------
Income Before Extraordinary Items....................................... 504 404 320
Extraordinary Items (net of income taxes) (Note 6)...................... (46) (948)
-------- -------- --------
Income (Loss) Before Dividends on Preferred Stock....................... 458 (544) 320
Preferred Stock Dividend Requirements................................... 26 25 24
-------- -------- --------
Net Income (Loss)....................................................... $ 432 ($569) $ 296
======== ======== ========
Earnings Per Share of Common Stock
Basic and Diluted (Note 1):
Income Before Extraordinary Items................................... $ 3.14 $ 2.29 $ 1.80
Extraordinary Items (net of tax).................................... (0.30) (5.75)
-------- -------- --------
Net Income (Loss)....................................................... $ 2.84 ($3.46) $ 1.80
======== ======== ========
Dividends Declared per Share of Common Stock............................ $ 1.00 $ 1.335 $ 1.67
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
1999 1998 1997
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income (loss).............................................. $ 432 ($569) $ 296
Extraordinary items (net of income taxes)...................... (46) (948)
------------ ------------ ------------
Net income before extraordinary items.......................... 478 379 296
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation and amortization................................ 257 338 385
Regulatory debits and credits................................ 194 (61) (36)
Amortization of property under capital leases................ 59 58 68
Amortization of NUG above market liability................... (104)
Gain on sale of generating assets and electric
energy projects............................................. (146)
Minority interest............................................ 14
Writedown of investments in electric energy projects......... 51
Preferred stock dividend requirement......................... 26 25 24
Equity in (earnings) loss of unconsolidated affiliates....... (59) (49) 2
Deferred income taxes and investment tax credits............. (43) 12 18
Change in current assets and current liabilities............... (82) (42) (2)
Other operating activities - net............................... (1) (23) 22
------------ ------------ ------------
Net cash provided by operating activities................. 644 637 777
------------ ------------ ------------
Cash Flows From Investing Activities
Expenditures for property plant and equipment.................. (318) (304) (310)
Sale of generating assets and electric energy projects........ 221
Investment in generating assets and electric energy projects... (1,095) (306) (152)
Sale of nuclear fuel to trust.................................. 14 54 60
Purchases of available-for-sale securities..................... (15) (72)
Sales and maturities of available-for-sale securities.......... 70 111
Purchases and sales of other financial investments - net....... 4 76
Other investing activities - net............................... (1) 12 (4)
------------ ------------ ------------
Net cash used in investing activities..................... (1,179) (485) (291)
------------ ------------ ------------
Cash Flows From Financing Activities
Issuance of long-term debt..................................... 2,620 495 111
Retirement of long-term debt................................... (1,644) (295) (210)
Issuance of common stock....................................... 8 62 76
Purchase of treasury stock..................................... (416) (419)
Issuance of Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts holding
solely parent debentures.................................... 250
Purchase of subsidiary's preferred stock....................... (369)
Payments on capital lease obligations.......................... (59) (58) (68)
Payment of common and preferred dividends...................... (180) (278) (298)
Net increase (decrease) in short-term debt..................... 215 487 (9)
Other financing activities - net............................... (71) (1) (20)
------------ ------------ ------------
Net cash provided by (used in) financing activities....... 473 (7) (537)
------------ ------------ ------------
Net Increase (Decrease) In Cash and Cash Equivalents............. (62) 145 (51)
Cash and Cash Equivalents at Beginning of Period............... 195 50 101
------------ ------------ ------------
Cash and Cash Equivalents at End of Period..................... $ 133 $ 195 $ 50
============ ============ ============
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of amount capitalized)........................ $ 267 $ 237 $ 208
Income taxes................................................ $ 184 $ 248 $ 244
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements
<PAGE>
CONSOLIDATED BALANCE SHEET AT DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
Assets 1999 1998
<S> <C> <C>
Current Assets
Cash and cash equivalents (Note 1)................................................ $ 133 $ 195
Accounts receivable (less reserve: 1999, $22; 1998, $16)......................... 399 298
Unbilled revenues................................................................. 310 170
Fuel, materials and supplies - at average cost.................................... 200 207
Prepayments....................................................................... 119 15
Unrealized energy trading gains................................................... 26 2
Other............................................................................. 106 61
------------- -------------
1,293 948
------------- -------------
Investments
Investment in unconsolidated affiliates at equity (Note 1)........................ 424 688
Nuclear plant decommissioning trust fund (Notes 1 and 9).......................... 255 206
Other (Note 10)................................................................... 16 12
------------- -------------
695 906
------------- -------------
Property, Plant and Equipment
Electric utility plant in service - net (Note 1)
Transmission and distribution................................................ 2,462 2,179
Generation................................................................... 2,352 1,601
General...................................................................... 259 223
------------- -------------
5,073 4,003
Construction work in progress - at cost........................................... 181 117
Nuclear fuel owned and leased - net............................................... 139 162
------------- -------------
Electric utility plant - net................................................. 5,393 4,282
Gas and oil utility plant - net................................................... 171 175
Other property - net.............................................................. 80 23
------------- -------------
5,644 4,480
------------- -------------
Regulatory Assets and Other Noncurrent Assets (Note 6)
Recoverable transition costs...................................................... 2,647 2,819
Other............................................................................. 895 454
------------- -------------
3,542 3,273
------------- -------------
$11,174 $9,607
============= =============
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
<TABLE>
<CAPTION>
Liabilities and Equity 1999 1998
<S> <C> <C>
Current Liabilities
Short-term debt (Note 11).......................................................... $ 857 $ 636
Long-term debt..................................................................... 468 1
Capital lease obligations.......................................................... 58 59
Above market NUG contracts (Note 6)................................................ 99 105
Accounts payable................................................................... 399 197
Taxes and interest accrued......................................................... 144 95
Dividends payable.................................................................. 43 46
Unrealized energy trading losses................................................... 28 9
Other.............................................................................. 184 128
------------- -------------
2,280 1,276
------------- -------------
Long-term Debt.......................................................................... 3,689 2,983
------------- -------------
Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes and investment tax credits (Note 8).......................... 1,548 1,574
Above market NUG purchases (Note 6) ............................................... 674 775
Capital lease obligations ......................................................... 67 109
Other (Notes 1 and 9) ............................................................ 892 753
------------- -------------
3,181 3,211
------------- -------------
Commitments and Contingent Liabilities (Note 16)........................................
------------- -------------
Minority Interest (Note 1).............................................................. 64
------------- -------------
Company-obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely company debentures................................. 250 250
------------- -------------
Preferred Stock
With sinking fund requirements..................................................... 47 47
Without sinking fund requirements.................................................. 50 50
------------- -------------
97 97
------------- -------------
Shareowners' Common Equity
Common stock....................................................................... 2 2
Capital in excess of par value..................................................... 1,860 1,866
Treasury stock (Note 1)............................................................ (836) (419)
Earnings reinvested................................................................ 654 372
Accumulated other comprehensive income (Note 1).................................... (55) (4)
Capital stock expense and other.................................................... (12) (27)
------------- -------------
1,613 1,790
------------- -------------
$11,174 $9,607
============= =============
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of the financial statements.
<PAGE>
CONSOLIDATED STATEMENT OF SHAREOWNERS' COMMON EQUITY
PPL Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
For the Years Ended December 31,
---------------------------------------
1999 1998 1997
----------- ---------- -----------
<S> <C> <C> <C>
Common stock at beginning of year........................................................ $ 2 $ 2 $ 2
Issuance of common stock...........................................................
----------- ---------- -----------
Common stock at end of year.............................................................. 2 2 2
----------- ---------- -----------
Capital in excess of par value at beginning of year...................................... 1,866 1,669 1,590
Common stock issued through the ESOP and the DRIP (a)............................... 8 62 76
Common stock issued for purchase of PPL Gas Utilities............................... 135
Other............................................................................... (14) 3
----------- ---------- -----------
Capital in excess of par value at end of year............................................ 1,860 1,866 1,669
----------- ---------- -----------
Treasury stock at beginning of year...................................................... (419)
Purchase of treasury stock.......................................................... (417) (419)
----------- ---------- -----------
Treasury stock at end of year............................................................ (836) (419)
----------- ---------- -----------
Earnings reinvested at beginning of year................................................. 372 1,164 1,143
Net income (loss) (b).............................................................. 432 (569) 296
Cash dividends declared on common stock............................................ (150) (223) (275)
----------- ---------- -----------
Earnings reinvested at end of year....................................................... 654 372 1,164
----------- ---------- -----------
Accumulated other comprehensive income at beginning of year (c).......................... (4) 13
Foreign currency translation adjustments, net of tax benefit of $6, $3, $0 (b)...... (51) 1 (13)
Unrealized gain (loss) on available-for-sale securities (b)......................... (2) 2
Minimum pension liability adjustment (b)............................................ (3) (2)
----------- ---------- -----------
Accumulated other comprehensive income at end of year.................................... (55) (4) -
----------- ---------- -----------
Capital stock expense at beginning of year (27) (26) (3)
Other................................................................................ 15 (1) (23)
----------- ---------- -----------
Capital stock expense at end of year..................................................... (12) (27) (26)
----------- ---------- -----------
Total Shareowners' Common Equity......................................................... $ 1,613 $ 1,790 $ 2,809
=========== ========== ===========
Common stock shares (thousands) at beginning of year (a)................................. 157,412 166,248 162,665
Common stock issued through ESOP and DRIP.......................................... 282 2,604 3,583
Common stock issued for purchase of PPL Gas Utilities............................... 5,556
Treasury stock purchased............................................................ (13,997) (16,996)
----------- ---------- -----------
Common stock shares at end of year....................................................... 143,697 157,412 166,248
=========== ========== ===========
(a) $.01 par value, 390,000 thousand shares authorized. Each share entitles
the holder to one vote on any question presented to any shareowners'
meeting.
(b) Statement of Comprehensive Income (Note 1):
Net income (loss)................................................................... $ 432 ($569) $ 296
Other comprehensive income, net of tax:
Foreign currency translation adjustments....................................... (51) 1 (13)
Unrealized gain (loss) on available-for-sale securities........................ (2) 2
Minimum pension liability adjustment........................................... (3) (2)
----------- ---------- -----------
Total other comprehensive income.................................................... (51) (4) (13)
----------- ---------- -----------
Comprehensive income (loss)......................................................... $ 381 ($573) $ 283
=========== ========== ===========
</TABLE>
(c) See Note 1 for disclosure of balances for each component of Accumulated
Other Comprehensive Income.
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
CONSOLIDATED STATEMENT OF PREFERRED STOCK AT DECEMBER 31,
PPL Corporation and Subsidiaries (a)
(Millions of Dollars)
<TABLE>
<CAPTION>
Shares
Outstanding Outstanding Shares
1999 1998 (b) 1999 (b) Authorized
<S> <C> <C> <C> <C>
PPL Electric Utilities
Preferred Stock - $100 par, cumulative
4-1/2%........................... $ 25 $ 25 247,658 629,936
Series........................... 72 72 726,665 10,000,000
-------- --------
$ 97 $ 97
======== ========
</TABLE>
Details of Preferred Stock (c)
<TABLE>
<CAPTION>
Sinking Fund
Optional Provisions
Shares Redemption Shares to be
Outstanding Outstanding Price Per Redeemed Redemption
1999 (b) 1998 (b) 1999 (b) Share Annually Period
<S> <C> <C> <C> <C> <C> <C>
With Sinking Fund Requirements
Series Preferred
5.95%............................ $ 1 $ 1 10,000 (d) 10,000 April 2001
6.125%........................... 31 31 315,500 (d) (e) 2003-2008
6.15%............................ 10 10 97,500 (d) 97,500 April 2003
6.33%............................ 5 5 46,000 (d) 46,000 July 2003
-------- --------
$ 47 $ 47
======== ========
Without Sinking Fund Requirements
4-1/2% Preferred................... $ 25 $ 25 247,658 $ 110.00
Series Preferred
3.35%............................ 2 2 20,605 103.50
4.40%............................ 11 11 117,676 102.00
4.60%............................ 3 3 28,614 103.00
6.75%............................ 9 9 90,770 (d)
-------- --------
$ 50 $ 50
======== ========
</TABLE>
Increases (Decreases) in Preferred Stock
There were no issuances or redemptions of preferred stock in 1999, 1998 or 1997.
(a) Each share of PPL Electric Utilities' preferred stock entitles the holder
to one vote on any question presented to PPL Electric Utilities'
shareowners' meetings. There were also 10,000,000 shares of PPL's preferred
stock and 5,000,000 shares of PPL Electric Utilities' preference stock
authorized; none were outstanding at December 31, 1999 and 1998.
(b) In 1997, PPL acquired 79.11% ($369 million par value) of the outstanding
preferred stock of PPL Electric Utilities in a tender offer. PPL Electric
Utilities repurchased these shares from PPL and cancelled them in August
1999, using the proceeds of securitization.
(c) The involuntary liquidation price of the preferred stock is $100 per share.
The optional voluntary liquidation price is the optional redemption price
per share in effect, except for the 4-1/2% Preferred Stock for which such
price is $100 per share (plus in each case any unpaid dividends).
(d) These series of preferred stock are not redeemable prior to the following
years: 5.95%, 2001; 6.125%, 6.15%, 6.33% and 6.75%, 2003.
(e) Shares to be redeemed annually on October 1 as follows: 2003-2007, 57,500;
2008, 28,000.
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
CONSOLIDATED STATEMENT OF COMPANY-OBLIGATED
MANDATORILY REDEEMABLE SECURITIES AT DECEMBER 31,
PPL Corporation and Subsidiaries (a)
PPL Electric Utilities Corporation and Subsidiaries (a)
(Millions of Dollars)
<TABLE>
<CAPTION>
Outstanding Outstanding
1999 1998 1999 Authorized Maturity (b)
<S> <C> <C> <C> <C> <C>
Company-Obligated Mandatorily Redeemable
Preferred Securities of Subsidiary Trusts Holding
Solely Company Debentures - $25 per security
8.10%.................. $ 150 $ 150 6,000,000 6,000,000 July 2027
8.20%.................. 100 100 4,000,000 4,000,000 April 2027
------- --------
$ 250 $ 250
======= ========
</TABLE>
(a) In 1997, PPL Electric Utilities arranged for the issuance of a total of
$250 million of company-obligated mandatorily redeemable preferred
securities of subsidiary trusts holding solely company debentures by PP&L
Capital Trust and PP&L Capital Trust II, two Delaware statutory business
trusts. These preferred securities are supported by a corresponding amount
of junior subordinated deferrable interest debentures issued by PPL
Electric Utilities to the trusts. PPL Electric Utilities owns all of the
common securities, representing the remaining undivided beneficial
ownership interest in the assets of the trusts. The proceeds derived from
the issuance of the preferred securities and the common securities were
used by PP&L Capital Trust and PP&L Capital Trust II to acquire $103
million and $155 million principal amount of Junior Subordinated Deferrable
Interest Debentures, ("Subordinated Debentures") respectively. PPL Electric
Utilities has guaranteed all of the trusts' obligations under the preferred
securities. The proceeds of the sale of these preferred securities were
loaned by PPL Electric Utilities to PPL for the tender offer for PPL
Electric Utilities preferred stock.
(b) The preferred securities are subject to mandatory redemption, in whole or
in part, upon the repayment of the Subordinated Debentures at maturity or
their earlier redemption. At the option of PPL Electric Utilities, the
Subordinated Debentures are redeemable on and after April 1, 2002 (for the
8.20% securities) and July 1, 2002 (for the 8.10% securities) in whole at
any time or in part from time to time. The amount of preferred securities
subject to such mandatory redemption will be equal to the amount of related
Subordinated Debentures maturing or being redeemed. The redemption price is
$25 per security plus an amount equal to accumulated and unpaid
distributions to the date of redemption.
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
CONSOLIDATED STATEMENT OF LONG-TERM DEBT AT DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
Outstanding
1999 1998 Maturity (b)
<S> <C> <C> <C>
First Mortgage Bonds (a)
6%.............................................. $ 125 $125 June 1, 2000
7 3/4%.......................................... 28 (c) 150 May 1, 2002
6 7/8%.......................................... 19 (c) 100 February 1, 2003
6 7/8%.......................................... 25 (c) 150 March 1, 2004
6 1/8% to 7.70%................................. 475 (c)(d) 675 2005-2009
7 3/8%.......................................... 10 (c) 100 2010-2014
9 1/4%.......................................... 28 (c) 215 2015-2019
9 3/8 to 7.30%.................................. 88 (c) 750 2020-2024
First Mortgage Pollution Control Bonds (a)
6.40% Series H.................................. 90 90 November 1, 2021
5.50% Series I.................................. 53 53 February 15, 2027
6.40% Series J.................................. 116 116 September 1, 2029
6.15% Series K.................................. 55 55 August 1, 2029
----------- -----------
1,112 2,579
Series 1999-1 Transition Bonds
6.08 to 7.15%................................... 2,390 (e) 2001-2008
Medium-Term Notes
5.75 to 7.7%..................................... 597 (f) 397 2000-2007
Pollution Control Revenue Bonds..................... 9 9 June 1, 2027
Unsecured Promissory Notes.......................... 17 18 2005-2022
Other Long-Term Debt................................ 38 (g) 2000-2015
----------- -----------
4,163 3,003
Unamortized (discount) and premium -- net........... (6) (19)
----------- -----------
4,157 2,984
Less amount due within one year.................... (468) (1)
----------- -----------
Total long-term debt............................ $ 3,689 $ 2,983
=========== ===========
</TABLE>
(a) Substantially all owned electric utility plant is subject to the lien of PPL
Electric Utilities' Mortgage.
(b) Aggregate long-term debt maturities through 2004 are (millions of dollars);
2000, $468; 2001, $315; 2002, $278; 2003, $364; 2004, $390. There are no
bonds outstanding that have sinking fund requirements.
(c) In August 1999, PPL Electric Utilities used a portion of the proceeds from
securitization to repurchase $1.467 billion of its first mortgage bonds
through tender offers and open market purchases.
(d) In May 1998, PPL Electric Utilities issued $200 million First Mortgage
Bonds, 6-1/8% Reset Put Securities Series due 2006. In connection with
issuance, PPL Electric Utilities assigned to a third party the option to
call the bonds from the holders on May 1, 2001. These bonds will mature on
May 1, 2006, but will be required to be surrendered by the existing holders
on May 1, 2001 either through the exercise of the call option by the
callholder or, if such option is not exercised, through the automatic
exercise of a mandatory put by the trustee on behalf of the bondholders.
(e) In August 1999 PP&L Transition Bond Company issued $2.42 billion of
transition bonds to securitize a portion of PPL Electric Utilities' stranded
costs. The bonds were issued in eight different classes, with expected
average lives of 1 to 8.7 years. On December 27, 1999, a $29.7 million bond
principal payment was made on Class A-1 bonds.
(f) In October 1999, PPL Capital Funding issued $200 million of medium-term
notes in the form of 7.70% Reset Put Securities due in 2007. In connection
with this issuance, PPL Capital Funding assigned to a third party an option
to call the notes from the holders on November 15, 2002. These notes will
mature on November 15, 2007, but will be required to be surrendered by the
existing holders on November 15, 2002 either through the exercise of the
call option by the callholder or, if such option is not exercised, through
the automatic exercise of a mandatory put.
(g) In 1999, PPL Global acquired additional interests in Emel and EC,
resulting in majority ownership and control of these companies. As a
result, in the third quarter PPL Global consolidated the financial
statements of Emel and EC.
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
CONSOLIDATED STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
1999 1998 1997
<S> <C> <C> <C>
Operating Revenues
Electric.............................................. $ 2,513 $ 2,410 $ 2,397
Wholesale energy marketing and trading................ 1,420 1,223 650
Energy related businesses............................. 19 10 2
---------- ---------- ----------
Total................................................. 3,952 3,643 3,049
---------- ---------- ----------
Operating Expenses
Operation
Electric fuel....................................... 445 490 476
Energy purchases for retail load and wholesale...... 1,367 1,060 504
Other............................................... 621 584 503
Amortization of recoverable transition costs........ 172
Maintenance........................................... 195 180 184
Depreciation and amortization (Note 1)................ 233 335 385
Taxes, other than income (Note 8)..................... 153 185 204
Energy related businesses............................. 17 8 3
---------- ---------- ----------
Total................................................. 3,203 2,842 2,259
---------- ---------- ----------
Operating Income........................................ 749 801 790
Other Income............................................ 97 77 12
---------- ---------- ----------
Income Before Interest and Income Taxes................. 846 878 802
Interest Expense........................................ 214 196 207
---------- ---------- ----------
Income Before Income Taxes and Extraordinary Items...... 632 682 595
Income Taxes (Note 8)................................... 151 273 247
---------- ---------- ----------
Income Before Extraordinary Items....................... 481 409 348
Extraordinary Item (net of income taxes) (Note 6)....... (46) (948)
---------- ---------- ----------
Net Income(Loss) Before Dividends on
Preferred Stock....................................... 435 (539) 348
Dividends on Preferred Stock............................ 37 48 40
---------- ---------- ----------
Earnings Available to PPL Corporation................... $ 398 ($587) $ 308
========== ========== ==========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements
<PAGE>
CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
1999 1998 1997
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income (loss)................................................... $ 435 ($539) $ 348
Extraordinary items (net of income taxes)........................... (46) (948)
---------- ---------- ----------
Net income before extraordinary items............................... 481 409 348
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation and amortization..................................... 233 335 385
Regulatory debts and credits...................................... 194 (61) (36)
Amortization of property under capital leases..................... 59 58 68
Amortization of NUG above market liability........................ (104)
Deferred income taxes and investment tax credits.................. (73) 12 20
Gain on sale of generating assets................................. (65)
Change in current assets and current liabilities.................... (73) 8 (14)
Other operating activities -- net................................... (7) (66) 15
---------- ---------- ----------
Net cash provided by operating activities...................... 645 695 786
---------- ---------- ----------
Cash Flows From Investing Activities
Expenditures for property, plant and equipment...................... (300) (297) (310)
Sales of nuclear fuel to trust...................................... 14 54 60
Sale of generating assets........................................... 99
Purchases of available-for-sale securities.......................... (15) (72)
Sales and maturities of available-for-sale securities............... 69 88
Purchases and sales of other financial investments - net............ 76
Loan to parent...................................................... (60) (375)
Other investing activities - net.................................... 1 6 (4)
---------- ---------- ----------
Net cash used in investing activities.......................... (246) (183) (537)
---------- ---------- ----------
Cash Flows From Financing Activities
Issuance of long-term debt.......................................... 2,419 200 9
Retirement of long-term debt........................................ (1,497) (266) (210)
Issuance of Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts holding
solely company debentures.......................................... 250
Capital contribution from parent.................................... 6 7
Retirement of preferred and preference stock........................ (380)
Purchase of treasury stock.......................................... (632)
Payments on capital lease obligations............................... (59) (58) (67)
Payment of common and preferred dividends........................... (231) (412) (344)
Net increase (decrease) in short-term debt.......................... 92 35 35
Other financing activities - net.................................... (90) (1) (9)
---------- ---------- ----------
Net cash used in financing activities.......................... (378) (496) (329)
---------- ---------- ----------
Net Increase (Decrease) in Cash and Cash Equivalents.................. 21 16 (80)
Cash and Cash Equivalents at Beginning of Period.................... 31 15 95
---------- ---------- ----------
Cash and Cash Equivalents at End of Period.......................... $ 52 $ 31 $ 15
========== ========== ==========
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of amount capitalized).............................. $ 202 $ 208 $ 201
Income taxes...................................................... $ 192 $ 261 $ 253
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
CONSOLIDATED BALANCE SHEET AT DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
Assets 1999 1998
<S> <C> <C>
Current Assets
Cash and cash equivalents (Note 1)......................... $ 52 $ 31
Accounts receivable (less reserve: 1999, $18; 1998, $16).. 274 230
Unbilled revenues.......................................... 275 163
Fuel, materials and supplies - at average cost............. 175 196
Prepayments................................................ 87 14
Unrealized energy trading gains............................ 26 2
Other...................................................... 78 58
-------- --------
967 694
-------- --------
Investments
Loan to parent and its affiliates.......................... 489 429
Nuclear plant decommissioning trust fund (Notes 1 and 9)... 255 206
Investment in unconsolidated affiliate at equity (Note 1).. 17 17
Other (Note 10)............................................ 15 13
-------- --------
776 665
-------- --------
Property, Plant and Equipment
Electric utility plant in service - net (Note 1)
Transmission and distribution............................ 2,193 2,179
Generation............................................... 1,620 1,601
General.................................................. 208 223
-------- --------
4,021 4,003
Construction work in progress - at cost.................... 139 117
Nuclear fuel owned and leased - net ....................... 139 162
-------- --------
Electric utility plant - net............................. 4,299 4,282
Gas and oil utility plant - net............................ 26 28
Other property - net....................................... 20 21
-------- --------
4,345 4,331
-------- --------
Regulatory Assets and Other Noncurrent Assets (Note 6)
Recoverable transition costs............................... 2,647 2,819
Other...................................................... 357 329
-------- --------
3,004 3,148
-------- --------
$ 9,092 $ 8,838
======== ========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
<TABLE>
<CAPTION>
Liabilities and Equity 1999 1998
<S> <C> <C>
Current Liabilities
Short-term debt (Note 11).......................................... $ 183 $ 91
Long-term debt..................................................... 352
Capital lease obligations.......................................... 58 59
Above market NUG contracts (Note 6)................................ 99 105
Accounts payable................................................... 284 178
Taxes and interest accrued......................................... 116 86
Dividends payable.................................................. 6 12
Unrealized energy trading losses................................... 28 9
Other.............................................................. 162 114
--------- ---------
1,288 654
--------- ---------
Long-term debt....................................................... 3,153 2,569
--------- ---------
Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes and investment tax credits (Note 8).......... 1,528 1,561
Above market NUG purchases (Note 6)................................ 674 775
Capital lease obligations.......................................... 67 109
Other (Notes 1 and 9).............................................. 739 724
--------- ---------
3,008 3,169
--------- ---------
Commitments and Contingent Liabilities (Note 16)..................
--------- ---------
Company-obligated mandatorily redeemable preferred securities of
subsidiary trust holding solely company debentures................. 250 250
--------- ---------
Preferred stock
With sinking fund requirements..................................... 47 295
Without sinking fund requirements.................................. 50 171
--------- ---------
97 466
--------- ---------
Shareowner's Common Equity
Common stock....................................................... 1,476 1,476
Additional paid-in capital......................................... 55 70
Treasury stock (Note 1)............................................ (632)
Earnings reinvested................................................ 419 210
Accumulated other comprehensive income (Note 1).................... (6) (6)
Capital stock expense and other.................................... (16) (20)
--------- ---------
1,296 1,730
--------- ---------
$ 9,092 $ 8,838
========= =========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
CONSOLIDATED STATEMENT OF SHAREOWNER'S COMMON EQUITY
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------------------
1999 1998 1997
------------- ------------ ------------
<S> <C> <C> <C>
Common stock at beginning of year.............................................. $1,476 $1,476 $1,476
Issuance of common stock..................................................
------------- ------------ ------------
Common stock at end of year.................................................... 1,476 1,476 1,476
------------- ------------ ------------
Additional paid-in capital at beginning of year ............................... 70 64 57
Capital contribution from PPL............................................. 6 7
Other..................................................................... (15)
------------- ------------ ------------
Additional paid-in capital at end of year...................................... 55 70 64
------------- ------------ ------------
Treasury stock at beginning of year............................................
Purchase of treasury stock................................................ (632)
------------- ------------ ------------
Treasury stock at end of year.................................................. (632)
------------- ------------ ------------
Earnings reinvested at beginning of year....................................... 210 1,092 1,094
Net income (loss) (b)..................................................... 398 (587) 308
Cash dividends declared on common stock................................... (189) (295) (310)
------------- ------------ ------------
Earnings reinvested at end of year............................................. 419 210 1,092
------------- ------------ ------------
Accumulated other comprehensive income at beginning of year (c)................ (6)
Unrealized gain (loss) on available-for sale securities (b)............... (3) 2
Minimum pension liability adjustment (b)................................. (3) (2)
------------- ------------ ------------
Accumulated other comprehensive income at end of year.......................... (6) (6) -
------------- ------------ ------------
Capital stock expense at beginning of year..................................... (20) (20) (10)
Other..................................................................... 4 (10)
------------- ------------ ------------
Capital stock expense at end of year........................................... (16) (20) (20)
------------- ------------ ------------
Total Shareowner's Common Equity............................................... $1,296 $1,730 $2,612
============= ============ ============
Common stock shares (thousands) at beginning of year (a)....................... 157,300 157,300 157,300
Treasury stock purchased.................................................. (55,070)
------------- ------------ ------------
Common stock shares at end of year............................................. 102,230 157,300 157,300
============= ============ ============
(a) No par value. 170,000 thousand shares authorized. All common shares of PPL Electric Utilities stock are owned by PPL.
(b) Statement of Comprehensive Income (Note 1):
Net income (loss)......................................................... $398 ($587) $308
Other comprehensive income, net of tax:
Unrealized gain (loss) on available-for-sale securities.............. (3) 2
Minimum pension liability adjustment................................. (3) (2)
------------- ------------ ------------
Total other comprehensive income.......................................... (6)
------------- ------------ ------------
Comprehensive Income...................................................... $398 ($593) $308
============= ============ ============
</TABLE>
(c) See Note 1 for disclosure of balances for each component of Accumulated
Other Comprehensive Income.
The accompanying Notes to Consolidated Financial Statements are an integral
part of the financial statements.
<PAGE>
CONSOLIDATED STATEMENT OF PREFERRED STOCK AT DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries(a)
(Millions of Dollars)
<TABLE>
<CAPTION>
Shares
Outstanding Outstanding Shares
1999 1998 1999 Authorized
<S> <C> <C> <C> <C>
Preferred Stock -- $100 par, cumulative
4-1/2%........................... $ 25 $ 53 247,658 629,936
Series........................... 72 413 726,665 10,000,000
-------- --------
$ 97 $ 466
======== ========
</TABLE>
Details of Preferred Stock (b)
<TABLE>
<CAPTION>
Sinking Fund
Optional Provisions
Shares Redemption Shares to be
Outstanding Outstanding Price Per Redeemed Redemption
1999 1998 1999 Share Annually Period
<S> <C> <C> <C> <C> <C> <C>
With Sinking Fund Requirements
Series Preferred
5.95% ........................... $ 1 $ 30 10,000 (c) 10,000 April 2001
6.05%............................ 25
6.125% .......................... 31 115 315,500 (c) (d) 2003-2008
6.15%............................ 10 25 97,500 (c) 97,500 April 2003
6.33% ........................... 5 100 46,000 (c) 46,000 July 2003
------- --------
$ 47 $ 295
======= ========
Without Sinking Fund Requirements
4-1/2% Preferred................... $ 25 $ 53 247,658 $110.00
Series Preferred
3.35%............................ 2 4 20,605 103.50
4.40%............................ 11 23 117,676 102.00
4.60%............................ 3 6 28,614 103.00
6.75%............................ 9 85 90,770 (c)
------- --------
$ 50 $ 171
======= ========
</TABLE>
Increases (Decreases) in Preferred Stock
<TABLE>
<CAPTION>
1999
Shares Amount
<S> <C> <C>
4-1/2% Preferred..................... (282,531) $ (28)
Series Preferred
3.35%........................... (21,178) (2)
4.40%........................... (111,097) (12)
4.60%........................... (34,386) (3)
5.95%........................... (290,000) (29)
6.05%........................... (250,000) (25)
6.125%.......................... (834,500) (84)
6.15%........................... (152,500) (15)
6.33%........................... (954,000) (95)
6.75%........................... (759,230) (76)
</TABLE>
Decreases in Preferred Stock normally represent: (i) the redemption of stock
pursuant to sinking fund requirements; or (ii) shares redeemed pursuant to
optional redemption provisions. There were no issuances or redemptions of
preferred stock in 1998 through these provisions. The decreases in 1999
indicated above represent PPL Electric Utilities' purchase and cancellation of
its preferred stock which had been held by PPL. PPL Electric Utilities used $380
million of securitization proceeds to effect this repurchase.
(a) Each share of PPL Electric Utilities' preferred stock entitles the holder
to one vote on any question presented to PPL Electric Utilities'
shareowners' meetings. There were 5,000,000 shares of PPL Electric
Utilities' preference stock authorized; none were outstanding at December
31, 1999 and 1998, respectively.
(b) The involuntary liquidation price of the preferred stock is $100 per share.
The optional voluntary liquidation price is the optional redemption price
per share in effect, except for the 4-1/2% Preferred Stock for which such
price is $100 per share (plus in each case any unpaid dividends).
(c) These series of preferred stock are not redeemable prior to the following
years: 5.95%, 2001; 6.125%, 6.15%, 6.33% and 6.75%, 2003.
(d) Shares to be redeemed annually on October 1 as follows: 2003-2007, 57,500;
2008, 28,000
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
CONSOLIDATED STATEMENT OF LONG-TERM DEBT AT DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
Outstanding
1999 1998 Maturity (b)
<S> <C> <C> <C>
First Mortgage Bonds (a)
6% ................................................... $ 125 $ 125 June 1, 2000
7 3/4%................................................ 28 (c) 150 May 1, 2002
6 7/8%................................................ 19 (c) 100 February 1, 2003
6 7/8%................................................ 25 (c) 150 March 1, 2004
6 1/8% to 7.70%....................................... 475 (c)(d) 675 2005-2009
7 3/8%................................................ 10 (c) 100 2010-2014
9 1/4%................................................ 28 (c) 215 2015-2019
9 3/8 to 7.30%........................................ 88 (c) 750 2020-2024
First Mortgage Pollution Control Bonds (a)
6.40% Series H...................................... 90 90 November 1, 2021
5.50% Series I...................................... 53 53 February 15, 2027
6.40% Series J...................................... 116 116 September 1, 2029
6.15% Series K...................................... 55 55 August 1, 2029
------ ------
1,112 2,579
Series 1999-1 Transition Bonds
6.08 to 7.15%....................................... 2,390 (e) 2001-2008
Pollution Control Revenue Bonds....................... 9 9 June 1, 2027
------ ------
3,511 2,588
Unamortized (discount) and premium -- net ............ (6) (19)
------ ------
3,505 2,569
Less amount due within one year....................... (352)
------ ------
Total Long-term debt................................ $3,153 $2,569
====== ======
</TABLE>
(a) Substantially all owned electric utility plant is subject to the lien of
PPL Electric Utilities' Mortgage.
(b) Aggregate long-term debt maturities through 2004 are (millions of dollars);
2000, $352; 2001, $240; 2002, $274; 2003, $275; 2004, $288. There are no
bonds outstanding that have sinking fund requirements.
(c) In August 1999, PPL Electric Utilities used a portion of the proceeds from
securitization to repurchase $1.467 billion of its first mortgage bonds
through tender offers and open market purchases.
(d) In May 1998, PPL Electric Utilities issued $200 million First Mortgage
Bonds, 6-1/8% Reset Put Securities Series due 2006. In connection with
issuance, PPL Electric Utilities assigned to a third party the option to
call the bonds from the holders on May 1, 2001. These bonds will mature on
May 1, 2006, but will be required to be surrendered by the existing holders
on May 1, 2001 either through the exercise of the call option by the
callholder or, if such option is not exercised, through the automatic
exercise of a mandatory put by the trustee on behalf of the bondholders.
(e) In August 1999 PP&L Transition Bond Company issued $2.42 billion of
transition bonds to securitize a portion of PPL Electric Utilities'
stranded costs. The bonds were issued in eight different classes, with
expected average lives of 1 to 8.7 years. On December 27, 1999, a $29.7
million bond principal payment was made on Class A-1 bonds.
The accompanying Notes to Consolidated Financial Statements are an integral part
of the financial statements.
<PAGE>
NOTES TO FINANCIAL STATEMENTS
Terms and abbreviations appearing in Notes to Financial Statements are
explained in the glossary.
1. Summary of Significant Accounting Policies
Business and Consolidation
At December 31, 1999, PPL was the parent holding company of PPL Electric
Utilities, PPL Global, PPL Montana, PPL Gas Utilities, PPL Capital Funding, PPL
Spectrum, H.T. Lyons, McClure, McCarl's and Western Mass. Holdings.
The financial condition and results of operations of PPL Electric Utilities
(including its subsidiary PPL EnergyPlus) and PPL Global are currently the
principal factors affecting PPL's financial condition and results of operations.
PPL Electric Utilities generates electricity, provides electricity delivery
service in eastern and central Pennsylvania, sells retail electricity throughout
Pennsylvania and deregulated markets, and trades or markets wholesale energy in
the United States and Canada. PPL Global develops electricity generation and
delivery projects worldwide.
PPL consolidates the financial statements of its affiliates when it has
majority ownership and control. All significant intercompany transactions have
been eliminated. Minority interests in operating results and equity ownership
are reflected in the consolidated financial statements.
The consolidated financial statements reflect the accounts of all
controlled affiliates on a current basis, with the exception of PPL Global's
investments in Emel and EC, which are included on a one-month lag. PPL Global's
investment in WPD (formerly SWEB) is accounted for using the equity method and
reported on a one-month lag. PPL Global has a 51% equity ownership interest in
WPD but lacks voting control. (See Note 3.) Less than 50% owned affiliates are
accounted for using the equity method, reported on a one-quarter lag. These
reporting lags are required because financial statements from these investments
are not timely for PPL Global to apply the equity method currently.
When ownership interest in an affiliate increases through a series of
acquisitions and subsequently results in control, as was the case for PPL
Global's investments in Emel and EC, the equity method of accounting ceases to
apply. In accordance with Accounting Research Bulletin 51, "Consolidated
Financial Statements," the affiliate's results are included in the consolidated
financial statements as though it were acquired at the beginning of the year.
The portion of the affiliate's earnings owned by outside shareowners prior to
PPL achieving control is included in "Minority Interest" on the Consolidated
Statement of Income.
Reclassification
Certain amounts in the 1998 and 1997 financial statements have been
reclassified to conform to the current presentation. The Consolidated Balance
Sheet has been reclassified, with components
<PAGE>
presented in order of liquidity. This change recognizes the increasing
significance of PPL's unregulated activities. The Consolidated Statement of
Shareowner's Common Equity has also been reclassified in connection with SFAS
130, "Reporting Comprehensive Income."
Earnings Per Share
SFAS 128, "Earnings Per Share," requires the disclosure of basic and
diluted EPS. Basic EPS is calculated by dividing earnings available to common
shareowners ("Net Income" on the PPL's Consolidated Statement of Income) by the
weighted average number of common shares outstanding during the period. In the
calculation of diluted EPS, weighted average shares outstanding are increased
for additional shares that would be outstanding if potentially dilutive
securities were converted to common stock. In April 1999, PPL made its initial
award of stock options under its Incentive Compensation Plan. (See Note 13 to
Financial Statements.) Stock options are the only potentially dilutive
securities outstanding, but had no impact on 1999 EPS. For the twelve months
ended December 31, 1999 and 1998, the weighted average shares outstanding (in
thousands) were 152,287 and 164,651, respectively.
Management's Estimates
These financial statements were prepared using management's best estimates
of existing conditions. Actual results could differ from these estimates.
Accounting Records
The accounting records for PPL Electric Utilities and PPL Gas Utilities are
maintained in accordance with the Uniform System of Accounts prescribed by the
FERC and adopted by the PUC.
Regulation
Historically, PPL Electric Utilities accounted for its operations in
accordance with the provisions of SFAS 71, which requires rate-regulated
entities to reflect the effects of regulatory decisions in their financial
statements. PPL Electric Utilities discontinued application of SFAS 71 for the
generation portion of its business, effective June 30, 1998. PPL Gas Utilities
continues to be subject to SFAS 71.
<PAGE>
Electric Utility Plant in Service
Following are the classes of PPL's Electric Utility Plant in Service with
associated accumulated depreciation reserves, at December 31, 1999 and 1998
(millions of dollars):
<TABLE>
<CAPTION>
Transmission
and
Distribution Generation General Total
------------ ---------- ------- -----
<S> <C> <C> <C> <C>
December 31, 1999:
Basis $ 3,836 $ 6,837 $ 415 $11,088
Accumulated Depreciation (1,374) (4,485) (156) (6,015)
------- ------- ------- -------
$2,462 $ 2,352 $ 259 $ 5,073
======= ======= ======= =======
December 31, 1998:
Basis $ 3,395 $ 6,351 $ 383 $10,129
Accumulated Depreciation (1,216) (4,750) (160) (6,126)
------- ------- ------- -------
$2,179 $ 1,601 $ 223 $ 4,003
======= ======= ======= =======
</TABLE>
Electric Utility Plant in Service is recorded at original cost, unless
impaired, in which case the plant's basis is reduced to its estimated fair
value. Property, plant and equipment acquired is recorded at the fair market
value at acquisition date. Generation plant is reflected at the lower of cost or
market value, as these assets are no longer subject to the provisions of SFAS
71. The other classes of Electric Utility Plant in Service, as well as items
capitalized subsequent to an acquisition, are recorded at historical cost.
AFUDC is capitalized as part of the construction costs for regulated
projects. Capitalized interest is recorded for generation-related projects.
The cost of repairs and replacements are charged to expense as incurred for
non-regulated projects. When regulated property, plant and equipment is
retired, the original cost plus the cost of retirement, less salvage, is charged
to accumulated depreciation. When entire regulated operating units are sold or
non-regulated plant is retired or sold, the costs of such assets and the related
accumulated depreciation are removed from the balance sheet and the gain or
loss, if any, is included in income, unless otherwise required by the FERC.
Depreciation is computed over the estimated useful lives of property using
various methods including the straight-line, composite, and group methods. PPL
Electric Utilities' provisions for depreciation, as a percent of average gross
depreciable property, approximated 2.1% in 1999, 3.7% in 1998 and 3.8% in 1997.
Amortization of Goodwill
Goodwill, which is included in "Regulatory Assets and Other Non-Current
Assets" on the Consolidated Balance Sheet, is amortized on a straight-line basis
over a 40-year period. Goodwill capitalized as part of PPL Global's investments
in unconsolidated affiliates is also being amortized over a 40-year period.
<PAGE>
Nuclear Decommissioning and Fuel Disposal
An annual provision for PPL Electric Utilities' share of the future cost to
decommission the Susquehanna station, equal to the amount allowed for ratemaking
purposes, is charged to depreciation expense. Such amounts are invested in
external trust funds which can be used only for future decommissioning costs.
See Note 9.
Recoverable Transition Costs
Based on the PUC Final Order, PPL Electric Utilities was amortizing its
competitive transition (or stranded) costs over an eleven-year transition period
beginning January 1, 1999 and ending December 31, 2009. In August 1999,
competitive transition costs of $2.402 billion were converted to intangible
transition costs when securitized by the issuance of transition bonds. The
intangible transition costs are being amortized over the life of the transition
bonds - August 1999 through December 2008, in accordance with an amortization
schedule filed with the PUC. The remaining competitive transition costs are
also being amortized based on an amortization schedule previously filed with the
PUC, adjusted for those competitive transition costs that were converted to
intangible transition costs. As a result of the conversion of a significant
portion of the competitive transition costs into intangible transition costs,
amortization of substantially all of the remaining competitive transition costs
will occur in 2009.
Liability for Above Market NUG Contracts
At June 30, 1998, PPL Electric Utilities recorded an estimated liability
for above market contracts with NUGS. Effective January 1999, PPL Electric
Utilities began reducing this liability as an offset to "Energy Purchases" on
the Consolidated Statement of Income. This reduction is based on the estimated
timing of the purchases from the NUGs and projected market prices for this
generation. This accounting will continue through 2014, when the last of the
existing NUG contracts expires.
Accounting for Price Risk Management
PPL engages in price risk management activities for both energy trading and
non-trading activities as defined by EITF 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities." In 1999, PPL
entered into commodity forward and financial contracts for the physical purchase
and sale of energy as well as energy contracts that can be settled financially.
In 1998, these instruments were reflected in the financial statements using the
accrual method of accounting. As of January 1, 1999, PPL adopted mark-to-market
accounting for energy trading contracts, in accordance with EITF 98-10, and
gains and losses from changes in market prices are reflected in "Energy
Purchases" on the Consolidated Statement of Income.
PPL will continue to use EITF 98-10 to account for its commodity forward
and financial contracts until it adopts SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities" effective on January 1, 2001. At that time,
PPL will change the accounting for any
<PAGE>
of its outstanding contracts that qualify as derivatives under SFAS 133.
PPL and PPL Electric Utilities entered into forward starting swaps and
treasury locks to hedge the interest rate risk associated with debt issuances.
The gains or losses on these swaps have been deferred and are being recognized
over the life of the debt, in accordance with SFAS 80, "Accounting for Futures
Contracts."
PPL or its subsidiaries also enter into foreign currency exchange contracts
to hedge future cash flows for firm transactions and commitments and to hedge
economic exposures such as anticipated dividends and projected asset sales or
acquisitions when there is a high degree of certainty that the exposure will be
realized. Until PPL adopts SFAS 133, market gains and losses are recognized in
accordance with SFAS 52, "Foreign Currency Translation," and are included in
accumulated other comprehensive income on the Consolidated Balance Sheet.
Leases
Leased property of PPL Electric Utilities capitalized on the Consolidated
Balance Sheet consists solely of nuclear fuel. Future lease payments for
nuclear fuel are based on the quantity of electricity produced at the
Susquehanna station. These payments are expected to approximate $50 to $59
million per year through 2004. The maximum amount of nuclear fuel available for
lease under current arrangements is $200 million. Payments on other leased
property, which are classified as operating leases, are projected at $28 million
per year through 2004. These leases included vehicles, personal computers and
other equipment.
Revenue Recognition
"Electric," "Natural Gas and Propane," and "Wholesale Energy Marketing and
Trading" revenues are recorded based on deliveries through the end of the
calendar month.
"Energy-Related Businesses" revenue includes PPL Global, PPL Spectrum, and
the mechanical contracting and engineering subsidiaries. PPL Global's revenue
reflects its proportionate share of affiliate earnings under the equity method
of accounting, as described in the Business and Consolidation section of this
Note 1. PPL Spectrum and the mechanical contracting and engineering
subsidiaries record profits from construction contracts on the percentage-of-
completion method of accounting. Under the percentage-of-completion method, the
relationship of actual costs incurred to total estimated costs of the contracts
is applied to total income to be derived from the contracts. Income from time
and material contracts is recognized currently as the work is performed. Costs
include all direct material and labor costs and job-related overhead.
Provisions for estimated loss on uncompleted contacts, if any, are made in the
period in which such losses are determined.
<PAGE>
Income Taxes
The provision for PPL Electric Utilities' deferred income taxes for
regulated assets is based upon the ratemaking principles reflected in rates
established by the PUC and FERC. The difference in the provision for deferred
income taxes for regulated assets and the amount that otherwise would be
recorded under generally accepted accounting principles is deferred and included
in taxes recoverable through future rates on the Consolidated Balance Sheet.
See Note 8.
PPL Electric Utilities deferred the investment tax credits when utilized,
and is amortizing the deferrals over the average lives of the related assets.
PPL and its subsidiaries file a consolidated federal income tax return.
Pensions and Other Postretirement and Postemployment Benefits
The subsidiaries of PPL have noncontributory pension plans covering
substantially all employees. Funding is based on actuarially determined
computations that consider the amount deductible for income tax purposes and the
minimum contribution required under the Employee Retirement Income Security Act
of 1974.
The company also provides for certain health care and life insurance
benefits for retired employees and inactive employees covered by disability
plans. See Note 14 for details presented in conformity with SFAS 132
"Employers' Disclosures about Pensions and Other Postretirement Benefits."
Cash Equivalents
All highly liquid debt instruments purchased with original maturities of
three months or less are considered to be cash equivalents.
Comprehensive Income
Comprehensive income consists of net income and other comprehensive income,
defined as changes in common equity from transactions not related to
shareowners. For PPL Electric Utilities, other comprehensive income consists of
unrealized gains or losses on available-for-sale securities and the excess of
additional pension liability over unamortized prior service costs. The other
comprehensive income of PPL consists of the foregoing as well as foreign
currency translation adjustments recorded by PPL Global. In accordance with
SFAS 130, comprehensive income is reflected on the Consolidated Statement of
Shareowners' Common Equity, and "Accumulated Other Comprehensive Income" is
presented on the Consolidated Balance Sheet.
The accumulated other comprehensive income of PPL at December 31, 1999
consists of (in millions): foreign currency translation adjustments, ($50);
unrealized gains on available-for-sale securities, $1; and adjustments to
minimum pension liability, ($6). Accumulated other comprehensive income was not
significant at December 31, 1998.
<PAGE>
Treasury Stock
Treasury shares are reflected on the Consolidated Balance Sheet as an
offset to common equity under the cost method of accounting. Management has no
definitive plans for the future use of these shares. Treasury shares are not
considered outstanding in calculating earnings per share.
Foreign Currency Translation
All assets and liabilities of foreign subsidiaries are translated at
period-end exchange rates. Income and expense items are translated at average
exchange rates prevailing during the relevant periods. The resulting translation
adjustments are recorded as a component of "Accumulated Other Comprehensive
Income." Gains or losses related to foreign currency transactions are recognized
in income currently.
2. Segment and Related Information
PPL's principal business segment is PPL Electric Utilities, which (in
conjunction with PPL EnergyPlus) provides electricity delivery service in
eastern and central Pennsylvania, sells retail electricity throughout
Pennsylvania and deregulated electricity markets, and markets wholesale
electricity in the United States and Canada. PPL's other reportable business
segment, PPL Global (excluding the Montana generating assets acquired in 1999,
which are owned by PPL Montana and not consolidated with PPL Global for
financial reporting purposes), invests in and develops worldwide power projects,
with the majority of its international investments located in the U.K., Chile,
and El Salvador. PPL Global also owns and operates generating facilities in the
United States. PPL Global's revenue represents equity earnings in unconsolidated
investments, revenues from the sale of generation to wholesale customers, and
revenue from the delivery of electricity to retail customers. Other operating
revenues of PPL represent gas distribution, unregulated generating activities
(including PPL Montana), mechanical contracting and engineering, and unregulated
energy services. Financial data for PPL's business segments were as follows
(millions of dollars):
<PAGE>
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Income Statement data
Operating revenues
PPL Electric Utilities $3,952 $3,643 $3,049
PPL Global 330 47 32
Other and Eliminations 308 96 (4)
------ ------ ------
4,590 3,786 3,077
Depreciation and amortization
PPL Electric Utilities 233 335 385
PPL Global 18
Other and Eliminations 6 3
------ ------ ------
257 338 385
Interest expense
PPL Electric Utilities 214 196 207
PPL Global 44 22 8
Other and Eliminations 19 12
------ ------ ------
277 230 215
Income taxes
PPL Electric Utilities 151 273 247
PPL Global 29 (4) (3)
Other and Eliminations (6) (10) (7)
------ ------ ------
174 259 237
Extraordinary items, net of taxes
PPL Electric Utilities (46) (948)
PPL Global
Other and Eliminations
------ ------ ------
(46) (948)
Net income (loss) - actual
PPL Electric Utilities 398 (587) 308
PPL Global 37 15 (17)
Other and Eliminations (3) 3 5
------ ------ ------
432 (569) 296
Net income (loss)- excluding
one-time adjustments (a)
PPL Electric Utilities 337 304 308
PPL Global 24 6 10
Other and Eliminations (3) 10
------ ------ ------
$ 358 $ 310 $ 328
<CAPTION>
(a) One-time adjustments:
additions to (deductions from)
net income 1999 1998 1997
---- ---- ----
<C> <C> <C>
PPL Electric Utilities
Sale of Sunbury plant and
related assets $ 42
Securitization 19
PUC restructuring charge (915)
FERC municipality settlement (32)
SER settlement 18
Other impacts of restructuring 38
------ ------ ------
61 (891)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PPL Global
<S> <C> <C> <C>
SWEB sale of supply business 64
Writedown of carrying value
of certain investments (51)
U.K. income tax rate reduction 9 10
Windfall profits tax (37)
------ ------ ------
13 9 (27)
Other and Eliminations
PPL Gas Utilities
acquisition costs 3 (5)
------ ------ ------
$ 3 $ (5)
</TABLE>
- -----------------------------------------------------------------
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Cash Flow data
Expenditures for property,
plant & equipment
PPL Electric Utilities $ 300 $ 297 $ 310
PPL Global 4
Other and Eliminations 14 7
------ ------ ------
318 304 310
Investment in generating assets
and electric energy projects
PPL Electric Utilities
PPL Global 315 306 152
Other and Eliminations 780
------ ------ ------
$1,095 $ 306 $ 152
- -----------------------------------------------------------------
1999 1998
---- ----
<S>
Balance Sheet data
Cumulative net investment in
unconsolidated affiliates
PPL Electric Utilities $ 17 $ 17
PPL Global 407 671
Other and Eliminations
------ ------
424 688
Total assets
PPL Electric Utilities 9,092 8,838
PPL Global 1,424 757
Other and Eliminations 658 12
------ ------
$11,174 $9,607
</TABLE>
3. Investments in Unconsolidated Affiliates
PPL's investments in unconsolidated affiliates were $424 million and $688
million at December 31, 1999 and 1998, respectively. The most significant
investment was PPL Global's investment in WPD, which was $303 million at
December 31, 1999 and $373 million at December 31, 1998. At December 31, 1999
PPL Global had a 51% equity ownership interest in WPD but lacked voting
control. Accordingly, PPL Global accounts for its investment in WPD (and other
investments where it has majority ownership but lacks voting control), under the
equity method of accounting. The December 31, 1998 balance included PPL Global's
$243 million investment in Emel and EC. In 1999 PPL Global acquired a
controlling interest in these affiliates, and consolidated their
<PAGE>
financial results. See Note 1 for additional information regarding
consolidation.
Investments in unconsolidated affiliates at December 31, 1999, and the
effective equity ownership percentages, are as follows:
Bolivian Generating Group, LLC - 29.3%
Latin American Energy & Electricity Fund I, LP - 16.6%
Aguaytia Energy, LLC - 11.4%
WPD Holdings UK - 51%
Hidrocentrais Reunidas, LDA - 50%
Hidro Iberica, B. V. - 50%
Bangor Pacific Hydro Associates - 50%
Southwest Power Partners, LLC - 50%
PPLG Lux Finance, S.a.r.l. - 53.4%
Safe Harbor Water Power Corporation - 33.3%
Summarized below is financial information from the financial statements of
these affiliates, as comprehended in the PPL consolidated financial statements
for the periods noted: (for purpose of comparability, the summarized information
of Emel and EC is excluded from all periods.)
(in millions of dollars)
Balance Sheet Data
- ------------------
<TABLE>
<CAPTION>
December 31
1999 1998
---- ----
<S> <C> <C>
Current Assets $ 389 $ 236
Noncurrent Assets 3,340 3,227
Current Liabilities 367 409
Noncurrent Liabilities 1,890 2,044
</TABLE>
<TABLE>
<CAPTION>
Income Statement Data
- ---------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Revenues $1,130 $1,206 $1,292
Operating Income 212 188 181
Net Income (Loss) 427 137 (14)
</TABLE>
4. PUC Restructuring Proceeding
In August 1998, the PUC entered its Final Order approving the settlement of
PPL Electric Utilities' restructuring proceeding under Pennsylvania's Customer
Choice Act. Among other things, that Order:
. permitted PPL Electric Utilities to recover $2.97 billion (on a net
present value basis) in stranded costs over 11 years - i.e., from
January 1, 1999 through December 31, 2009. PPL Electric Utilities'
stranded costs are those which would have been recoverable under
traditional rate regulation, but may not be recoverable in the
competitive marketplace. PPL Electric Utilities was permitted a return
of 10.86% on the unamortized balance of these stranded costs.
. authorized PPL Electric Utilities to issue transition bonds to
securitize up to $2.85 billion of its stranded costs. In
<PAGE>
August 1999, PP&L Transition Bond Company issued $2.42 billion of
transition bonds.
. required PPL Electric Utilities to reduce rates to all retail
customers by four percent effective January 1, 1999 through December
31, 1999.
. required PPL Electric Utilities to unbundle its retail electric rates
beginning on January 1, 1999, to reflect separate prices for the
transmission and distribution charges, the CTC, the ITC, and the
generation charge. The CTC is a charge paid by all customers who
receive delivery service from PPL Electric Utilities, to recover PPL
Electric Utilities' stranded costs. The ITC, which offsets the CTC on
customer bills, is a charge paid by delivery customers to reflect the
securitization of stranded costs.
. required PPL Electric Utilities to transfer its retail marketing
function to a new subsidiary, PPL EnergyPlus. PPL EnergyPlus has a PUC
license to act as a Pennsylvania EGS. This license permits PPL
EnergyPlus to offer retail electric supply to participating customers
in PPL Electric Utilities' service territory and in the service
territories of other Pennsylvania utilities. In 1999, PPL EnergyPlus
offered energy to industrial and commercial customers in Pennsylvania
and in other states that have opened their markets to competitive
suppliers.
. permitted, but did not require, PPL Electric Utilities to transfer
ownership and operation of its generating facilities to a separate
corporate entity at book value.
5. Securitization
In August 1999, PP&L Transition Bond Company issued $2.42 billion of
transition bonds to securitize a portion of PPL Electric Utilities' stranded
costs. The bonds were issued in eight different classes, with expected average
lives of 1 to 8.7 years. PP&L Transition Bond Company, a special purpose
Delaware limited liability company, was formed for the purpose of purchasing and
owning ITP, and pledging its interest in ITP to a trustee to collateralize
transition bonds. The assets of PP&L Transition Bond Company, including the
ITP, are not available to creditors of PPL or PPL Electric Utilities. The
transition bonds are obligations of PP&L Transition Bond Company and are non-
recourse to PPL and PPL Electric Utilities.
PPL Electric Utilities used a portion of the securitization proceeds to
acquire equity held by PPL, including $380 million of preferred stock and $481
million of common stock. In addition, PPL Electric Utilities used a portion of
the proceeds to repurchase $1.467 billion of its first mortgage bonds through
tender offers and open market purchases. In August 1999, PPL Electric Utilities
recorded an extraordinary charge of $59 million for the premiums and related
expenses to extinguish this first mortgage debt. See Note 6 for additional
information.
PPL used $417 million of the proceeds it received from PPL Electric
Utilities to purchase 14 million shares of its common stock.
<PAGE>
PPL Electric Utilities' customers will benefit from securitization through
an expected average rate reduction of approximately one percent for the period
the transition bonds are outstanding. With securitization, a substantial portion
of the CTC has been replaced with an ITC, which passes 75% of the net financing
savings back to customers. The actual reduction will vary by year, by customer
class and by level of use.
In December 1999, the PUC approved PPL Electric Utilities' calculation of
ITC under-recoveries for the period from August through November 1999. PPL
Electric Utilities calculated ITC under-recoveries of $14.5 million for this
period. The PUC accepted rates proposed by PPL Electric Utilities to implement
new ITC rates to collect these under-recoveries in 2000.
6. Extraordinary Items
PUC Restructuring and FERC Settlement
Historically, PPL Electric Utilities prepared its financial statements for
its regulated operations in accordance with SFAS 71, which requires rate-
regulated companies to reflect the effects of regulatory decisions in their
financial statements. PPL Electric Utilities deferred certain costs pursuant to
rate actions of the PUC and the FERC and recovered, or expected to recover, such
costs in electric rates charged to customers.
The EITF addressed the appropriateness of the continued application of SFAS
71 by entities in states that have enacted restructuring legislation similar to
Pennsylvania's Customer Choice Act. The EITF came to a consensus on Issue No.
97-4, "Deregulation of the Pricing of Electricity - Issues Related to the
Application of FASB Statements 71 and 101," which concluded that an entity
should cease to apply SFAS 71 when a deregulation plan is in place and its terms
are known. For PPL Electric Utilities, with respect to the generation portion
of its business, this occurred effective June 30, 1998 based upon the outcome of
the PUC restructuring proceeding. PPL Electric Utilities adopted SFAS 101 for
the generation side of its business. SFAS 101 required a determination of
impairment of plant assets performed in accordance with SFAS 121, and the
elimination of all effects of rate regulation that were recognized as assets and
liabilities under SFAS 71.
PPL Electric Utilities performed impairment tests of its electric
generation assets on a plant specific basis and determined that $2.388 billion
of its generation plant was impaired at June 30, 1998. Impaired plant was the
excess of the net plant investment at June 30, 1998 over the present value of
the net cash flows during the remaining lives of the plants. Annual net cash
flows were determined by comparing estimated generation sustenance costs to
estimated regulated revenues for the remainder of 1998, market revenues for 1999
and beyond, and revenues from bulk power contracts. The net cash flows were
then discounted to present value.
In addition to the impaired generation plant, PPL Electric Utilities
estimated that there were other stranded costs totaling
<PAGE>
$1.989 billion at June 30, 1998. This primarily included generation-related
regulatory assets and liabilities and an estimated liability for above-market
purchases under NUG contracts. The total estimated impairment described above
was $4.377 billion. The PUC's Final Order in the restructuring proceeding,
entered on August 27, 1998, permitted the recovery of $2.819 billion through the
CTC on a present value basis, excluding amounts for nuclear decommissioning and
consumer education, resulting in a net under-recovery of $1.558 billion. PPL
Electric Utilities recorded an extraordinary charge for this under-recovery in
June 1998.
Under FERC Order 888, 16 small utilities which had power supply agreements
with PPL Electric Utilities signed before July 11, 1994, requested and were
provided with PPL Electric Utilities' current estimate of its stranded costs
applicable to these customers if they were to terminate their agreements in
1999. Subject to certain conditions, FERC-approved settlement agreements
executed with 15 of these customers provide for continued power supply by PPL
Electric Utilities through January 2004. As a result of these settlements, PPL
Electric Utilities, in the second quarter of 1998, recorded an extraordinary
charge in the amount of $56 million.
The extraordinary items related to the PUC restructuring proceeding and the
FERC settlement are reflected on the Consolidated Statement of Income, net of
income taxes.
Details of amounts written-off in June 1998 were as follows (millions of
dollars):
<TABLE>
<S> <C>
Impaired generation-related assets $ 2,388
Above-market NUG contracts 854
Generation-related regulatory assets and other 1,135
-------
Total 4,377
Recoverable transition costs (a) (2,819)
-------
Extraordinary item pre-tax - PUC 1,558
- FERC 56
-------
1,614
Tax effects (666)
-------
Extraordinary items $ 948
=======
</TABLE>
(a) Excluding recoveries for nuclear decommissioning and consumer education
expenditures.
PPL Electric Utilities believes that the electric transmission and
distribution operations continue to meet the requirements of SFAS 71 and that
regulatory assets associated with these operations will continue to be recovered
through rates from customers. At December 31, 1999, $309 million of net
regulatory assets, other than the recoverable transition costs, remain on PPL
Electric Utilities' books. These regulatory assets will continue to be
recovered through regulated transmission and distribution rates over periods
ranging from one to 30 years.
Extinguishment of Debt
SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt," requires
that a material aggregate gain or loss from the
<PAGE>
extinguishment of debt be classified as an extraordinary item, net of the
related income tax effect.
As explained in Note 5, PPL Electric Utilities repurchased $1.467 billion
of first mortgage bonds in August 1999, using the proceeds from the issuance of
transition bonds. PPL Electric Utilities recorded an extraordinary charge of $59
million for the premiums and related expenses to reacquire these first mortgage
bonds. Details of this extraordinary charge were as follows (millions of
dollars):
<TABLE>
<CAPTION>
<S> <C>
Reacquisition cost of debt $ 1,554
Net carrying amount of debt (1,454)
-------
Extraordinary charge pre-tax 100
Tax effects (41)
-------
Extraordinary charge $ 59
=======
</TABLE>
The extraordinary charge related to extinguishment of debt was partially
offset in December 1999 with a credit relating to wholesale power activity.
7. Sales to Other Electric Utilities
PPL Electric Utilities provided JCP&L with 189,000 kilowatts of capacity
and related energy from all of its generating units during 1999. This agreement
terminated on December 31, 1999. PPL Electric Utilities is reselling the
returning capacity and energy through its Energy Marketing Center. Under a
separate agreement, PPL Electric Utilities is providing additional capacity and
energy to JCP&L. This capacity and energy sale increased from 200,000 kilowatts
to 300,000 kilowatts in June 1999 and continues at this level through May 2004.
Prices for this capacity and energy are market-based.
In August 1999, the FERC approved new interconnection and power supply
agreements between PPL Electric Utilities and UGI. Under the new power supply
agreement, effective August 1999, UGI purchases capacity from PPL Electric
Utilities equal to UGI's PJM capacity obligation less the capacity reserve value
of UGI's owned generation and an existing power purchase agreement. In 2000,
UGI will purchase a firm block of energy in addition to the capacity. The
agreement terminates in February 2001.
PPL Electric Utilities provides BG&E with 129,000 kilowatts, or 6.6%, of
its share of capacity and related energy from the Susquehanna station. Sales to
BG&E will continue through May 2001.
8. Income and Other Taxes
For 1999, 1998 and 1997 the corporate federal income tax rate was 35%, and
the PA corporate net income tax rate was 9.99%.
<PAGE>
The tax effects of significant temporary differences comprising PPL's net
deferred income tax liability were as follows (millions of dollars):
<TABLE>
<CAPTION>
PPL Electric
PPL Utilities
--- ----------------
1999 1998 1999 1998
------- ------- ------- -------
<S> <C> <C> <C> <C>
Deferred Tax Assets
Deferred investment tax credits $ 71 $ 78 $ 71 $ 78
Purchase contracts 360 389 337 389
Accrued pension costs 108 99 106 99
Contribution in aid of construction 28 22 27 22
Other 153 128 138 124
Valuation allowance (6) (6) (4) (4)
------ ------ ------ ------
714 710 675 708
------ ------ ------ ------
Deferred Tax Liabilities
Electric utility plant - net 813 743 811 743
Restructuring - CTC/ITP 1,026 1,169 1,026 1,169
Taxes recoverable through
future rates 107 100 107 100
Reacquired debt costs 14 13 13 13
Other 82 40 31 26
------ ------ ------ ------
2,042 2,065 1,988 2,051
------ ------ ------ ------
Net deferred tax liability $1,328 $1,355 $1,313 $1,343
====== ====== ====== ======
</TABLE>
Details of the components of income tax expense, a reconciliation of
federal income taxes derived from statutory tax rates applied to income from
continuing operations for accounting purposes, and details of taxes other than
income are as follows (millions of dollars):
Income Tax Expense
<TABLE>
<CAPTION>
PPL PPL Electric Utilities
------ ----------------------
1999 1998 1997 1999 1998 1997
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Income Tax Expense
Provision-Federal $ 188 $ 183 $ 162 $ 190 $ 198 $ 170
Provision-State 36 64 57 35 64 58
----- ----- ----- ----- ----- -----
224 247 219 225 262 228
----- ----- ----- ----- ----- -----
Deferred-Federal 76 19 19 53 18 20
Deferred-State (109) 3 9 (110) 3 9
----- ----- ----- ----- ----- -----
(33) 22 28 (57) 21 29
----- ----- ----- ----- ----- -----
Investment tax credit,
net-federal (17) (10) (10) (17) (10) (10)
----- ----- ----- ----- ----- -----
Total $ 174 $ 259 $ 237 $ 151 $ 273 $ 247
===== ===== ===== ===== ===== =====
Federal 247 192 171 226 206 180
State (73) 67 66 (75) 67 67
----- ----- ----- ----- ----- -----
$ 174 $ 259 $ 237 $ 151 $ 273 $ 247
===== ===== ===== ===== ===== =====
</TABLE>
<PAGE>
Reconciliation of Income Tax Expense
<TABLE>
<CAPTION>
PPL PPL Electric Utilities
--- ----------------------
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Reconciliation of
Income Tax Expense
Indicated federal income
tax on pre-tax income
before extraordinary
items at statutory tax
rate - 35% $242 $232 $195 $221 $230 $209
Increase/(decrease) due to:
State income taxes (50) 43 40 (51) 43 40
Flow through of
depreciation differences
not previously normalized 3 9 22 3 9 22
Amortization of investment
tax credit (12) (10) (10) (12) (10) (10)
Research & experimentation
income tax credits 0 (1) (1) 0 (1) (1)
Other (9) (14) (9) (10) 2 (13)
---- ---- ---- ---- ---- ----
(68) 27 42 (70) 43 38
---- ---- ---- ---- ---- ----
Total income tax expense $174 $259 $237 $151 $273 $247
==== ==== ==== ==== ==== ====
Effective income tax rate 25.1% 39.1% 42.5% 23.9% 40.0% 41.5%
</TABLE>
In August 1999, PPL Electric Utilities released approximately $78 million
of deferred income taxes associated with the CTC that were no longer required
because of securitization.
<TABLE>
<CAPTION>
Taxes Other than Income PPL PPL Electric Utilities
--- ----------------------
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
State gross receipts $108 $105 $104 $105 $104 $104
State utility realty 13 41 46 12 41 46
State capital stock 13 18 34 11 17 34
Social security and other 27 24 20 25 23 20
---- ---- ---- ---- ---- ----
$161 $188 $204 $153 $185 $204
==== ==== ==== ==== ==== ====
</TABLE>
9. Nuclear Decommissioning Costs
PPL Electric Utilities' most recent estimate of the cost to decommission
the Susquehanna station was completed in 1993 and was a site-specific study,
based on immediate dismantlement and decommissioning of each unit following
final shutdown. The study indicated that PPL Electric Utilities' 90% share of
the total estimated cost of decommissioning the Susquehanna station is
approximately $724 million in 1993 dollars. The estimated cost includes
decommissioning the radiological portions of the station and the cost of removal
of nonradiological structures and materials. The operating licenses for Units 1
and 2 expire in 2022 and 2024, respectively.
Decommissioning costs have been historically charged to operating expense
and have been based upon amounts included in customer rates. Beginning in 1998,
decommissioning costs have been reclassified as a component of depreciation
expense. Beginning in January 1999, in
<PAGE>
accordance with the PUC Final Order, decommissioning costs will be recovered
from customers through the CTC over the 11 year life of the CTC rather than the
remaining life of Susquehanna. The recovery will include a return on unamortized
decommissioning costs. Decommissioning charges were $27 million in 1999 and $12
million in 1998 and 1997.
Amounts collected from customers for decommissioning, less applicable
taxes, are deposited in external trust funds for investment and can be used only
for future decommissioning costs. The market value of securities held and
accrued income in the trust funds at December 31, 1999 and 1998 were
approximately $255 million and $206 million, respectively. The trust funds
experienced, on a fair market value basis, a $26 million net gain in 1999, which
included net unrealized appreciation of $21 million, and a net gain in 1998 of
$31 million, which included net unrealized appreciation of $26 million. The
trust fund activity is reflected in the nuclear plant decommissioning trust fund
and in other noncurrent liabilities on the Consolidated Balance Sheet. Accrued
nuclear decommissioning costs were $260 million and $209 million at December 31,
1999 and 1998, respectively.
In February 2000, the FASB issued another exposure draft on the accounting
for liabilities related to closure and removal of long-lived assets, including
decommissioning of nuclear power plants. As a result, current industry
accounting practices for decommissioning may change, including the possibility
that the estimated cost for decommissioning could be recorded as a liability at
the present value of the estimated future cash outflows that will be required to
satisfy those obligations.
10. Financial Instruments
During 1999, PPL and PPL Electric Utilities entered into forward starting
interest rate swaps and treasury locks with various counterparties to hedge the
interest rate risk associated with anticipated debt issuances, including the
issuance of transition bonds in August 1999. All financial instruments
associated with hedging the interest rate risk of the transition bonds were
settled at the end of July. Proceeds of $24.8 million were received and deferred
on the balance sheet in August, and will subsequently be amortized over the life
of the transition bonds using the effective interest rate method. Seventy-five
percent of these savings are being passed back to customers. On the same day
that PPL Electric Utilities priced its transition bonds, it entered into short-
dated treasury lock transactions with a notional amount of $1.07 billion to lock
in the treasury rate related to its offer to purchase any or all of $1.66
billion of selected series of its first mortgage bonds. These contracts were
settled one week later for an amount that was not significant. See Note 5 for
additional information about transition bonds.
In October 1999, PPL settled $170 million of notional amount of swaps in
connection with the issuance of medium-term notes (as described in Note 11). PPL
received net proceeds from these settlements of about $9 million. This amount
has been deferred on the
<PAGE>
balance sheet and will subsequently be amortized over the life of the medium-
term notes using the effective interest rate method.
At December 31, 1999, PPL had also entered into forward-starting interest
rate swap agreements with various counterparties to hedge the interest rate risk
associated with debt issuances expected in the first quarter of 2000. These
interest rate swap agreements involve the future exchange of floating rate
interest payments for fixed rate interest payments over the life of the
agreements. PPL agreed to pay fixed rates between 5.88% - 7.06% on notional
amounts of $1.05 billion, with maturity dates between February 15, 2005 and
March 31, 2030. PPL will receive a variable rate interest payment based on
either a 3-month or 6-month LIBOR rate through the maturity dates of these
agreements. The estimated fair value of the forward interest rate swaps, which
represents the estimated amount PPL would receive if it had terminated these
agreements at December 31, 1999, was $32.5 million. In the fourth quarter, PPL
Electric Utilities also entered into $171 million notional amount of interest
rate swaps whereby the company agreed to pay a floating interest rate and
receive a fixed interest rate payment. These swaps were executed with the intent
of adjusting the amount of floating-rate debt carried in its liability
portfolio. At December 31, 1999 the estimated fair value of these contracts,
representing the amount PPL Electric Utilities would pay if it terminated these
agreements at December 31, 1999 was $4.9 million.
During the fourth quarter of 1999, PPL also executed forward currency
agreements with various counterparties to hedge a portion of its currency risk
associated with its net investment in a foreign subsidiary. These agreements
were settled in December 1999 with a realized gain of $1.9 million. This gain
was recorded in "Accumulated Other Comprehensive Income" on the Consolidated
Balance Sheet. At December 31, 1999 there were no forward currency agreements
outstanding.
The carrying amount on the Consolidated Balance Sheet and the estimated
fair value of PPL's financial instruments are as follows (millions of dollars):
<TABLE>
<CAPTION>
December 31, 1999 December 31, 1998
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------ ----- ------ -----
<S> <C> <C> <C> <C>
Assets
Nuclear plant decommis-
sioning trust fund (a) $ 255 $ 255 $ 206 $ 206
Financial investments (a) 1 1 1 1
Other investments (a) 15 15 11 11
Cash and cash equivalents (a) 133 133 195 195
Other financial instru-
ments included in
other current assets (a) 4 4 5 5
</TABLE>
<PAGE>
<TABLE>
<S> <C> <C> <C> <C>
Liabilities
Preferred stock with sinking
fund requirements (b) 47 45 47 50
Company-obligated mandatorily
redeemable preferred secur-
ities of subsidiary trusts
holding solely company
debentures (b) 250 217 250 259
Long-term debt (b) 4,157 4,189 2,984 3,176
Commercial paper and
bank loans (a) 857 857 636 636
</TABLE>
(a) The carrying value of these financial instruments generally is based on
established market prices and approximates fair value.
(b) The fair value generally is based on quoted market prices for the
securities where available and estimates based on current rates offered to PPL
where quoted market prices are not available.
11. Credit Arrangements & Financing Activities
PPL Electric Utilities issues commercial paper and, from time to time,
borrows from banks to provide short-term funds for general corporate purposes.
Bank borrowings generally bear interest at rates negotiated at the time of the
borrowing. At December 31, 1999, PPL Electric Utilities had $183 million of
commercial paper outstanding.
PPL Capital Funding, whose purpose is to provide debt funding for PPL and
its subsidiaries other than PPL Electric Utilities, also issues commercial
paper. As with all PPL Capital Funding debt, this commercial paper is guaranteed
by PPL. At December 31, 1999, PPL Capital Funding had $298 million of commercial
paper outstanding.
In July 1999, PPL Electric Utilities, PPL Capital Funding and PPL (as
guarantor for PPL Capital Funding) entered into a new 364-day $750 million
credit facility with a group of banks. This facility replaced a $350 million
364-day revolving credit facility shared by PPL Electric Utilities and PPL
Capital Funding and five separate $80 million 364-day credit facilities
maintained by PPL Capital Funding. No borrowings are outstanding under this new
facility.
In June 1999, PPL Electric Utilities instituted a short-term bond program
in order to meet short-term working capital requirements and to increase
financing flexibility. Under this program, a total of $600 million of short-term
bonds were issued, with no more than $200 million of such bonds outstanding at
any one time. This program was completed in August 1999, and no such bonds were
outstanding at December 31, 1999.
In August 1999, PPL purchased 14 million shares of common stock for $417
million, under forward purchase agreements with third parties. Also in August
1999, PPL Electric Utilities repurchased and subsequently retired $1.467 billion
of first mortgage bonds through tender offers and open market purchases. See
Note 5 for additional information on the issuance of $2.42 billion of transition
bonds to securitize stranded costs, some of the proceeds of which were used to
fund this purchase of common stock and tendered debt.
<PAGE>
In January 1999, PPL and PPL Capital Funding filed a $400 million shelf
registration with the SEC for the registration of debt securities. In October
1999, PPL Capital Funding used this shelf registration to issue $200 million of
medium-term notes in the form of 7.70% Reset Put Securities Series due 2007. In
connection with this issuance, PPL Capital Funding assigned to a third party the
option to call the notes from the holders on November 15, 2002. These notes will
mature on November 15, 2007, but will be required to be surrendered by the
existing holders on November 15, 2002 either through the exercise of the call
option or, if such option is not exercised, through the automatic exercise of a
mandatory put. If the call option is exercised, the notes will be remarketed and
the interest rate will be reset for the remainder of their term to the maturity
date. If the call option is not exercised, the mandatory put will be exercised
and PPL Capital Funding will be required to repurchase the notes at 100% of
their principal amount on November 15, 2002.
PPL, PPL Capital Funding and PP&L Capital Funding Trust I filed a $1.2
billion shelf registration with the SEC in September 1999 for the registration
of debt and equity securities. It is expected that such securities will be
issued from time to time to provide funding for general corporate purposes,
including making loans to the unregulated subsidiaries of PPL and reducing
commercial paper balances.
In November 1999, PPL Montana entered into $950 million of credit
facilities, non-recourse to PPL, with a group of banks, including a $675 million
364-day facility and two revolving credit facilities totaling $275 million which
mature in 2002. The purpose of these facilities is to provide bridge loan
financing for the acquisition of the Montana assets and to fund PPL Montana's
working capital needs. At December 31, 1999, $370 million of borrowings were
outstanding under these facilities.
In December 1999, Emel repaid $145 million of outstanding bank loans with
proceeds from a borrowing from CEP Reserves, Inc., a PPL Electric Utilities
indirect subsidiary. A $145 million demand note was established for the
repayment of funds from Emel to CEP Reserves. Emel will pay a market-based rate
of interest on the outstanding loan.
12. Acquisitions and Divestitures
In August 1998 PPL acquired PPL Gas Utilities. The transaction was treated
as a purchase for accounting and financial reporting purposes. PPL issued
approximately 5.6 million shares of common stock with a value of approximately
$135 million, to acquire all PPL Gas Utilities' common and preferred stock.
Under the terms of the merger agreement, shareowners of PPL Gas Utilities
received 6.968 common shares of PPL for each common share of PPL Gas Utilities
that they owned and 0.682 common shares of PPL for each preferred share of PPL
Gas Utilities that they owned.
In February 1999, PPL acquired McCarl's; in April 1999, PPL Spectrum
acquired Burns Mechanical; and in September 1999, PPL acquired Western Mass.
Holdings. In October 1999, Burns Mechanical merged with DVY. The purchase prices
for these mechanical contractor
<PAGE>
and engineering firms were not individually significant. In 1998 PPL had
acquired H.T. Lyons and McClure.
In May 1999, PPL Global acquired most of Bangor Hydro's generating assets
and certain transmission rights, as well as its interest in an oil-fired
generation facility, for $79 million. In August 1999, PPL Global purchased
Bangor Hydro's 50% interest in the 20-megawatt West Enfield hydroelectric
station for $10 million.
In July 1999, PPL Global acquired an additional 29.4% interest in Emel for
$95 million, resulting in majority ownership and control of the company. In
August 1999, PPL Global acquired an additional 18.5% interest in Emel for $44
million. During October and November 1999, PPL Global acquired another 10%
interest in Emel for $23 million and acquired interests in four of Emel's
subsidiaries at a cost of $48 million. As a result of these acquisitions, PPL
Global's ownership of Emel increased to 95.4%. Acquisition of the controlling
interest in Emel in July 1999 also gave PPL Global a majority interest in EC, a
holding company jointly owned by PPL Global and Emel. As a result, PPL Global
consolidated the financial statements of Emel and EC effective January 1, 1999.
In July 1999, PPL Global reached an agreement with Duke Energy North
America to jointly complete the Griffith Energy Project, a gas-fired, combined-
cycle power plant near Kingman, Arizona. As part of the agreement, PPL Global
transferred a 50% interest in the project to Duke. PPL Global will fund 50% of
the capital cost of the project. The facility, expected to be in service in
2001, will have a nominal base-load capacity of 500 megawatts and a peak
capacity of 600 megawatts. The project cost is anticipated to be about $300
million.
In September 1999, PPL Global's U.K. subsidiary, SWEB, sold its electricity
supply business to London Electricity for about $264 million. PPL Global
recorded an after tax gain from the sale of $64 million. The supply business
provided about 15% of SWEB's annual earnings. PPL Global and Southern Energy
will continue joint ownership of the electric delivery business, which has been
renamed Western Power Distribution (WPD). WPD will continue to own and operate
an extensive power network in southwest Britain, transporting and delivering
electricity to 1.4 million customers.
In November 1999, PPL Electric Utilities sold its Sunbury plant and the
principal assets of its wholly-owned coal processing subsidiary, Lady Jane
Collieries, to Sunbury Holdings, LLC. PPL Electric Utilities received cash
proceeds of $107 million for these assets, which resulted in an after tax gain
of about $42 million.
In 1998, PPL Global signed definitive agreements with the Montana Power
Company ("Montana Power"), Portland General Electric Company ("Portland") and
Puget Sound Energy, Inc. ("Puget") to acquire interests in 13 Montana power
plants, with 2,372 gross megawatts of generating capacity, for a purchase price
of $1.546 billion. The acquisition involves the Colstrip and Corette coal-fired
plants, 11 hydroelectric facilities and a storage reservoir. The Puget and
Portland agreements also provide for the acquisition of related transmission
assets for an additional $126 million, subject to certain conditions.
In December 1999, PPL Global completed the purchase of about 1,315 gross
megawatts of generating assets from Montana Power for $757 million. PPL Montana
used $365 million of credit facilities, and PPL contributed approximately $392
million of project equity funds, through the issuance of PPL Capital Funding
commercial paper and the redemption of investments, to acquire these assets.
PPL Montana applied purchase accounting to record the transaction, and the
assets acquired and the liabilities assumed were recorded at estimated fair
value. The excess of the purchase price over the recorded assets and
liabilities was about $71 million at December 31, 1999, and was allocated as
goodwill. This acquisition transferred to PPL Montana the 11 hydroelectric
facilities, the storage reservoir, the Corette plant and Montana Power's
ownership interest in three of the four units of the Colstrip plant, along with
other generation-related assets. PPL Montana is now operating these facilities.
PPL Montana also acquired the energy marketing and trading operation of Montana
Power for an amount that was not significant. The Montana marketing and trading
operation, which is now part of PPL EnergyPlus, is selling electricity in
wholesale and retail markets in Montana and the Northwest.
PPL Global's acquisition of the Colstrip interests of Portland and Puget,
totaling 1,057 additional megawatts, is subject to several conditions, primarily
the receipt of satisfactory regulatory approvals from the state utility
commissions in Oregon and Washington. The Washington Utilities and
Transportation Commission issued a decision in September 1999 with respect to
Puget's 735-megawatt interest in Colstrip, which Puget is disputing in the state
appellate court. On February 29, 2000, the Oregon Public Utility Commission
denied Portland's application to sell its 322-megawatt interest in Colstrip, but
stated that it would be willing to reconsider the decision if Portland could
demonstrate sufficient additional benefits to Oregon ratepayers as a result of
the sale. The interested parties are reviewing the regulatory decisions and
evaluating possible actions to address the decisions. The acquisition agreements
permit each party to terminate the respective agreements if closing does not
occur by April 30, 2000. PPL cannot predict the outcome of these proceedings,
whether the outcome will be satisfactory to the parties, or the effect of these
proceedings on the timing or the ability to complete these acquisitions.
<PAGE>
In December 1999, the U.K.'s Office of Gas and Electricity Markets, the
regulatory authority for electricity and natural gas distribution, announced the
final price review for the electric distribution companies, including WPD. In
this final price review, WPD was given a one-time rate cut of 19%, the lowest
rate among distribution companies in the U.K. The price cut will be effective
for five years starting in April 2000. As a result of this action, PPL Global
evaluated the carrying value of its investment in WPD and the investment was
written down by $36 million. In unrelated transactions, PPL Global wrote down
the carrying value of two other international investments by a total of $16
million.
13. Stock-Based Compensation
Under the PPL Incentive Compensation Plan ("ICP") and the Incentive
Compensation Plan for Key Employees ("ICPKE") (together, the "Plans"),
restricted shares of common stock as well as stock options may be granted to
officers and other key employees of PPL, PPL Electric Utilities and other
affiliated companies. Awards under the Plans are made in the common stock of
PPL by the Compensation and Corporate Governance Committee of the Board of
Directors in the case of the ICP, and by the PPL Corporate Leadership Council in
the case of the ICPKE. Each Plan limits the number of shares available for
awards to two percent of the outstanding common stock of PPL on the first day of
each calendar year. The maximum number of options which can be awarded under
each Plan to any single eligible employee in any calendar year is 1.5 million
shares. Any portion of these shares that has not been granted may be carried
over and used in any subsequent year. If any award lapses or is forfeited or the
rights to the participant terminate, any shares of common stock are again
available for grant. Shares delivered under the Plans may be in the form of
authorized and unissued common stock, common stock held in treasury by PPL or
common stock purchased on the open market (including private purchases) in
accordance with applicable securities laws.
Restricted Stock
- ----------------
Restricted shares of common stock are outstanding shares with full voting
and dividend rights. However, the shares are subject to forfeiture or
accelerated payout under Plan provisions for
<PAGE>
termination, retirement, disability and death. Restricted shares vest fully if
control of PPL changes, as defined by the Plans.
Restricted stock awards of 108,890, 107,198 and 39,011 shares, with per
share weighted-average fair values of $26.74, $22.74, and $23.39, were granted
in 1999, 1998 and 1997, respectively. Compensation expense for these three years
was less than $2 million annually. At December 31, 1999, there were 224,903
restricted shares outstanding. These awards currently vest three years from the
date of grant.
Stock Options
- -------------
Under the Plans, stock options may also be granted with an option exercise
price per share not less than the fair market value of PPL's common stock on the
date of grant. The options are exercisable beginning one year after the date of
grant, assuming the individual is still employed by PPL or a subsidiary, in
installments as determined by the Compensation and Corporate Governance
Committee of the Board of Directors in the case of the ICP, and the Corporate
Leadership Council in the case of the ICPKE. The Committee (or the Corporate
Leadership Council, in the case of the ICPKE) has discretion to accelerate the
exercisability of the options. All options expire ten years from the grant date.
The options become exercisable if control of PPL changes, as defined by the
Plans.
At December 31, 1999, there were 626,020 stock options outstanding, with a
fair value of $2.37 per option. Fair value was determined using a modified
Black-Scholes model with the following assumptions: Risk-free interest rate -
5.61%; Expected stock volatility - 16.19%; Expected dividend yield rate - 6.60%;
and Expected Option life (years) - 10.
PPL applies Accounting Principles Board Opinion 25 "Accounting for Stock
Issued to Employees" and related interpretations in accounting for stock
options. Since stock options are granted at market price, no compensation cost
has been recognized. Compensation calculated in accordance with the disclosure
requirements of FASB 123, "Accounting for Stock-Based Compensation," was not
significant and had no impact on earnings per share. (See Note 1).
In April 1999, PPL made its initial award of stock options under the Plan.
A summary of the stock option activity for 1999 follows:
<TABLE>
<CAPTION>
Shares Weighted Average Price
-------- ----------------------
<S> <C> <C>
Outstanding December 31, 1998 0
Granted 704,800 $26.8465
Exercised 0
Forfeited (78,780) $26.8438
Outstanding December 31, 1999 626,020 $26.8468
Exercisable December 31, 1999 13,570 $26.8438
</TABLE>
Outstanding options had a weighted-average remaining life of 9.2 years at
December 31, 1999.
<PAGE>
14. Retirement and Postemployment Benefits
Pension and Other Postretirement Benefits
PPL and its subsidiaries sponsor various pension and other postretirement
and postemployment benefit plans.
PPL Electric Utilities, PPL Montana, Penobscot Hydro, and PPL Gas Utilities
have funded, noncontributory defined benefit plans covering substantially all
employees. PPL and its subsidiaries also provide supplemental retirement
benefits to directors, executives, and other key management employees through
nonqualified retirement plans.
Substantially all employees of PPL's subsidiaries will become eligible for
certain health care and life insurance benefits upon retirement through
contributory plans. The employees of North Penn Gas, a subsidiary of PPL Gas
Utilities, are eligible for certain health care and life insurance benefits upon
retirement through a noncontributory plan. Benefits for the PPL Electric
Utilities and North Penn Gas postretirement benefits are paid from funded VEBA
trusts sponsored by each company. PPL Electric Utilities and North Penn Gas made
contributions to the VEBA trusts of $29 million and $1 million, respectively,
during 1999. At December 31, 1999, PPL Electric Utilities had a regulatory asset
of $7 million relating to postretirement benefits that is being amortized and
recovered in rates with a remaining life of 13 years.
Net pension and postretirement medical benefit costs were (millions of
dollars):
<TABLE>
<CAPTION>
Postretirement
Pension Benefits Medical Benefits
---------------- ----------------
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 42 $ 35 $ 32 $ 5 $ 4 $ 4
Interest cost 78 69 64 19 16 17
Expected return on plan assets (99) (87) (77) (7) (4) (2)
Net amortization and deferral (9) (13) (11) 12 9 10
---- ---- ---- ---- ---- ----
Net periodic pension and
postretirement benefit cost $ 12 $ 4 $ 8 $ 29 $ 25 $ 29
==== ==== ==== ==== ==== ====
</TABLE>
The net periodic pension cost charged to operating expenses was $9 million
in 1999, $2 million in 1998 and $5 million in 1997. Retiree health and benefits
costs charged to operating expenses were approximately $20 million in 1999, $19
million in 1998 and $23 million in 1997. Costs in excess of the amounts charged
to expense were charged to construction and other accounts.
<PAGE>
Postretirement medical costs at December 31, 1999 were based on the
assumption that costs would increase 7.5% in 1999, then the rate of increase
would decline gradually to 6% in 2006 and thereafter. A one-percentage point
change in the assumed health care cost trend assumption would have the following
effects (in millions):
<TABLE>
<CAPTION>
One Percentage Point One Percentage Point
Increase Decrease
-------------------- --------------------
<S> <C> <C>
Effect on service cost and
interest cost components $ 1 $ (1)
Effect on postretirement
benefit obligation 12 (10)
</TABLE>
The following assumptions were used in the valuation of the benefit
obligations:
<TABLE>
<CAPTION>
Postretirement
Pension Benefits Medical Benefits
---------------- ----------------
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Discount rate 7.0% 6.25% 6.75% 7.0% 6.25% 6.75%
Expected return on plan assets 8.0% 8.0% 8.0% 6.35% 6.35% 6.5%
Rate of compensation increase 5.0% 5.0% 5.0% 5.0% 5.0% 5.0%
</TABLE>
The funded status of the combined plans was as follows (millions of
dollars):
<TABLE>
<CAPTION>
Postretirement
Pension Benefits Medical Benefits
---------------- ----------------
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
Change in Benefit Obligation
- ----------------------------
Benefit Obligation, January 1 $1,232 $1,022 $ 303 $ 244
Service cost 42 35 5 4
Interest cost 78 69 19 16
Plan amendments 2 67 18 10
Actuarial (gain)/loss (127) 77 (15) 42
Acquisitions/Divestitures 25* 2*
Special termination benefits 3 9
Actual expense paid (3) (3)
Net benefits paid (46) (44) (15) (13)
------ ------ ----- -----
Benefit Obligation, December 31 1,206 1,232 317 303
Change in Plan Assets
- ---------------------
Plan assets at fair value, January 1 1,627 1,429 104 66
Actual return on plan assets 201 244 9 13
Employer contributions 1 1 33
Acquisitions/Divestitures 19*
Actual expense paid (3) (3) 38
Net benefits paid (46) (44) (16) (13)
------ ------ ----- -----
Plan assets at fair value, December 31 1,799 1,627 130 104
Funded Status
- -------------
Funded Status of Plan 593 395 (187) (199)
Unrecognized transition assets (45) (49) 113 122
Unrecognized prior service cost 110 115 33 14
Unrecognized net (gain)/loss (906) (691) 23 44
------ ------ ----- -----
Asset/(liability) recognized (248) (230) (18) (19)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Amounts recognized in the Consolidated
Balance Sheet consist of:
Prepaid benefit cost 1 1
Accrued benefit liability (250) (231) (18) (19)
Intangible asset 1 1
Additional minimum liability (11) (13)
Accumulated other comprehensive income 11 12
------- ------ ----- -----
Net Amount Recognized $ (248) $ (230) $ (18) $ (19)
</TABLE>
*Acquisition of PPL Montana & Penobscot Hydro net of Sunbury divestiture.
The projected benefit obligation, accumulated benefit obligation, and fair
value of plan assets for pension plans with accumulated benefit obligations in
excess of plan assets were (in millions) $41, $34 and $6 respectively, as of
December 31, 1999, and $40, $34 and $6 respectively, as of December 31, 1998.
PPL Electric Utilities and its subsidiaries formerly engaged in coal mining
accrued an additional liability for the cost of health care of their retired
miners. At December 31, 1999, the liability was $19 million. The liability is
net of $50 million of estimated future benefit payments offset by $31 million of
available assets in PPL Electric Utilities funded VEBA trusts.
Savings Plans
Substantially all employees of PPL's subsidiaries are eligible to
participate in deferred savings plans (401k's). Company contributions to the
plans approximated $6 million in 1999, $4 million in 1998, and $2 million in
1997. Increasing contributions were the result of company acquisitions and a
1999 enhanced matching formula for the PPL Electric Utilities plans.
Postemployment Benefits
PPL Electric Utilities provides health and life insurance benefits to
disabled employees and income benefits to eligible spouses of deceased
employees. Postemployment benefits charged to operating expenses were not
significant in 1999, 1998 or 1997.
<PAGE>
15. Jointly Owned Facilities
At December 31, 1999, subsidiaries of PPL owned undivided interests in the
following facilities (millions of dollars):
<TABLE>
<CAPTION>
Electric
Utility Construction
Ownership Plant in Other Accumulated Work in
Interest Service Property Depreciation Progress
--------- ------- -------- ------------ --------
<S> <C> <C> <C> <C> <C>
PPL Electric Utilities
- ----------------------
Generating Stations
Susquehanna 90.00% $ 4,133 $ 3,408 $ 26
Keystone 12.34% 69 43 1
Conemaugh 11.39% 104 50 2
Merrill Creek Reservoir 8.37% $ 22 11
PPL Montana
- -----------
Generating Stations
Colstrip Units 1 & 2 50.00% 192 4 4
Colstrip Unit 3 30.00% 160 3 2
PPL Global
- ----------
Generating Station
Wyman 8.33% 15
</TABLE>
Each participant, either on its own behalf or through another PPL
affiliate, provided its own financing for its share of the facility. Each of the
participants received a portion of the total output of the generating stations
equal to its percentage ownership. The participant's share of fuel and other
operating costs associated with the stations is reflected on the Consolidated
Statement of Income.
16. Commitments and Contingent Liabilities
Construction Expenditures
PPL Electric Utilities' construction expenditures for the period 2000-2004
are estimated to aggregate $1.7 billion, including AFUDC and capitalized
interest. For discussion pertaining to construction expenditures, see Review of
Financial Condition and Results of Operations under the caption "Financial
Condition - Capital Expenditure Requirements."
Nuclear Insurance
PPL Electric Utilities is a member of certain insurance programs which
provide coverage for property damage to members' nuclear generating stations.
Facilities at the Susquehanna station are insured against property damage losses
up to $2.75 billion under these programs. PPL Electric Utilities is also a
member of an insurance program which provides insurance coverage for the cost of
replacement power during prolonged outages of nuclear units caused by certain
specified conditions. Under the property and replacement power insurance
programs, PPL Electric Utilities could be assessed retroactive premiums in the
event of the insurers' adverse loss experience. At December 31, 1999, the
maximum amount PPL Electric
<PAGE>
Utilities could be assessed under these programs was about $24 million.
PPL Electric Utilities' public liability for claims resulting from a
nuclear incident at the Susquehanna station is limited to about $9.7 billion
under provisions of The Price Anderson Amendments Act of 1988. PPL Electric
Utilities is protected against this liability by a combination of commercial
insurance and an industry assessment program. In the event of a nuclear incident
at any of the reactors covered by The Price Anderson Amendments Act of 1988, PPL
Electric Utilities could be assessed up to $168 million per incident, payable at
a rate of $20 million per year, plus an additional 5% surcharge, if applicable.
Environmental Matters
Air
---
The Clean Air Act deals, in part, with acid rain, attainment of federal
ambient ozone standards and toxic air emissions. PPL subsidiaries are in
compliance with the 1995 Phase I acid rain provisions and have taken steps to
comply with the year 2000 Phase II acid rain provisions.
PPL Electric Utilities has met the 1995 ambient ozone requirements of the
Clean Air Act by reducing its rate of NOx emissions by nearly 50% through the
use of low NOx burners. During 1999, further seasonal (May-June) NOx reductions
to 55% from 1990 levels were achieved in response to PA DEP's rule implementing
the Northeast Ozone Transport Region's Memorandum of Understanding (OTR MOU).
These reductions were achieved with operational initiatives that rely, to a
large extent, on the low NOx burners.
The PA DEP has proposed further seasonal (May-June) NOx reductions to 80%
from 1990 levels starting in 2003. These further reductions are based on the
requirements of the OTR MOU and two EPA ambient ozone initiatives: the
September, 1998, EPA SIP-call issued under Section 110 of the Clean Air Act,
requiring reductions from 22 eastern states, including Pennsylvania; and the
Northeastern states, requiring reductions from sources in 12 northeastern states
and D.C., including PPL Electric Utilities' sources. Despite various court
challenges to the EPA initiatives, the PA DEP is expected to move forward with
the 2003 NOx reductions based on the OTR MOU. PPL Electric Utilities estimates
that the 2003 NOx reductions will be achieved with the installation of SCR
(selective catalytic reduction) technology on PPL Electric Utilities' three
largest units.
EPA has also developed new standards for ambient levels of fine
particulates. These standards were challenged and remanded to EPA by the D.C.
Circuit Court in 1999. The new particulates standard, if finalized, may require
further reductions in SO2 for certain PPL subsidiaries and may expand the
planned seasonal NOx reductions at PPL Electric Utilities to year-round
commencing in 2010-2012.
Under the Clean Air Act, the EPA has been studying the health effects of
hazardous air emissions from power plants and other sources, in order to
determine what should be regulated. The EPA has
<PAGE>
concluded that mercury is the power plant air toxin of greatest concern, but
that more evaluation is needed before it can determine whether it must be
regulated. The EPA is now seeking mercury and chlorine sampling and other data
from electric generating units, including those operated by PPL Electric
Utilities and PPL Montana.
The EPA recently initiated enforcement actions against eight utilities,
asserting that older, coal-fired power plants operated by those utilities have,
over the years, been modified in ways that subject them to more stringent "New
Source" requirements under the Clean Air Act. The EPA also has threatened
similar enforcement action with respect to plants operated by other, unnamed
utilities, as well as facilities in other industries. PPL and PPL Electric
Utilities at this time are unable to predict whether such EPA enforcement
actions will be brought with respect to any PPL Electric Utilities or PPL
Montana plants and the scope, outcome or ultimate financial impact of any
potential EPA actions. Compliance with any such EPA enforcement actions could
result in additional capital and operating expenses in amounts which are not now
determinable but which could be significant.
The EPA is also proposing to revise its regulations in a way that will
require power plants to meet new source performance standards and/or undergo new
source review for many maintenance and repair activities that are currently
exempted as routine.
Expenditures to meet the 2000 acid rain and 2003 NOx reduction requirements
are included in the table of projected construction expenditures in the section
entitled "Financial Condition - Capital Expenditure Requirements" in the Review
of the Financial Condition and Results of Operations. PPL currently estimates
that additional capital expenditures and operating costs for environmental
compliance under the Clean Air Act will be incurred beyond 2002 in amounts which
are not now determinable, but which could be significant.
Water and Residual Waste
------------------------
The final NPDES permit for PPL Electric Utilities' Montour plant contains
stringent limits for iron and chlorine discharges. Depending on the results of a
toxic reduction study, additional water treatment facilities or operational
changes may be needed at this plant.
Capital expenditures through the year 2003 to correct groundwater
degradation at fossil-fueled generating stations, and to address waste water
control at PPL Electric Utilities' facilities are included in the table of
construction expenditures in the section entitled "Financial Condition - Capital
Expenditure Requirements" in the Review of the Financial Condition and Results
of Operations. In this regard, PPL Electric Utilities currently estimates that
about $6 million of additional capital expenditures may be required in the next
four years to close some of the ash basins and address other ash basin issues at
various generating plants. Additional capital expenditures could be required
beyond the year 2003 in amounts which are not now determinable but which could
be material. Actions taken to correct
<PAGE>
groundwater degradation, to comply with the DEP's regulations and to address
waste water control, are also expected to result in increased operating costs in
amounts which are not now determinable but which could be material.
Superfund and Other Remediation
-------------------------------
In 1995, PPL Electric Utilities entered into a consent order with the DEP
to address a number of sites where PPL Electric Utilities may be liable for
remediation or contamination. This may include potential PCB contamination at
certain PPL Electric Utilities substations and pole sites; potential
contamination at a number of coal gas manufacturing facilities formerly owned
and operated by PPL Electric Utilities; and oil or other contamination which may
exist at some of PPL Electric Utilities' former generating facilities. As of
December 31, 1999, PPL Electric Utilities has completed work on approximately
two-thirds of the sites included in the consent order.
In 1996, PPL Gas Utilities entered into a similar consent order with the
DEP to address a number of its sites where PPL Gas Utilities may be liable for
remediation of contamination. The sites primarily include former coal gas
manufacturing facilities. Prior to PPL acquiring PPL Gas Utilities in August of
1998 PPL Gas Utilities had obtained a "no further action" determination from the
DEP for two of the 20 sites covered by the order.
At December 31, 1999, PPL Electric Utilities and PPL Gas Utilities had
accrued approximately $6 million and $16 million, respectively, representing the
amounts they can reasonably estimate they will have to spend for site
remediation, including those sites covered by each company's consent orders
mentioned above.
In October 1999, the Montana Supreme Court held in favor of several
citizens' groups that the right to a clean and healthful environment is a
fundamental right guaranteed by the Montana Constitution. The Court's ruling
could result in significantly more stringent environmental laws and regulations
as well as an increase in citizens' suits under Montana's environmental laws.
The effect on PPL Montana of any such changes in laws or regulations or any such
increase in citizen suits is not currently determinable but could be
significant.
Future cleanup or remediation work at sites currently under review, or at
sites not currently identified, may result in material additional operating
costs for PPL subsidiaries that cannot be estimated at this time. PPL Montana
has been indemnified by the Montana Power Company for any preacquisition
environmental liability. However, this indemnification is conditioned on certain
circumstances that can result in PPL Montana and the Montana Power Company
sharing in certain costs within limits set forth in the Asset Purchase
Agreement.
General
-------
Due to the environmental issues discussed above or other environmental
matters, PPL Electric Utilities may be required to modify, replace or cease
operating certain facilities to comply with
<PAGE>
statutes, regulations and actions by regulatory bodies or courts. In this
regard, PPL Electric Utilities also may incur capital expenditures, operating
expenses and other costs in amounts which are not now determinable but which
could be material.
Loan Guarantees of Affiliated Companies
PPL provides certain guarantees for its subsidiaries. Specifically, PPL
guarantees all of the debt of PPL Capital Funding. As of December 31, 1999, PPL
guaranteed $597 million of medium-term notes and $298 million of commercial
paper issued by PPL Capital Funding. At December 31, 1998 PPL had guaranteed
$397 million of PPL Capital Funding's medium-term notes, and $552 million of its
commercial paper. PPL also provided loan guarantees to PPL Global subsidiaries,
totaling $118 million in 1999 and $13 million in 1998. Also, PPL guaranteed
notes of a subsidiary of PPL Gas Utilities, amounting to $18 million and $19
million at the end of 1999 and 1998, respectively. Additionally, PPL has
guaranteed certain obligations of PPL EnergyPlus for up to $271 million under
power purchase and sales agreements. These guarantees amounted to $31 million in
1998.
At December 31, 1999 and 1998, PPL Electric Utilities provided a guarantee
in the amount of $12 million in support of one of its subsidiaries.
Source of Labor Supply
As of December 31, 1999, PPL and its subsidiaries had 9,166 employees,
including 6,314 full-time PPL Electric Utilities employees and 470 full-time PPL
Montana employees. Approximately 62 percent of PPL Electric Utilities' full-time
employees are represented by the IBEW. Approximately 68 percent of PPL Montana
employees are represented by the IBEW. PPL Electric Utilities reached a new
labor agreement with the IBEW in 1998. This agreement expires in May 2002. PPL
Montana's contract with the IBEW expires in 2001.
17. New Accounting Standards
In June 1999, the FASB issued SFAS 137 which defers the effective date of
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," to
fiscal years beginning after June 15, 2000. PPL and PPL Electric Utilities
intend to adopt SFAS 133 as of January 1, 2001. The impact of adopting this
statement on the net income and financial position of PPL and PPL Electric
Utilities is not expected to be material.
18. Subsequent Events
In February 2000, PPL Capital Funding issued $500 million of medium-term
notes in the form of 7.75% series due 2005. This issuance used $500 million of
the $1.2 billion SEC shelf registration filed in September 1999. At the time of
issuance, PPL also settled a number of forward-starting swaps that had been
entered into in a lower interest rate environment as a means to lock-in interest
rates and limit exposure to increasing interest rates, all pursuant to PPL's
Interest Rate Risk Management Program. The Company received net proceeds of
$15.8 million from the settlement of these contracts, which will be
<PAGE>
deferred on the balance sheet and subsequently amortized over the life of the
medium-term notes. The effective interest rate on the medium-term notes was
reduced by approximately 75 basis points as a result of this hedging activity.
Also, in conjunction with this transaction, PPL swapped $350 million notional
amount of these notes from fixed to floating-rate instruments with an initial
average rate of three-months LIBOR plus 45 basis points to adjust the amount of
floating-rate debt carried in its liability portfolio.
<PAGE>
<TABLE>
<CAPTION>
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A Column B Column C Column D Column E
-------- -------- -------- -------- --------
Deductions
from
Balance Additions Reserves -
---------------------
at Charged Losses or Balance at
Beginning Charged to Other Expenses End of
Description of Period to Income Accounts Applicable Period
--------- --------- -------- ---------- ----------
(Millions of Dollars)
<S> <C> <C> <C> <C> <C>
PPL Corporation
- ---------------
Year Ended December 31, 1999
- ----------------------------
Reserves deducted from assets in
the Balance Sheet
Uncollectible accounts............................ $16 $22 $16 $22
Obsolete inventory - Materials and supplies....... 11 3 11 3
Year Ended December 31, 1998
- ----------------------------
Reserves deducted from assets in
the Balance Sheet
Uncollectible accounts............................ 16 24 24 16
Obsolete inventory - Materials and supplies....... 12 1 11
Year Ended December 31, 1997
- ----------------------------
Reserves deducted from assets in
the Balance Sheet
Uncollectible accounts ........................... 25 17 26 16
PPL Electric Utilities Corporation
- ----------------------------------
Year Ended December 31, 1999
- ----------------------------
Reserves deducted from assets in
the Balance Sheet
Uncollectible accounts ........................... 15 22 19 18
Obsolete inventory - Materials and supplies....... 11 11
Year Ended December 31, 1998
- ----------------------------
Reserves deducted from assets in
the Balance Sheet
Uncollectible accounts ........................... 16 20 21 15
Obsolete inventory - Materials and supplies....... 12 1 11
Year Ended December 31, 1997
- ----------------------------
Reserves deducted from assets in
the Balance Sheet
Uncollectible accounts ........................... 26 15 25 16
</TABLE>
<PAGE>
QUARTERLY FINANCIAL, COMMON STOCK PRICE AND DIVIDEND DATA (Unaudited)
PPL Corporation and Subsidiaries
(Millions of Dollars, except per share data)
<TABLE>
<CAPTION>
For the Quarters Ended (a)
March 31 June 30 Sept. 30 Dec. 31
<S> <C> <C> <C> <C>
1999
Operating revenues........................................ $ 1,067 $ 1,004 $1,386 $ 1,133
Operating income.......................................... 262 164 238 208
Net income before extraordinary items..................... 120 63 161 134
Net income................................................ 120 63 102 147
Earnings per common share (b)............................. 0.76 0.40 0.68 1.02
Dividends declared per common share (c)................... 0.25 0.25 0.25 0.25
Price per common share
High.................................................... 28-1/2 31-7/8 32 28-1/2
Low..................................................... 24-3/4 24-1/8 25-3/8 20-3/8
1998
Operating revenues........................................ $ 880 $ 838 $1,166 $ 902
Operating income.......................................... 236 148 262 181
Net income before extraordinary items..................... 101 54 136 88
Net income (loss)......................................... 101 (894) 136 88
Earnings per common share (b)............................. 0.60 (5.34) 0.81 0.56
Dividends declared per common share (c)................... 0.4175 0.4175 0.25 0.25
Price per common share
High.................................................... 24-1/4 24-3/8 26-3/8 28-15/16
Low..................................................... 21-11/16 20-7/8 22 24-15/16
</TABLE>
(a) PPL's electric and gas utility businesses are seasonal in nature with peak
sales periods generally occurring in the winter months. In addition,
earnings in 1999 and 1998 were affected by one-time adjustments.
Accordingly, comparisons among quarters of a year may not be indicative of
overall trends and changes in operations.
(b) The sum of the quarterly amounts may not equal annual earnings per share
due to changes in the number of common shares outstanding during the year
or rounding.
(c) PPL has paid quarterly cash dividends on its common stock in every year
since 1946. The dividends paid per share in 1998 were $1.50 and in 1999
were $1.00. The most recent regular quarterly dividend paid by PPL was 25
cents per share (equivalent to $1.00 per annum) paid January 1, 2000.
Future dividends, declared at the discretion of the Board of Directors,
will be dependent upon future earnings, financial requirements and other
factors.
QUARTERLY FINANCIAL DATA (Unaudited)
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
<TABLE>
<CAPTION>
For the Quarters Ended (a)
March 31 June 30 Sept. 30 Dec. 31
<S> <C> <C> <C> <C>
1999
Operating revenues........................................ $ 968 $ 923 $1,128 $ 933
Operating income.......................................... 237 148 190 174
Net income before extraordinary items..................... 120 73 166 122
Net income................................................ 120 73 107 135
Earnings available to PPL................................. 108 61 101 128
1998
Operating revenues........................................ $ 861 $ 818 $1,131 $ 833
Operating income.......................................... 231 143 259 168
Net income before extraordinary items..................... 109 63 137 100
Net income (loss)......................................... 109 (885) 137 100
Earnings available to PPL................................. 97 (897) 125 88
</TABLE>
(a) PPL Electric Utilities Corporation's electric utility business is seasonal
in nature with peak sales periods generally occurring in the winter months.
In addition, earnings in several quarters were affected by several one-time
adjustments. Accordingly, comparisons among quarters of a year may not be
indicative of overall trends and changes in operations.
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
------------------------
None.
<PAGE>
PART III
--------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
- ------------------------------------------------------------
Information for this item concerning directors of PPL will be set forth in
the sections entitled "Nominees for Directors," "Directors Continuing in Office"
and "Retiring Directors" in PPL's 2000 Notice of Annual Meeting and Proxy
Statement, which will be filed with the SEC not later than 120 days after
December 31, 1999, and which information is incorporated herein by reference.
Information required by this item concerning the executive officers of PPL is
set forth at the end of Part I of this report.
Information for this item concerning directors of PPL Electric Utilities
will be set forth in the sections entitled "Nominees for Directors," "Directors
Continuing in Office" and "Retiring Directors" in PPL Electric Utilities' 2000
Notice of Annual Meeting and Information Statement, which will be filed with the
SEC not later than 120 days after December 31, 1999, and which information is
incorporated herein by reference. Information required by this item concerning
the executive officers of PPL Electric Utilities is set forth at the end of Part
I of this report.
ITEM 11. EXECUTIVE COMPENSATION
-------------------------------
Information for this item for PPL will be set forth in the sections
entitled "Compensation of Directors," "Summary Compensation Table," "Option
Grants in Last Fiscal Year" and "Retirement Plans for Executive Officers" in
PPL's 2000 Notice of Annual Meeting and Proxy Statement, which will be filed
with the SEC not later than 120 days after December 31, 1999, and which
information is incorporated herein by reference.
Information for this item for PPL Electric Utilities will be set forth in
the sections entitled "Compensation of Directors," "Summary Compensation Table,"
"Option Grants in Last Fiscal Year" and "Retirement Plans for Executive
Officers" in PPL Electric Utilities' 2000 Notice of Annual Meeting and
Information Statement, which will be filed with the SEC not later than 120 days
after December 31, 1999, and which information is incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
--------------------------------
Information for this item for PPL will be set forth in the section entitled
"Stock Ownership" in PPL's 2000 Notice
<PAGE>
of Annual Meeting and Proxy Statement, which will be filed with the SEC not
later than 120 days after December 31, 1999, and which information is
incorporated herein by reference.
Information for this item for PPL Electric Utilities will be set forth in
the section entitled "Stock Ownership" in PPL Electric Utilities' 2000 Notice of
Annual Meeting and Information Statement, which will be filed with the SEC not
later than 120 days after December 31, 1999, and which information is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
-------------------------------------------------------
Information for this item for PPL will be set forth in the section entitled
"Certain Transactions Involving Directors or Executive Officers" in PPL's 2000
Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC
not later than 120 days after December 31, 1999, and which information is
incorporated herein by reference.
Information for this item for PPL Electric Utilities will be set forth in
the section entitled "Certain Transactions Involving Directors or Executive
Officers" in PPL Electric Utilities' 2000 Notice of Annual Meeting and
Information Statement, which will be filed with the SEC not later than 120 days
after December 31, 1999, and which information is incorporated herein by
reference.
<PAGE>
PART IV
-------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
----------------------------------
(a) The following documents are filed as part of this report:
1. Financial Statements - included in response to Item 8.
PPL Corporation
Report of Independent Accountants
Consolidated Statement of Income for each of the Three
Years Ended December 31, 1999, 1998 and 1997
Consolidated Statement of Cash Flows for each of
the Three Years Ended December 31, 1999,
1998 and 1997
Consolidated Balance Sheet at December 31, 1999
and 1998
Consolidated Statement of Shareowners' Common Equity
for each of the Three Years Ended December 31,
1999, 1998 and 1997
Consolidated Statement of Preferred Stock at
December 31, 1999 and 1998
Consolidated Statement of Company-Obligated
Mandatorily Redeemable Securities at
December 31, 1999 and 1998
Consolidated Statement of Long-Term Debt at
December 31, 1999 and 1998
Notes to Financial Statements
PPL Electric Utilities Corporation
Report of Independent Accountants
Consolidated Statement of Income for each of the
Three Years Ended December 31, 1999, 1998 and 1997
Consolidated Statement of Cash Flows for each of
the Three Years Ended December 31, 1999, 1998
and 1997
Consolidated Balance Sheet at December 31, 1999
and 1998
Consolidated Statement of Shareowner's Common Equity
for each of the Three Years Ended December 31, 1999,
1998 and 1997
Consolidated Statement of Preferred Stock at
December 31, 1999 and 1998
Consolidated Statement of Company-Obligated
Mandatorily Redeemable Securities at
December 31, 1999 and 1998
Consolidated Statement of Long-Term Debt at
December 31, 1999 and 1998
Notes to Financial Statements
2. Supplementary Data and Supplemental Financial Statement
Schedule - included in response to Item 8.
<PAGE>
Schedule II - Valuation and Qualifying Accounts and
Reserves for the Three Years Ended
December 31, 1999
All other schedules are omitted because of the absence of the conditions
under which they are required or because the required information is
included in the financial statements or notes thereto.
3. Exhibits
Exhibit Index on page xxx.
(b) Reports on Form 8-K:
The following Reports on Form 8-K were filed during the three months ended
December 31, 1999:
Report dated October 27, 1999
-----------------------------
Item 5. Other Events
Information regarding PPL Corporation's third quarter earnings.
Item 7. Financial Statements and Exhibits
Press Release dated October 27, 1999, regarding PPL Corporation's third
quarter earnings.
Report dated December 16, 1999
------------------------------
Item 5. Other Events
Information regarding PPL Corporation's revised earnings forecasts for 1999
and 2000.
Report dated December 17, 1999
------------------------------
Item 5. Other Events
Information regarding PPL Global's acquisition of certain generation assets
from Montana Power through an indirect subsidiary, PPL Montana LLC, for a
purchase price of $757 million.
<PAGE>
SHAREOWNER AND INVESTOR INFORMATION
-----------------------------------
Annual Meetings: The annual meetings of shareowners of PPL Corporation and PPL
Electric Utilities Corporation are held each year on the fourth Friday of April.
The 2000 annual meetings will be held on Friday, April 28, 2000, at Lehigh
University's Stabler Arena, at the Goodman Campus Complex located in Lower
Saucon Township, outside Bethlehem, PA.
Proxy and Information Statement Material: A proxy statement and information
statement and notice of PPL's and PPL Electric Utilities' annual meetings are
mailed to all shareowners of record as of February 29, 2000.
Dividends: The 2000 dates for consideration of the declaration of dividends on
PPL common stock and PPL Electric Utilities preferred stock by the Board of
Directors or its Executive Committee are February 25, May 26, August 25 and
November 17. Subject to the declaration, such dividends are paid on the first
day of April, July, October and January. Dividend checks are mailed in advance
of those dates with the intention that they arrive as close as possible to the
payment dates. The 2000 record dates for dividends are expected to be March 10,
June 9, September 8, and December 8.
Direct Deposit of Dividends: Shareowners may choose to have their dividend
checks deposited directly into their checking or savings account. Quarterly
dividend payments are electronically credited on the dividend date, or the first
business day thereafter.
Dividend Reinvestment Plan: Shareowners may choose to have dividends on their
PPL common stock or PPL Electric Utilities preferred stock reinvested in PPL
common stock instead of receiving the dividend by check.
Certificate Safekeeping: Shareowners participating in the Dividend Reinvestment
Plan may choose to have their common stock certificates forwarded to PPL
Electric Utilities for safekeeping.
Lost Dividend or Interest Checks: Dividend or interest checks lost by
investors, or those that may be lost in the mail, will be replaced if the check
has not been located by the 10th business day following the payment date.
Transfer of Stock or Bonds: Stock or bonds may be transferred from one name to
another or to a new account in the name of another person. Please contact
Investor Services regarding transfer instructions.
Bondholder Information: Much of the information and many of the procedures
detailed here for shareowners also apply to bondholders. Questions related to
bondholder accounts should be directed to Investor Services.
<PAGE>
Lost Stock or Bond Certificates: Please contact Investor Services for an
explanation of the procedure to replace lost stock or bond certificates.
PPL Summary Annual Report: Published and mailed in mid-March to all shareowners
of record.
Shareowner News: An easy-to-read newsletter containing current items of
interest to shareowners -- published and mailed at the beginning of each
quarter.
Periodic Mailings: Letters regarding new investor programs, special items of
interest, or other pertinent information are mailed on a non-scheduled basis as
necessary.
Duplicate Mailings: The summary annual report and other investor publications
are mailed to each investor account. If you have more than one account, or if
there is more than one investor in your household, you may contact Investor
Services to request that only one publication be delivered to your address.
Please provide account numbers for all duplicate mailings.
Shareowner Information Line: Shareowners can get detailed corporate and
financial information 24 hours a day using the Shareowner Information Line.
They can hear timely recorded messages about earnings, dividends and other
company news releases; request information by fax; and request printed materials
in the mail.
The toll-free Shareowner Information Line is 1-800-345-3085.
Other PPL publications, such as the annual and quarterly reports to the
Securities and Exchange Commission (Forms 10-K and 10-Q) will be mailed upon
request.
Another part of this service is an enhanced Internet home page
(www.pplresources.com). Shareowners can access PPL Securities and Exchange
Commission filings, stock quotes and historical performance. Visitors to our
website can provide their E-mail address and indicate their desire to receive
future earnings or news releases automatically.
Investor Services: For any questions you have or additional information you
require about PPL and its subsidiaries, please call the Shareowner Information
Line, or write to:
George I. Kline
Manager-Investor Services
PPL Corporation
Two North Ninth Street
Allentown, PA 18101
Internet Access: For updated information throughout the year, check out our
home page at http://www.pplresources.com. You may also contact Investor
Services via E-mail at [email protected].
<PAGE>
Listed Securities: Fiscal Agents:
New York Stock Exchange Stock Transfer Agents and
Registrars
PPL Corporation: Norwest Bank Minnesota, N.A.
Common Stock (Code: PPL) Shareowner Services
161 North Concord Exchange
PPL Electric Utilities Corporation: South St. Paul, MN 55075
4-1/2% Preferred Stock
(Code: PPLPRB) PPL Electric Utilities Corporation
4.40% Series Preferred Stock Investor Services Department
(Code: PPLPRA)
Dividend Disbursing Office and
Dividend Reinvestment Plan Agent
PP&L Capital Trust: PPL Electric Utilities Corporation
8.20% Preferred Securities Investor Services Department
(Code: PPLPRC)
Mortgage Bond Trustee
PP&L Capital Trust II: Bankers Trust Co.
8.10% Preferred Securities Attn: Security Transfer Unit
(Code: PPLPRD) P.O. Box 291569
Nashville, TN 37229
Philadelphia Stock Exchange
Bond Interest Paying Agent
PPL Corporation: PPL Electric Utilities Corporation
Common Stock Investor Services Department
PPL Electric Utilities Corporation
4-1/2% Preferred Stock
3.35% Series Preferred Stock
4.40% Series Preferred Stock
4.60% Series Preferred Stock
<PAGE>
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PPL Corporation
---------------
(Registrant)
PPL Electric Utilities Corporation
----------------------------------
(Registrant)
By /s/ William F. Hecht
- ---------------------------------------
William F. Hecht - Chairman, President
and Chief Executive
Officer (PPL Corporation
and PPL Electric Utilities
Corporation)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
TITLE
-----
By /s/ William F. Hecht Principal Executive
- ---------------------------------------
William F. Hecht - Chairman, President Officer and Director
and Chief Executive
Officer (PPL Corporation
and PPL Electric Utilities
Corporation)
By /s/ John R. Biggar Principal Financial
- ---------------------------------------
John R. Biggar - Senior Vice President Officer
and Chief Financial Officer
(PPL Corporation
and PPL Electric Utilities
Corporation)
By /s/ Joseph J. McCabe Principal Accounting
- ---------------------------------------
Joseph J. McCabe - Vice President and Officer
Controller (PPL Corporation
and PPL Electric Utilities
Corporation)
Frederick M. Bernthal Stuart Heydt
E. Allen Deaver Frank A. Long Directors
William J. Flood Norman Robertson
Elmer D. Gates Marilyn Ware
By /s/ William F. Hecht
- ---------------------------------------
William F. Hecht, Attorney-in-fact Date: March 1, 2000
<PAGE>
EXHIBIT INDEX
The following Exhibits indicated by an asterisk preceding the Exhibit
number are filed herewith. The balance of the Exhibits have heretofore been
filed with the Commission and pursuant to Rule 12(b)-32 are incorporated herein
by reference. Exhibits indicated by a are filed or listed pursuant to Item
601(b)(10)(iii) of Regulation S-K.
3(a)-1 - Articles of Incorporation of PP&L Resources, Inc. (Exhibit B
to Proxy Statement of PP&L and Prospectus of PP&L Resources,
dated March 9, 1995)
3(a)-2 - Amended and Restated Articles of PP&L, Inc. (Exhibit 3(i) to
PP&L's Form 10-Q Report (File No. 1-905) for the quarter
ended March 31, 1999)
3(b)-1 - By-laws of PP&L Resources, Inc. (Exhibit 3(ii)(a) to PP&L
Resources' Form 10-Q Report (File No. 1-905) for the quarter
ended September 30, 1998)
3(b)-2 - By-laws of PP&L, Inc. (Exhibit 3(ii)(b) to PP&L's Form 10-Q
Report (File No. 1-905) for the quarter ended September 30,
1998)
4(a)-1 - Amended and Restated Employee Stock Ownership Plan,
effective January 1, 1998 (Exhibit 4(a)-1 to PP&L Resources'
Form 10-K Report (File No. 1-905) for the year ended
December 31, 1998)
4(a)-2 - Amendment No. 1 to said Employee Stock Ownership Plan,
effective January 1, 1998 (Exhibit 4(a)-2 to PP&L Resources'
Form 10-K Report (File No. 1-905) for the year ended
December 31, 1998)
4(a)-3 - Amendment No. 2 to said Employee Stock Ownership Plan,
effective December 1, 1998 (Exhibit 4(a)-3 to PP&L
Resources' Form 10-K Report (File No. 1-905) for the year
ended December 31, 1998)
*4(a)-4 - Amendment No. 3 to said Employee Stock Ownership Plan,
effective September 14, 1998
<PAGE>
*4(a)-5 - Amendment No. 4 to said Employee Stock Ownership Plan,
effective January 1, 1999
*4(a)-6 - Amendment No. 5 to said Employee Stock Ownership Plan, dated
June 2, 1999
4(b)-1 - Mortgage and Deed of Trust, dated as of October 1, 1945,
between PP&L and Guaranty Trust Company of New York, as
Trustee (now Bankers Trust Company, as successor Trustee)
(Exhibit 2(a)-4 to Registration Statement No. 2-60291)
4(b)-2 - Supplement, dated as of July 1, 1954, to said Mortgage and
Deed of Trust (Exhibit 2(b)-5 to Registration Statement No.
219255)
4(b)-3 - Supplement, dated as of October 1, 1989, to said Mortgage
and Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated November 6, 1989)
4(b)-4 - Supplement, dated as of July 1, 1991, to said Mortgage and
Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated July 29, 1991)
4(b)-5 - Supplement, dated as of May 1, 1992, to said Mortgage and
Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated June 1, 1992)
4(b)-6 - Supplement, dated as of November 1, 1992, to said Mortgage
and Deed of Trust (Exhibit 4(b)-29 to PP&L's Form
10-K Report (File 1-905) for the year ended December 31,
1992)
4(b)-7 - Supplement, dated as of February 1, 1993, to said Mortgage
and Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated February 16, 1993)
4(b)-8 - Supplement, dated as of April 1, 1993, to said Mortgage and
Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated April 30, 1993)
<PAGE>
4(b)-9 - Supplement, dated as of June 1, 1993, to said Mortgage and
Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated July 7, 1993)
4(b)-10 - Supplement, dated as of October 1, 1993, to said Mortgage
and Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated October 29, 1993)
4(b)-11 - Supplement, dated as of February 15, 1994, to said Mortgage
and Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated March 11, 1994)
4(b)-12 - Supplement, dated as of March 1, 1994, to said Mortgage and
Deed of Trust (Exhibit 4(b) to PP&L's Form 8-K
Report (File No. 1-905) dated March 11, 1994)
4(b)-13 - Supplement, dated as of March 15, 1994, to said Mortgage and
Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated March 30, 1994)
4(b)-14 - Supplement, dated as of September 1, 1994, to said Mortgage
and Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
(File No. 1-905) dated October 3, 1994)
4(b)-15 - Supplement, dated as of October 1, 1994, to said Mortgage
and Deed of Trust (Exhibit 4(a) to PP&L's Form 8-K
Report (File No. 1-905) dated October 3, 1994)
4(b)-16 - Supplement, dated as of August 1, 1995, to said Mortgage and
Deed of Trust (Exhibit 6(a) to PP&L's Form 10-Q
Report (File No. 1-905) for the quarter ended September 30,
1995)
4(b)-17 - Supplement, dated as of April 1, 1997 to said Mortgage and
Deed of Trust (Exhibit 4(b)-17 to PP&L's Form 10-K
Report (File No. 1-905) for the year ended December 31,
1997)
<PAGE>
4(b)-18 - Supplement, dated as of May 5, 1998, to said Mortgage and
Deed of Trust (Exhibit 4.3 to PP&L's Form 8-K
Report (File No. I-905) dated May 1, 1998)
*4(b)-19 - Supplement, dated as of June 1, 1999, to said Mortgage and
Deed of Trust
4(c)-1 - Indenture, dated as of November 1, 1997, among PP&L
Resources, Inc., PP&L Capital Funding, Inc. and The Chase
Manhattan Bank, as Trustee (Exhibit 4.1 to PP&L Resources 8-
K Report (File No. 1-905) dated November 12, 1997)
4(c)-2 - Supplement, dated as of November 1, 1997, to said Indenture
(Exhibit 4.2 to PP&L Resources' 8-K Report (File No. 1-905)
dated November 12, 1997)
4(c)-3 - Supplement, dated as of March 1, 1999, to said Indenture
(Exhibit 4.3 to Registration Statement Nos. 333-87847, 333-
87847-01 and 333-87847-02)
*4(c)-4 - Supplement, dated as of October 1, 1999, to said Indenture
4(d)-1 - Junior Subordinated Indenture, dated as of April 1, 1997,
between PP&L, Inc. and The Chase Manhattan Bank, as Trustee
(Exhibit 4.1 to Registration Statement No. 333-20661)
4(d)-2 - Amended and Restated Trust Agreement, dated as of April 8,
1997, among PP&L, Inc., The Chase Manhattan Bank, as
Property Trustee, Chase Manhattan Bank (Delaware), as
Delaware Trustee, and John R. Biggar and James E. Abel, as
Administrative Trustees (Exhibit 4.4 to Registration
Statement No. 333-20661)
4(d)-3 - Guarantee Agreement, dated as of April 8, 1997, between
PP&L, Inc. and The Chase Manhattan Bank, as Trustee (Exhibit
4.6 to Registration Statement No. 333-20661)
<PAGE>
4(e)-1 - Amended and Restated Trust Agreement, dated as of June 13,
1997, among PP&L, Inc., The Chase Manhattan Bank, as
Property Trustee, Chase Manhattan Bank (Delaware), as
Delaware Trustee, and John R. Biggar and James E. Abel, as
Administrative Trustees (Exhibit 4.4 to Registration
Statement No. 333-27773)
4(e)-2 - Guarantee Agreement, dated as of June 13, 1997, between
PP&L, Inc. and The Chase Manhattan Bank, as Trustee (Exhibit
4.6 to Registration Statement No. 333-27773)
10(a) - Amended and Restated 364-Day Revolving Credit Agreement,
dated as of July 1, 1999, among PP&L, Inc., PP&L Capital
Funding, Inc., PP&L Resources, Inc. and the banks named
therein (Exhibit 10 to PP&L Resources' Form 10-Q Report
(File No. 1-905) for the quarter ended June 30, 1999)
10(b) - Five-Year Revolving Credit Agreement, dated as of November
20, 1997, among PP&L, Inc., PP&L Capital Funding, Inc., PP&L
Resources, Inc. and the banks named therein (Exhibit 10(b)
to PP&L Resources' Form 10-K Report (File No. 1-905) for the
year ended December 31, 1997)
*10(b)-1 - Amendment No. 1 to said Five-Year Revolving Credit Agreement
10(c) - Pollution Control Facilities Agreement, dated as of May 1,
1973, between PP&L, Inc. and the Lehigh County Industrial
Development Authority (Exhibit 5(z) to Registration
Statement No. 2-60834)
*10(d) - Amended and Restated Operating Agreement of the PJM
Interconnection, L.L.C., dated September 3, 1999
10(e)-1 - Capacity and Energy Sales Agreement, dated March 9, 1984,
between PP&L, Inc. and Jersey Central Power & Light Company
(Exhibit 10(f)-3 to PP&L's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1984)
<PAGE>
10(e)-2 - First Supplement, effective February 28, 1986, to said
Capacity and Energy Sales Agreement (Exhibit 10(e)-4 to
PP&L's Form 10-K Report (File No. 1-905) for the year
ended December 31, 1986)
10(e)-3 - Second Supplement, effective January 1, 1987, to said
Capacity and Energy Sales Agreement (Exhibit 10(g)-3 to
PP&L's Form 10-K Report (File No. 1-905) for the year
ended December 31, 1989)
10(e)-4 - Amendments to Exhibit A, effective October 1, 1987, to said
Capacity and Energy Sales Agreement (Exhibit 10(e)-6 to
PP&L's Form 10-K Report (File No. 1-905) for the year
ended December 31, 1987)
10(e)-5 - Third Supplement, effective December 1, 1988, to said
Capacity and Energy Sales Agreement (Exhibit 10(g)-5 to
PP&L's Form 10-K Report (File No. 1-905) for the year
ended December 31, 1989)
10(e)-6 - Fourth Supplement, effective December 1, 1988, to said
Capacity and Energy Sales Agreement (Exhibit 10(g)-6 to
PP&L's Form 10-K Report (File No. 1-905) for the year
ended December 31, 1989)
10(f)-1 - Capacity and Energy Sales Agreement, dated January 28, 1988,
between PP&L, Inc. and Baltimore Gas and Electric Company
(Exhibit 10(e)-7 to PP&L's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1987)
10(f)-2 - First Supplement, effective November 1, 1988, to said
Capacity and Energy Sales Agreement (Exhibit 10(i)-2 to
PP&L's Form 10-K Report (File No. 1-905) for the year
ended December 31, 1989)
10(f)-3 - Second Supplement, effective June 1, 1989, to said Capacity
and Energy Sales Agreement (Exhibit 10(i)-3 to
PP&L's Form 10-K Report (File No. 1-905) for the year
ended December 31, 1989)
<PAGE>
10(f)-4 - Third Supplement, effective June 1, 1991, to said Capacity
and Energy Sales Agreement (Exhibit 10(g)-4 to PP&L's
Form 10-K Report (File No. 1-905) for the year
ended December 31, 1991)
10(f)-5 - Fourth Supplement, effective June 1, 1992, to said Capacity
and Energy Sales Agreement (Exhibit 10(h)-5 to PP&L's
Form 10-K Report (File No. 1-905) for the year
ended December 31, 1997)
10(f)-6 - Fifth Supplement, effective July 15, 1993, to said Capacity
and Energy Sales Agreement (Exhibit 10(h)-6 to PP&L's
Form 10-K Report (File No. 1-905) for the year
ended December 31, 1997)
10(f)-7 - Sixth Supplement, effective June 1, 1993, to said Capacity
and Energy Sales Agreement (Exhibit 10(h)-7 to PP&L's
Form 10-K Report (File No. 1-905) for the year
ended December 31, 1997)
*10(g) - Capacity and Energy Sales Agreement, dated May 25, 1999,
between PP&L, Inc. and UGI Utilities, Inc.
10(h) - Amended and Restated Directors Deferred Compensation Plan,
effective January 1, 1998 (Exhibit 10(l) to PP&L Resources'
Form 10-K Report (File No. 1-905) for the year ended
December 31, 1998)
[_]10(i)-1 - Amended and Restated Officers Deferred Compensation Plan,
effective January 1, 1998 (Exhibit 10(m)-1 to PP&L
Resources' Form 10-K Report (File No. 1-905) for the year
ended December 31, 1998)
[_]10(i)-2 - Amendment No. 1 to said Officers Deferred Compensation Plan,
effective September 1, 1998 (Exhibit 10(m)-2 to PP&L
Resources' Form 10-K Report (File No. 1-905) for the year
ended December 31, 1998)
<PAGE>
[_]10(j)-1 - Amended and Restated Supplemental Executive Retirement Plan,
effective January 1, 1998 (Exhibit 10(n)-1 to PP&L
Resources' Form 10-K Report (File No. 1-905) for the year
ended December 31, 1998)
[_]10(j)-2 - Amendment No. 1 to said Supplemental Executive Retirement
Plan, effective September 1, 1998 (Exhibit 10(n)-2 to PP&L
Resources' Form 10-K Report (File No. 1-905) for the year
ended December 31, 1998)
*10(j)-3 - Amendment No. 2 to said Supplemental Executive Retirement
Plan, effective July 1, 1999
10(k)-1 - Amended and Restated Incentive Compensation Plan, effective
January 1, 1999 (Schedule A to Proxy Statement of PP&L
Resources, dated March 12, 1999)
*10(k)-2 - Amendment No. 1 to said Amended and Restated Incentive
Compensation Plan, effective January 1, 1999
10(l) - Short-Term Incentive Plan (Schedule B to Proxy Statement of
PP&L Resources, dated March 12, 1999)
[_]10(m) - Terry H. Hunt Employment Agreement, dated as of October 1,
1998, among PP&L Resources, Inc., Terry H. Hunt and Penn
Fuel Gas, Inc. (Exhibit 10(q) to PP&L Resources' Form 10-K
Report (File No. 1-905) for the year ended December 31,
1998)
[_]10(n) - Form of Severance Agreement entered into between PP&L
Resources and Officers (Exhibit 10 to PP&L Resources' Form
10-Q Report (File No. 1-905) for the quarter ended June 30,
1998)
10(o) - Nuclear Fuel Lease, dated as of February 1, 1982, between
PP&L, as lessee, and Newton I. Waldman, not in his
individual capacity, but solely as Cotrustee of the
Pennsylvania Power & Light Energy Trust, as lessor (Exhibit
10(g) to PP&L's Form 10-K Report (File No. 1-905) for the
year ended December 31, 1981)
<PAGE>
10(p)-1 - Asset Purchase Agreement between PP&L Global, Inc. and The
Montana Power Company (Exhibit 10(a) to PP&L Resources' Form
10-Q Report (File No. 1-905) for the quarter ended September
30, 1998)
10(p)-2 - Equity Contribution Agreement among PP&L Resources, Inc.,
PP&L Global Inc. and The Montana Power Company (Exhibit
10(b) to PP&L Resources' Form 10-Q Report (File No. 1-905)
for the quarter ended September 30, 1998)
10(q)-1 - Asset Purchase Agreement between PP&L Global, Inc. and
Portland General Electric Company (Exhibit 10(c) to PP&L
Resources' Form 10-Q Report (File No. 1-905) for the quarter
ended September 30, 1998)
10(q)-2 - Equity Contribution Agreement among PP&L Resources, Inc.,
PP&L Global, Inc. and Portland General Electric Company
(Exhibit 10(d) to PP&L Resources' Form 10-Q Report (File No.
1-905) for the quarter ended September 30, 1998)
10(r)-1 - Asset Purchase Agreement between PP&L Global, Inc. and Puget
Sound Energy, Inc. (Exhibit 10(e) to PP&L Resources' Form
10-Q Report (File No. 1-905) for the quarter ended September
30, 1998)
10(r)-2 - Equity Contribution Agreement among PP&L Resources, Inc.,
PP&L Global, Inc. and Puget Sound Energy, Inc. (Exhibit
10(f) to PP&L Resources' Form 10-Q Report (File No. 1-905)
for the quarter ended September 30, 1998)
10(s)-1 - Asset Purchase Agreement among PP&L Global, Inc., Penobscot
Hydro Co., Inc. and Bangor Hydro-Electric Company (Exhibit
10(w)-1 to PP&L Resources' 10-K Report for the year ended
December 31, 1998)
10(s)-2 - Equity Contribution Agreement, among PP&L Global, Inc., PP&L
Resources, Inc., Penobscot Hydro Co., Inc. and Bangor Hydro-
Electric Company (Exhibit 10(w)-2 to PP&L Resources' 10-K
Report for the year ended December 31, 1998)
<PAGE>
*12(a) - PPL Corporation and Subsidiaries Computation of Ratio of
Earnings to Fixed Charges
*12(b) - PPL Electric Utilities Corporation and Subsidiaries
Computation of Ratio of Earnings to Fixed Charges
*23 - Consent of PricewaterhouseCoopers LLP
*24 - Power of Attorney
*27 - Financial Data Schedule
<PAGE>
EXHIBIT 4(a)-4
AMENDMENT NO. 3
TO
PP&L
EMPLOYEE STOCK OWNERSHIP PLAN
WHEREAS, PP&L, Inc. ("Company") has adopted the PP&L Employee Stock
Ownership Plan ("Plan") effective January 1, 1975; and
WHEREAS, the Plan was amended and restated effective January 1, 1998, and
subsequently amended by Amendment Nos. 1 and 2; and
WHEREAS, the Company desires to further amend the Plan;
NOW, THEREFORE, the Plan is hereby amended as follows:
I. Effective September 14, 1998 the following sections of Articles II, III, IV,
V, VII, VIII, IX, X, XII and XIII are amended to read:
2.3 "Affiliated Company" or "Affiliated Companies" shall mean with respect
to any Participating Company, (a) any corporation that is a member of a
controlled group of corporations, as determined under section 414(b) of the
Code, which includes such Participating Company; (b) any member of an affiliated
service group, as determined under section 414(m) of the Code, of which such
Participating Company is a member; (c) any trade or business (whether or not
incorporated) that is under common control with such Participating Company, as
determined under section 414(c) of the Code; and (d) any other organization or
entity which is required to be aggregated with the Participating Company under
section 414(o) of the Code and regulations issued thereunder. "50% Affiliated
Company" means an Affiliated Company, but determined with "more than 50%"
substituted for the phrase "at least 80%" in section 1563(a) of the Code, when
applying sections 414(b) and (c) of the Code.
2.7 "Compensation" shall mean the annual compensation received by an
Employee from a Participating Company as reported on Internal Revenue Service
Form W-2 or a successor form plus the Employee's elective deferrals under the
Employee Savings Plan or Deferred Savings Plan; provided, however, that
Compensation shall not
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<PAGE>
include fringe benefits not normally included in compensation, such as tuition
refunds, moving expenses, etc. and shall not, for purposes of allocation under
Section 5.2(a), include any amount in excess of (i) for the 1975 and 1976 Plan
Years, $16,000 and (ii) commencing with the 1977 Plan Year, the median annual
compensation of all Participants during the Plan Year or $100,000, whichever is
less. Such median compensation shall be determined as of the close of a Plan
Year and shall be rounded to an even thousand dollars. For an Employee
classified as a Managers Compensation Plan employee, Compensation shall also
include the full amount of any single-sum award paid to the Participant from the
fund credited annually with a percentage of annualized base pay salaries in
accordance with the Managers Compensation Plan.
2.11 "Dividend-based Contribution" shall mean the contribution made by a
Participating Company or Resources in accordance with Section 4.4.
2.14 "Employee" shall mean any person classified by a Participating Company
as an employee of such Participating Company, including officers, shareholders,
or directors who are employees, but excluding:
(a) persons covered by a collective bargaining agreement unless such
agreement specifically provides for participation under the Retirement Plan;
(b) persons classified by the Participating Company as independent
contractors, regardless of whether they are subsequently determined to be
employees for employment tax or any other purpose;
(c) persons classified by the Participating Company as leased employees,
whether or not as described in section 414(n) of the Code;
(d) persons classified by the Participating Company as specific
professional employees, cooperative associates, or college interns, as those
terms are defined under Participating Company policy.
2.26 "Participating Company" shall mean PP&L, PP&L EnergyPlus Co., and each
other Affiliated Company which is authorized by the Board to adopt this Plan by
action of its board of directors.
2.31 "Qualified Military Service" means any service (either voluntary or
involuntary) by an individual in the Uniformed Services if such individual is
entitled to reemployment rights with a Participating Company with respect to
such service.
2.34 "Returning Veteran" means a former Employee who on or after December
12, 1994, returns from Qualified Military Service to employment by a
Participating Company within the period of time during which his reemployment
rights are
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<PAGE>
protected by law.
3.1 Eligibility.
(a) All persons who were participants in the Plan immediately prior to the
Effective Date and who are in the employ of a Participating Company on the
Effective Date shall be Participants hereunder as of such date. All Employees
as of the Effective Date (but who are not eligible to participate under the
preceding sentence) who have completed one year of Credited Service shall be
Participants as of that date. Other Employees shall become Participants on the
first day of the calendar month next following the date on which an Employee
completes one year of Credited Service, or if later, on which an individual
becomes an Employee. A "year of Credited Service," for the purposes of this
Article, shall require completion of at least 1,000 Hours of Service during the
12 months from commencement of employment. An Employee who fails to complete
1,000 Hours of Service during his initial 12 months of employment shall complete
a year of Credited Service as of the end of any Plan Year in which he completes
1,000 Hours of Service; provided, however, that the first Plan Year during which
such Employee shall have the opportunity to complete such 1,000 Hours of Service
shall include the anniversary of his commencement of employment.
(b) An Employee may elect in writing not to become a Participant by filing
such election with the Employee Benefit Plan Board.
3.4 Officers, Directors, and Shareholders. Officers, directors, and
shareholders of a Participating Company who are Participants shall participate
in the Plan on the same basis as other Participants.
4.4 Dividend-based Contribution. Commencing with the 1990 Plan Year, a
Participating Company or Resources may contribute to the Plan an amount
determined at the sole discretion of PP&L or Resources relating to the reduction
in taxes arising out of the payment of dividends to participants and the
contribution thereof to the Plan. The Dividend-based Contribution is in
addition to contributions made pursuant to Sections 4.1, 4.2 and 4.3. All
contributions by PP&L, Resources or a Participating Company are expressly
conditioned upon their deductibility for federal income tax purposes.
5.3 Allocation of Earnings. Any dividends or other distributions on the
Stock allocated to a Participant's Account shall be paid no later than 90 days
after the close of the Plan Year to the Participant in cash either by the
Trustee or directly by PP&L, a Participating Company or Resources.
5.5 Maximum Allocation. The provisions of this Section shall be construed
to comply with section 415 of the Code.
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<PAGE>
(a) Notwithstanding anything in this Article to the contrary, in no event
shall the sum of (1) any Participating Company or Resources contributions and
other employer contributions, (2) any forfeitures and (3) the Participant's own
contributions, if any, allocated for any Limitation Year to any Participant
under this and any other defined contribution plan maintained by PP&L or any 50%
Affiliated Company, exceed the lesser of (A) $30,000 plus the lesser of $30,000
or the value of the Stock contributed to the Plan for such Plan Year or (B)
twenty-five percent (25%) of any Participant's compensation for the Limitation
Year. Amounts described in sections 415(l) and 419A(d)(2) of the Code
contributed for any Plan Year for the benefit of any Participant shall be
treated as annual additions to the extent provided in such Sections.
7.2 Death. If a Participant dies either while in the employment of a
Participating Company or after termination of employment but prior to the
commencement of benefit payments, the full amount of his interest in the Fund
shall be paid to the Participant's beneficiary in a single sum.
7.7 Timing of Distribution.
(b) A Participant who terminates employment with a Participating Company on
or after age 55, and whose Account exceeds, or exceeded at the time of any prior
distribution, $5,000, shall be entitled to defer payment of his benefits until a
date not later than that specified in Section 7.7(a)(2).
8.2 Duties and Powers of Employee Benefit Plan Board and Administrative
Committee.
(a) In addition to the duties and powers described elsewhere hereunder, the
Employee Benefit Plan Board shall have all such powers as may be necessary to
discharge its duties hereunder including but not limited to the following
specific duties and powers:
(9) to establish a claims procedure under which claims will be reviewed
by the Manager-Employee Benefits of PP&L, or such other individual as may be
designated by the Vice President-Human Resources of PP&L and under which each
claimant shall receive notice in writing in the event any claim for benefits
with respect to a Participant's participation in the Plan has been denied; such
notice shall set forth the specific reasons for such denial. Such claims
procedure shall also provide an opportunity for full and fair review by the
Administrative Committee of the Employee Benefit Plan Board;
8.3 Reliance on Reports and Certificates. The members of the Employee
Benefit Plan Board and the officers and directors of PP&L, any Participating
Company and Resources shall be entitled to rely upon all valuations,
certificates and reports made
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<PAGE>
by the Trustee or by any duly appointed accountant, and upon all opinions given
by any duly appointed legal counsel.
8.5 Indemnification of the Employee Benefit Plan Board. Each member of the
Employee Benefit Plan Board, the Administrative Committee, and each of their
designees shall be indemnified by the Participating Companies against expenses
(other than amounts paid in settlement to which a Participating Company does not
consent) reasonably incurred by him in connection with any action to which he
may be a party by reason of the delegation to him of administrative functions
and duties, except in relation to matters as to which he shall be adjudged in
such action to be personally guilty of negligence or willful misconduct in the
performance of his duties. The foregoing right to indemnification shall be in
addition to such other rights as the member of the Employee Benefit Plan Board,
the Administrative Committee, and each of their designees may enjoy as a matter
of law or by reason of insurance coverage of any kind. Rights granted hereunder
shall be in addition to and not in lieu of any rights to indemnification to
which the member of the Employee Benefit Plan Board, the Administrative
Committee and each of their designees may be entitled pursuant to the bylaws of
PP&L. Service on the Employee Benefit Plan Board shall be deemed in partial
fulfillment of the Employee Benefit Plan Board member's function as an employee,
officer and/or director of PP&L or Resources, if he serves in such other
capacity as well.
9.5 Expenses. All expenses of administration of this Plan shall be paid
from the Fund unless they are paid directly by a Participating Company.
10.1 Amendment. PP&L reserves the power to amend the Plan at any time by or
pursuant to action of the Board of Directors. In addition, the Employee Benefit
Plan Board may make such amendments to the Plan as it deems necessary or
desirable except those amendments which substantially increase the cost of the
Plan to PP&L or a Participating Company or significantly alter the benefit
design or eligibility requirements of the Plan. Each amendment to the Plan will
be binding on each Participating Company. Except as expressly provided
elsewhere in the Plan, prior to the satisfaction of all liabilities with respect
to the benefits provided under this Plan, no such amendment or termination shall
cause any part of the monies contributed hereunder to revert to PP&L or to be
diverted to any purpose other than for the exclusive benefit of Participants and
their beneficiaries. No amendment shall have the effect of retroactively
depriving Participants of benefits already accrued under the Plan. Upon
complete termination of the Plan without establishment or maintenance of a
successor plan (other than an employee stock ownership plan as defined in
section 4975(e)(7) of the Code), Participants may receive distribution of their
Accounts. Amendments to the allocation formulas contained in Article V shall
not be made more frequently than once every six months.
10.2 Termination. The Plan and the Fund forming part of the Plan may be
terminated or contributions completely discontinued at any time by or pursuant
to action
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<PAGE>
of the board of directors of Resources. In the event of a termination, partial
termination, or a complete discontinuance of contributions or in the event
Resources is dissolved, liquidated, or adjudicated a bankrupt, the interest of
the Participants, their estates and beneficiaries, shall be nonforfeitable and
shall be fully vested, and distributions shall be made to them in full shares of
Stock and cash in lieu of fractional shares based on the price at which the
Trustee sells such Stock or the fair market value thereof. When all assets have
been paid out by the Trustee, the Fund shall cease. Any distribution after
termination of the Plan may be made at any time, and from time to time, in whole
or in part in full shares of Stock and cash in lieu of fractional shares based
on the price at which the Trustee sells such Stock or the fair market value
thereof; provided, however, that no Stock may be distributed to a Participant
within seven years after the month in which such Stock was allocated to the
Participant's Account except in the case of the Participant's retirement, Total
Disability, death or other termination of employment with PP&L and all
Affiliated Companies. In making such distributions, any and all determinations,
divisions, appraisals, apportionments and allotments so made shall be final and
conclusive.
12.1 No Employment Rights. Neither the action of PP&L in establishing the
Plan, nor any provisions of the Plan, nor any action taken by it or by the
Employee Benefit Plan Board shall be construed as giving to any employee of a
Participating Company the right to be retained in its employ, or any right to
payment except to the extent of the benefits provided in the Plan to be paid
from the Fund.
12.2 Source of Benefits. All benefits payable under the Plan shall be paid
or provided for solely from the Fund, and neither any Participating Company nor
Resources assume liability or responsibility therefor.
12.5 Incapacity. If the Employee Benefit Plan Board deems any Participant
who is entitled to receive payments hereunder incapable of receiving or
disbursing the same by reason of age, illness or infirmity or incapacity of any
kind, the Employee Benefit Plan Board may direct the Trustee to apply such
payment directly for the comfort, support and maintenance of such Participant or
to pay the same to any responsible person caring for the Participant as
determined by the Employee Benefit Plan Board to be qualified to receive and
disburse such payments for the Participant's benefit, and the receipt of benefit
such person shall be a complete acquittance for the payment of benefit.
Payments pursuant to this Section 12.5 shall be complete discharge to the extent
thereof of any and all liability of the Participating Companies, Resources, the
Employee Benefit Plan Board, the Administrative Committee (if any), the Trustee,
and the Fund.
12.7 Voting or Tendering Stock.
(c) Confidentiality. All instructions received by the Trustee from
individual participants (or beneficiaries) pursuant to this Section 12.7 shall
be held by the
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<PAGE>
Trustee in strict confidence and shall not be divulged or released to any
person; provided, that, to the extent necessary for the operation of the Plan or
compliance with applicable law, such instructions may be relayed by the Trustee
to a recordkeeper, auditor or other person providing services to the Plan or
responsible for monitoring compliance with applicable laws, if such person is
either:
(1) a person who is not a Participating Company or an
Affiliated Company or an employee, officer or director
of a Participating Company or an Affiliated Company and
who agrees not to divulge such instructions to any
other person, including a Participating Company, an
Affiliated Company, or employees, officers and
directors of a Participating Company or an Affiliated
Company; or
(2) a person who is an employee of a Participating Company
or an Affiliated Company, if such person is
specifically authorized by the Employee Benefit Plan
Board to receive such information pursuant to
confidentiality procedures designed to safeguard the
confidentiality of such information. The Employee
Benefit Plan Board shall be responsible for monitoring
compliance with such procedures, for the adequacy of
such procedures, and for appointing an independent
fiduciary to carry out activities relating to any
situation that, in the determination of the Employee
Benefit Plan Board, involves a potential for undue
employer influence on Participants (or beneficiaries)
with regard to their exercise of rights under this
Section 12.7.
13.1 Applicability and Effective Date. The rights of any Returning Veteran
who resumes employment with a Participating Company on or after December 12,
1994 shall be modified as set forth in this Article.
13.3 Restoration of TRASOP, PAYSOP, and Dividend-based Contributions. With
respect to any Plan Year for which a Returning Veteran would have been a
Participant, but failed to share in TRASOP, PAYSOP, or Dividend-based
Contributions under Sections 4.1, 4.3 and 4.4 solely by reason of his Qualified
Military Service, the Participating Company shall contribute to such
Participant's Account an amount equal to the TRASOP, PAYSOP, and Dividend-based
Contributions that would have been allocated to his Account, but for his absence
for Qualified Military Service. Such contribution shall not include the
earnings that would have accrued on such amount.
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<PAGE>
13.4 Restoration of Matching Contributions.
(a) Each Returning Veteran who, during his period of Qualified Military
Service, would have been eligible to make Matching Contributions shall be
permitted to contribute an amount equal to the Matching Contributions that he
could have made during such absence from employment. Such "make-up"
contributions shall be made during the period that begins with his reemployment
by a Participating Company and ends with (1) the expiration of a period of five
years, or (2) if shorter, a period of three times the period of Qualified
Military Service.
(b) Any make-up contributions described in Subsection (a) hereof shall be
in addition to those Matching Contributions that the Participant may elect to
make pursuant to Section 4.2.
13.5 Determination of Compensation. For purposes of determining the amount
of any make-up contributions under Section 13.3 or Section 13.4 and for applying
the limits of Section 5.5, a Participant's compensation during any period of
Qualified Military Service shall be deemed to equal either:
(a) the compensation he would have received but for such Qualified Military
Service, based on the rate of pay he would have received from a Participating
Company; or
(b) if the amount described in (a) above is not reasonably certain, his
average compensation from a Participating Company during the 12-month period
immediately preceding the Qualified Military Service (or, if shorter, the period
of employment immediately preceding the Qualified Military Service). Such
amount shall be adjusted as necessary to reflect the length of the Participant's
Qualified Military Service.
II. Except as provided for in this Amendment No. 3, all other provisions of
the Plan shall remain in full force and effect.
IN WITNESS WHEREOF, this Amendment No. 3 is executed this _____ day of
________________, 1999.
PP&L, INC.
By:____________________________________
John M. Chappelear
Vice President-Investments & Pensions
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<PAGE>
EXHIBIT 4(a)-5
AMENDMENT NO. 4
TO
PP&L
EMPLOYEE STOCK OWNERSHIP PLAN
WHEREAS, PP&L, Inc. ("PP&L") has adopted the PP&L Employee Stock Ownership
Plan ("Plan") effective January 1, 1975; and
WHEREAS, the Plan was amended and restated effective January 1, 1998, and
subsequently amended by Amendment Nos. 1, 2 and 3; and
WHEREAS, the Company desires to further amend the Plan;
NOW, THEREFORE, the Plan is hereby amended as follows:
I. Effective January 1, 1999 the following section of Article II is amended to
read:
2.14 "Employee" shall mean any person classified by a Participating Company
as an employee of such Participating Company, including officers, shareholders,
or directors who are employees, but excluding:
(d) persons classified by the Participating Company as cooperative
associates or college interns, as those terms are defined under Participating
Company policy.
II. Except as provided for in this Amendment No. 4, all other provisions of
the Plan shall remain in full force and effect.
IN WITNESS WHEREOF, this Amendment No. 4 is executed this _____ day of
________________, 1999.
PP&L, INC.
By:_______________________________________
John M. Chappelear
Vice President-Investments & Pensions
<PAGE>
EXHIBIT 4(a)-6
AMENDMENT NO. 5
TO
PP&L
EMPLOYEE STOCK OWNERSHIP PLAN
WHEREAS, PP&L, Inc. ("PP&L") has adopted the PP&L Employee Stock Ownership
Plan ("Plan") effective January 1, 1975; and
WHEREAS, the Plan was amended and restated effective January 1, 1998, and
subsequently amended by Amendment Nos. 1, 2, 3 and 4; and
WHEREAS, recent litigation involving the eligibility of independent
contractors to participate in the employee benefit plans of other companies has
highlighted the need to clarify that those individuals who are classified by
PP&L or affiliated companies as independent contractors have at no time, since
the inception of the Plan, been entitled to be eligible employees under the
Plan; and
WHEREAS, the modifications to the definition of "Employee" set forth in
this amendment do not change the terms of the Plan, but rather clarify existing
terms of the Plan;
NOW THEREFORE, the following section of Article II is hereby amended to
read as follows, to clarify the manner in which the Plan has been operated since
its inception:
2.14 "Employee" shall mean any person classified by a Participating Company
as an employee of such Participating Company, including officers, shareholders,
or directors who are employees, but excluding:
(a) persons covered by a collective bargaining agreement unless such
agreement specifically provides for participation under the Retirement Plan;
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<PAGE>
(b) persons classified by the Participating Company as independent
contractors, regardless of whether they are subsequently determined to be
employees for employment tax or any other purpose. In no event shall the term
"Employee" include persons classified by a Participating Company as independent
contractors, regardless of whether they are subsequently determined to be
employees for employment tax or any other reason, or persons classified by a
Participating Company as leased employees, whether or not described in section
414(n) of the Code. For purposes of the preceding sentence, an "independent
contractor" shall be an individual who is classified by the Participating
Company in accordance with objective business criteria as an independent
contractor in a good faith determination consistent with the factors set forth
in Revenue Ruling 87-41 or any successor thereto, provided that the
Participating Company has communicated to the individual that he has been
engaged as an independent contractor rather than as an Employee. The foregoing
exclusion is intended solely to prevent the retroactive participation by
individuals classified in good faith as independent contractors in the event
that such status should be determined, for employment tax or any other purposes,
to be incorrect.
Except as provided for in this Amendment No. 5, all other provisions of the
Plan shall remain in full force and effect.
IN WITNESS WHEREOF, this Amendment No. 5 is executed this _____ day of
________________, 1999.
PP&L, INC.
By:_____________________________________
John M. Chappelear
Vice President-Investments & Pensions
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<PAGE>
EXHIBIT 4(B).19
- --------------------------------------------------------------------------------
PP&L, INC
(formerly Pennsylvania Power & Light Company)
TO
BANKERS TRUST COMPANY
(successor to Morgan Guaranty Trust Company of New York,
formerly Guaranty Trust Company of New York)
As Trustee under PP&L, Inc.'s
Mortgage and Deed of Trust,
Dated as of October 1, 1945
________________________
Sixty-seventh Supplemental Indenture
Providing among other things for
First Mortgage Bonds, Short-Term Series B
________________________
Dated as of June 1, 1999
- -------------------------------------------------------------------------------
<PAGE>
SIXTY-SEVENTH SUPPLEMENTAL INDENTURE
SIXTY-SEVENTH SUPPLEMENTAL INDENTURE, dated as of the 1st day of June, 1999
made and entered into by and between PP&L, INC. (formerly Pennsylvania Power &
Light Company), a corporation of the Commonwealth of Pennsylvania, whose address
is Two North Ninth Street, Allentown, Pennsylvania 18101 (hereinafter sometimes
called the Company), and BANKERS TRUST COMPANY (successor to MORGAN GUARANTY
TRUST COMPANY OF NEW YORK, formerly GUARANTY TRUST COMPANY OF NEW YORK), a
corporation of the State of New York, whose address is 130 Liberty Street, New
York, New York 10006 (hereinafter sometimes called the Trustee), as Trustee
under the Mortgage and Deed of Trust, dated as of October 1, 1945 (hereinafter
called the Mortgage and, together with any indentures supplemental thereto,
hereinafter called the Indenture), which Mortgage was executed and delivered by
Pennsylvania Power & Light Company to secure the payment of bonds issued or to
be issued under and in accordance with the provisions of the Mortgage, reference
to which said Mortgage is hereby made, this instrument (hereinafter called the
Sixty-seventh Supplemental Indenture) being supplemental thereto;
WHEREAS, said Mortgage was or is to be recorded in various Counties in the
Commonwealth of Pennsylvania, which Counties include or will include all
Counties in which this Sixty-seventh Supplemental Indenture is to be recorded;
and
WHEREAS, by an amendment to its Articles of Incorporation filed with the
Office of the Secretary of State of Pennsylvania on September 12, 1997, the
Company changed its name to PP&L, Inc.; and
WHEREAS, an instrument, dated August 5, 1994, was executed by the Company
appointing Bankers Trust Company as Trustee in succession to said Morgan
Guaranty Trust Company of New York (resigned) under the Indenture, and by
Bankers Trust Company accepting said appointment, which instrument was or is to
be recorded in various Counties in the Commonwealth of Pennsylvania; and
WHEREAS, by the Mortgage the Company covenanted that it would execute and
deliver such supplemental indenture or indentures and such further instruments
and do such further acts as might be necessary or proper to carry out more
effectually the purposes of the Indenture and to make subject to the lien of the
Indenture any property thereafter acquired and intended to be subject to the
lien thereof; and
WHEREAS, the Company executed and delivered as supplements to the Mortgage,
the following supplemental indentures:
Designation Dated as of
----------- -----------
First Supplemental Indenture.................. July 1, 1947
Second Supplemental Indenture................. December 1, 1948
Third Supplemental Indenture.................. February 1, 1950
Fourth Supplemental Indenture................. March 1, 1953
Fifth Supplemental Indenture.................. August 1, 1955
Sixth Supplemental Indenture.................. December 1, 1961
Seventh Supplemental Indenture................ March 1, 1964
Eighth Supplemental Indenture................. June 1, 1966
Ninth Supplemental Indenture.................. November 1, 1967
Tenth Supplemental Indenture.................. December 1, 1967
Eleventh Supplemental Indenture............... January 1, 1969
Twelfth Supplemental Indenture................ June 1, 1969
Thirteenth Supplemental Indenture............. March 1, 1970
Fourteenth Supplemental Indenture............. February 1, 1971
Fifteenth Supplemental Indenture.............. February 1, 1972
Sixteenth Supplemental Indenture.............. January 1, 1973
<PAGE>
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Designation Dated as of
----------- -----------
Seventeenth Supplemental Indenture............ May 1, 1973
Eighteenth Supplemental Indenture............. April 1, 1974
Nineteenth Supplemental Indenture............. October 1, 1974
Twentieth Supplemental Indenture.............. May 1, 1975
Twenty-first Supplemental Indenture........... November 1, 1975
Twenty-second Supplemental Indenture.......... December 1, 1976
Twenty-third Supplemental Indenture........... December 1, 1977
Twenty-fourth Supplemental Indenture.......... April 1, 1979
Twenty-fifth Supplemental Indenture........... April 1, 1980
Twenty-sixth Supplemental Indenture........... June 1, 1980
Twenty-seventh Supplemental Indenture......... June 1, 1980
Twenty-eighth Supplemental Indenture.......... December 1, 1980
Twenty-ninth Supplemental Indenture........... February 1, 1981
Thirtieth Supplemental Indenture.............. February 1, 1981
Thirty-first Supplemental Indenture........... September 1, 1981
Thirty-second Supplemental Indenture.......... April 1, 1982
Thirty-third Supplemental Indenture........... August 1, 1982
Thirty-fourth Supplemental Indenture.......... October 1, 1982
Thirty-fifth Supplemental Indenture........... November 1, 1982
Thirty-sixth Supplemental Indenture........... February 1, 1983
Thirty-seventh Supplemental Indenture......... November 1, 1983
Thirty-eighth Supplemental Indenture.......... March 1, 1984
Thirty-ninth Supplemental Indenture........... April 1, 1984
Fortieth Supplemental Indenture............... August 15, 1984
Forty-first Supplemental Indenture............ December 1, 1984
Forty-second Supplemental Indenture........... June 15, 1985
Forty-third Supplemental Indenture............ October 1, 1985
Forty-fourth Supplemental Indenture........... January 1, 1986
Forty-fifth Supplemental Indenture............ February 1, 1986
Forty-sixth Supplemental Indenture............ April 1, 1986
Forty-seventh Supplemental Indenture.......... October 1, 1986
Forty-eighth Supplemental Indenture........... March 1, 1988
Forty-ninth Supplemental Indenture............ June 1, 1988
Fiftieth Supplemental Indenture............... January 1, 1989
Fifty-first Supplemental Indenture............ October 1, 1989
Fifty-second Supplemental Indenture........... July 1, 1991
Fifty-third Supplemental Indenture............ May 1, 1992
Fifty-fourth Supplemental Indenture........... November 1, 1992
Fifty-fifth Supplemental Indenture............ February 1, 1993
Fifty-sixth Supplemental Indenture............ April 1, 1993
Fifty-seventh Supplemental Indenture.......... June 1, 1993
Fifty-eighth Supplemental Indenture........... October 1, 1993
Fifty-ninth Supplemental Indenture............ February 15, 1994
Sixtieth Supplemental Indenture............... March 1, 1994
Sixty-first Supplemental Indenture............ March 15, 1994
Sixty-second Supplemental Indenture........... September 1, 1994
Sixty-third Supplemental Indenture............ October 1, 1994
Sixty-fourth Supplemental Indenture........... August 1, 1995
<PAGE>
-3-
Designation Dated as of
----------- -----------
Sixty-fifth Supplemental Indenture............ April 1, 1997
Sixty-sixth Supplemental Indenture............ May 1, 1998
which supplemental indentures were or are to be recorded in various Counties in
the Commonwealth of Pennsylvania; and
WHEREAS, the Company executed and delivered its Supplemental Indenture,
dated July 1, 1954, creating a security interest in certain personal property of
the Company, pursuant to the provisions of the Pennsylvania Uniform Commercial
Code, as a supplement to the Mortgage, which Supplemental Indenture was filed in
the Office of the Secretary of the Commonwealth of Pennsylvania on July 1, 1954,
and all subsequent supplemental indentures were so filed; and
WHEREAS, in addition to the property described in the Mortgage, as
heretofore supplemented, the Company has acquired certain other property, rights
and interests in property; and
WHEREAS, the Company has heretofore issued, in accordance with the
provisions of the Mortgage, as supplemented, the following series of First
Mortgage Bonds:
Principal Principal
Amount Amount
Series Issued Outstanding
- ------ ------ -----------
3% Series due 1975..................... $ 93,000,000 None
2-3/4% Series due 1977................. 20,000,000 None
3-1/4% Series due 1978................. 10,000,000 None
2-3/4% Series due 1980................. 37,000,000 None
3-1/2% Series due 1983................. 25,000,000 None
3-3/8% Series due 1985................. 25,000,000 None
4-5/8% Series due 1991................. 30,000,000 None
4-5/8% Series due 1994................. 30,000,000 None
5-5/8% Series due 1996................. 30,000,000 None
6-3/4% Series due 1997................. 30,000,000 None
6-1/2% Series due 1972................. 15,000,000 None
7% Series due 1999..................... 40,000,000 None
8-1/8% Series due June 1, 1999......... 40,000,000 None
9% Series due 2000..................... 50,000,000 None
7-1/4% Series due 2001................. 60,000,000 None
7-5/8% Series due 2002................. 75,000,000 None
7-1/2% Series due 2003................. 80,000,000 None
Pollution Control Series A............. 28,000,000 None
9-1/4% Series due 2004................. 80,000,000 None
10-1/8% Series due 1982................ 100,000,000 None
9-3/4% Series due 2005................. 125,000,000 None
9-3/4% Series due November 1, 2005..... 100,000,000 None
8-1/4% Series due 2006................. 150,000,000 None
8-1/2% Series due 2007................. 100,000,000 None
9-7/8% Series due 1983-1985............ 100,000,000 None
<PAGE>
-4-
Principal Principal
Amount Amount
Series Issued Outstanding
- ------ ------ -----------
15-5/8% Series due 2010................. $100,000,000 None
11-3/4% Series due 1984................. 30,000,000 None
Pollution Control Series B.............. 70,000,000 None
Pollution Control Series C.............. 20,000,000 None
14% Series due December 1, 1990......... 125,000,000 None
15% Series due 1984-1986................ 50,000,000 None
14-3/4% Series A due 1986............... 30,000,000 None
14-3/4% Series B due 1986............... 20,000,000 None
16-1/2% Series due 1987-1991............ 52,000,000 None
16-1/8% Series due 1992................. 100,000,000 None
16-1/2% Series due 1986-1990............ 92,500,000 None
13-1/4% Series due 2012................. 100,000,000 None
Pollution Control Series D.............. 70,000,000 None
12-1/8% Series due 1989-1993............ 50,000,000 None
13-1/8% Series due 2013................. 125,000,000 None
Pollution Control Series E.............. 37,750,000 None
13-1/2% Series due 1994................. 125,000,000 None
Pollution Control Series F.............. 115,500,000 None
12-3/4% Series due 2014................. 125,000,000 None
Pollution Control Series G.............. 55,000,000 None
12% Series due 2015..................... 125,000,000 None
10-7/8% Series due 2016................. 125,000,000 None
9-5/8% Series due 1996.................. 125,000,000 None
9% Series due 2016...................... 125,000,000 None
9-1/2% Series due 2016.................. 125,000,000 None
9-1/4% Series due 1998.................. 125,000,000 None
9-5/8% Series due 1998.................. 125,000,000 None
10% Series due 2019..................... 125,000,000 None
9-1/4% Series due 2019.................. 250,000,000 $215,000,000
9-3/8% Series due 2021.................. 150,000,000 99,750,000
7-3/4% Series due 2002.................. 150,000,000 150,000,000
8-1/2% Series due 2022.................. 150,000,000 150,000,000
Pollution Control Series H.............. 90,000,000 90,000,000
6-7/8% Series due 2003.................. 100,000,000 100,000,000
7-7/8% Series due 2023.................. 200,000,000 200,000,000
5-1/2% Series due 1998.................. 150,000,000 None
6-1/2% Series due 2005.................. 125,000,000 125,000,000
6% Series due 2000...................... 125,000,000 125,000,000
6-3/4% Series due 2023.................. 150,000,000 150,000,000
Pollution Control Series I.............. 53,250,000 53,250,000
6.55% Series due 2006................... 150,000,000 150,000,000
7.30% Series due 2024................... 150,000,000 150,000,000
6-7/8% Series due 2004.................. 150,000,000 150,000,000
7-3/8% Series due 2014.................. 100,000,000 100,000,000
Pollution Control Series J.............. 115,500,000 115,500,000
<PAGE>
-5-
Principal Principal
Amount Amount
Series Issued Outstanding
- ------ ------ -----------
7.70% Series due 2009....................... $200,000,000 $200,000,000
Pollution Control Series K.................. 55,000,000 55,000,000
Short-Term Series A......................... 800,000,000 None
6 1/8% REset Put Securities Series due 2006. 200,000,000 200,000,000
which bonds are also sometimes called bonds of the First through Seventy-fourth
Series, respectively; and
WHEREAS, Section 8 of the Mortgage provides that the form of each series of
bonds (other than the First Series) issued thereunder shall be established by
Resolution of the Board of Directors of the Company and that the form of such
series, as established by said Board of Directors, shall specify the descriptive
title of the bonds and various other terms thereof, and may also contain such
provisions not inconsistent with the provisions of the Indenture as the Board of
Directors may, in its discretion, cause to be inserted therein expressing or
referring to the terms and conditions upon which such bonds are to be issued
and/or secured under the Indenture; and
WHEREAS, Section 120 of the Mortgage provides, among other things, that any
power, privilege or right expressly or impliedly reserved to or in any way
conferred upon the Company by any provision of the Indenture, whether such
power, privilege or right is in any way restricted or is unrestricted, may be in
whole or in part waived or surrendered or subjected to any restriction if at the
time unrestricted or to additional restriction if already restricted, and the
Company may enter into any future covenants, limitations or restrictions for the
benefit of any one or more series of bonds issued thereunder, or the Company may
cure any ambiguity contained therein or in any supplemental indenture or may
establish the terms and provisions of any series of bonds other than said First
Series, by an instrument in writing executed and acknowledged by the Company in
such manner as would be necessary to entitle a conveyance of real estate to
record in all of the States in which any property at the time subject to the
lien of the Indenture shall be situated; and
WHEREAS, the Company now desires to create a new series of bonds and to add
to its covenants and agreements contained in the Mortgage, as heretofore
supplemented, certain other covenants and agreements to be observed by it and to
alter and amend in certain respects the covenants and provisions contained in
the Mortgage; and
WHEREAS, the execution and delivery by the Company of this Sixty-seventh
Supplemental Indenture, and the terms of the bonds of the Seventy-fifth Series,
hereinafter referred to, have been duly authorized by the Board of Directors of
the Company by appropriate Resolutions of said Board of Directors;
NOW, THEREFORE, THIS INDENTURE WITNESSETH: That PP&L, Inc., in
consideration of the premises and of One Dollar to it duly paid by the Trustee
at or before the ensealing and delivery of these presents, the receipt whereof
is hereby acknowledged, and in further evidence of assurance of the estate,
title and rights of the Trustee and in order further to secure the payment both
of the principal of and interest and premium, if any, on the bonds from time to
time issued under the Indenture, according to their tenor and effect and the
performance of all the provisions of the Indenture (including any modification
made as in the Mortgage provided) and of said bonds, hereby grants, bargains,
sells, releases, conveys, assigns, transfers, mortgages, pledges, sets over and
confirms (subject, however, to Excepted Encumbrances as defined in Section 6 of
the Mortgage) unto Bankers Trust Company, as Trustee under the Indenture, and to
its successor or successors in said trust, and to said Trustee and its
successors and assigns forever, all property, real, personal and mixed, of the
kind or nature specifically mentioned in the Mortgage, as heretofore
supplemented, or of any other kind or nature, acquired by the Company after the
date of the execution and delivery of the Sixty-sixth Supplemental Indenture
(except any herein or in the Mortgage, as heretofore supplemented, expressly
excepted and except any which may not lawfully be mortgaged or pledged under the
Indenture), now owned
<PAGE>
-6-
or, subject to the provisions of Section 87 of the Mortgage, hereafter acquired
by the Company (by purchase, consolidation, merger, donation, construction,
erection or in any other way) and wheresoever situated, including (without in
anywise limiting or impairing by the enumeration of the same the scope and
intent of the foregoing) all lands, power sites, flowage rights, water rights,
water locations, water appropriations, ditches, flumes, reservoirs, reservoir
sites, canals, raceways, dams, dam sites, aqueducts, and all other rights or
means for appropriating, conveying, storing and supplying water; all rights of
way and roads; all plants for the generation of electricity by steam, water
and/or other power; all power houses, gas plants, street lighting systems,
standards and other equipment incidental thereto, telephone, radio and
television systems, air-conditioning systems and equipment incidental thereto,
water works, water systems, steam heat and hot water plants, substations, lines,
service and supply systems, bridges, culverts, tracks, ice or refrigeration
plants and equipment, offices, buildings and other structures and the equipment
thereof; all machinery, engines, boilers, dynamos, electric, gas and other
machines, regulators, meters, transformers, generators, motors, electrical, gas
and mechanical appliances, conduits, cables, water, steam heat, gas or other
pipes, gas mains and pipes, service pipes, fittings, valves and connections,
pole and transmission lines, wires, cables, tools, implements, apparatus,
furniture and chattels; all municipal and other franchises, consents or permits;
all lines for the transmission and distribution of electric current, gas, steam
heat or water for any purpose including towers, poles, wires, cables, pipes,
conduits, ducts and all apparatus for use in connection therewith; all real
estate, lands, easements, servitudes, licenses, permits, franchises, privileges,
rights of way and other rights in or relating to real estate or the occupancy of
the same and (except as herein or in the Mortgage, as heretofore supplemented,
expressly excepted) all the right, title and interest of the Company in and to
all other property of any kind or nature appertaining to and/or used and/or
occupied and/or enjoyed in connection with any property hereinbefore or in the
Mortgage, as heretofore supplemented, described.
TOGETHER with all and singular the tenements, hereditaments, prescriptions,
servitudes, and appurtenances belonging or in anywise appertaining to the
aforesaid property or any part thereof, with the reversion and reversions,
remainder and remainders and (subject to the provisions of Section 57 of the
Mortgage) the tolls, rents, revenues, issues, earnings, income, product and
profits thereof, and all the estate, right, title and interest and claim
whatsoever, at law as well as in equity, which the Company now has or may
hereafter acquire in and to the aforesaid property and franchises and every part
and parcel thereof.
IT IS HEREBY AGREED by the Company that, subject to the provisions of
Section 87 of the Mortgage and to the extent permitted by law, all the property,
rights, and franchises acquired by the Company (by purchase, consolidation,
merger, donation, construction, erection or in any other way) after the date
hereof, except any herein or in the Mortgage, as heretofore supplemented,
expressly excepted, shall be and are as fully granted and conveyed hereby and as
fully embraced within the lien hereof and the lien of the Indenture, as if such
property, rights and franchises were now owned by the Company and were
specifically described herein and conveyed hereby.
IT IS HEREBY DECLARED by the Company that all the property, rights and
franchises now owned or hereafter acquired by the Company have been, or are, or
will be owned or acquired with the intention to use the same in carrying on the
business or branches of business of the Company, and it is hereby declared that
it is the intention of the Company that all thereof, except any herein or in the
Mortgage, as heretofore supplemented, expressly excepted, shall (subject to the
provisions of Section 87 of the Mortgage and to the extent permitted by law) be
embraced within the lien of this Sixty-seventh Supplemental Indenture and the
lien of the Indenture.
PROVIDED that the following are not and are not intended to be now or
hereafter granted, bargained, sold, released, conveyed, assigned, transferred,
mortgaged, pledged, set over or confirmed hereunder and are hereby expressly
excepted from the lien and operation of this Sixty-seventh Supplemental
Indenture and from the lien and operation of the Indenture, viz: (1) cash,
---
shares of stock, bonds, notes and other obligations and other securities not
hereafter specifically pledged, paid, deposited, delivered or held under the
Indenture or covenanted so to be; (2) goods, wares, merchandise, equipment,
apparatus, materials, or supplies held for the purpose of sale or other
disposition in the usual course of business; fuel, oil and similar materials and
supplies consumable in the operation of any of the properties of the Company;
construction equipment acquired for temporary use; all aircraft, rolling stock,
trolley coaches, buses,
<PAGE>
-7-
motor coaches, automobiles and other vehicles and materials and supplies held
for the purposes of repairing or replacing (in whole or part) any of the same;
all timber, minerals, mineral rights and royalties; (3) bills, notes and
accounts receivable, judgments, demands and choses in action, and all contracts,
leases and operating agreements not specifically pledged under the Indenture or
covenanted so to be; the Company's contractual rights or other interest in or
with respect to tires not owned by the Company; (4) the last day of the term of
any lease or leasehold which may be or become subject to the lien of the
Indenture; and (5) electric energy, gas, steam, ice, and other materials or
products generated, manufactured, produced or purchased by the Company for sale,
distribution or use in the ordinary course of its business; provided, however,
that the property and rights expressly excepted from the lien and operation of
the Indenture in the above subdivisions (2) and (3) shall (to the extent
permitted by law) cease to be so excepted in the event and as of the date that
the Trustee or a receiver or trustee shall enter upon and take possession of the
Mortgaged and Pledged Property in the manner provided in Article XIII of the
Mortgage by reason of the occurrence of a Default as defined in Section 65
thereof, as supplemented by the provisions of this Sixty-seventh Supplemental
Indenture.
TO HAVE AND TO HOLD all such properties, real, personal and mixed, granted,
bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged,
set over or confirmed by the Company as aforesaid, or intended so to be, unto
Bankers Trust Company, as Trustee, and its successors and assigns forever.
IN TRUST NEVERTHELESS for the same purposes and upon the same terms, trusts
and conditions and subject to and with the same provisos and covenants as are
set forth in the Mortgage, as heretofore supplemented, this Sixty-seventh
Supplemental Indenture being supplemental to the Mortgage.
AND IT IS HEREBY COVENANTED by the Company that all the terms, conditions,
provisos, covenants and provisions contained in the Mortgage, as heretofore
supplemented, shall affect and apply to the property hereinbefore described and
conveyed and to the estate, rights, obligations and duties of the Company and
the Trustee and the beneficiaries of the trust with respect to said property,
and to the Trustee and its successors as Trustee of said property in the same
manner and with the same effect as if the said property had been owned by the
Company at the time of the execution of the Mortgage, and had been specifically
and at length described in and conveyed to the Trustee by the Mortgage as a part
of the property therein stated to be conveyed.
The Company further covenants and agrees to and with the Trustee and its
successors in said trust under the Indenture, as follows:
ARTICLE I.
Seventy-fifth Series of Bonds
SECTION 1. There shall be a series of bonds designated "Short-Term Series
B" (herein sometimes referred to as the "Seventy-fifth Series"), each of which
shall also bear the descriptive title First Mortgage Bonds, and the form
thereof, which shall be established by Resolution of the Board of Directors of
the Company, shall contain suitable provisions with respect to the matters
hereinafter in this Section specified. Bonds of the Seventy-fifth Series shall
be limited to $600 million in aggregate principal amount (with no more than $200
million in aggregate principal amount to be Outstanding at any one time), except
as provided in Section 16 of the Mortgage, and shall be issued as fully
registered bonds in denominations of One Thousand Dollars and in any multiple or
multiples of One Thousand Dollars; each bond of the Seventy-fifth Series shall
mature on a date not more than sixty days from the date of issue, shall bear
interest at such rate or rates and have such other terms and provisions not
inconsistent with the Mortgage as the Board of Directors may determine in
accordance with one or more resolutions filed with the Trustee and one or more
written orders referring to this Sixty-seventh Supplemental Indenture; the
principal of and interest on each said bond to be payable at the office or
agency of the Company in the Borough of Manhattan, The City of New York, and
interest
<PAGE>
-8-
on each said bond to be also payable at the office of the Company in the City of
Allentown, Pennsylvania, in such coin or currency of the United States of
America as at the time of payment is legal tender for public and private debts.
Bonds of the Seventy-fifth Series shall be dated as in Section 10 of the
Mortgage provided.
Notwithstanding the foregoing, so long as there is no existing default in
the payment of interest on the bonds of the Seventy-fifth Series, the person in
whose name any bond of the Seventy-fifth Series is registered at the close of
business on any Record Date with respect to any interest payment date shall be
entitled to receive the interest payable on such interest payment date; provided
that, interest payable on the maturity date will be payable to the person to
whom the principal thereof shall be payable. "Record Date" for bonds of the
Seventy-fifth Series, shall mean the business day next preceding the
corresponding interest payment date. "Original Interest Accrual Date" with
respect to bonds of the Seventy-fifth Series of a designated interest rate and
maturity shall mean the date of first authentication of Bonds of a designated
interest rate and maturity unless the written order filed for such bonds with
the Trustee on or before such date shall specify another date from which
interest shall accrue, in which case "Original Interest Accrual Date" shall mean
such other date specified in the written order for Bonds of such designated
interest rate and maturity.
(I) Each holder of a bond of the Seventy-fifth Series, except as may be
provided in the written order requesting authentication and delivery of such
bond, consents that the bonds of the Seventy-fifth Series may be redeemable at
the option of the Company or pursuant to the requirements of the Indenture in
whole at any time, or in part from time to time, prior to maturity, without
notice provided in Section 52 of the Mortgage, at the principal amount of the
bonds to be redeemed, in each case, together with accrued interest to the date
fixed for redemption by the Company in a notice delivered on or before the date
fixed for redemption by the Company to the Trustee and to the holders of the
bonds to be redeemed.
(II) At the option of the registered owner, any bonds of the Seventy-fifth
Series, upon surrender thereof, for cancellation, at the office or agency of the
Company in the Borough of Manhattan, The City of New York, shall be exchangeable
for a like aggregate principal amount of bonds of the same series, interest
rate, maturity and other terms of other authorized denominations.
Bonds of the Seventy-fifth Series shall be transferable, upon the surrender
thereof for cancellation, together with a written instrument of transfer in form
approved by the registrar duly executed by the registered owner or by his duly
authorized attorney, at the office or agency of the Company in the Borough of
Manhattan, The City of New York; provided that such transfer shall not result in
any security being required to be registered under the Securities Act of 1933,
as amended, and an opinion of counsel satisfactory to the Company to such effect
shall have been provided to the Company.
Upon any transfer or exchange of bonds of the Seventy-fifth Series, the
Company may make a charge therefor sufficient to reimburse it for any tax or
taxes or other governmental charge, as provided in Section 12 of the Mortgage,
but the Company hereby waives any right to make a charge in addition thereto for
any exchange or transfer of bonds of the Seventy-fifth Series.
ARTICLE II.
Maintenance and Replacement Fund Covenant -- Dividend Covenant --
Other Related Provisions of the Mortgage
SECTION 2. Subject to the provisions of Section 3 hereof, the Company
covenants and agrees that the provisions of Section 39 of the Mortgage, which
were to remain in effect so long as any bonds of the First Series remained
Outstanding, shall remain in full force and effect so long as any bonds of the
Seventy-fifth Series are Outstanding.
<PAGE>
-9-
Clause (d) of subsection (II)(B) of Section 4 of the Mortgage, as
heretofore amended, is hereby further amended by inserting the words "and
Seventy-fifth Series" after the words "and Seventy-fourth Series" each time such
words appear therein.
Clause (6) and clause (e) of Section 5 of the Mortgage and Section 29 of
the Mortgage, as heretofore amended, are hereby further amended by inserting
therein "Seventy-fifth, before "Seventy-fourth," each time such words occur
therein.
ARTICLE III.
Miscellaneous Provisions
SECTION 3. The Company reserves the right to make such amendments to the
Mortgage, as supplemented, as shall be necessary in order to delete subsection
(I) of Section 39 of the Mortgage, and each holder of bonds of the Seventy-fifth
Series hereby consents to such deletion without any other or further action by
any holder of bonds of the Seventy-fifth Series.
SECTION 4. The terms defined in the Mortgage, as heretofore supplemented,
shall, for all purposes of this Sixty-seventh Supplemental Indenture, have the
meanings specified in the Mortgage, as heretofore supplemented.
SECTION 5. Whenever in this Sixty-seventh Supplemental Indenture either
of the parties hereto is named or referred to, this shall, subject to the
provisions of Articles XVI and XVII of the Mortgage, be deemed to include the
successors and assigns of such party, and all the covenants and agreements in
this Sixty-seventh Supplemental Indenture contained by or on behalf of the
Company, or by or on behalf of the Trustee shall, subject as aforesaid, bind and
inure to the respective benefits of the respective successors and assigns of
such parties, whether so expressed or not.
SECTION 6. So long as any bonds of the Seventy-fifth Series remain
Outstanding, unless this provision shall have been waived in writing by the
holders of seventy per centum (70%) in aggregate principal amount of bonds of
the Seventy-fifth Series Outstanding at the time of such consent, subdivision
(c) of Section 65 of the Mortgage shall read as follows:
"(c) Failure to pay interest or premium, if any, upon or
principal (whether at maturity as therein expressed or by declaration,
or otherwise) of any Outstanding Qualified Lien Bonds or of any
outstanding indebtedness secured by any mortgage or other lien (not
included in the term Excepted Encumbrances) prior to the lien of this
Indenture, existing upon any property of the Company which is subject
to the lien and operation of this Indenture continued beyond the
period of grace, if any, specified in such mortgage or Qualified Lien
or other lien securing the same;"
SECTION 7. A breach of a specified covenant or agreement of the Company
contained in this Sixty-seventh Supplemental Indenture shall become a Default
under the Indenture upon the happening of the events provided in Section 65(g)
of the Mortgage with respect to such a covenant or agreement.
SECTION 8. The Trustee hereby accepts the trusts herein declared,
provided, created or supplemented and agrees to perform the same upon the terms
and conditions herein and in the Mortgage, as heretofore supplemented, set forth
and upon the following terms and conditions:
The Trustee shall not be responsible in any manner whatsoever for or in
respect of the validity or sufficiency of this Sixty-seventh Supplemental
Indenture or for or in respect of the recitals contained herein, all of which
<PAGE>
-10-
recitals are made by the Company solely. Each and every term and condition
contained in Article XVII of the Mortgage, as heretofore amended by said First
through Sixty-sixth Supplemental Indentures, shall apply to and form part of
this Sixty-seventh Supplemental Indenture with the same force and effect as if
the same were herein set forth in full with such omissions, variations and
insertions, if any, as may be appropriate to make the same conform to the
provisions of this Sixty-seventh Supplemental Indenture.
SECTION 9. Nothing in this Sixty-seventh Supplemental Indenture,
expressed or implied, is intended, or shall be construed, to confer upon, or to
give to, any person, firm or corporation, other than the parties hereto and the
holders of the bonds and coupons Outstanding under the Indenture, any right,
remedy or claim under or by reason of this Sixty-seventh Supplemental Indenture
or by any covenant, condition, stipulation, promise or agreement hereof, and all
the covenants, conditions, stipulations, promises and agreements in this Sixty-
seventh Supplemental Indenture contained by or on behalf of the Company shall be
for the sole and exclusive benefit of the parties hereto, and of the holders of
the bonds and coupons Outstanding under the Indenture.
SECTION 10. This Sixty-seventh Supplemental Indenture shall be executed in
several counterparts, each of which shall be an original and all of which shall
constitute but one and the same instrument.
PP&L, INC. does hereby constitute and appoint JAMES E. ABEL, Vice
President -Finance and Treasurer of PP&L, INC., to be its attorney for it, and
in its name and as and for its corporate act and deed to acknowledge this Sixty-
seventh Supplemental Indenture before any person having authority by the laws of
the Commonwealth of Pennsylvania to take such acknowledgment, to the intent that
the same may be duly recorded, and BANKERS TRUST COMPANY does hereby constitute
and appoint JACKIE BARTNICK, a Vice President of BANKERS TRUST COMPANY, to be
its attorney for it, and in its name and as and for its corporate act and deed
to acknowledge this Sixty-seventh Supplemental Indenture before any person
having authority by the laws of the Commonwealth of Pennsylvania to take such
acknowledgment, to the intent that the same may be duly recorded.
<PAGE>
-11-
IN WITNESS WHEREOF, PP&L, INC. has caused its corporate name to be
hereunto affixed, and this instrument to be signed and sealed by its President
or one of its Vice Presidents, and its corporate seal to be attested by its
Secretary or one of its Assistant Secretaries for and in its behalf, in the City
of Allentown, Pennsylvania, and BANKERS TRUST COMPANY has caused its corporate
name to be hereunto affixed, and this instrument to be signed and sealed by one
of its Principals, Vice Presidents or Trust Officers, and its corporate seal to
be attested by one of its Vice Presidents, Assistant Vice Presidents or Trust
Officers, in The City of New York, as of the day and year first above written.
PP&L, INC.
By /s/ James E. Abel
--------------------------------------
Vice President - Finance and Treasurer
Attest:
/s/ Diane M. Koch
- ---------------------------
Assistant Secretary
<PAGE>
-12-
BANKERS TRUST COMPANY, as Trustee
By /s/ Jackie Bartnick
---------------------------------
Vice President
Attest:
/s/ Vincent Chorney
- -----------------------------
Assistant Vice President
<PAGE>
-13-
COMMONWEALTH OF PENNSYLVANIA )
) ss.:
COUNTY OF LEHIGH )
On this ____ day of June, 1999, before me, a notary public, the undersigned
officer, personally appeared JAMES E. ABEL, who acknowledged himself to be the
Vice President - Finance and Treasurer of PP&L, INC., a corporation and that he,
as such Vice President - Finance and Treasurer, being authorized to do so,
executed the foregoing instrument for the purposes therein contained, by signing
the name of the corporation by himself as Vice President - Finance and
Treasurer.
In witness whereof, I hereunto set my hand and official seal.
/s/ Francine A. Greenzweig
-------------------------------
Notary Public
<PAGE>
-14-
STATE OF NEW YORK )
) ss.:
COUNTY OF KINGS )
On this 23rd day of June, 1999, before me, a notary public, the undersigned
officer, personally appeared JACKIE BARTNICK, who acknowledged herself to be a
Vice President of BANKERS TRUST COMPANY, a corporation and that she, as such
Vice President, being authorized to do so, executed the foregoing instrument for
the purposes therein contained, by signing the name of the corporation by
herself as Vice President.
In witness whereof, I hereunto set my hand and official seal.
By: /s/ Boris Treyger
------------------------
BORIS TREYGER
Notary Public, State of New York
No. 01TR6016003
Qualified in Kings County
Commission Expires Nov. 9, 2000
Bankers Trust Company hereby certifies that its precise name and address as
Trustee hereunder are:
Bankers Trust Company
130 Liberty Street
New York, New York 10006
BANKERS TRUST COMPANY
By: /s/ Vincent Chorney
-------------------------
Assistant Vice President
<PAGE>
EXHIBIT 4(C)-4
================================================================================
PP&L CAPITAL FUNDING, INC.,
Issuer
and
PP&L RESOURCES, INC.,
Guarantor
TO
THE CHASE MANHATTAN BANK,
Trustee
_________
Supplemental Indenture No. 3
Dated as of October 1, 1999
Supplemental to the Indenture
dated as of November 1, 1997
Establishing a series of Securities designated
Medium-Term Notes, Series C
limited in aggregate principal amount to $500,000,000
================================================================================
<PAGE>
SUPPLEMENTAL INDENTURE No. 3, dated as of October 1, 1999 among PP&L
CAPITAL FUNDING, INC., a corporation duly organized and existing under the laws
of the State of Delaware (herein called the "Company"), PP&L RESOURCES, INC., a
corporation duly organized and existing under the laws of the Commonwealth of
Pennsylvania (herein called the "Guarantor"), and THE CHASE MANHATTAN BANK, a
New York banking corporation, as Trustee (herein called the "Trustee), under the
Indenture dated as of November 1, 1997 (hereinafter called the "Original
Indenture"), this Supplemental Indenture No. 3 being supplemental thereto. The
Original Indenture and any and all indentures and instruments supplemental
thereto are hereinafter sometimes collectively called the "Indenture."
Recitals of the Company and the Guarantor
The Original Indenture was authorized, executed and delivered by the
Company and the Guarantor to provide for the issuance by the Company from time
to time of its Securities (such term and all other capitalized terms used herein
without definition having the meanings assigned to them in the Original
Indenture), to be issued in one or more series as contemplated therein, and for
the Guarantee by the Guarantor of the payment of the principal, premium, if any,
and interest, if any, on such Securities.
As contemplated by Sections 301 and 1201(f) of the Original Indenture,
the Company wishes to establish a series of Securities to be designated "Medium-
Term Notes, Series C" to be limited in aggregate principal amount (except as
contemplated in Section 301(b) of the Original Indenture) to $500,000,000, such
series of Securities to be hereinafter sometimes called "Series No. 3."
As contemplated by Section 201 and 1402 of the Original Indenture, the
Guarantor wishes to establish the form and terms of the Guarantees to be
endorsed on the Securities of Series No. 3.
The Company has duly authorized the execution and delivery of this
Supplemental Indenture No. 3 to establish the Securities of Series No. 3 and has
duly authorized the issuance of such Securities; the Guarantor has duly
authorized the execution and delivery of this Supplemental Indenture No. 3 and
has duly authorized its Guarantees of the Securities of Series No. 3; and all
acts necessary to make this Supplemental Indenture No. 3 a valid agreement of
the Company and the Guarantor, to make the Securities of Series No. 3 valid
obligations of the Company, and to make the Guarantees valid obligations of the
Guarantor, have been performed.
NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE No. 3 WITNESSETH:
For and in consideration of the premises and of the purchase of the
Securities by the Holders thereof, it is mutually covenanted and agreed, for the
equal and proportionate benefit of all Holders of the Securities of Series No.
3, as follows:
<PAGE>
EXHIBIT 10.B1
AMENDMENT dated as of July 15, 1999 (this "Amendment"), to
the 5-Year Revolving Credit Agreement dated as of November 20,
1997 (the "Credit Agreement"), among PP&L, INC. ("PPL"), a
Pennsylvania corporation and PP&L CAPITAL FUNDING, INC., a
Delaware corporation ("Finance Co."), as Borrowers (the
"Borrowers"); PP&L RESOURCES, INC., a Pennsylvania corporation
("Resources"), as guarantor of the obligations of Finance Co.
thereunder; the banks from time to time party thereto (the
"Banks") and THE CHASE MANHATTAN BANK, a New York banking
corporation, as fronting bank, as collateral agent, and as agent
for the Banks to the extent and in the manner provided in Section
8 therein (in such capacity, the "Agent").
WHEREAS, the Borrowers have requested that the Banks amend certain
provisions of the Credit Agreement as set forth herein;
WHEREAS, the Banks are willing, on the terms, subject to the
conditions and to the extent set forth below, to provide such amendments; and
WHEREAS, capitalized terms used and not otherwise defined herein shall
have the meanings assigned to them in the Credit Agreement.
NOW, THEREFORE, in consideration of the premises and the agreements,
provisions and covenants herein contained, the parties hereto hereby agree, on
the terms and subject to the conditions set forth herein, as follows:
SECTION 1. Amendment to Credit Agreement. Section 1.2 of the Credit
-----------------------------
Agreement is amended by replacing the amount "$500,000" contained in such
section with the amount "$1,000,000".
SECTION 2. Amendment to Credit Agreement. Subsection (a) of Section
-----------------------------
1.4 of the Credit Agreement is amended by replacing the first sentence with the
following:
"The outstanding principal balance of each Loan shall be due and payable by
the Borrower to which such Loan was made on the Expiry Date."
SECTION 3. Amendment to Credit Agreement. Section 3.4 is amended by
-----------------------------
replacing such section with the following:
<PAGE>
"3.4 Net Payments. All payments under this Agreement shall be made
------------
without set-off or counterclaim and in such amounts as may be necessary in
order that all such payments of principal and interest in connection with
Loans (after deduction or withholding for or on account of (i) any present
or future taxes, levies, imposts, duties or other charges of whatsoever
nature imposed by any government or any political subdivision or taxing
authority thereof, excluding any tax on or measured by the net income of a
Bank pursuant to the income tax laws of the jurisdiction where such Bank's
principal or lending office is located or in which such Bank maintains a
place of business (all such non-excluded taxes, levies, imposts, duties or
other charges, the "Taxes") and (ii) any taxes on or measured by the net
income payable by any such Bank with respect to the amount by which the
payments required to be made by this (S) 3.4 exceed the amount otherwise
specified to be paid under this Agreement) shall not be less than the
amounts otherwise specified to be paid under this Agreement; and the
Borrowers further agree to pay and to save the Agent, the Fronting Bank and
the Banks (and any participant, to the extent provided in Section
10.6(b)(B)) harmless, on an after-tax basis, from all liability for Taxes
on or in connection with Loans or any payments thereunder, and any
interest, penalties or additions with respect thereto, provided, however,
-----------------
that such interest, penalties and additions are not a result of any action,
omission or failure to act on the part of the Agent, the Fronting Bank or
the Banks. A certificate as to any additional amounts payable to any Bank
under this (S) 3.4 submitted to the applicable Borrower by such Bank shall
show in reasonable detail the amount payable and the calculations used to
determine such amount and shall, absent manifest error, be final,
conclusive and binding upon all parties hereto. With respect to each
deduction or withholding for or on account of any Taxes, the applicable
Borrower shall promptly furnish to each Bank such certificates, receipts
and other documents as may be required (in the judgment of such Bank) to
establish any tax credit to which such Bank may be entitled."
SECTION 4. Amendment to Credit Agreement. Subsection (a) of each of
-----------------------------
Section 5.1A and Section 5.1B of the Credit Agreement is amended by replacing
the words "Price Waterhouse" with "PricewaterhouseCoopers".
SECTION 5. Amendment to Credit Agreement. Section 7.6A to the Credit
-----------------------------
Agreement is amended by replacing the words "Regulations G, U or X" contained in
such Section with "Regulation U or X".
SECTION 6. Amendment to Credit Agreement. Section 7.9A of the Credit
-----------------------------
Agreement is amended by replacing such section with the following:
"7.9A Subsidiaries. The assets of all Subsidiaries of PPL, excluding
------------
intangible transition property created under the
<PAGE>
3
Pennsylvania Electricity Generation Customer Choice and Competition Act
held by PP&L Transition Bond Company LLC, a subsidiary of PPL, or any
similar special purpose company organized for the purpose of issuing bonds
payable from revenues associated with such transition property, do not
comprise in the aggregate more than 35% of the total consolidated assets of
PPL."
SECTION 7. Amendment to Credit Agreement. Section 7.11A of the
-----------------------------
Credit Agreement is amended by replacing such section with the following:
"7.11A Public Utility Holding Company Act. PPL is not a "holding company"
----------------------------------
within the meaning of the Public Utility Holding Company Act of 1935, as
amended."
SECTION 8. Amendment to Credit Agreement. Section 10.1 of the Credit
-----------------------------
Agreement is amended by deleting the definition of "364-Day Agreement".
SECTION 9. Amendment to Credit Agreement. Section 10.1 of the Credit
-----------------------------
Agreement is amended by replacing the definition of "Bank" with the following:
"'Bank' shall mean each Person listed on Schedule I hereto and any other
----
Person that shall have become a party hereto as a result of an assignment
pursuant to Section 10.6(b)(A) hereto, other than any such Person that
ceases to be a party hereto as a result of an assignment pursuant to
Section 10.6(b)(A) hereto."
SECTION 10. Amendment to Credit Agreement. Section 10.1 of the
-----------------------------
Credit Agreement is amended by replacing the definition of "Commitment" with the
following:
"'Commitment', for each Bank, shall mean the amount specified opposite its
----------
name on Schedule I hereto or in the assignment pursuant to which such Bank
shall have assumed its Commitment, as applicable, such Commitment to be
reduced by the amount of any reduction thereto effected pursuant to (S)
1.7, (S) 6 and/or (S) 10.6(b)(A)."
SECTION 11. Amendment to Credit Agreement. Subsection (i) of the
-----------------------------
definition of "Indebtedness" contained in Section 10.1 of the Credit Agreement
is amended by replacing the parenthetical with the following:
"(the amount of any such obligation to be the net amount that would be
payable upon the acceleration, termination or liquidation thereof)"
SECTION 12. Amendment to Credit Agreement. Section 10.1 of the
-----------------------------
Credit Agreement is amended by adding the following
<PAGE>
4
language to subsection (a) of the definition of "Interest Period" after the
words "on the date of such Loan":
"or on the last day of the most recent Interest Period applicable thereto"
SECTION 13. Amendment to Credit Agreement. Section 10.1 of the Credit
-----------------------------
Agreement is amended by replacing the definition of "Non-Recourse Indebtedness
of PPL" with the following:
"'Non-Recourse Indebtedness of PPL' shall mean (a) indebtedness that is
--------------------------------
nonrecourse to PPL or any of its Subsidiaries and (b) any transition bonds
issued by PP&L Transition Bond Company LLC, a subsidiary of PPL, or any
similar special purpose company organized for the purpose of issuing bonds
payable from revenues associated with intangible transition property
created under the Pennsylvania Electricity Generation Customer Choice and
Competition Act or other assets of PP&L Transition Bond Company LLC or any
such other special purpose company, provided that (i) such bonds are
--------
nonrecourse to PPL or any of its subsidiaries (other than PP&L Transition
Bond Company LLC or any such other special purpose company) and (ii) the
aggregate amount of such transition bonds shall not exceed $2,850,000,000."
SECTION 14. Amendment to Credit Agreement. Section 10.1 of the
-----------------------------
Credit Agreement is amended by replacing the definition of "Non-Recourse
Indebtedness of Resources" with the following:
"'Non-Recourse Indebtedness of Resources' shall mean (a) indebtedness that
--------------------------------------
is nonrecourse to Resources, either Borrower or any of PPL's Subsidiaries
and (b) any transition bonds issued by PP&L Transition Bond Company LLC, a
subsidiary of PPL, or any similar special purpose company organized for the
purpose of issuing bonds payable from revenues associated with intangible
transition property created under the Pennsylvania Electricity Generation
Customer Choice and Competition Act or other assets of PP&L Transition Bond
Company LLC or any such other special purpose company, provided that (i)
--------
such bonds are nonrecourse to PPL or any of its subsidiaries (other than
PP&L Transition Bond Company LLC or any such other special purpose company)
and (ii) the aggregate amount of such transition bonds shall not exceed
$2,850,000,000."
SECTION 15. Amendment to Credit Agreement. Section 10.6(b)(A) of the
-----------------------------
Credit Agreement is amended by deleting clause (iii) of the proviso in its
entirety and then renumbering clause (iv) to be clause (iii).
<PAGE>
5
SECTION 16. Amendment to Credit Agreement. Section 10.6(b)(B) of the
-----------------------------
Credit Agreement is amended by replacing the proviso contained in the last
sentence of such section with the following:
"provided that such participant shall be entitled to receive additional
--------
amounts under (S)(S) 1.8, 2.5 and 3.4 on the same basis as if it were a
Bank but in no case shall be entitled to any amount greater than would have
been payable had the Bank not sold such participations."
SECTION 17. Representations and Warranties. The Borrowers and
------------------------------
Resources hereby represent and warrant to each Bank, on and as of the date
hereof, and after giving effect to this Amendment, that:
(a) the representations and warranties set forth in Sections 7.A and
7.B of the Credit Agreement are true and correct in all material respects
on and as of the date hereof, except to the extent such representations and
warranties relate to an earlier date; and
(b) no Default or Event of Default has occurred and is continuing.
SECTION 18. Effectiveness. The amendments to the Credit Agreement
-------------
set forth in this Amendment shall become effective only upon receipt by the
Agent of duly executed counterparts hereof which, when taken together, bear the
authorized signatures of the Borrowers, Resources and the Required Banks.
SECTION 19. Governing Law. THIS AMENDMENT SHALL BE CONSTRUED IN
-------------
ACCORDANCE WITH AND GOVERNED BY THE LAW OF THE STATE OF NEW YORK.
SECTION 20. Counterparts. This Amendment may be executed in any
------------
number of counterparts, each of which shall be an original but all of which,
when taken together, shall constitute but one instrument. Delivery of an
executed counterpart of a signature page of this Amendment by facsimile
transmission shall be as effective as delivery of a manually executed
counterpart of this Amendment.
SECTION 21. Expenses. The Borrowers agree to pay all expenses
--------
incurred by the Agent in connection with the preparation, execution and delivery
of this Amendment, including the fees, charges and disbursements of counsel.
SECTION 22. Headings. Section headings used herein are for
--------
convenience of reference only, are not part of this
<PAGE>
6
Amendment and are not to affect the construction of, or to be taken into
consideration in interpreting, this Amendment.
SECTION 23. EFFECT OF THIS AMENDMENT GENERALLY. Except as expressly
----------------------------------
set forth herein, this Amendment shall not by implication or otherwise limit,
impair, constitute a waiver of, or otherwise affect the rights and remedies of
the Banks under the Credit Agreement or any other Loan Document, and shall not
alter, modify, amend or in any way affect any of the terms, conditions,
obligations, covenants or agreements contained in the Credit Agreement or any
other Loan Document, all of which are ratified and affirmed in all respects and
shall continue in full force and effect. Nothing herein shall be deemed to
entitle the Borrowers to a consent to, or a waiver, amendment, modification or
other change of, any of the terms, conditions, obligations, covenants or
agreements contained in the Credit Agreement or any other Loan Document in
similar or different circumstances. This Amendment shall apply and be effective
only with respect to the provisions of the Credit Agreement specifically
referred to herein.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to
be duly executed by their respective authorized officers as of the day and year
first above written.
PP&L INC.,
By: /s/ James E. Abel
-------------------------
Name: James E. Abel
Title: Vice President-
Finance and Treasurer
PP&L CAPITAL FUNDING, INC.,
By: /s/ Russell R. Clelland
-------------------------
Name: Russell R. Celland
Title: Manager-Finance
PP&L RESOURCES, INC.,
By: /s/ James E. Abel
-------------------------
Name: James E. Abel
Title: Vice President-
Finance and Treasurer
<PAGE>
7
THE CHASE MANHATTAN BANK,
individually and as
Agent and Fronting Bank,
By: /s/ Jaimin Patel
--------------------------
Name: Jaimin Patel
Title: Vice President
<PAGE>
CITIBANK, N.A.,
By: /s/ Robert J. Harrity, Jr
--------------------------
Name: Robert J. Harrity, Jr.
Title: Managing Director
THE BANK OF NEW YORK,
By: /s/ John N. Watt
--------------------------
Name: John N. Watt
Title: Vice President
THE BANK OF NOVA SCOTIA
By: /s/ J. Alan Edwards
--------------------------
Name: J. Alan Edwards
Title: Authorized Signatory
CREDIT SUISSE FIRST BOSTON,
By: /s/ Douglas E. Maher
--------------------------
Name: Douglas E. Maher
Title: Vice President
By: /s/ James P. Moran
--------------------------
Name: James P. Moran
Title: Director
DEUTSCHE BANK AG, NEW YORK BRANCH
and/or CAYMAN ISLANDS BRANCH,
By: /s/
--------------------------
Name:
Title:
<PAGE>
THE FIRST NATIONAL BANK OF CHICAGO,
By: /s/ George R. Schanz
--------------------------
Name: George R. Schanz
Title: First Vice President
FIRST UNION NATIONAL BANK,
By: /s/ Michael J. Kolosowsky
--------------------------
Name: Michael J. Kolosowsky
Title: Vice President
THE FUJI BANK, LIMITED, NEW YORK BRANCH
By: /s/
--------------------------
Name:
Title:
MELLON BANK, N.A.,
By: /s/ Mark W. Rogers
--------------------------
Name: Mark W. Rogers
Title: Vice President
NATIONSBANK, N.A.,
By: /s/ Michael R. Williams
--------------------------
Name: Michael R. Williams
Title: Managing Director
TORONTO DOMINION (TEXAS), INC.,
By: /s/ Alva J. Jones
-------------------------
Name: Alva J. Jones
Title: Vice President
<PAGE>
EXHIBIT 10(d)
================================================================================
Amended and Restated
Operating Agreement
of
PJM Interconnection, L.L.C.
Please Note: This document does not include certain
-----------
Operating Agreement revisions that are pending FERC approval.
Dated June 2, 1997
(Revised December 31, 1997, January 26, 1998, January 30, 1998,
March 17, 1998, May 15, 1998, June 26, 1998, September 24, 1998,
October 14, 1998, October 15, 1998, November 19, 1998, January 29, 1999
February 12, 1999, March 2, 1999, April 27, 1999, March 31, 1999,
May 11, 1999, May 12, 1999, May 25, 1999, June 16, 1999,
July 19, 1999, and September 3, 1999)
================================================================================
<PAGE>
OPERATING AGREEMENT
Table of Contents
<TABLE>
<CAPTION>
<S> <C>
1. DEFINITIONS............................................................ 2
1.1 Act............................................................. 2
1.2 Affiliate....................................................... 2
1.3 Agreement....................................................... 2
1.4 Annual Meeting of the Members................................... 2
1.5 Board Member.................................................... 2
1.6 Capacity Resource............................................... 2
1.7 Control Area.................................................... 3
1.8 Electric Distributor............................................ 3
1.9 Effective Date.................................................. 3
1.10 Emergency....................................................... 3
1.11 End-Use Customer................................................ 3
1.12 FERC............................................................ 3
1.13 Finance Committee............................................... 4
1.14 Generation Owner................................................ 4
1.15 Good Utility Practice........................................... 4
1.16 Interconnection................................................. 4
1.17 LLC............................................................. 4
1.18 Load Serving Entity............................................. 4
1.19 Locational Marginal Price....................................... 4
1.20 MAAC............................................................ 4
1.21 Market Buyer.................................................... 5
1.22 Market Participant.............................................. 5
1.23 Market Seller................................................... 5
1.24 Member.......................................................... 5
1.25 Members Committee............................................... 5
1.26 NERC............................................................ 5
1.27 Office of the Interconnection................................... 5
1.28 Operating Reserve............................................... 5
1.29 Original PJM Agreement.......................................... 5
1.30 Other Supplier.................................................. 6
1.31 PJM Board....................................................... 6
1.32 PJM Control Area................................................ 6
1.33 PJM Dispute Resolution Procedures............................... 6
1.34 PJM Interchange Energy Market................................... 6
1.35 PJM Manuals..................................................... 6
1.36 PJM Tariff...................................................... 6
1.37 Planning Period................................................. 6
1.38 President....................................................... 6
1.39 Related Parties................................................. 7
</TABLE>
Second Revised: November 19, 1998
Effective: January 19, 1999
i
<PAGE>
<TABLE>
<S> <C>
1.40 Reliability Assurance Agreement................................ 7
1.41 Sector Votes................................................... 7
1.42 State.......................................................... 7
1.43 System......................................................... 7
1.44 Transmission Facilities........................................ 7
1.45 Transmission Owner............................................. 7
1.46 Transmission Owners Agreement.................................. 8
1.47 User Group..................................................... 8
1.48 Voting Member.................................................. 8
1.49 Weighted Interest.............................................. 8
2. FORMATION, NAME; PLACE OF BUSINESS.................................... 8
2.1 Formation of LLC; Certificate of Formation..................... 8
2.2 Name of LLC.................................................... 9
2.3 Place of Business.............................................. 9
2.4 Registered Office and Registered Agent......................... 9
3. PURPOSES AND POWERS OF LLC............................................ 9
3.1 Purposes....................................................... 9
3.2 Powers......................................................... 10
4. EFFECTIVE DATE AND TERMINATION........................................ 10
4.1 Effective Date and Termination................................. 10
4.2 Governing Law.................................................. 10
5. WORKING CAPITAL AND CAPITAL CONTRIBUTIONS............................. 11
5.1 Funding of Working Capital and Capital Contributions........... 11
5.2 Contributions to Association................................... 11
6. TAX STATUS AND DISTRIBUTIONS.......................................... 11
6.1 Tax Status..................................................... 11
6.2 Return of Capital Contributions................................ 12
6.3 Liquidating Distribution....................................... 12
7. PJM BOARD............................................................. 12
7.1 Composition.................................................... 12
7.2 Qualifications................................................. 13
7.3 Term of Office................................................. 13
7.4 Quorum......................................................... 13
7.5 Operating and Capital Budgets.................................. 14
7.5.1 Finance Committee....................................... 14
7.5.2 Adoption of Budgets..................................... 14
7.6 By-laws........................................................ 14
7.7 Duties and Responsibilities of the PJM Board................... 14
8. MEMBERS COMMITTEE..................................................... 16
8.1 Sectors........................................................ 16
8.1.1 Designation............................................. 16
8.1.2 Related Parties......................................... 17
8.2 Representatives................................................ 17
8.2.1 Appointment............................................. 17
8.2.2 Regulatory Authorities.................................. 17
8.2.3 Initial Representatives................................. 17
8.2.4 Change of or Substitution for a Representative.......... 17
</TABLE>
Second Revised: November 19, 1998
Effective: January 19, 1999
ii
<PAGE>
<TABLE>
<S> <C>
8.3 Meetings........................................................ 18
8.3.1 Regular and Special Meetings............................. 18
8.3.2 Attendance............................................... 18
8.3.3 Quorum................................................... 18
8.4 Manner of Acting................................................ 18
8.5 Chair and Vice Chair of the Members Committee................... 19
8.5.1 Selection and Term....................................... 19
8.5.2 Duties................................................... 19
8.6 Other Committees................................................ 19
8.7 User Groups..................................................... 20
8.8 Powers of the Members Committee................................. 20
9. OFFICERS............................................................... 21
9.1 Election and Term............................................... 21
9.2 President....................................................... 21
9.3 Secretary....................................................... 21
9.4 Treasurer....................................................... 22
9.5 Renewal of Officers; Vacancies.................................. 22
9.6 Compensation.................................................... 22
10. OFFICE OF THE INTERCONNECTION......................................... 22
10.1 Establishment................................................... 22
10.2 Processes and Organization...................................... 22
10.3 Confidential Information........................................ 23
10.4 Duties and Responsibilities..................................... 23
11. MEMBERS............................................................... 25
11.1 Management Rights............................................... 25
11.2 Other Activities................................................ 25
11.3 Member Responsibilities......................................... 25
11.3.1 General................................................. 25
11.3.2 Facilities Planning and Operation....................... 26
11.3.3 Electric Distributors................................... 27
11.3.4 Reports to the Office of the Interconnection............ 28
11.4 Regional Transmission Expansion Planning Protocol............... 28
11.5 Member Right to Petition........................................ 28
11.6 Membership Requirements......................................... 29
12. TRANSFERS OF MEMBERSHIP INTEREST...................................... 30
13. INTERCHANGE........................................................... 30
13.1 Interchange Arrangements with Non-Members....................... 30
13.2 Energy Market................................................... 30
14. METERING.............................................................. 30
14.1 Installation, Maintenance and Reading of Meters................. 30
14.2 Metering Procedures............................................. 30
14.3 Integrated Megawatt-Hours....................................... 31
14.4 Meter Locations................................................. 31
15. ENFORCEMENT OF OBLIGATIONS............................................ 31
15.1 Failure to Meet Obligations..................................... 31
15.1.1 Termination of Market Buyer Rights...................... 31
15.1.2 Termination of Market Seller Rights..................... 31
</TABLE>
Second Revised: November 19, 1998
Effective: January 19, 1999
iii
<PAGE>
<TABLE>
<S> <C>
15.1.3 Payment of Bills........................................ 32
15.2 Enforcement of Obligations...................................... 33
15.3 Obligations to a Member in Default.............................. 33
15.4 Obligations of a Member in Default.............................. 33
15.5 No Implied Waiver............................................... 33
16. LIABILITY AND INDEMNITY............................................... 34
16.1 Members......................................................... 34
16.2 LLC Indemnified Parties......................................... 35
16.3 Worker' Compensation Claims..................................... 36
16.4 Limitation of Liability......................................... 36
16.5 Resolution of Disputes.......................................... 36
16.6 Gross Negligence or Willful Misconduct.......................... 36
16.7 Insurance....................................................... 36
17. MEMBER REPRESENTATIONS, WARRANTIES AND COVENANTS...................... 37
17.1 Representations and Warranties.................................. 37
17.1.1 Organization and Existence.............................. 37
17.1.2 Power and Authority..................................... 37
17.1.3 Authorization and Enforceability........................ 37
17.1.4 No Government Consents.................................. 37
17.1.5 No Conflict or Breach................................... 37
17.1.6 No Proceedings.......................................... 38
17.2 Municipal Electric Systems...................................... 38
17.3 Survival........................................................ 38
18. MISCELLANEOUS PROVISIONS.............................................. 38
18.1 [Reserved]...................................................... 38
18.2 Fiscal and Taxable Year......................................... 38
18.3 Reports......................................................... 38
18.4 Bank Accounts; Checks, Notes and Drafts......................... 39
18.5 Books and Records............................................... 39
18.6 Amendment....................................................... 40
18.7 Interpretation.................................................. 40
18.8 Severability.................................................... 40
18.9 Force Majeure................................................... 41
18.10 Further Assurances............................................. 41
18.11 Seal........................................................... 41
18.12 Counterparts................................................... 41
18.13 Costs of Meetings.............................................. 41
18.14 Notice......................................................... 42
18.15 Headings....................................................... 42
18.16 No Third-Party Beneficiaries................................... 42
18.17 Confidentiality................................................ 42
18.17.1 Party Access.......................................... 42
18.17.2 Required Disclosure................................... 43
18.18 Termination and Withdrawal..................................... 43
18.18.1 Termination........................................... 43
18.18.2 Withdrawal............................................ 43
18.18.3 Winding Up............................................ 44
</TABLE>
Second Revised: November 19, 1998
Effective: January 19, 1999
iv
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<TABLE>
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SCHEDULE 1 - PJM INTERCHANGE ENERGY MARKET.............................. 1
1. MARKET OPERATIONS.................................................. 1
1.1 Introduction.................................................. 1
1.2 Cost-based Offers............................................. 1
1.3 Definitions................................................... 1
1.3.1 Dispatch Rate.................................... 1
1.3.2 Equivalent Load.................................. 1
1.3.3 External Market Buyer............................ 1
1.3.4 External Resource................................ 2
1.3.5 Fixed Transmission Right......................... 2
1.3.6 Generating Market Buyer.......................... 2
1.3.7 Generator Forced Outage.......................... 2
1.3.8 Generator Maintenance Outage..................... 2
1.3.9 Generator Planned Outage......................... 2
1.3.10 Internal Market Buyer............................ 2
1.3.11 Inadvertent Interchange.......................... 2
1.3.12 Market Operations Center......................... 3
1.3.13 Maximum Generation Emergency..................... 3
1.3.14 Minimum Generation Emergency..................... 3
1.3.14a NERC Interchange Distribution Calculator......... 3
1.3.15 Network Resource................................. 3
1.3.16 Network Service User............................. 3
1.3.17 Network Transmission Service..................... 3
1.3.18 Normal Maximum Generation........................ 3
1.3.19 Normal Minimum Generation........................ 3
1.3.20 Offer Data....................................... 3a
1.3.21 Office of the Interconnection Control Center..... 4
1.3.22 Operating Day.................................... 4
1.3.23 Operating Margin................................. 4
1.3.24 Operating Margin Customer........................ 4
1.3.25 PJM Interchange.................................. 4
1.3.26 PJM Interchange Export........................... 4
1.3.27 PJM Interchange Import........................... 5
1.3.28 PJM Open Access Same-time Information System..... 5
1.3.29 Point-to-Point Transmission Service.............. 5
1.3.30 Ramping Capability............................... 5
1.3.31 Regulation....................................... 5
1.3.32 Regulation Class................................. 5
1.3.32a Spot Market Backup............................... 5
1.3.33 Spot Market Energy............................... 5a
1.3.34 Transmission Congestion Charge................... 5a
1.3.35 Transmission Congestion Credit................... 6
1.3.36 Transmission Customer............................ 6
1.3.37 Transmission Forced Outage....................... 6
1.3.37a Transmission Loading Relief...................... 6
1.3.37b Transmission Loading Relief Customer............. 6
1.3.38 Transmission Planned Outage...................... 6
</TABLE>
Second Revised: November 19, 1998
Effective: January 19, 1999
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1.4 Market Buyers.................................................... 6
1.4.1 Qualification.......................................... 6
1.4.2 Submission of Information.............................. 7
1.4.3 Fees and Costs......................................... 7
1.4.4 Office of the Interconnection Determination............ 8
1.4.5 Existing Participants.................................. 8
1.4.6 Withdrawal............................................. 8
1.5 Market sellers................................................... 9
1.5.1 Qualification.......................................... 9
1.5.2 Withdrawal............................................. 9
1.6 Office of the Interconnec1.5.2 Withdrawal........................ 9
1.6.1 Operation of the PJM Interchange Energy Market......... 9
1.6.2 Scope of Services...................................... 9
1.6.3 Records and Reports.................................... 10
1.6.4 PJM Manuals............................................ 11
1.7 General.......................................................... 11
1.7.1 Market Sellers......................................... 11
1.7.2 Market Buyers.......................................... 11
1.7.3 Agents................................................. 11
1.7.4 General Obligations of the Market Participants......... 11
1.7.5 Market Operations Center............................... 13
1.7.6 Scheduling and Dispatching............................. 13
1.7.7 Pricing................................................ 13
1.7.8 Generating Market Buyer Resources...................... 13
1.7.9 Delivery to an External Market Buyer................... 13
1.7.10 Other Transactions..................................... 14
1.7.11 Emergencies............................................ 14
1.7.12 Fees and Charges....................................... 14
1.7.13 Relationship to PJM Control Area....................... 14a
1.7.14 PJM Manuals............................................ 15
1.7.15 Corrective Action...................................... 15
1.7.16 Recording.............................................. 15
1.7.17 Operating Reserves..................................... 15
1.7.18 Regulation............................................. 15a
1.7.19 Ramping................................................ 16
1.7.20 Communication and Operating Requirements............... 16
1.7.21 Multi-settlement System................................ 17
1.8 Selection, Scheduling and Dispatch Procedure Adjustment Process.. 17
1.8.1 PJM Dispute Resolution Agreement....................... 17
1.8.2 Market or Control Area Hourly Operational Disputes..... 17
1.9 Prescheduling.................................................... 18
1.9.1 Outage Scheduling...................................... 18
1.9.2 Planned Outages........................................ 18
1.9.3 Generator Maintenance Outages.......................... 19
1.9.4 Forced Outages......................................... 19
1.9.5 Market Participant Responsibilities.................... 20
</TABLE>
Third Revised: July 19, 1999
Effective: July 19, 1999
vi
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<TABLE>
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1.9.6 Internal Market Buyer Responsibilities................................ 20
1.9.7 Market Seller Responsibilities........................................ 20
1.9.8 Office of the Interconnection Responsibilities........................ 20
1.10 Scheduling........................................................................ 21
1.10.1 Day-Ahead Scheduling.................................................. 21
1.10.2 Pool-Scheduled Resources.............................................. 23
1.10.3 Self-scheduled Resources.............................................. 24
1.10.4 Capacity Resources.................................................... 24
1.10.5 External Resources.................................................... 25
1.10.6 External Market Buyers................................................ 26
1.10.6A Transmission Loading Relief Customers................................. 26
1.10.7 Bilateral Transactions................................................ 26a
1.10.8 Office of the Interconnection Responsibilities........................ 27
1.10.9 Hourly Scheduling..................................................... 27
1.11 Dispatch.......................................................................... 28
1.11.1 Resource Output....................................................... 28
1.11.2 Operating Basis....................................................... 28
1.11.3 Pool-dispatched Resources............................................. 29
1.11.3a Maximum Generation Emergency.......................................... 29
1.11.4 Regulation............................................................ 29
1.11.5 PJM Open Access Same-time Information System.......................... 29
2. CALCULATION OF LOCATIONAL MARGINAL PRICES................................................ 30
2.1 Introduction....................................................................... 30
2.2 General............................................................................ 30
2.3 Determination of System Conditions Using the State Estimator....................... 31
2.4 Determination of Energy Offers Used in Calculating Locational Marginal Prices...... 31
2.5 Calculation of Locational Marginal Prices.......................................... 32
2.6 Performance Evaluation............................................................. 32
3. ACCOUNTING AND BILLING................................................................... 33
3.1 Introduction....................................................................... 33
3.2 Market Buyers...................................................................... 33
3.2.1 Spot Market Energy.................................................... 33
3.2.2 Regulation............................................................ 34
3.2.3 Operating Reserves.................................................... 35
3.2.4 Transmission Congestion............................................... 35
3.2.5 Transmission Losses................................................... 35
3.2.6 Emergency Energy...................................................... 36
3.2.7 Billing............................................................... 36
3.3 Market Sellers..................................................................... 36
3.3.1 Spot Market Energy.................................................... 37
3.3.2 Regulation............................................................ 37
3.3.3 Operating Reserves.................................................... 37
3.3.4 Emergency Energy...................................................... 37
3.3.5 Billing............................................................... 38
</TABLE>
Second Revised: November 19, 1998
Effective: January 19, 1999
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3.4 Transmission Customers............................................. 38
3.4.1 Transmission Congestion.................................. 38
3.4.2 Transmission Losses...................................... 38
3.4.3 Billing.................................................. 38
3.5 Other Control Areas................................................ 39
3.5.1 Energy Sales............................................. 39
3.5.2 Operating Margin Sales................................... 39
3.5.3 Transmission Congestion.................................. 39
3.5.4 Billing.................................................. 39
3.6 Metering Reconciliation............................................ 39
3.6.1 Meter Correction Billing................................. 39
3.6.2 Meter Corrections Between Market Participants............ 40
3.6.3 500 kV Meter Errors...................................... 40
3.6.4 Meter Corrections Between Control Areas.................. 40
3.6.5 Meter Correction Data.................................... 40
3.6.6 Correction Limits........................................ 40
4. RATE TABLE............................................................... 41
4.1 Offered Price Rates................................................ 41
4.2 Transmission Losses................................................ 41
4.3 Emergency Energy Purchases......................................... 41
5. CALCULATION OF TRANSMISSION CONGESTION CHARGES AND CREDITS............... 42
5.1 Transmission Congestion Charge Calculation......................... 42
5.1.1 Calculation by Office of the Interconnection............. 42
5.1.2 General.................................................. 42
5.1.3 Network Service User Calculation......................... 42
5.1.4 Transmission Customer Calculation........................ 42
5.1.5 Operating Margin Customer Calculation.................... 42
5.1.6 Transmission Loading Relief Customer Calculation......... 43
5.1.7 Total Transmission Congestion Charges.................... 43
5.2 Transmission Congestion Credit Calculation......................... 43
5.2.1 Eligibility.............................................. 43
5.2.2 Fixed Transmission Rights................................ 43
5.2.3 Target Allocation for Network Service Users.............. 44
5.2.4 Target Allocation for other Holders...................... 44
5.2.5 Calculation of Transmission Congestion Credits........... 44
5.2.6 Distribution of Excess Congestion Charges................ 44
5.3 Unscheduled Transmission Service (Loop Flow)....................... 44a
6. "MUST-RUN" FOR RELIABILITY GENERATION.................................... 45
6.1 Introduction...................................................... 45
6.2 Identification of Facility Outages................................ 45
6.3 Dispatch for Local Reliability.................................... 45
6.3.1 Request and Dispatch.................................... 45
6.3.2 Designation of Facilities............................... 45a
6.4 Price Caps........................................................ 45a
6.4.1 Applicability........................................... 45a
6.4.2 Level................................................... 45b
</TABLE>
Fourth Revised: July 19, 1999
Effectivd: July 19, 1999
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7. FIXED TRANSMISSION RIGHTS AUCTIONS....................................................................... 46
7.1 Auctions of Fixed Transmission Rights.......................................................... 46
7.1.1 Auction Period and Scope of Auctions................................................ 46
7.1.2 Frequency and Time of Auctions...................................................... 46
7.1.3 Duration of Fixed Transmission Rights................................................ 46
7.2 Fixed Transmission Rights Characteristics...................................................... 47
7.2.1 Reconfiguration of Fixed Transmission Rights........................................ 47
7.2.2 Specified Buses..................................................................... 47
7.2.3 Transmission Congestion Charges.............................................................. 47
7.3 Auction Procedures............................................................................. 47
7.3.1 Role of the Office of the Interconnection........................................... 47
7.3.2 Notice of Offer..................................................................... 48
7.3.3 Pending Applications for Firm Service............................................... 48
7.3.4 On-Peak and Off-Peak Periods........................................................ 48
7.3.5 Offers and Bids..................................................................... 49
7.3.6 Determination of Winning Bids and Clearing Price.................................... 50
7.3.7 Announcements of Winners and Prices................................................. 50
7.3.8 Auction Settlements................................................................. 51
7.3.9 Allocation of Auction Revenues...................................................... 51
7.4 Simultaneous Feasibility....................................................................... 51
SCHEDULE 2 - COMPONENTS OF COST.............................................................................. 1
SCHEDULE 2A - EXPLANATION OF THE TREATMENT OF THE COSTS OF EMISSIONS ALLOWANCES.............................. 1
SCHEDULE 3 - ALLOCATION OF THE COST AND EXPENSES OF THE OFFICE OF THE INTERCONNECTION........................ 1
SCHEDULE 4 - STANDARD FORM OF AGREEMENT TO BECOME A MEMBER OF THE LLC........................................ 1
</TABLE>
Second Revised: July 19, 1999
Effective: July 19, 1999
viiia
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<TABLE>
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SCHEDULE 5 - PJM DISPUTE RESOLUTION PROCEDURES............................................................... 1
1. DEFINITIONS............................................................................................... 1
1.1 Alternate Dispute Resolution Committee.......................................................... 1
1.2 MAAC Dispute Resolution Committee............................................................... 1
1.3 Related PJM Agreements.......................................................................... 1
2. PURPOSES AND OBJECTIVES................................................................................... 1
2.1 Common and Uniform Procedures................................................................... 1
2.2 Interpretation.................................................................................. 1
3. NEGOTIATION AND MEDIATION................................................................................. 2
3.1 When Required................................................................................... 2
3.2 Procedures...................................................................................... 2
3.2.1 Initiation........................................................................... 2
3.2.2 Selection of Mediator................................................................ 2
3.2.3 Advisory Mediator.................................................................... 2
3.2.4 Mediation Process.................................................................... 3
3.2.5 Mediator's Assessment................................................................ 3
3.3 Costs........................................................................................... 4
4. ARBITRATION............................................................................................... 4
4.1 When Required................................................................................... 4
4.2 Binding Decision................................................................................ 4
4.3 Initiation...................................................................................... 4
4.4 Selection of Arbitrator(s)...................................................................... 4
4.5 Procedures...................................................................................... 5
4.6 Summary Disposition and Interim Measures........................................................ 5
4.6.1 Lack of Good Faith Basis............................................................. 5
4.6.2 Discovery Limits..................................................................... 5
4.6.3 Interim Decision..................................................................... 5
4.7 Discovery of Facts.............................................................................. 6
4.7.1 Discovery Procedures................................................................. 6
4.7.2 Procedures Arbitrator................................................................ 6
4.8 Evidentiary Hearing............................................................................. 6
4.9 Confidentiality................................................................................. 7
4.9.1 Designation.......................................................................... 7
4.9.2 Compulsory Disclosure................................................................ 7
4.9.3 Public Information................................................................... 7
4.10 Timetable...................................................................................... 8
4.11 Advisory Interpretations....................................................................... 8
4.12 Decisions...................................................................................... 8
4.13 Costs.......................................................................................... 8
4.14 Enforcement.................................................................................... 9
5. ALTERNATE DISPUTE RESOLUTION COMMITTEE.................................................................... 9
5.1 Membership...................................................................................... 9
5.1.1 Representatives...................................................................... 9
5.1.2 Term................................................................................. 9
5.2 Voting Requirements............................................................................. 9
5.3 Officers........................................................................................ 9
5.4 Meetings........................................................................................ 10
</TABLE>
Second Revised: November 19, 1998
Effective: January 19, 1999
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<TABLE>
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5.5 Responsibilities................................................................................ 10
SCHEDULE 6 - REGIONAL TRANSMISSION EXPANSION PLANNING PROTOCOL............................................... 1
1. REGIONAL TRANSMISSION EXPANSION PLANNING PROTOCOL......................................................... 1
1.1 Purpose and Objectives.......................................................................... 1
1.2 Conformity with NERC and MAAC Criteria.......................................................... 1
1.3 Establishment of Committees..................................................................... 1
1.4 Contents of the Regional Transmission Expansion Plan............................................ 2
1.5 Procedure for Development of the Regional Transmission Expansion Plan........................... 2
1.5.1 Commencement of the Process.......................................................... 2
1.5.2 Development of Scope, Assumptions and Procedures..................................... 3
1.5.3 Scope of Studies..................................................................... 3
1.5.4 Supply of Data....................................................................... 3
1.5.5 Coordination of the Regional Transmission Expansion Plan............................. 3
1.5.6 Development of the Recommended Regional Transmission Expansion Plan.................. 3a
1.6 Approval of the Final Regional Transmission Expansion Plan...................................... 4
1.7 Obligation to Build............................................................................. 5
1.8 Relationship to the PJM Control Area Open Access Transmission PJM Tariff........................ 5
SCHEDULE 7 - UNDERFREQUENCY RELAY OBLIGATIONS AND CHARGES.................................................... 1
1. UNDERFREQUENCY RELAY OBLIGATION........................................................................... 1
1.1 Application..................................................................................... 1
1.2 Obligations..................................................................................... 1
2. UNDERFREQUENCY RELAY CHARGES.............................................................................. 1
3. DISTRIBUTION OF UNDERFREQUENCY RELAY CHARGES.............................................................. 2
3.1 Share of Charges................................................................................ 2
3.2 Allocation by the Office of the Interconnection................................................. 2
SCHEDULE 8 - DELEGATION OF RELIABILITY RESPONSIBILITIES...................................................... 1
1. DELEGATION................................................................................................ 1
2. NEW PARTIES............................................................................................... 1
3. IMPLEMENTATION OF RELIABILITY ASSURANCE AGREEMENT......................................................... 1
SCHEDULE 9 - EMERGENCY PROCEDURE CHARGES..................................................................... 1
1. EMERGENCY PROCEDURE CHARGE................................................................................ 1
2. DISTRIBUTION OF EMERGENCY PROCEDURE CHARGES............................................................... 1
2.1 Complying Parties............................................................................... 1
2.2 All Parties..................................................................................... 1
SCHEDULE 10 - ACCOUNTING FOR UNSCHEDULED TRANSMISSION
SERVICE COMPENSATION......................................................................................... 1
SCHEDULE 11 - PJM CAPACITY CREDIT MARKETS.................................................................... 1
1. PURPOSES AND OBJECTIVES.................................................................................. 1
1.1 PJM Capacity Credit Markets.................................................................... 1
1.2 Voluntary Use of PJM Capacity Credit Market.................................................... 1
1.3 Use of Capacity Credits........................................................................ 1
2. DEFINITIONS.............................................................................................. 1
2.1 [Reserved.].................................................................................... 1
</TABLE>
Third Revised: July 19, 1999
Effective: July 19, 1999
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<TABLE>
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2.2 Buy Bid........................................................................................ 1
2.3 Capacity Credit................................................................................ 2
2.4 Capacity Credit Market Implementation Date..................................................... 2
2.5 Capacity Resources............................................................................. 2
2.6 Fixed Block.................................................................................... 2
2.7 Holiday........................................................................................ 2
2.8 PJM Capacity Credit Market..................................................................... 2
2.9 PJM Daily Capacity Credit Market............................................................... 2
2.10 PJM Monthly Capacity Credit Market............................................................ 2
2.11 Sell Offer.................................................................................... 2
2.12 Unforced Capacity............................................................................. 3
2.13 Up-To Block.................................................................................... 3
3. PARTICIPATION IN THE PJM CAPACITY CREDIT MARKET.......................................................... 3
3.1 Eligibility.................................................................................... 3
3.2 Effect of Withdrawal........................................................................... 3
4. RESPONSIBILITIES OF THE OFFICE OF THE INTERCONNECTION.................................................... 3
4.1 Operation of the PJM Capacity Credit Market.................................................... 3
4.2 Records and Reports............................................................................ 4
5. GENERAL PROVISIONS....................................................................................... 4
5.1 Market Sellers................................................................................. 4
5.2 Market Buyers.................................................................................. 4
5.3 Agents......................................................................................... 5
5.4 General Obligations Market Participants........................................................ 5
5.5 Relationship of Capacity Credits to Capacity Obligations Imposed Under the
Reliability Assurance Agreement................................................................ 5
5.6 Deficiency Charges............................................................................. 5
5.7 Fixed Transmission Rights...................................................................... 5
5.8 Confidentiality................................................................................ 6
6. OPERATION OF THE PJM CAPACITY CREDIT MARKETS............................................................. 6
6.1 Content of Sell Offers......................................................................... 6
6.1.1 Specifications...................................................................... 6
6.1.2 Market-based Offers................................................................. 6
6.1.3 Availability of Capacity Credits for Sale........................................... 6
6.2 Content of Buy Bids............................................................................ 7
6.3 Submission of Sell Offers and Buy Bids......................................................... 7
6.4 Conduct of PJM Capacity Credit Markets......................................................... 8
6.4.1 PJM Daily Capacity Credit Markets................................................... 8
6.4.2 PJM Monthly Capacity Credit Markets................................................. 9
6.5 Market Clearing Procedures..................................................................... 9
6.6 Settlement Procedures.......................................................................... 10
6.7 Billing........................................................................................ 10
6.8 Time Standard.................................................................................. 11
</TABLE>
Revised: July 19, 1999
Effective: July 19, 1999
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<TABLE>
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7. EFFECTIVE DATE AND TRANSITION............................................................................ 11
7.1 Effective Date................................................................................. 11
7.2 Transition Provisions.......................................................................... 11
7.3 Capacity Credit................................................................................ 11
7.4 Mandatory Sell Offers and Buy Bids............................................................. 11
</TABLE>
Revised: July 19, 1999
Effective: July 19, 1999
xii
<PAGE>
Amended and Restated
Operating Agreement
of
PJM Interconnection, L.L.C.
This Amended and Restated Operating Agreement of PJM Interconnection,
L.L.C., dated as of this 2/nd/ day of June, 1997, amends and restates as of the
Effective Date the Operating Agreement of PJM Interconnection, L.L.C. filed with
the FERC on April 2, 1997, as amended.
WHEREAS, certain of the Members have previously entered into an agreement,
originally dated September 26, 1956, as amended and supplemented up to and
including December 31, 1996, stating "their respective rights and obligations
with respect to the coordinated operation of their electric supply systems and
the interchange of electric capacity and energy among their systems" (such
agreement as amended and supplemented being referred to as the "Original PJM
Agreement"), and which coordinated operations and interchange came to be known
as the PJM Interconnection (the "Interconnection"); and
WHEREAS, pursuant to a resolution of June 16, 1993, an unincorporated
association comprised of the parties to the Original PJM Agreement was formed
for the purpose of implementation of the Original PJM Agreement as it then
existed and as it subsequently has been amended and supplemented, such
association being known as the "PJM Interconnection Association"; and
WHEREAS, because of changes in federal law and policy, the Original PJM
Agreement, together with other documents and agreements, was amended, restated
and submitted to FERC on December 31, 1996 to restructure fundamental aspects of
the operation of the Interconnection; and
WHEREAS, so that the provisions of the Original PJM Agreement could be
placed into effect consistent with a February 28, 1997 order of FERC, including
those provisions related to the governance of the Interconnection, the parties
to the Original PJM Agreement, along with the other interested parties, approved
the conversion of the PJM Interconnection Association into the LLC pursuant to
the provisions of the Delaware Limited Liability Company Act, as amended (the
"Delaware LLC Act"), pursuant to a Certificate of Formation (the "Certificate of
Formation") and a Certificate of Conversion (the "Certificate of Conversion"),
each filed with the Delaware Secretary of State (the "Recording Office") on
March 31, 1997; and
WHEREAS, the Members wish to amend and restate the Operating Agreement of
PJM Interconnection, L.L.C. adopted in connection with the formation of the LLC
and as in effect immediately prior to the Effective Date in the form set forth
below; and
WHEREAS, the Members intend to form an Independent System Operator in
accordance with the regulations of the Federal Energy Regulatory Commission; and
Now, therefore, in consideration of the foregoing, and of the covenants and
agreements hereinafter set forth, the Members hereby agree as follows:
1
<PAGE>
DEFINITIONS
Unless the context otherwise specifies or requires, capitalized terms used
in this Agreement shall have the respective meanings assigned herein or in the
Schedules hereto for all purposes of this Agreement (such definitions to be
equally applicable to both the singular and the plural forms of the terms
defined). Unless otherwise specified, all references herein to Sections,
Schedules, Exhibits or Appendices are to Sections, Schedules, Exhibits or
Appendices of this Agreement. As used in this Agreement:
1.1 Act.
"Act" shall mean the Delaware Limited Liability Company Act, Title 6,
(S) (S) 18-101 to 18-1109 of the Delaware Code.
1.2 Affiliate.
"Affiliate" shall mean any two or more entities, one of which controls the
other or that are under common control. "Control" shall mean the possession,
directly or indirectly, of the power to direct the management or policies of an
entity. Ownership of publicly-traded equity securities of another entity shall
not result in control or affiliation for purposes of this Agreement if the
securities are held as an investment, the holder owns (in its name or via
intermediaries) less than 10 percent of the outstanding securities of the
entity, the holder does not have representation on the entity's board of
directors (or equivalent managing entity) or vice versa, and the holder does not
in fact exercise influence over day-to-day management decisions. Unless the
contrary is demonstrated to the satisfaction of the Members Committee, control
shall be presumed to arise from the ownership of or the power to vote, directly
or indirectly, ten percent or more of the voting securities of such entity.
1.3 Agreement.
"Agreement" shall mean this Amended and Restated Operating Agreement of PJM
Interconnection, L.L.C., including all Schedules, Exhibits, Appendices, addenda
or supplements hereto, as amended from time to time.
1.4 Annual Meeting of the Members.
"Annual Meeting of the Members" shall mean the meeting specified in Section
8.3.1 of this Agreement.
1.5 Board Member.
"Board Member" shall mean a member of the PJM Board.
1.6 Capacity Resource.
"Capacity Resource" shall mean the net capacity from owned or contracted
for generating facilities all of which (i) are accredited to a Load Serving
Entity pursuant to the procedures set forth in the Reliability Assurance
Agreement and (ii) are committed to satisfy that Load Serving Entity's
obligations under the Reliability Assurance Agreement and this Agreement.
2
<PAGE>
1.7 Control Area.
"Control Area" shall mean an electric power system or combination of
electric power systems bounded by interconnection metering and telemetry to
which a common automatic generation control scheme is applied in order to:
(a) match the power output of the generators within the electric power
system(s) and energy purchased from entities outside the electric power
system(s), with the load within the electric power system(s);
(b) maintain scheduled interchange with other Control Areas, within the
limits of Good Utility Practice;
(c) maintain the frequency of the electric power system(s) within
reasonable limits in accordance with Good Utility Practice and the criteria of
NERC and the applicable regional reliability council of NERC;
(d) maintain power flows on transmission facilities within appropriate
limits to preserve reliability; and
(e) provide sufficient generating capacity to maintain operating reserves
in accordance with Good Utility Practice.
1.8 Electric Distributor.
"Electric Distributor" shall mean a Member that owns or leases with rights
equivalent to ownership electric distribution facilities that are used to
provide electric distribution service to electric load within the PJM Control
Area.
1.9 Effective Date.
"Effective Date" shall mean August 1, 1997, or such later date that FERC
permits this Agreement to go into effect.
1.10 Emergency.
"Emergency" shall mean: (i) an abnormal system condition requiring manual
or automatic action to maintain system frequency, or to prevent loss of firm
load, equipment damage, or tripping of system elements that could adversely
affect the reliability of an electric system or the safety of persons or
property; or (ii) a fuel shortage requiring departure from normal operating
procedures in order to minimize the use of such scarce fuel; or (iii) a
condition that requires implementation of emergency procedures as defined in the
PJM Manuals.
1.11 End-Use Customer.
"End-Use Customer" shall mean a Member that is a retail end-user of
electricity within the PJM Control Area.
1.12 FERC.
"FERC" shall mean the Federal Energy Regulatory Commission or any successor
federal agency, commission or department exercising jurisdiction over this
Agreement.
3
<PAGE>
1.13 Finance Committee.
"Finance Committee" shall mean the body formed pursuant to Section 7.5.1 of
this Agreement.
1.14 Generation Owner.
"Generation Owner" shall mean a Member that owns or leases with rights
equivalent to ownership facilities for the generation of electric energy that
are located within the PJM Control Area. Purchasing all or a portion of the
output of a generation facility shall not be sufficient to qualify a Member as a
Generation Owner.
1.15 Good Utility Practice.
"Good Utility Practice" shall mean any of the practices, methods and acts
engaged in or approved by a significant portion of the electric utility industry
during the relevant time period, or any of the practices, methods and acts
which, in the exercise of reasonable judgment in light of the facts known at the
time the decision was made, could have been expected to accomplish the desired
result at a reasonable cost consistent with good business practices,
reliability, safety and expedition. Good Utility Practice is not intended to be
limited to the optimum practice, method, or act to the exclusion of all others,
but rather is intended to include acceptable practices, methods, or acts
generally accepted in the region.
1.16 Interconnection.
"Interconnection" shall mean the coordinated operations and interchange
resulting from the Original PJM Agreement as continued in this Agreement.
1.17 LLC.
"LLC" shall mean PJM Interconnection, L.L.C., a Delaware limited liability
company.
1.18 Load Serving Entity.
"Load Serving Entity" shall mean an entity, including a load aggregator or
power marketer, (1) serving end-users within the PJM Control Area, and (2) that
has been granted the authority or has an obligation pursuant to state or local
law, regulation or franchise to sell electric energy to end-users located within
the PJM Control Area, or the duly designated agent of such an entity.
1.19 Locational Marginal Price.
"Locational Marginal Price" shall mean the hourly integrated market
clearing marginal price for energy at the location the energy is delivered or
received, calculated as specified in Section 2 of Schedule 1 of this Agreement.
1.20 MAAC.
"MAAC" shall mean the Mid-Atlantic Area Council, a reliability council
under (S) 202 of the Federal Power Act established pursuant to the MAAC
Agreement dated August 1, 1994, or any successor thereto.
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1.21 Market Buyer.
"Market Buyer" shall mean a Member that has met reasonable creditworthiness
standards established by the Office of the Interconnection and that is otherwise
able to make purchases in the PJM Interchange Energy Market or PJM Capacity
Credit Market.
1.22 Market Participant.
"Market Participant" shall mean a Market Buyer or a Market Seller, or both.
1.23 Market Seller.
"Market Seller" shall mean a Member that has met reasonable
creditworthiness standards established by the Office of the Interconnection and
that is otherwise able to make sales in the PJM Interchange Energy Market or PJM
Capacity Credit Market.
1.24 Member.
"Member" shall mean an entity that satisfies the requirements of
Section 11.6 of this Agreement and that (i) is a member of the LLC immediately
prior to the Effective Date, or (ii) has executed an Additional Member Agreement
in the form set forth in Schedule 4 hereof.
1.25 Members Committee.
"Members Committee" shall mean the committee specified in Section 8 of this
Agreement composed of representatives of all the Members.
1.26 NERC.
"NERC" shall mean the North American Electric Reliability Council, or any
successor thereto.
1.27 Office of the Interconnection.
"Office of the Interconnection" shall mean the employees and agents of the
LLC engaged in implementation of this Agreement and administration of the PJM
Tariff, subject to the supervision and oversight of the PJM Board acting
pursuant to this Agreement.
1.28 Operating Reserve.
"Operating Reserve" shall mean the amount of generating capacity scheduled
to be available for a specified period of an Operating Day to ensure the
reliable operation of the PJM Control Area, as specified in the PJM Manuals.
1.29 Original PJM Agreement.
"Original PJM Agreement" shall mean that certain agreement between certain
of the Members, originally dated September 26, 1956, and as amended and
supplemented up to and including December 31, 1996, relating to the coordinated
operation of their electric supply systems and the interchange of electric
capacity and energy among their systems.
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1.30 Other Supplier.
"Other Supplier" shall mean a Member that is (i) a seller, buyer or
transmitter of electric capacity or energy in, from or through the PJM Control
Area, and (ii) is not a Generation Owner, Electric Distributor, Transmission
Owner or End-Use Customer.
1.31 PJM Board.
"PJM Board" shall mean the Board of Managers of the LLC, acting pursuant to
this Agreement.
1.32 PJM Control Area.
"PJM Control Area" shall mean the Control Area recognized by NERC as the
PJM Control Area.
1.33 PJM Dispute Resolution Procedures
"PJM Dispute Resolution Procedures" shall mean the procedures for the
resolution of disputes set forth in Schedule 5 of this Agreement.
1.34 PJM Interchange Energy Market.
"PJM Interchange Energy Market" shall mean the regional competitive market
administered by the Office of the Interconnection for the purchase and sale of
spot electric energy at wholesale in interstate commerce and related services
established pursuant to Schedule 1 to this Agreement.
1.35 PJM Manuals.
"PJM Manuals" shall mean the instructions, rules, procedures and guidelines
established by the Office of the Interconnection for the operation, planning,
and accounting requirements of the PJM Control Area and the PJM Interchange
Energy Market.
1.36 PJM Tariff.
"PJM Tariff" shall mean the PJM Open Access Transmission Tariff providing
transmission service within the PJM Control Area, including any schedules,
appendices, or exhibits attached thereto, as in effect from time to time.
1.37 Planning Period.
"Planning Period" shall initially mean the 12 months beginning June 1 and
extending through May 31 of the following year, or such other period established
by the Reliability Committee established under the Reliability Assurance
Agreement.
1.38 President.
"President" shall have the meaning specified in Section 9.2.
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1.39 Related Parties.
"Related Parties" shall mean, solely for purposes of the governance
provisions of this Agreement: (i) any generation and transmission cooperative
and one of its distribution cooperative members; and (ii) any joint municipal
agency and one of its members. For purposes of this Agreement, representatives
of state or federal government agencies shall not be deemed Related Parties with
respect to each other, and a public body's regulatory authority, if any, over a
Member shall not be deemed to make it a Related Party with respect to that
Member.
1.40 Reliability Assurance Agreement.
"Reliability Assurance Agreement" shall mean that certain agreement, dated
June 2, 1997 and as amended from time to time, establishing obligations,
standards and procedures for maintaining the reliable operation of the PJM
Control Area.
1.41 Sector Votes.
"Sector Votes" shall mean the affirmative and negative votes of each sector
on the Members Committee, as specified in Section 8.4.
1.42 State.
"State" shall mean the District of Columbia and any State or Commonwealth
of the United States.
1.43 System.
"System" shall mean the interconnected electric supply system of a Member
and its interconnected subsidiaries exclusive of facilities which it may own or
control outside of the PJM Control Area. Each Member may include in its system
the electric supply systems of any party or parties other than Members which are
within the PJM Control Area, provided its interconnection agreements with such
other party or parties do not conflict with such inclusion.
1.44 Transmission Facilities.
"Transmission Facilities" shall mean facilities that: (i) are within the
PJM Control Area; (ii) meet the definition of transmission facilities pursuant
to FERC's Uniform System of Accounts or have been classified as transmission
facilities in a ruling by FERC addressing such facilities; and (iii) have been
demonstrated to the satisfaction of the Office of the Interconnection to be
integrated with the PJM Control Area transmission system and integrated into the
planning and operation of the PJM Control Area to serve all of the power and
transmission customers within the PJM Control Area.
1.45 Transmission Owner.
"Transmission Owner" shall mean a Member that owns or leases with rights
equivalent to ownership Transmission Facilities. Taking transmission service
shall not be sufficient to qualify a Member as a Transmission Owner.
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1.46 Transmission Owners Agreement.
"Transmission Owners Agreement" shall mean that certain agreement, dated
June 2, 1997 and as amended from time to time, by and among Transmission Owners
in the PJM Control Area providing for an open-access transmission tariff in the
PJM Control Area, and for other purposes.
1.47 User Group.
"User Group" shall mean a group formed pursuant to Section 8.7 of this
Agreement.
1.48 Voting Member
"Voting Member" shall mean (i) a Member as to which no other Member is an
Affiliate or Related Party, or (ii) a Member together with any other Members as
to which it is an Affiliate or Related Party.
1.49 Weighted Interest.
"Weighted Interest" shall be equal to (0.1(1/N) + 0.5(B/C) + 0.2(D/E) +
0.2(F/G)), where:
N = the total number of Members
B = the Member's internal peak demand for the previous calendar year
C = the sum of factor B for all Members
D = the Member's net installed generating capacity located in the
PJM Control Area as of January 1 of the current calendar year
E = the sum of factor D for all Members
F = the sum of the Member's circuit miles of transmission facilities
multiplied by the respective operating voltage for facilities 100
kV and above as of January 1 of the current calendar year
G = the sum of factor F for all Members
2. FORMATION, NAME; PLACE OF BUSINESS
2.1 Formation of LLC; Certificate of Formation.
The Members of the LLC hereby:
(a) acknowledge the conversion of the PJM Interconnection Association into
the LLC, a limited liability company pursuant to the Act, by virtue of the
filing of both the Certificate of Formation and the Certificate of Conversion
with the Recording Office, effective as of March 31, 1997;
(b) confirm and agree to their status as Members of the LLC;
(c) enter into this Agreement for the purpose of amending and restating
the rights, duties, and relationship of the Members; and
(d) agree that if the laws of any jurisdiction in which the LLC transacts
business so require, the PJM Board also shall file, with the appropriate office
in that jurisdiction, any documents necessary for the LLC to qualify to
transact business under such laws; and (ii) agree
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and obligate themselves to execute, acknowledge, and cause to be filed for
record, in the place or places and manner prescribed by law, any amendments to
the Certificate of Formation as may be required, either by the Act, by the laws
of any jurisdiction in which the LLC transacts business, or by this Agreement,
to reflect changes in the information contained therein or otherwise to comply
with the requirements of law for the continuation, preservation, and operation
of the LLC as a limited liability company under the Act.
2.2 Name of LLC.
The name under which the LLC shall conduct its business is "PJM
Interconnection, L.L.C."
2.3 Place of Business.
The location of the principal place of business of the LLC shall be 955
Jefferson Avenue, Valley Forge Corporate Center, Norristown, Pennsylvania 19403-
2497. The LLC may also have offices at such other places both within and without
the State of Delaware as the PJM Board may from time to time determine or the
business of the LLC may require.
2.4 Registered Office and Registered Agent.
The street address of the initial registered office of the LLC shall be
1209 Orange Street, Wilmington, Delaware 19801, and the LLC's registered agent
at such address shall be The Corporation Trust Company. The registered office
and registered agent may be changed by resolution of the PJM Board.
3. PURPOSES AND POWERS OF LLC
3.1 Purposes.
The purposes of the LLC shall be:
(a) to operate in accordance with FERC requirements as an Independent
System Operator, comprised of the PJM Board, the Office of the Interconnection,
and the Members Committee, with the authorities and responsibilities set forth
in this Agreement;
(b) as necessary for the operation of the Interconnection as specified
above: (i) to acquire and obtain licenses, permits and approvals, (ii) to own or
lease property, equipment and facilities, and (iii) to contract with third
parties to obtain goods and services, provided that, the L.L.C. may procure
goods and services from a Member only after open and competitive bidding; and
(c) to engage in any lawful business permitted by the Act or the laws of
any jurisdiction in which the LLC may do business and to enter into any lawful
transaction and engage in any lawful activities in furtherance of the foregoing
purposes and as may be necessary, incidental or convenient to carry out the
business of the LLC as contemplated by this Agreement.
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3.2 Powers.
The LLC shall have the power to do any and all acts and things necessary,
appropriate, advisable, or convenient for the furtherance and accomplishment of
the purposes of the LLC, including, without limitation, to engage in any kind of
activity and to enter into and perform obligations of any kind necessary to or
in connection with, or incidental to, the accomplishment of the purposes of the
LLC, so long as said activities and obligations may be lawfully engaged in or
performed by a limited liability company under the Act.
4. EFFECTIVE DATE AND TERMINATION
4.1 Effective Date and Termination.
(a) The existence of the LLC commenced on March 31, 1997, as provided in
the Certificate of Formation and Certificate of Conversion which were filed with
the Recording Office on March 31, 1997. This Agreement shall amend and restate
the Operating Agreement of PJM Interconnection, L.L.C. as of the Effective Date.
(b) The LLC shall continue in existence until terminated in accordance
with the terms of this Agreement. The withdrawal or termination of any Member is
subject to the provisions of Section 18.18 of this Agreement.
(c) Any termination of this Agreement or withdrawal of any Member from the
Agreement shall be filed with the FERC and shall become effective only upon the
FERC's approval.
Governing Law.
This Agreement and all questions with respect to the rights and obligations
of the Members, the construction, enforcement and interpretation hereof, and the
formation, administration and termination of the LLC shall be governed by the
provisions of the Act and other applicable laws of the State of Delaware, and
the Federal Power Act.
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5. WORKING CAPITAL AND CAPITAL CONTRIBUTIONS
5.1 Funding of Working Capital and Capital Contributions.
(a) The Office of the Interconnection shall attempt to obtain financing of
up to twenty-five percent (25%) of the approved annual operating budget of the
LLC adopted by the PJM Board pursuant to (S) 7.5.2 of this Agreement to meet the
working capital needs of the LLC, which shall be limited to such working capital
needs that arise from timing in cash flows from interchange accounting, tariff
administration and payment of the operating costs of the Office of the
Interconnection. Such financing, which shall be non-recourse to the Members of
the LLC and which shall be for a stated term without penalty for prepayment, may
be obtained by borrowing the amount required at market-based interest rates,
negotiated on an arm's length basis, (i) from a Member or Members or (ii) from a
commercial lender, supported, if necessary, by credit enhancements provided by a
Member or Members; provided, however, no Member shall be obligated to provide
such financing or credit enhancements. The LLC shall make such filings and seek
such approvals as necessary in order for the principal, interest and fees
related to any such borrowing to be repaid through charges under the PJM Tariff
as appropriate under Schedule 3 of this Agreement.
(b) In the event financing of the working capital needs of the Office of
the Interconnection is unavailable on commercially reasonable terms, the PJM
Board may require the Members to contribute capital in the aggregate up to five
million two hundred thousand dollars ($5,200,000) for the working capital needs
that could not be financed; provided that in such event each Member's obligation
to contribute additional capital shall be in proportion to its Weighted
Interest, multiplied by the amount so requested by the PJM Board. Each Member
that contributes such capital shall be entitled to earn a return on the
contribution to the extent such contribution has not been repaid, which return
shall be at a fair market rate as determined by the PJM Board but in no event
less than the current interest rate established pursuant to 18 C.F.R. (S)
35.19a(a)(2)(iii); provided further, that any Member not wanting to contribute
the requested capital contribution may withdraw from the LLC upon 90 days
written notice as provided in Section 18.18.2 of this Agreement.
(c) Authority to borrow capital for LLC Operations. Nothing in
Section 5.1(a) and (b) shall be construed to restrict the authority of the PJM
Board to authorize the LLC to borrow or raise capital in excess of twenty-five
percent of the approved annual operating budget of the LLC, for working capital
or otherwise, as the PJM Board deems appropriate to fund the operations of the
LLC, in accordance with the general powers of the LLC under Section 3.2 to enter
into obligations of any kind to accomplish the purposes of the LLC. Nor shall
anything in Section 5.1(a) and (b) in any way restrict the authority of the PJM
Board to authorize the LLC to grant to lenders such security interests or other
rights in assets or revenues received under the PJM Tariff with respect to the
costs of operating the LLC and the Office of the Interconnection and to take
such other actions as it deems necessary and appropriate to obtain such
financing in accordance with such general powers of the LLC under Section 3.2.
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5.2 Contributions to Association.
All contributions prior to the Effective Date of the original Operating
Agreement of PJM Interconnection, L.L.C. of cash or other assets to the PJM
Interconnection Association by persons who are now or in the future may become
Members of the LLC shall be deemed contributions by such Members to the LLC.
6. TAX STATUS AND DISTRIBUTIONS
6.1 Tax Status.
The LLC shall make all necessary filings under the applicable Treasury
Regulations to have the LLC taxed as a corporation.
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6.2 Return of Capital Contributions.
(a) In the event Members are required to contribute capital to the LLC in
accordance with Section 5.1 herein, the LLC shall request the Transmission
Owners to recover such working capital through charges under the PJM Tariff as
provided in Schedule 3 of this Agreement. In the event all or a portion of the
working capital is recovered pursuant to the PJM Tariff, such amount(s) shall be
returned to the Members in accordance with their actual contributions.
(b) Except for return of capital contributions and liquidating
distributions as provided in the foregoing section and Section 6.3 herein,
respectively, the LLC does not intend to make any distributions of cash or other
assets to its Members.
6.3 Liquidating Distribution.
Upon termination or liquidation of the LLC, the cash or other assets of the
LLC shall be distributed as follows:
(a) first, in the event the LLC has any liabilities at the time of its
termination or dissolution, the LLC shall liquidate such of its assets as is
necessary to satisfy such liabilities;
(b) second, any capital contribution in cash or in kind by any Member of
the PJM Interconnection Association prior to the Effective Date shall be
distributed by the LLC back to such Member in the form received by the PJM
Interconnection Association; and
(c) third, any remaining assets of the LLC shall be distributed to the
Members in proportion to their Weighted Interests.
7. PJM BOARD
7.1 Composition.
There shall be an LLC Board of Managers, referred to herein as the "PJM
Board," composed of seven voting members, with the President as a non-voting
member. The seven voting Board Members shall be elected by the Members Committee
from a slate of candidates for the then-existing vacancies or expiring terms on
the PJM Board. An independent consultant, retained by the Office of the
Interconnection upon consideration of the advice and recommendations of the
Members Committee, shall be directed to prepare a list of persons qualified and
willing to serve on the PJM Board. Not later than 30 days prior to each Annual
Meeting of the Members, the Office of the Interconnection shall distribute to
the representatives on the Members Committee a slate from among the list
proposed by the independent consultant, along with information on the background
and experience of the persons on the slate appropriate to evaluating their
fitness for service on the PJM Board. Elections for the PJM Board shall be held
at each Annual Meeting of the Members, for the purpose of selecting the initial
PJM Board in accordance with the provisions of Section 7.3(a), or selecting a
person to fill the seat of a Board Member whose term is expiring. Should the
Members Committee fail to elect a full PJM Board from the slate proposed by the
independent consultant, the Office of the Interconnection shall direct the
independent consultant, or a replacement consultant selected by the Office of
the Interconnection, to propose a list for a slate of nominees for any vacancies
on the PJM Board for consideration by the Members at the next regular meeting of
the Members Committee.
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7.2 Qualifications.
A Board Member shall not be, and shall not have been at any time within
five years of election to the PJM Board, a director, officer or employee of a
Member or of an Affiliate or Related Party of a Member. Except as provided in
the LLC's Standards of Conduct filed with the FERC, at any time while serving on
the PJM Board, a Board Member shall have no direct business relationship or
other affiliation with any Member or its Affiliates or Related Parties. Of the
seven Board Members, four shall have expertise and experience in the areas of
corporate leadership at the senior management or board of directors level, or in
the professional disciplines of finance or accounting, engineering, or utility
laws and regulation. Of the other three Board Members, one shall have expertise
and experience in the operation or concerns of transmission dependent utilities,
one shall have expertise and experience in the operation or planning of
transmission systems, and one shall have expertise and experience in the area of
commercial markets and trading and associated risk management.
7.3 Term of Office.
(a) The persons serving as the Board of Managers of the LLC immediately
prior to the Effective Date shall continue in office until the first Annual
Meeting of the Members. At the first Annual Meeting of the Members, the then
current members of the PJM Board who desire to continue in office shall be
elected by the Members to serve until the second Annual Meeting of the Members
or until their successors are elected, along with such additional persons as
necessary to meet the composition requirements of Section 7.1 and the
qualification requirements of Section 7.2.
(b) A Board Member shall serve for a term of three years commencing with
the Annual Meeting of the Members at which the Board Member was elected;
provided, however, that two of the Board Members elected at the first Annual
Meeting of the Members following the Effective Date shall be chosen by lot to
serve a term of one year, three of such Board Members shall be chosen by lot to
serve a term of two years and the final two such Board Members shall serve a
term of three years.
(c) Vacancies on the PJM Board occurring between Annual Meetings of the
Members shall be filled by vote of the then remaining Board Members; a Board
Member so selected shall serve until the next Annual Meeting at which time a
person shall be elected to serve the balance of the term of the vacant Board
Seat. Removal of a Board Member shall require the approval of the Members
Committee.
7.4 Quorum.
The presence in person or by telephone or other authorized electronic means
of a majority of the voting Board Members shall constitute a quorum at all
meetings of the PJM Board for the transaction of business except as otherwise
provided by statute. If a quorum shall not be present, the Board Members then
present shall have the power to adjourn the meeting from time to time, until a
quorum shall be present. Provided a quorum is present at a meeting, the PJM
Board shall act by majority vote of the Board Members present.
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7.5 Operating and Capital Budgets.
7.5.1 Finance Committee.
Not later than February 1 of each year, the entities specified below
shall select the members of a Finance Committee. The Finance Committee shall be
composed of one representative of the parties to the Reliability Assurance
Agreement chosen by the parties to that agreement, one representative of the
parties to the Transmission Owners Agreement chosen by the parties to that
agreement, two representatives of the Members Committee chosen by the Members
Committee and that are not representatives of an entity that is a party to the
Transmission Owners Agreement or an Affiliate or Related Party of such an
entity, one representative of the Office of the Interconnection selected by the
President, and two Board Members selected by the PJM Board. The Members
Committee shall endeavor to elect members of the Finance Committee that are
broadly representative of the diversity of interests among the Members. The
Office of the Interconnection shall prepare annual budgets in accordance with
processes and procedures established by the PJM Board, and shall timely submit
its budgets to the Finance Committee for review. The Finance Committee shall
submit its analysis of and recommendations on the budgets to the PJM Board, with
copies to the Members Committee. The Finance Committee shall also review and
comment upon any additional or amended budgets prepared by the Office of the
Interconnection at the request of the PJM Board or the Members Committee.
7.5.2 Adoption of Budgets.
The PJM Board shall adopt, upon consideration of the advice and
recommendations of the Finance Committee, operating and capital budgets for the
LLC, and shall distribute to the Members for their information final annual
budgets for the following fiscal year not later than 60 days prior to the
beginning of each fiscal year of the LLC.
7.6 By-laws.
To the extent not inconsistent with any provision of this Agreement, the
PJM Board shall adopt such by-laws establishing procedures for the
implementation of this Agreement as it may deem appropriate, including but not
limited to by-laws governing the scheduling, noticing and conduct of meetings of
the PJM Board, selection of a Chair and Vice Chair of the PJM Board, action by
the PJM Board without a meeting, and the organization and responsibilities of
standing and special committees of the PJM Board. Such by-laws shall not modify
or be inconsistent with any of the rights or obligations established by this
Agreement.
7.7 Duties and Responsibilities of the PJM Board.
In accordance with this Agreement, the PJM Board shall supervise and
oversee all matters pertaining to the Interconnection and the LLC, and carry out
such other duties as are herein specified, including but not limited to the
following duties and responsibilities:
i) As its primary responsibility, ensure that the President, the
other officers of the LLC, and Office of the Interconnection
perform the duties and responsibilities set forth in this
Agreement, including but not limited to those set forth in
Sections 9.2 through 9.4 and Section 10.4 in a manner
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consistent with (A) the safe and reliable operation of the
Interconnection, (B) the creation and operation of a robust,
competitive, and non-discriminatory electric power market in the
PJM Control Area, and (C) the principle that a Member or group
of Members shall not have undue influence over the operation of
the Interconnection;
ii) Select the Officers of the LLC;
iii) Adopt budgets for the LLC;
iv) Approve the Regional Transmission Expansion Plan in accordance
with the provisions of the Regional Transmission Expansion
Planning Protocol set forth in Schedule 6 of this Agreement.
v) On its own initiative or at the request of a User Group as
specified herein, submit to the Members Committee such proposed
amendments to this Agreement or any Schedule hereto, or a
proposed new Schedule, as it may deem appropriate;
vi) Petition FERC to modify any provision of this Agreement or any
Schedule or practice hereunder that the PJM Board believes to be
unjust, unreasonable, or unduly discriminatory under Section 206
of the Federal Power Act, subject to the right of any Member or
the Members to intervene in any resulting proceedings;
vii) Review for consistency with the creation and operation of a
robust, competitive and non-discriminatory electric power market
in the PJM Control Area any change to rate design or to non-rate
terms and conditions proposed by Transmission Owners for filing
under Section 205 of the Federal Power Act.
viii) If and to the extent it shall deem appropriate, intervene in any
proceeding at FERC initiated by the Members in accordance with
Section 11.5(b), and participate in other state and federal
regulatory proceedings relating to the interests of the LLC;
ix) Review, in accordance with Section 15.1.3, determinations of the
Office of the Interconnection with respect to events of default;
x) Assess against the other Members in proportion to their Weighted
Interest an amount equal to any payment to the Office of the
Interconnection, including interest thereon, as to which a
Member is in default;
xi) Establish reasonable sanctions for failure of a Member to comply
with its obligations under this Agreement;
xii) Direct the Office of the Interconnection on behalf of the LLC to
take appropriate legal or regulatory action against a Member (A)
to recover any unpaid amounts due from the Member to the Office
of the Interconnection under this Agreement and to make whole
any Members subject to an assessment as a result of such unpaid
amount, or (B) as may otherwise be
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necessary to enforce the obligations of this Agreement;
xiii) Resolve claims by a Member that the Reliability Committee
established by the Reliability Assurance Agreement has exercised
its responsibilities in a manner inconsistent with the creation
and operation of a robust, competitive and non-discriminatory
electric power market in the PJM Control Area, upon due
consideration of the views of the Member and of the Reliability
Committee, and of the need to preserve the reliability of
electric service in the PJM Control Area.
xiv) Solicit the views of Members on, and commission from time to
time as it shall deem appropriate independent reviews of, (A)
the performance of the PJM Interchange Energy Market, (B)
compliance by Market Participants with the rules and
requirements of the PJM Interchange Energy Market, and (C) the
performance of the Office of the Interconnection under
performance criteria proposed by the Members Committee and
approved by the PJM Board; and
xv) Terminate a Member as may be appropriate under the terms of this
Agreement.
8. MEMBERS COMMITTEE
8.1 Sectors.
8.1.1 Designation.
Voting on the Members Committee shall be by sectors. The Members
Committee shall be composed of five sectors, one for Generation Owners, one for
Other Suppliers, one for Transmission Owners, one for Electric Distributors, and
one for End-Use Customers, provided that there are at least five Members in each
Sector. Except as specified in Section 8.1.2, each Voting Member shall have one
vote. Each Voting Member shall, within thirty (30) days after the Effective Date
or, if later, thirty (30) days after becoming a Member, and thereafter not later
than 10 days prior to the Annual Meeting of the Members for each annual period
beginning with the Annual Meeting of the Members, submit to the President a
sealed notice of the sector in which it is qualified to vote or, if qualified to
participate in more than one sector, its rank order preference of the sectors in
which it wishes to vote, and shall be assigned to its highest-ranked sector that
has the minimum number of Members specified above. If a Member is assigned to a
sector other than its highest-ranked sector in accordance with the preceding
sentence, its higher sector preference or preferences shall be honored as soon
as a higher-ranked sector has five or more Members. A Voting Member may
designate as its voting sector any sector for which it or its Affiliate or
Related Party Members is qualified. The sector designations of the Voting
Members shall be announced by the President at the Annual Meeting.
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8.1.2 Related Parties.
The Members in a group of Related Parties shall each be entitled to a
vote, provided that all the Members in a group of Related Parties that chooses
to exercise such rights shall be assigned to the Electric Distributor sector.
8.2 Representatives.
8.2.1 Appointment.
Each Member may appoint a representative to serve on the Members
Committee, with authority to act for that Member with respect to actions or
decisions by the Members Committee. Each Member may appoint an alternate
representative to act for that Member at meetings of the Members Committee in
the absence of the representative. A Member participating in the PJM Interchange
Energy Market through an agent may be represented on the Members Committee by
that agent. A Member shall appoint its representative by giving written notice
identifying its representative and alternate representative to the Office of the
Interconnection. Members that are Affiliates or Related Parties may each appoint
a representative and alternate representative to the Members Committee, but
shall vote as specified in Section 8.1.
8.2.2 Regulatory Authorities.
FERC and any other federal agency with regulatory authority over a
Member, each State electric utility regulatory commission with regulatory
jurisdiction within the PJM Control Area, and each office of consumer advocate
from each State all or any part of the territory of which is within the PJM
Control Area, may nominate one representative to serve as an ex officio non-
voting member of the Members Committee.
8.2.3 Initial Representatives.
Initial representatives to the Members Committee shall be appointed no
later than 30 days after the Effective Date; provided, however, that each
representative to the Management Committee under the Operating Agreement of PJM
Interconnection, L.L.C. as in effect immediately prior to the Effective Date
shall automatically become a representative to the Members Committee on the
Effective Date unless replaced as specified in Section 8.2.4. An entity becoming
a Member shall appoint a representative to the Members Committee no later than
30 days after becoming a Member.
8.2.4 Change of or Substitution for a Representative.
Any Member may change its representative or alternate on the Members
Committee at any time by providing written notice to the Office of the
Interconnection identifying its replacement representative or alternate. Any
representative to the Members Committee may, by written notice to the Chair,
designate a substitute representative from that Member to act for him or her
with respect to any matter specified in such notice.
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8.3 Meetings.
8.3.1 Regular and Special Meetings.
The Members Committee shall hold regular meetings, no less frequently
than once each calendar quarter at such time and at such place as shall be fixed
by the Chair. The Members Committee shall hold an Annual Meeting of the Members
each calendar year at such time and place as shall be specified by the Chair. At
the Annual Meeting of the Members, Board Members as necessary, officers of the
Members Committee, and representatives to the Finance Committee shall be
elected. The Members Committee may hold special meetings for one or more
designated purposes within the scope of the authority of the Members Committee
when called by the Chair on the Chair's own initiative, or at the request of
five or more representatives on the Members Committee. The notice of a regular
or special meeting shall be distributed to the representatives as specified in
Section 18.13 of this Agreement not later than seven days prior to the meeting,
shall state the time and place of the meeting, and shall include an agenda
sufficient to notify the representatives of the substance of matters to be
considered at the meeting; provided, however, that meetings may be called on
shorter notice at the discretion of the Chair as the Chair shall deem necessary
to deal with an emergency or to meet a deadline for action.
8.3.2 Attendance.
Regular and special meetings may be conducted in person or by
telephone, or other electronic means as authorized by the Members Committee.
The attendance in person or by telephone or other electronic means of a
representative or a duly designated substitute shall be required in order to
vote.
8.3.3 Quorum.
The attendance as specified in Section 8.3.2 of a majority of the
Voting Members from each of at least three sectors that each have at least five
Members shall constitute a quorum, however, a quorum shall only require one-
third of the Voting Members, but not less than ten, from any sector that has
more than 20 Voting Members. No action may be taken by the Members Committee at
a meeting unless a quorum is present; provided, however, that if a quorum is not
present, the Voting Members then present shall have the power to adjourn the
meeting from time to time until a quorum shall be present.
8.4 Manner of Acting.
(a) All matters brought up for a vote or approval by the Members Committee
shall be stated in the form of a motion, which must be seconded. Only one motion
may be pending at one time.
(b) Each Sector shall be entitled to cast one and zero one-hundredths
(1.00) Sector Votes. Each Voting Member shall be entitled to cast one (1) non-
divisible vote in its sector. In the case of a Voting Member comprised of
Affiliates or Related Parties, any representative, alternate or substitute of
any of the Affiliated or Related Parties may cast the vote of the Voting Member.
The Sector Vote of each sector shall be split into an affirmative component
based on votes for the pending motion, and a negative component based on votes
against the pending motion, in direct proportion to the votes cast within the
sector for and against the pending motion, rounded to two decimal places.
(c) The sum of affirmative Sector Votes necessary to pass the pending
motion shall be
Revised: November 19, 1998
Effective: January 14, 1999
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greater than (but not merely equal to) the product of .667 multiplied by the
number of sectors that have at least five Members and that participated in the
vote.
(d) Voting Members not in attendance at the meeting as specified in
Section 8.3.2 of this Agreement or abstaining shall not be counted as
affirmative or negative votes.
8.5 Chair and Vice Chair of the Members Committee.
8.5.1 Selection and Term.
The representatives or their alternates or substitutes on the Members
Committee shall elect from among the representatives a Chair and a Vice Chair.
The offices of Chair and Vice Chair shall be held for a term of one year and
until succession to the office occurs as specified herein. Except as specified
below, at each Annual Meeting of the Members the Vice Chair shall succeed to the
office of Chair, and a new Vice Chair shall be elected. If the office of Chair
becomes vacant, or the Chair leaves the employment of the Member for whom the
Chair is the representative, or the Chair is no longer the representative of
such Member, the Vice Chair shall succeed to the office of Chair, and a new Vice
Chair shall be elected at the next regular or special meeting of the Members
Committee, both such officers to serve until the second Annual Meeting of the
Members following such succession or election to a vacant office. If the office
of Vice Chair becomes vacant, or the Vice Chair leaves the employment of the
Member for whom the Vice Chair is the representative, or the Vice Chair is no
longer the representative of such Member, a new Vice Chair shall be elected at
the next regular or special meeting of the Members Committee.
8.5.2 Duties.
The Chair shall call and preside at meetings of the Members Committee,
and shall carry out such other responsibilities as the Members Committee shall
assign. The Chair shall cause minutes of each meeting of the Members Committee
to be taken and maintained, and shall cause notices of meetings of the Members
Committee to be distributed. The Vice Chair shall preside at meetings of the
Members Committee in the absence of the Chair, and shall otherwise act for the
Chair at the Chair's request.
8.6 Other Committees.
(a) The Members Committee may form, select the membership, and oversee the
activities, of an Operating Committee, a Planning Committee, and an Energy
Market Committee as standing committees, and such other committees,
subcommittees, task forces, working groups or other bodies as it shall deem
appropriate, to provide advice and recommendations to the Members Committee or
to the Office of the Interconnection as directed by the Members Committee.
(b) The Members Committee shall elect representatives to the Alternate
Dispute Resolution Committee as specified in the PJM Dispute Resolution
Procedures.
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8.7 User Groups.
(a) Any five or more Members sharing a common interest may form a User
Group, and may invite such other Members to join the User Group as the User
Group shall deem appropriate. Notification of the formation of a User Group
shall be provided to all members of the Members Committee.
(b) The Members Committee shall create a User Group composed of
representatives of bona fide public interest and environmental organizations
that are interested in the activities of the LLC and are willing and able to
participate in such a User Group.
Meetings of User Groups shall be open to all Members and the Office of the
Interconnection. Notices and agendas of meetings of a User Group shall be
provided to all Members that ask to receive them.
(d) Any recommendation or proposal for action adopted by affirmative vote
of three-fourths or more of the members of a User Group shall be circulated by
the Office of the Interconnection to the representatives on the Members
Committee and shall be considered by the Members Committee at its next regular
meeting occurring not earlier than 30 days after the circulation of such notice.
(e) If the Members Committee does not adopt a recommendation or proposal
submitted to it by a User Group, upon vote of nine-tenths or more of the members
of the User Group the recommendation or proposal may be submitted to the PJM
Board for its consideration in accordance with Section 7.7(v).
8.8 Powers of the Members Committee.
The Members Committee, acting by adoption of a motion as specified in
Section 8.4, shall have the power to take the actions specified in this
Agreement, including:
i) Elect the members of the PJM Board;
ii) In accordance with the provisions of Section 18.6 of this
Agreement, amend any portion of this Agreement, including the
Schedules hereto, or create new Schedules, and file any such
amendments or new Schedules with FERC or other regulatory body of
competent jurisdiction;
iii) Terminate this Agreement; and
iv) Provide advice and recommendations to the PJM Board and the
Office of the Interconnection.
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9. OFFICERS
9.1 Election and Term.
The officers of the LLC shall consist of a President, a Secretary and a
Treasurer. The PJM Board may elect such other officers as it deems necessary to
carry out the business of the LLC. All officers shall be elected by the PJM
Board and shall hold office until the next annual meeting of the PJM Board and
until their successors are elected. Any number of offices may be held by the
same person, except that the offices of the President and Treasurer may not be
held by the same person.
9.2 President.
The PJM Board shall appoint a President and Chief Executive Officer of the
LLC (the "President"). The President shall direct and supervise the day-to-day
operation of the LLC, and shall report to the PJM Board. The President shall be
responsible for directing and supervising the Office of the Interconnection in
the performance of the duties and responsibilities specified in Section 10.4.
The President shall execute bonds, mortgages and other contracts requiring a
seal, under the seal of the LLC, except where required or permitted by law to be
otherwise signed and executed and except where the signing and execution thereof
shall be expressly delegated by the board to some other officer or agent of the
LLC. In the absence of the President or in the event of his or her inability or
refusal to act, and if a vice president has been appointed by the PJM Board, the
Vice President (or in the event there be more than one Vice President, the Vice
Presidents in the order designated by the PJM Board in its Minutes) shall
perform the duties of the President, and when so acting, shall have all the
powers of and be subject to all the restrictions upon the President. The Vice
President shall perform such other duties and have such other powers as the PJM
Board may from time to time prescribe.
9.3 Secretary.
The Secretary shall attend all meetings of the PJM Board and record all the
proceedings of the meetings of the PJM Board in a minute book to be kept for
that purpose and shall perform like duties for the standing committees or
special committees when required. He or she shall give, or cause to be given,
notice of all special meetings of the PJM Board, and shall perform such other
duties as may be prescribed by the PJM Board or President, under whose
supervision he or she shall be. He or she shall have custody of the corporate
seal of the LLC, and he or she, or an assistant secretary, shall have authority
to affix the same to any instrument requiring it and, when so affixed, it may be
attested by his or her signature or by the signature of such assistant
secretary. The PJM Board may give general authority to any other officer to
affix the seal of the LLC and to attest the affixing by his or her signature.
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9.4 Treasurer.
The Treasurer shall have or arrange for the custody of the LLC's funds and
securities and shall keep full and accurate accounts of receipts and
disbursements in books belongings to the LLC and shall deposit all moneys and
other valuable effects in the name and to the credit of the LLC in such
depositories as may be designated by the PJM Board. The Treasurer shall disburse
the funds of the LLC as may be ordered by the PJM Board, taking proper vouchers
for such disbursements, and shall render to the President and PJM Board at its
regular meetings, or when the PJM Board so requires, an account of his or her
transactions as Treasurer and of the financial condition of the LLC. If required
by the Board, the Treasurer shall give the LLC a bond (which shall be renewed
periodically) in such sum and with such surety or sureties as shall be
satisfactory to the PJM Board for the faithful performance of the duties of his
office and of the restoration to the LLC, in case of his or her death,
resignation, retirement or removal from office, of all books, papers, vouchers,
money and other property of whatever kind in his or her possession or under his
or her control belonging to the LLC.
9.5 Renewal of Officers; Vacancies.
Any officer elected or appointed by the PJM Board may be removed at any
time by the affirmative vote of a majority of the PJM Board eligible to vote.
Any vacancy occurring in any office of the LLC shall be filled by the PJM Board.
9.6 Compensation.
The salaries of all officers and agents of the LLC, and the reasonable
compensation of the PJM Board, shall be fixed by the PJM Board.
10. OFFICE OF THE INTERCONNECTION.
10.1 Establishment.
The Office of the Interconnection shall implement this Agreement,
administer the PJM Tariff, and undertake such other responsibilities as set
forth herein. All personnel of the Office of the Interconnection shall be
employees of the LLC or under contract thereto. The cost of the Office of the
Interconnection and expenses associated therewith, including salaries and
expenses of said personnel, space and any necessary facilities or other capital
expenditures, shall be recovered in accordance with Schedule 3. The Office of
the Interconnection shall adopt, publish and comply with standards of conduct
that satisfy the regulations of FERC.
10.2 Processes and Organization.
In order to carry out the responsibilities of the Office of the
Interconnection for the safe and reliable operation of the Interconnection, the
President may establish processes and organization for operating personnel and
facilities as the President shall deem appropriate, and shall request such
Members as the President shall deem appropriate to participate in such processes
and organization. All such processes and organization shall be carried out in
accordance with all applicable code of conduct or other functional separation
requirements of FERC.
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10.3 Confidential Information.
The Office of the Interconnection shall comply with the requirements of
Section 18.17 with respect to any proprietary or confidential information
received from or about any Member.
10.4 Duties and Responsibilities.
The Office of the Interconnection, under the direction of the President as
supervised and overseen by the PJM Board, shall carry out the following duties
and responsibilities, in accordance with the provisions of this Agreement:
i) Administer and implement this Agreement;
ii) Perform such functions in furtherance of this Agreement as the
PJM Board, acting within the scope of its duties and
responsibilities under this Agreement, may direct;
iii) Prepare, maintain, update and disseminate the PJM Manuals;
iv) Comply with MAAC and NERC operation and planning standards,
principles and guidelines;
v) Maintain an appropriately trained workforce, and such equipment
and facilities, including computer hardware and software and
backup power supplies, as necessary or appropriate to implement
or administer this Agreement;
vi) Direct the operation and coordinate the maintenance of the
facilities of the Interconnection used for both load and
reactive supply, so as to maintain reliability of service and
obtain the benefits of pooling and interchange consistent with
this Agreement and the Reliability Assurance Agreement;
vii) Direct the operation and coordinate the maintenance of the bulk
power supply facilities of the Interconnection with such
facilities and systems of others not party to this Agreement in
accordance with agreements between the LLC and such other
systems to secure reliability and continuity of service and
other advantages of pooling on a regional basis;
viii) Perform interchange accounting and maintain records pertaining
to the operation of the PJM Interchange Energy Market and the
Interconnection;
ix) Notify the Members of the receipt of any application to become a
Member, and of the action of the Office of the Interconnection
on such application, including but not limited to the completion
of integration of a new Member's system into the PJM Control
Area as specified in Section 11.6(f);
x) Calculate the Weighted Interest of each Member;
xi) Maintain accurate records of the sectors in which each Voting
Member is entitled to vote, and calculate the results of any
vote taken in the Members Committee;
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xii) Furnish appropriate information and reports as are required to
keep the Members regularly informed of the outlook for, the
functioning of, and results achieved by the Interconnection;
xiii) File with FERC on behalf of the Members any amendments to this
Agreement or the Schedules hereto, any new Schedules hereto,
and make any other regulatory filings on behalf of the Members
or the LLC necessary to implement this Agreement;
xiv) At the direction of the PJM Board, submit comments to
regulatory authorities on matters pertinent to the
Interconnection;
xv) Consult with the standing or other committees established
pursuant to Section 8.6(a) on matters within the responsibility
of the committee;
xvi) Perform operating studies of the bulk power supply facilities
of the Interconnection and make such recommendations and
initiate such actions as may be necessary to maintain reliable
operation of the Interconnection;
xvii) Accept, on behalf of the Members, notices served under this
Agreement;
xviii) Perform those functions and undertake those responsibilities
transferred to it under the Transmission Owners Agreement,
including (A) direct the operation of the transmission
facilities of the parties to the Transmission Owners Agreement,
(B) administer the PJM Tariff, and (C) administer the Regional
Transmission Expansion Planning Protocol set forth as
Schedule 6 to this Agreement.
xix) Perform those functions and undertake those responsibilities
transferred to it under the Reliability Assurance Agreement, as
specified in Schedule 8 of this Agreement.
xx) Monitor the operation of the PJM Control Area, ensure that
appropriate Emergency plans are in place and appropriate
Emergency drills are conducted, declare the existence of an
Emergency, and direct the operations of the Members as
necessary to manage, alleviate or end an Emergency;
xxi) Incorporate the grid reliability requirements applicable to
nuclear generating units in the PJM Control Area planning and
operating principles and practices; and
xxii) Initiate such legal or regulatory proceedings as directed by
the PJM Board to enforce the obligations of this Agreement.
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11. MEMBERS
11.1 Management Rights.
The Members or any of them shall not take part in the management of the
business of, and shall not transact any business for, the LLC in their capacity
as Members, nor shall they have power to sign for or to bind the LLC.
11.2 Other Activities.
Except as otherwise expressly provided herein, any Member may engage in or
possess any interest in another business or venture of any nature and
description, independently or with others, even if such activities compete
directly with the business of the LLC, and neither the LLC nor any Member hereof
shall have any rights in or to any such independent ventures or the income or
profits derived therefrom.
11.3 Member Responsibilities.
11.3.1 General.
To facilitate and provide for the work of the Office of the
Interconnection and of the several committees appointed by the Members
Committee, each Member shall, to the extent applicable;
(a) Maintain adequate records and, subject to the provisions of this
Agreement for the protection of the confidentiality of proprietary or
commercially sensitive information, provide data required for (i) coordination
of operations, (ii) accounting for all interchange transactions, (iii)
preparation of required reports, (iv) coordination of planning, including those
data required for capacity accounting, (v) preparation of maintenance schedules,
(vi) analysis of system disturbances, and (vii) such other purposes, including
those set forth in Schedule 2, as will contribute to the reliable and economic
operation of the Interconnection;
(b) Provide such recording, telemetering, communication and control
facilities as are required for the coordination of its operations with the
Office of the Interconnection and those of the other Members and to enable the
Office of the Interconnection to operate the PJM Control Area and otherwise
implement and administer this Agreement, including equipment required in normal
and Emergency operations and for the recording and analysis of system
disturbances;
(c) Provide adequate and properly trained personnel to (i) permit
participation in the coordinated operation of the Interconnection, (ii) meet its
obligation on a timely basis for supply of records and data, (iii) serve on
committees and participate in their investigations, and (iv) share in the
representation of the Interconnection in inter-regional and national reliability
activities;
(d) Share in the costs of committee activities and investigations
(including costs of consultants, computer time and other appropriate items),
communication facilities used by all the Members (in addition to those provided
in the Office of the Interconnection), and such other expenses as are approved
for payment by the PJM Board, such costs to be recovered as provided in
Schedule 3;
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(e) Comply with the requirements of the PJM Manuals and all
directives of the Office of the Interconnection to take any action for the
purpose of managing, alleviating or ending an Emergency, and authorize the
Office of the Interconnection to direct the transfer or interruption of the
delivery of energy on their behalf to meet an Emergency and to implement
agreements with other Control Areas interconnected with the PJM Control Area for
the mutual provision of service to meet an Emergency, and be subject to the
emergency procedure charges specified in Schedule 9 of this Agreement for any
failure to follow the Emergency instructions of the Office of the
Interconnection.
11.3.2 Facilities Planning and Operation.
Consistent with and subject to the requirements of this Agreement, the
PJM Tariff, the MAAC Agreement, the Reliability Assurance Agreement, the
Transmission Owners Agreement, and the PJM Manuals, each Member shall cooperate
with the other Members in the coordinated planning and operation of the
facilities of its System within the PJM Control Area so as to obtain the
greatest practicable degree of reliability, compatible economy and other
advantages from such coordinated planning and operation. In furtherance of such
cooperation each Member shall, as applicable:
(a) Consult with the other Members and the Office of the
Interconnection, and coordinate the installation of its electric generation and
Transmission Facilities with those of such other Members so as to maintain
reliable service in the PJM Control Area;
(b) Coordinate with the other Members, the Office of the
Interconnection and with others in the planning and operation of the regional
facilities to secure a high level of reliability and continuity of service and
other advantages;
(c) Cooperate with the other Members and the Office of the
Interconnection in the implementation of all policies and procedures established
pursuant to this Agreement for dealing with Emergencies, including but not
limited to policies and procedures for maintaining or arranging for a portion of
a Member's Capacity Resources at least equal to the level established pursuant
to the Reliability Assurance Agreement to have the ability to go from a shutdown
condition to an operating condition and start delivering power without
assistance from the power system;
(d) Cooperate with the members of MAAC to augment the reliability of
the bulk power supply facilities of the region and comply with MAAC and NERC
operating and planning standards, principles and guidelines and the PJM Manuals;
(e) Obtain or arrange for transmission service as appropriate to
carry out this Agreement;
(f) Cooperate with the Office of the Interconnection's coordination
of the operating and maintenance schedules of the Member's generating and
Transmission Facilities with the facilities of other Members to maintain
reliable service to its own customers and those of the other Members and to
obtain economic efficiencies consistent therewith;
(g) Cooperate with the other Members and the Office of the
Interconnection in the analysis, formulation and implementation of plans to
prevent or eliminate conditions that
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impair the reliability of the Interconnection; and
(h) Adopt and apply standards adopted pursuant to this Agreement
and conforming to MAAC and NERC standards, principles and guidelines and the PJM
Manuals, for system design, equipment ratings, operating practices and
maintenance practices.
11.3.3 Electric Distributors.
In addition to any of the foregoing responsibilities that may be
applicable, each Member that is an Electric Distributor, whether or not that
Member votes in the Members Committee in the Electric Distributor sector or
meets the eligibility requirements for any other sector of the Members
Committee, shall:
(a) Accept, comply with or be compatible with all standards
applicable within the PJM Control Area with respect to system design, equipment
ratings, operating practices and maintenance practices as set forth in the PJM
Manuals, or be subject to an interconnected Member's requirements relating to
the foregoing, so that sufficient electrical equipment, control capability,
information and communication are available to the Office of the Interconnection
for planning and operation of the PJM Control Area;
(b) Assure the continued compatibility of its local system energy
management system monitoring and telecommunications systems to satisfy the
technical requirements of interacting automatically or manually with the Office
of the Interconnection as it directs the operation of the PJM Control Area;
(c) Maintain or arrange for a portion of its connected load to be
subject to control by automatic underfrequency, under-voltage, or other load-
shedding devices at least equal to the levels established pursuant to the
Reliability Assurance Agreement, or be subject to another Member's control for
these purposes;
(d) Provide or arrange for sufficient reactive capability and
voltage control facilities to conform to Good Utility Practice and (i) to meet
the reactive requirements of its system and customers and (ii) to maintain
adequate voltage levels and the stability required by the bulk power supply
facilities of the Interconnection;
(e) Shed connected load, share Capacity Resources, initiate active
load management programs, and take such other coordination actions as may be
necessary in accordance with the directions of the Office of the Interconnection
in Emergencies;
(f) Maintain or arrange for a portion of its Capacity Resources at
least equal to the level established pursuant to the Reliability Assurance
Agreement to have the ability to go from a shutdown condition to an operating
condition and start delivering power without assistance from the power system;
(g) Provide or arrange through another Member for the services of
a 24-hour local control center to coordinate with the Office of the
Interconnection, each such control center to be furnished with appropriate
telemetry equipment as specified in the PJM Manuals, and to be staffed by system
operators trained and delegated sufficient authority to take any action
necessary to assure that the system for which the operator is responsible is
operated in a stable and reliable manner;
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(h) Provide to the Office of the Interconnection all System,
accounting, customer tracking, load forecasting and other data necessary or
appropriate to implement or administer this Agreement or the Reliability
Assurance Agreement; and
(i) Comply with the underfrequency relay obligations and charges
specified in Schedule 7 of this Agreement.
11.3.4 Reports to the Office of the Interconnection.
Each Member shall report as promptly as possible to the Office of the
Interconnection any changes in its operating practices and procedures relating
to the reliability of the bulk power supply facilities of the Interconnection.
The Office of the Interconnection shall review such reports, and if any change
in an operating practice or procedure of the Member is not in accord with the
established operating principles, practices and procedures for the
Interconnection and such change adversely affects the Interconnection and
regional reliability, it shall so inform such Member, and the other Members
through their representative on the Operating Committee, and shall direct that
such change be modified to conform to the established operating principles,
practices and procedures.
11.4 Regional Transmission Expansion Planning Protocol.
The Members shall participate in regional transmission expansion planning
in accordance with the Regional Transmission Expansion Planning Protocol set
forth in Schedule 6 to this Agreement.
11.5 Member Right to Petition.
(a) Nothing herein shall deprive any Member of the right to petition FERC
to modify any provision of this Agreement or any Schedule or practice hereunder
that the petitioning Member believes to be unjust, unreasonable, or unduly
discriminatory under Section 206 of the Federal Power Act, subject to the right
of any other Member (a) to oppose said proposal, or (b) to withdraw from the LLC
pursuant to Section 4.1.
(b) Nothing herein shall be construed as affecting in any way the right of
the Members, acting pursuant to a vote of the Members Committee as specified in
Section 8.4, unilaterally to make an application to FERC for a change in any
rate, charge, classification, tariff or service, or any rule or regulation
related thereto, under section 205 of the Federal Power Act and pursuant to the
rules and regulations promulgated by FERC thereunder, subject to the right of
any Member that voted against such change in any rate, charge, classification,
tariff or service, or any rule or regulation related thereto, in intervene in
opposition to any such application.
(c) Nothing in this Agreement shall preclude those Members joining in the
proposal to utilize Locational Marginal Prices to deal with transmission
congestion from (i) filing amendments to the Agreement necessary to implement
the use of Locational Marginal Prices in the PJM Control Area in accordance with
such orders or other directives as may be issued by FERC relating thereto, or
(ii) implementing the provisions of Sections 1.7.21 and 5.2.2(d) of Schedule 1
to this Agreement, without further authorization or approval by the Members
Committee.
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11.6 Membership Requirements.
(a) To qualify as a Member, an entity shall:
i) Be a Transmission Owner within the PJM Control Area or an
Eligible Customer under the PJM Tariff;
ii) If not a Transmission Owner, be a Generation Owner, an Other
Supplier, an Electric Distributor, or an End-Use Consumer;
iii) Be engaged in buying, selling or transmitting electric energy in
or through the Interconnection or have a good faith intent to do
so; and
iv) Accept the obligations set forth in this Agreement.
(b) Certain Members that are Load Serving Entities are parties to the
Reliability Assurance Agreement. Upon becoming a Member, any entity that is a
Load Serving Entity and that wishes to become a Market Buyer shall also
simultaneously execute the Reliability Assurance Agreement.
(c) An entity that wishes to become a party to this Agreement shall apply,
in writing, to the President setting forth its request, its qualifications for
membership, its agreement to supply data as specified in this Agreement, its
agreement to pay all costs and expenses in accordance with Schedule 3, and
providing all information specified pursuant to the Schedules to this Agreement
for entities that wish to become Market Participants. Any such application that
meets all applicable requirements shall be approved by the President within
sixty (60) days.
(d) Nothing in this Section 11 is intended to remove, in any respect, the
choice of participation by other utility companies or organizations in the
operation of the Interconnection through inclusion in the System of a Member.
(e) An entity whose application is accepted by the President pursuant to
Section 11.6(c) shall execute a supplement to this Agreement in substantially
the form prescribed in Schedule 4, which supplement shall be countersigned by
the President and tendered for filing with FERC by the President. The entity
shall become a Member effective on the date specified by FERC when accepting the
supplement for filing.
(f) Entities whose applications contemplate expansion or rearrangement of
the PJM Control Area may become Members promptly as described in Sections
11.6(c) and 11.6(e) above, but the integration of the applicant's system into
all of the operation and accounting provisions of this Agreement and the
Reliability Assurance Agreement shall occur only after completion of all
required installations and modifications of metering, communications, computer
programming, and other necessary and appropriate facilities and procedures, as
determined by the Office of the Interconnection. The Office of the
Interconnection shall notify the other Members when such integration has
occurred.
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12. TRANSFERS OF MEMBERSHIP INTEREST
The rights and obligations created by this Agreement shall inure to and
bind the successors and assigns of such Member; provided, however, that the
rights and obligations of any Member hereunder shall not be assigned without the
approval of the Members Committee except as to a successor in operation of a
Member's electric operating properties by reason of a merger, consolidation,
reorganization, sale, spinoff, or foreclosure, as a result of which
substantially all such electric operating properties are acquired by such a
successor, and such successor becomes a Member.
13. INTERCHANGE
13.1 Interchange Arrangements with Non-Members.
Any Member may enter into interchange arrangements with others who are not
Members with respect to the delivery or receipt of capacity and energy to
fulfill its obligations hereunder or for any other purpose, subject to the
standards and requirements established in or pursuant to this Agreement.
13.2 Energy Market.
The Office of the Interconnection shall administer an efficient energy
market within the Interconnection, to be known as the PJM Interchange Energy
Market, in which Members may buy and sell energy. The Office of the
Interconnection will schedule in advance and dispatch generation on the basis of
least-cost, security-constrained dispatch and the prices and operating
characteristics offered by sellers within and into the Interconnection,
continuing until sufficient generation is dispatched to serve the energy
purchase requirements of the Interconnection and buyers out of the
Interconnection, as well as the requirements of the Interconnection for
ancillary services provided by such generation. Scheduling and dispatch shall be
conducted in accordance with applicable schedules to the PJM Tariff and the
Schedules to this Agreement.
14. METERING
14.1 Installation, Maintenance and Reading of Meters.
The quantities of electric energy involved in determination of the amounts
of the billing rendered hereunder shall be ascertained by means of meters
installed, maintained and read either at the expense of the party on whose
premises the meters are located or as otherwise provided for by agreement
between the parties concerned.
14.2 Metering Procedures.
Procedures with respect to maintenance, testing, calibrating, correction
and registration records, and precision tolerance of all metering equipment
shall be in accordance with Good Utility Practice. The expense of testing any
meter shall be borne by the party owning such meter, except that when a meter
tested upon request of another party is found to register within the established
tolerance the party making the request shall bear the expense of such test.
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14.3 Integrated Megawatt-Hours
All metering of energy required herein shall be the integration of megawatt
hours in the clock hour, and the quantities thus obtained shall constitute the
megawatt load for such clock hour; provided, however, that adjustment shall be
made for other contractual obligations of any Member as may be required to
determine the quantity to be accounted for hereunder, and for transmission
losses.
14.4 Meter Locations.
The meter locations to be used by the Members in determining their energy
transactions on the Interconnection shall be as reasonably determined from time
to time by the Member or the Office of the Interconnection.
15. ENFORCEMENT OF OBLIGATIONS
15.1 Failure to Meet Obligations.
15.1.1 Termination of Market Buyer Rights.
The Office of the Interconnection shall terminate a Market Buyer's
right to make purchases from the PJM Interchange Energy Market and PJM Capacity
Credit Market if it determines that the Market Buyer does not continue to meet
the obligations set forth in this Agreement, provided that the Office of the
Interconnection has notified the Market Buyer of any such deficiency and
afforded the Market Buyer a reasonable opportunity to cure it. The Office of the
Interconnection shall reinstate a Market Buyer's right to make purchases from
the PJM Interchange Energy Market and PJM Capacity Credit Market upon
demonstration by the Market Buyer that it has come into compliance with the
obligations set forth in this Agreement.
15.1.2 Termination of Market Seller Rights.
The Office of the Interconnection shall not accept offers from a
Market Seller that has not complied with the prices, terms, or operating
characteristics of any of its prior scheduled transactions in the PJM
Interchange Energy Market, unless such Market Seller has taken appropriate
measures to the satisfaction of the Office of the Interconnection to ensure
future compliance.
Revised: January 29, 1999
Effective: March 31, 1999
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15.1.3 Payment of Bills.
(a) A Member shall make full and timely payment, in accordance with
the terms specified by the Office of the Interconnection, of all bills rendered
in connection with or arising under or from this Agreement, any service or rate
schedule, any tariff, or any services performed by the Office of the
Interconnection, notwithstanding any disputed amount, but any such payment shall
not be deemed a waiver of any right with respect to such dispute. With respect
to any payment that the LLC is required to make to a Member in connection with
or arising under this Agreement, any service or rate schedule, or any tariff,
the LLC shall have a right of setoff equal to any amount that the Member is
required to pay the LLC in connection with or arising under or from this
Agreement, any service or rate schedule, any tariff, or any services performed
by the Office of the Interconnection. Any Member that fails to make full and
timely payment to the LLC, or otherwise fails to meet its financial or other
obligations to a Member, the Office of the Interconnection or the LLC under this
Agreement, shall upon expiration of the 10 day period specified below be in
default. If the Office of the Interconnection concludes, upon its own initiative
or the recommendation of or complaint by the Members Committee or any Member,
that a Member is in breach of any obligation under this Agreement, the Office of
the Interconnection shall so notify such Member and inform all other Members.
The notified Member may remedy such asserted breach by: (i) paying all amounts
assertedly due, along with interest on such amounts calculated in accordance
with the methodology specified for interest on refunds in FERC's regulations at
18 C.F.R. (S) 35.19a(a)(2)(iii); and (ii) demonstration to the satisfaction of
the Office of the Interconnection that the Member has taken appropriate measures
to meet any other obligation of which it was deemed to be in breach; provided,
however, that any such payment or demonstration may be subject to a reservation
of rights, if any, to subject such matter to the PJM Dispute Resolution
Procedures; and provided, further, that any such determination by the Office of
the Interconnection may be subject to review by the PJM Board upon request of
the Member involved or the Office of the Interconnection. If a Member has not
remedied a breach by the 10th business day following receipt of the Office of
the Interconnection's notice, or receipt of the PJM Board's decision on review,
if applicable, then the Member shall be in default and, in addition to such
other remedies as may be available to the LLC:
i) A defaulting Market Participant shall be precluded from buying or
selling energy in the PJM Interchange Energy Market until the
default is remedied as set forth above.
ii) A defaulting Member shall not be entitled to participate in the
activities of any committee or other body established by the
Members Committee or the Office of the Interconnection.
iii) A defaulting Member shall not be entitled to vote on the Members
Committee or any other committee or other body established
pursuant to this Agreement.
Revised: January 29, 1999
Effective: March 31, 1999
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15.2 Enforcement of Obligations.
If the Office of the Interconnection sends a notice to the PJM Board that a
Member has failed to perform an obligation under this Agreement, the PJM Board
shall initiate such action against such Member to enforce such obligation as the
PJM Board shall deem appropriate. Subject to the procedures specified in Section
15.1, a Member's failure to perform such obligation shall be deemed to be a
default under this Agreement. In order to remedy a default, but without limiting
any rights the LLC may have against the defaulting Member, the PJM Board may
assess against, and collect from, the Members not in default, in proportion to
their Weighted Interest, an amount equal to the amount that the defaulting
Member has failed to pay to the Office of the Interconnection, along with
appropriate interest, but such assessment shall in no way relieve the defaulting
Member of its obligations, and shall confer upon the Members Committee the right
to recover the assessed amounts from the defaulting Member. In addition to any
amounts in default, the defaulting Member shall be liable to the LCC for
reasonable costs incurred in enforcing the defaulting Member's obligations.
15.3 Obligations to a Member in Default.
The Members have no continuing obligation to provide the benefits of
interconnected operations to a Member in default.
15.4 Obligations of a Member in Default.
A Member found to be in default shall take all possible measures to
mitigate the continued impact of the default on the Members not in default,
including, but not limited to, loading its own generation to supply its own load
to the maximum extent possible.
15.5 No Implied Waiver.
A failure of a Member, the PJM Board, or the LLC to insist upon or enforce
strict performance of any of the provisions of this Agreement shall not be
construed as a waiver or relinquishment to any extent of such entity's right to
assert or rely upon any such provisions, rights and remedies in that or any
other instance; rather, the same shall be and remain in full force and effect.
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16. LIABILITY AND INDEMNITY
16.1 Members.
(a) As between the Members, except as may be otherwise agreed upon between
individual Members with respect to specified interconnections, each Member will
indemnify and hold harmless each of the other Members, and its directors,
officers, employees, agents, or representatives, of and from any and all
damages, losses, claims, demands, suits, recoveries, costs and expenses
(including all court costs and reasonable attorneys' fees), caused by reason of
bodily injury, death or damage to property of any third party, resulting from or
attributable to the fault, negligence or willful misconduct of such Member, its
directors, officers, employees, agents, or representatives, or resulting from,
arising out of, or in any way connected with the performance of its obligations
under this Agreement, excepting only, and to the extent, such cost, expense,
damage, liability or loss may be caused by the fault, negligence or willful
misconduct of any other Member. The duty to indemnify under this Agreement will
continue in full force and effect notwithstanding the expiration or termination
of this Agreement or the withdrawal of a Member from this Agreement, with
respect to any loss, liability, damage or other expense based on facts or
conditions which occurred prior to such termination or withdrawal.
(b) The amount of any indemnity payment arising hereunder shall be reduced
(including, without limitation, retroactively) by any insurance proceeds or
other amounts actually recovered by the Member seeking indemnification in
respect of the indemnified action, claim, demand, costs, damage or liability. If
any Member shall have received an indemnity payment for an action, claim,
demand, cost, damage or liability and shall subsequently actually receive
insurance proceeds or other amounts for such action, claim, demand, cost, damage
or liability, then such Member shall pay to the Member that made such indemnity
payment the lesser of the amount of such insurance proceeds or other amounts
actually received and retained or the net amount of the indemnity payments
actually received previously.
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16.2 LLC Indemnified Parties.
(a) The LLC will indemnify and hold harmless the PJM Board, the LLC's
officers, employees and agents, and any representatives of the Members serving
on the Members Committee and any other committee created under Section 8 of this
Agreement (all such Board Members, officers, employees, agents and
representatives for purposes of this Section 16 being referred to as "LLC
Indemnified Parties"), of and from any and all actions, claims, demands, costs
(including consequential or indirect damages, economic losses and all court
costs and reasonable attorneys' fees) and liabilities to any third parties,
arising from, or in any way connected with, the performance of the LLC under
this Agreement, or the fact that such LLC Indemnified Party was serving in such
capacity, except to the extent that such action, claim, demand, cost or
liability results from the willful misconduct of any LLC Indemnified Party with
respect to participation in the misconduct. To the extent any dispute arises
between any Member and the LLC arising from, or in any way connected with, the
performance of the LLC under this Agreement, the Member and the LLC shall follow
the PJM Dispute Resolution Procedures. To the extent that any such action,
claim, demand, cost or liability arises from a Member's contractual or other
obligation to provide electric service directly or indirectly to said third
party, which obligation to provide service is limited by the terms of any
tariff, service agreement, franchise, statute, regulatory requirement, court
decision or other limiting provision, the Member designates the LLC and each LLC
Indemnified Party a beneficiary of said limitation.
(b) An LLC Indemnified Party shall not be personally liable for monetary
damages for any breach of fiduciary duty by such LLC Indemnified Party, except
that an LLC Indemnified Party shall be liable to the extent provided by
applicable law (i) for acts or omissions not in good faith or that involve
intentional misconduct or a knowing violation of law, or (ii) for any
transaction from which the LLC Indemnified Party derived an improper personal
benefit. Notwithstanding (i) and (ii), indemnification shall be made in respect
of any claim, issue or matter as to which such person shall have been adjudged
to be liable to the LLC if and to the extent that the court in which such action
or suit was brought shall determine upon application that, despite the
adjudication of liability but in view of all the circumstances of the case, such
person is fairly and reasonably entitled to indemnity for such expenses which
such court shall deem proper. If applicable law is hereafter construed or
amended to authorize the further elimination or limitation of the liability of
LLC Indemnified Parties, then the liability of the LLC Indemnified Parties, in
addition to the limitation on personal liability provided herein, shall be
limited to the fullest extent permitted by law. No amendment to or repeal of
this section shall apply to or have any effect on the liability or alleged
liability of any LLC Indemnified Party or with respect to any acts or omissions
occurring prior to such amendment or repeal. The termination of any action, suit
or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo
contendere or its equivalent, shall not, of itself, create a presumption that
the person did not act in good faith and in a manner which such person
reasonably believed to be in or not opposed to the best interests of the LLC,
and with respect to any criminal action or proceeding, had reasonable cause to
believe that his or her conduct was unlawful.
(c) The LLC may pay expenses incurred by an LLC Indemnified Party in
defending a civil, criminal, administrative or investigative action, suit or
proceeding in advance of the final disposition of such action, suit or
proceeding upon receipt of an undertaking by or on behalf of
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such LLC Indemnified Party to repay such amount if it shall ultimately be
determined that such LLC Indemnified Party is not entitled to be indemnified by
the LLC as authorized in this Section.
(d) In the event the LLC incurs liability under this Section 16.2 that is
not adequately covered by insurance, such amounts shall be recovered pursuant to
the PJM Tariff as provided in Schedule 3 of this Agreement.
16.3 Worker' Compensation Claims.
Each Member shall be solely responsible for all claims of its own
employees, agents and servants growing out of any Worker's Compensation Law.
16.4 Limitation of Liability.
No Member or its directors, officers, employees, agents, or representatives
shall be liable to any other Member or its directors, officers, employees,
agents, or representatives, whether liability arises out of contract, tort
(including negligence), strict liability, or any other cause of or form of
action whatsoever, for any indirect, incidental, consequential, special or
punitive cost, expense, damage or loss, including but not limited to loss of
profits or revenues, cost of capital of financing, loss of goodwill or cost of
replacement power, arising from such Member's performance or failure to perform
any of its obligations under this Agreement or the ownership, maintenance or
operation of its System; provided, however, that nothing herein shall be deemed
to reduce or limit the obligations of any Member with respect to the claims of
persons or entities that are not parties to this Agreement.
16.5 Resolution of Disputes.
To the extent any dispute arises between one or more Members regarding any
issue covered by this Agreement, the Members shall follow the dispute resolution
procedures set forth in the PJM Dispute Resolution Procedures.
16.6 Gross Negligence or Willful Misconduct.
Neither the LLC nor the LLC Indemnified Parties shall be liable to the
Members or any of them for any claims, demands or costs arising from, or in any
way connected with, the performance of the LLC under this Agreement other than
actions, claims or demands based on gross negligence or willful misconduct;
provided, however, that nothing herein shall limit or reduce the obligations of
the LLC to the Members or any of them under the express terms of this Agreement
or the PJM Tariff, including, but not limited to, those set forth in Sections
6.2 and 6.3 of this Agreement.
16.7 Insurance.
The PJM Board shall be authorized to procure insurance against the risks
borne by the LLC and the LLC Indemnified Parties, the cost of which shall be
treated as a cost and expense of the LLC.
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17. MEMBER REPRESENTATIONS, WARRANTIES AND COVENANTS
17.1 Representations and Warranties.
Each Member makes the following representations and warranties to the LLC
and each other Member, as of the Effective Date or such later date as such
Member shall become admitted as a Member of the LLC.
17.1.1 Organization and Existence.
Such Member is an entity duly organized, validly existing and in
good standing under the laws of the state of its organization.
17.1.2 Power and Authority.
Such Member has the full power and authority to execute, deliver and
perform this Agreement and to carry out the transactions contemplated hereby.
17.1.3 Authorization and Enforceability.
The execution and delivery of this Agreement by such Member and the
performance of its obligations hereunder have been duly authorized by all
requisite action on the part of the Member, and do not conflict with any
applicable law or with any other agreement binding upon the Member. The
Agreement has been duly executed and delivered by such Member and constitutes
the legal, valid and binding obligation of such Member, enforceable against it
in accordance with the terms thereof, except insofar as such enforceability may
be limited by applicable bankruptcy, insolvency, reorganization, fraudulent
conveyance, moratorium or other similar laws affecting the enforcement of
creditors' rights generally, and to general principles of equity whether such
principles are considered in proceedings in law or in equity.
17.1.4 No Government Consents.
No authorization, consent, approval or order of, notice to or
registration, qualification, declaration or filing with, any governmental
authority is required for the execution, delivery and performance by such Member
of this Agreement or the carrying out by such Member of the transactions
contemplated hereby other than such authorization, consent, approval or order
of, notice to or registration, qualification, declaration or filing that is
pending before such governmental authority.
17.1.5 No Conflict or Breach.
None of the execution, delivery and performance by such Member of
this Agreement, the compliance with the terms and provisions hereof and the
carrying out of the transactions contemplated hereby, conflicts or will conflict
with or will result in a breach or violation of any of the terms, conditions or
provisions of any law, governmental rule or regulation or the charter documents
or bylaws of such Member or any applicable order, writ, injunction, judgment or
decree of any court or governmental authority against such Member or by which it
or any of its properties, is bound, or any loan agreement, indenture, mortgage,
bond, note, resolution, contract or other agreement or instrument to which such
Member is a party or by which it or any of its properties is bound, or
constitutes or will constitute a default thereunder or will result in the
imposition of any lien upon any of its properties.
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17.1.6 No Proceedings.
There are no actions at law, suits in equity, proceedings or claims
pending or, to the knowledge of the Member, threatened against the Member before
any federal, state, foreign or local court, tribunal or government agency or
authority that might materially delay, prevent or hinder the performance by the
Member of its obligations hereunder.
17.2 Municipal Electric Systems.
Any provisions of Section 17.1 notwithstanding, if any Member that is a
municipal electric system believes in good faith that the provisions of Sections
5.1(b) and 16.1 of this Agreement may not lawfully be applied to that Member
under applicable state law governing municipal activities, the Member may
request a waiver of the pertinent provisions of the Agreement. Any such request
for waiver shall be supported by an opinion of counsel for the Member to the
effect that the provision of the Agreement as to which waiver is sought may not
lawfully be applied to the Member under applicable state law. The PJM Board
shall have the right to have the opinion of the Member's counsel reviewed by
counsel to the LLC. If the PJM Board concludes that either or both of Sections
5.1(b) and 16.1 of this Agreement may not lawfully be applied to a municipal
electric system Member, it shall waive the application of the affected provision
or provisions to such municipal Member. Any Member not permitted by law to
indemnify the other Members shall not be indemnified by the other Members.
17.3 Survival.
All representations and warranties contained in this Section 17 shall
survive the execution and delivery of this Agreement.
18. MISCELLANEOUS PROVISIONS
18.1 [Reserved.]
18.2 Fiscal and Taxable Year.
The fiscal year and taxable year of the LLC shall be the calendar year.
18.3 Reports.
Each year prior to the Annual Meeting of the Members, the PJM Board shall
cause to be prepared and distributed to the Members a report of the LLC's
activities since the prior report.
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18.4 Bank Accounts; Checks, Notes and Drafts.
(a) Funds of the LLC shall be deposited in an account or accounts of a
type, in form and name and in a bank(s) or other financial institution(s) which
are participants in federal insurance programs as selected by the PJM Board.
The PJM Board shall arrange for the appropriate conduct of such accounts. Funds
may be withdrawn from such accounts only for bona fide and legitimate LLC
purposes and may from time to time be invested in such short-term securities,
money market funds, certificates of deposit or other liquid assets as the PJM
Board deems appropriate. All checks or demands for money and notes of the LLC
shall be signed by any officer or by any other person designated by the PJM
Board.
(b) The Members acknowledge that the PJM Board may maintain LLC funds in
accounts, money market funds, certificates of deposit, other liquid assets in
excess of the insurance provided by the Federal Deposit Insurance Corporation,
or other depository insurance institutions and that the PJM Board shall not be
accountable or liable for any loss of such funds resulting from failure or
insolvency of the depository institution.
(c) Checks, notes, drafts and other orders for the payment of money shall
be signed by such persons as the PJM Board from time to time may authorize.
When the PJM Board so authorizes, the signature of any such person may be a
facsimile.
18.5 Books and Records.
(a) At all times during the term of the LLC, the PJM Board shall keep, or
cause to be kept, full and accurate books of account, records and supporting
documents, which shall reflect, completely, accurately and in reasonable detail,
each transaction of the LLC. The books of account shall be maintained and tax
returns prepared and filed on the method of accounting determined by the PJM
Board. The books of account, records and all documents and other writings of the
LLC shall be kept and maintained at the principal office of the Interconnection.
(b) The PJM Board shall cause the Office of the Interconnection to keep at
its principal office the following:
i) A current list in alphabetical order of the full name and last
known business address of each Member, the Weighted Interest of
each Member, and the Members Committee sector of each Voting
Member;
ii) A copy of the Certificate of Formation and the Certificate of
Conversion, and all Certificates of Amendment thereto;
iii) Copies of the LLC's federal, state, and local income tax returns
and reports, if any, for the three most recent years; and
iv) Copies of the Operating Agreement, as amended, and of any
financial statements of the LLC for the three most recent years.
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18.6 Amendment.
(a) Except as provided by law or otherwise set forth herein, this
Agreement, including any Schedule hereto, may be amended, or a new Schedule may
be created, only upon: (i) submission of the proposed amendment to the PJM Board
for its review and comments; (ii) approval of the amendment or new Schedule by
the Members Committee, after consideration of the comments of the PJM Board, in
accordance with Section 8.4, or written agreement to an amendment of all Members
not in default at the time the amendment is agreed upon; and (iii) approval
and/or acceptance for filing of the amendment by FERC and any other regulatory
body with jurisdiction thereof as may be required by law. If and as necessary,
the Members Committee may file with FERC or other regulatory body of competent
jurisdiction any amendment to this Agreement or to its Schedules or a new
Schedule not filed by the Office of the Interconnection.
(b) Notwithstanding the foregoing, an applicant eligible to become a
Member in accordance with the procedures specified in this Agreement shall
become a Member by executing a counterpart of this Agreement without the need
for amendment of this Agreement or execution of such counterpart by any other
Member.
(c) Each of the following fundamental changes to the LLC shall require or
be deemed to require an amendment to this Agreement and shall require the prior
approval of FERC:
i) Adoption of any plan of merger or consolidation;
ii) Adoption of any plan of sale, lease or exchange of assets
relating to all, or substantially all, of the property and assets
of the LLC;
iii) Adoption of any plan of division relating to the division of the
LLC into two or more corporations or other legal entities;
iv) Adoption of any plan relating to the conversion of the LLC into a
stock corporation;
v) Adoption of any proposal of voluntary dissolution; or
vi) Taking any action which has the purpose or effect of the adoption
of any plan or proposal described in items (i), (ii), (iii), (iv)
or (v) above.
18.7 Interpretation.
Wherever the context may require, any noun or pronoun used herein shall
include the corresponding masculine, feminine or neuter forms. The singular
form of nouns, pronouns and verbs shall include the plural and vice versa.
18.8 Severability.
Each provision of this Agreement shall be considered severable and if for
any reason any provision is determined by a court or regulatory authority of
competent jurisdiction to be invalid, void or unenforceable, the remaining
provisions of this Agreement shall continue in full force and effect and shall
in no way be affected, impaired or invalidated, and such invalid, void or
unenforceable provision shall be replaced with valid and enforceable provision
or provisions which otherwise give effect to the original intent of the invalid,
void or unenforceable provision.
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18.9 Force Majeure.
No Member shall be liable to any other Member for damages or otherwise be
in breach of this Agreement to the extent and during the period such Member's
performance is prevented by any cause or causes beyond such Member's control and
without such Member's fault or negligence, including but not limited to any act,
omission, or circumstance occasioned by or in consequence of any act of God,
labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm
or flood, explosion, breakage or accident to machinery or equipment, or
curtailment, order, regulation or restriction imposed by governmental, military
or lawfully established civilian authorities; provided, however, that any such
foregoing event shall not excuse any payment obligation. Upon the occurrence of
an event considered by a Member to constitute a force majeure event, such Member
shall use due diligence to endeavor to continue to perform its obligations as
far as reasonably practicable and to remedy the event, provided that no Member
shall be required by this provision to settle any strike or labor dispute.
18.10 Further Assurances.
Each Member hereby agrees that it shall hereafter execute and deliver such
further instruments, provide all information and take or forbear such further
acts and things as may be reasonably required or useful to carry out the intent
and purpose of this Agreement and as are not inconsistent with the terms hereof.
18.11 Seal.
The seal of the LLC shall have inscribed thereon the name of the LLC, the
year of its organization and the words "Corporate Seal, Delaware." The seal may
be used by causing it or a facsimile thereof to be impressed or affixed or
reproduced or otherwise.
18.12 Counterparts.
This Agreement may be executed in any number of counterparts, each of which
shall be an original but all of which together will constitute one instrument,
binding upon all parties hereto, notwithstanding that all of such parties may
not have executed the same counterpart.
18.13 Costs of Meetings.
Each Member shall be responsible for all costs of its representative,
alternate or substitute in attending any meeting. The Office of the
Interconnection shall pay the other reasonable costs of meetings of the PJM
Board and the Members Committee, and such other committees, subcommittees, task
forces, working groups, User Groups or other bodies as determined to be
appropriate by the Office of the Interconnection, which costs otherwise shall be
paid by the Members attending. The Office of the Interconnection shall
reimburse all Board Members for their reasonable costs of attending meetings.
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18.14 Notice.
(a) Except as otherwise expressly provided herein, notices required
under this Agreement shall be in writing and shall be sent to a Member by
overnight courier, hand delivery, telecopier or other reliable electronic means
to the representative on the Members Committee of such Member at the address for
such Member previously provided by such Member to the other Members or as
otherwise directed by the Members Committee. Any such notice so sent shall be
deemed to have been given (i) upon delivery if given by overnight couriers or
hand delivery, or (ii) upon confirmation if given by telecopier or other
reliable electronic means.
(b) Notices, as well as copies of the agenda and minutes of all meetings
of committees, subcommittees, task forces, working groups, User Groups, or other
bodies formed under this Agreement, shall be posted in a timely fashion on and
made available for downloading from the PJM website.
18.15 Headings.
The section headings used in this Agreement are for convenience only and
shall not affect the construction or interpretation of any of the provisions of
this Agreement.
18.16 No Third-Party Beneficiaries.
This Agreement is intended to be solely for the benefit of the Members and
their respective successors and permitted assigns and, unless expressly stated
herein, is not intended to and shall not confer any rights or benefits on any
third party (other than successors and permitted assigns) not a signatory
hereto.
18.17 Confidentiality.
18.17.1 Party Access.
No Member shall have a right hereunder to receive or review any
documents, data or other information of another Member, including documents,
data or other information provided to the Office of the Interconnection, to the
extent such documents, data or information have been designated as confidential
pursuant to the procedures adopted by the Office of the Interconnection or to
the extent that they have been designated as confidential by such other Member;
provided, however, a Member may receive and review any composite documents, data
and other information that may be developed based on such confidential
documents, data or information if the composite does not disclose any individual
Member's confidential data or information.
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18.17.2 Required Disclosure.
(a) Notwithstanding anything in the foregoing Section to the
contrary, if a Member or the Office of the Interconnection is required by
applicable law, or in the course of administrative or judicial proceedings, to
disclose information that is otherwise required to be maintained in confidence
pursuant to this Agreement, that Member or the Office of the Interconnection may
make disclosure of such information; provided, however, that as soon as the
Member or the Office of the Interconnection learns of the disclosure requirement
and prior to making disclosure, that Member or the Office of the Interconnection
shall notify the affected Member or Members of the requirement and the terms
thereof and the affected Member or Members may direct, at their sole discretion
and cost, any challenge to or defense against the disclosure requirement. The
disclosing Member and the Office of the Interconnection shall cooperate with
such affected Members to the maximum extent practicable to minimize the
disclosure of the information consistent with applicable law. Each Member and
the Office of the Interconnection shall cooperate with the affected Members to
obtain proprietary or confidential treatment of such information by the person
to whom such information is disclosed prior to any such disclosure.
(b) The Office of the Interconnection shall endeavor to impose on
any contractors retained to provide technical support or otherwise to assist
with the implementation or administration of this Agreement a contractual duty
of confidentiality consistent with this Agreement. A Member shall not be
obligated to provide confidential or proprietary information to any contractor
that does not assume such a duty of confidentiality, and the Office of the
Interconnection shall not provide any such information to any such contractor
without the express written permission of the Member providing the information.
18.18 Termination and Withdrawal.
18.18.1 Termination.
Upon termination of this Agreement, final settlement for obligations
under this Agreement shall include the accounting for the period ending with the
last day of the last month for which the Agreement was effective.
18.18.2 Withdrawal.
Subject to the requirements of Section 4.1(c) of this Agreement and
Section 1.4.6 of the Schedule 1 to this Agreement, any Member may withdraw from
this Agreement upon 90 days notice to the Office of the Interconnection.
43
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18.18.3 Winding Up.
Any provision of this Agreement that expressly or by implication comes
into or remains in force following the termination or expiration of this
Agreement shall survive such termination or expiration. The surviving provisions
shall include, but shall not be limited to: (i) those provisions necessary to
permit the orderly conclusion, or continuation pursuant to another agreement, of
transactions entered into prior to the decision to terminate this Agreement,
(ii) those provisions necessary to conduct final billing, collection, and
accounting with respect to all matters arising hereunder, and (iii) the
indemnification provisions as applicable to periods prior to such termination or
expiration.
IN WITNESS whereof, the Members have caused this Agreement to be executed by
their duly authorized representatives.
44
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SCHEDULE 1
----------
PJM INTERCHANGE ENERGY MARKET
-----------------------------
(Revises and replaces former Schedules 7.01 and 7.03)
Issued: June 2, 1997
Effective: April 1, 1998
1. MARKET OPERATIONS
1.1 Introduction.
This Schedule sets forth the scheduling, other procedures, and certain
general provisions applicable to the operation of the PJM Interchange Energy
Market within the PJM Control Area. This Schedule addresses each of the three
time-frames pertinent to the daily operation of the PJM Interchange Energy
Market: Prescheduling, Scheduling, and Dispatch.
1.2 Cost-based Offers.
Unless and until the FERC shall authorize the use of market-based prices in
the PJM Interchange Energy Market, all offers for energy or other services to be
sold on the PJM Interchange Energy Market from generating resources located
within the PJM Control Area shall not exceed the variable cost of producing such
energy or other service, as determined in accordance with Schedule 2 to this
Agreement and applicable regulatory standards, requirements and determinations;
provided that, a Market Seller may offer to the PJM Interchange Energy Market
the right to call on energy from a resource the output of which has been sold on
a bilateral basis, with the rate for such energy if called equal to the
curtailment rate specified in the bilateral contract.
1.3 Definitions.
1.3.1 Dispatch Rate.
"Dispatch Rate" shall mean the control signal, expressed in dollars
per megawatt-hour, calculated and transmitted continuously and dynamically to
direct the output level of all generation resources dispatched by the Office of
the Interconnection in accordance with the Offer Data.
1.3.2 Equivalent Load.
"Equivalent Load" shall mean the sum of a Market Participant's net
system requirements to serve its customer load in the PJM Control Area, if any,
plus its net bilateral transactions.
1.3.3 External Market Buyer.
"External Market Buyer" shall mean a Market Buyer making purchases of
energy from the PJM Interchange Energy Market for consumption by end-users
outside the PJM Control Area, or for load in the Control Area that is not served
by Network Transmission Service.
Revised: June 26, 1998
Effective: September 17, 1998
<PAGE>
1.3.4 External Resource.
"External Resource" shall mean a generation resource located outside
the metered boundaries of the PJM Control Area.
1.3.5 Fixed Transmission Right.
"Fixed Transmission Right" shall mean a right to receive Transmission
Congestion Credits as specified in Section 5.2.2 of this Schedule.
1.3.6 Generating Market Buyer.
"Generating Market Buyer" shall mean an Internal Market Buyer that is
a Load Serving Entity that owns or has contractual rights to the output of
generation resources capable of serving the Market Buyer's load in the PJM
Control Area, or of selling energy or related services in the PJM Interchange
Energy Market or elsewhere.
1.3.7 Generator Forced Outage.
"Generator Forced Outage" shall mean an immediate reduction in output
or capacity or removal from service, in whole or in part, of a generating unit
by reason of an Emergency or threatened Emergency, unanticipated failure, or
other cause beyond the control of the owner or operator of the facility, as
specified in the relevant portions of the PJM Manuals. A reduction in output or
removal from service of a generating unit in response to changes in market
conditions shall not constitute a Generator Forced Outage.
1.3.8 Generator Maintenance Outage.
"Generator Maintenance Outage" shall mean the scheduled removal from
service, in whole or in part, of a generating unit in order to perform necessary
repairs on specific components of the facility, if removal of the facility meets
the guidelines specified in the PJM Manuals.
1.3.9 Generator Planned Outage.
"Generator Planned Outage" shall mean the scheduled removal from
service, in whole or in part, of a generating unit for inspection, maintenance
or repair with the approval of the Office of the Interconnection in accordance
with the PJM Manuals.
1.3.10 Internal Market Buyer.
"Internal Market Buyer" shall mean a Market Buyer making purchases of
energy from the PJM Interchange Energy Market for ultimate consumption by end-
users inside the PJM Control Area that are served by Network Transmission
Service.
1.3.11 Inadvertent Interchange.
"Inadvertent Interchange" shall mean the difference between net actual
energy flow and net scheduled energy flow into or out of the PJM Control Area,
as determined and allocated each hour by the Office of the Interconnection in
accordance with the procedures set forth in the PJM Manuals to each Electric
Distributor that reports to the Office of the Interconnection its hourly net
energy flows from metered tie lines.
Third Revised: March 2, 1999
Effective: April 13, 1999
2
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1.3.12 Market Operations Center.
"Market Operations Center" shall mean the equipment, facilities and
personnel used by or on behalf of a Market Participant to communicate and
coordinate with the Office of the Interconnection in connection with
transactions in the PJM Interchange Energy Market or the operation of the PJM
Control Area.
1.3.13 Maximum Generation Emergency.
"Maximum Generation Emergency" shall mean an Emergency declared by the
Office of the Interconnection in which the Office of the Interconnection
anticipates requesting one or more Capacity Resources to operate at its maximum
net or gross electrical power output, subject to the equipment stress limits for
such Capacity Resource, in order to manage, alleviate, or end the Emergency.
1.3.14 Minimum Generation Emergency.
"Minimum Generation Emergency" shall mean an Emergency declared by the
Office of the Interconnection in which the Office of the Interconnection
anticipates requesting one or more generating resources to operate at or below
Normal Minimum Generation, in order to manage, alleviate, or end the Emergency.
1.3.14a NERC Interchange Distribution Calculator.
"NERC Interchange Distribution Calculator" shall mean the NERC
mechanism that is in effect and being used to calculate the distribution of
energy, over specific transmission interfaces, from energy transactions.
1.3.15 Network Resource.
"Network Resource" shall have the meaning specified in the PJM Tariff.
1.3.16 Network Service User.
"Network Service User" shall mean an entity using Network Transmission
Service.
1.3.17 Network Transmission Service.
"Network Transmission Service" shall mean transmission service
provided pursuant to the rates, terms and conditions set forth in Part III of
the PJM Tariff, or transmission service comparable to such service that is
provided to a Load Serving Entity that is also a Regional Transmission Owner as
that term is defined in the PJM Tariff.
1.3.18 Normal Maximum Generation.
"Normal Maximum Generation" shall mean the highest output level of a
generating resource under normal operating conditions.
1.3.19 Normal Minimum Generation.
"Normal Minimum Generation" shall mean the lowest output level of a
generating resource under normal operating conditions.
Revised: November 19, 1998
Effective: January 19, 1999
3
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1.3.20 Offer Data.
"Offer Data" shall mean the scheduling, operations planning, dispatch,
new resource, and other data and information necessary to schedule and dispatch
generation resources for the provision of energy and other services and the
maintenance of the reliability and security of the transmission system in the
PJM Control Area, and specified for submission to the PJM Interchange Energy
Market for such purposes by the Office of the Interconnection.
Revised: November 19, 1998
Effective: January 19, 1999
3a
<PAGE>
1.3.21 Office of the Interconnection Control Center.
"Office of the Interconnection Control Center" shall mean the
equipment, facilities and personnel used by the Office of the Interconnection to
coordinate and direct the operation of the PJM Control Area and to administer
the PJM Interchange Energy Market, including facilities and equipment used to
communicate and coordinate with the Market Participants in connection with
transactions in the PJM Interchange Energy Market or the operation of the PJM
Control Area.
1.3.22 Operating Day.
"Operating Day" shall mean the daily 24 hour period beginning at
midnight for which transactions on the PJM Interchange Energy Market are
scheduled.
1.3.23 Operating Margin.
"Operating Margin" shall mean the incremental adjustments, measured in
megawatts, required in PJM Control Area operations in order to accommodate, on a
first contingency basis, an operating contingency in the PJM Control Area
resulting from operations in an interconnected Control Area. Such adjustments
may result in constraints causing Transmission Congestion Charges, or may result
in Ancillary Services charges pursuant to the PJM Tariff.
1.3.24 Operating Margin Customer.
"Operating Margin Customer" shall mean a Control Area purchasing
Operating Margin pursuant to an agreement between such other Control Area and
the LLC.
1.3.25 PJM Interchange.
"PJM Interchange" shall mean the following, as determined in
accordance with the Schedules to this Agreement: (a) for a Market Participant
that is a Network Service User, the amount by which its hourly Equivalent Load
exceeds, or is exceeded by, the sum of the hourly outputs of its operating
generating resources; or (b) for a Market Participant that is not a Network
Service User, the amount of its Spot Market Backup; or (c) the hourly scheduled
deliveries of Spot Market Energy by a Market Seller from an External Resource;
or (d) the hourly net metered output of any other Market Seller; or (e) the
hourly scheduled deliveries of Spot Market Energy to an External Market Buyer;
or (f) the hourly scheduled deliveries to an Internal Market Buyer that is not a
Network Service User.
1.3.26 PJM Interchange Export.
"PJM Interchange Export" shall mean the following, as determined in
accordance with the Schedules to this Agreement: (a) for a Market Participant
that is a Network Service User, the amount by which its hourly Equivalent Load
is exceeded by the sum of the hourly outputs of its operating generating
resources; or (b) for a Market Participant that is not a Network Service User,
the amount of its Spot Market Backup sales; or (c) the hourly scheduled
deliveries of Spot Market Energy by a Market Seller from an External Resource;
or (d) the hourly net metered output of any other Market Seller.
Revised: June 26, 1998
Effective: September 17, 1998
4
<PAGE>
1.3.27 PJM Interchange Import.
"PJM Interchange Import" shall mean the following, as determined in
accordance with the Schedules to this Agreement: (a) for a Market Participant
that is a Network Service User, the amount by which its hourly Equivalent Load
exceeds the sum of the hourly outputs of its operating generating resources; or
(b) for a Market Participant that is not a Network Service User, the amount of
its Spot Market Backup purchases; or (c) the hourly scheduled deliveries of Spot
Market Energy to an External Market Buyer; or (d) the hourly scheduled
deliveries to an Internal Market Buyer that is not a Network Service User.
1.3.28 PJM Open Access Same-time Information System.
"PJM Open Access Same-time Information System" shall mean the
electronic communication system for the collection and dissemination of
information about transmission services in the PJM Control Area, established and
operated by the Office of the Interconnection in accordance with FERC standards
and requirements.
1.3.29 Point-to-Point Transmission Service.
"Point-to-Point Transmission Service" shall mean transmission service
provided pursuant to the rates, terms and conditions set forth in Part II of the
PJM Tariff.
1.3.30 Ramping Capability.
"Ramping Capability" shall mean the sustained rate of change of
generator output, in megawatts per minute.
1.3.31 Regulation.
"Regulation" shall mean the capability of a specific generating unit
with appropriate telecommunications, control and response capability to increase
or decrease its output in response to a regulating control signal, in accordance
with the specifications in the PJM Manuals.
1.3.32 Regulation Class.
"Regulation Class" shall mean a subset of the generation units capable
of providing Regulation to the PJM Control Area determined by a range of costs
for providing Regulation as specified by the Office of the Interconnection using
procedures specified in the PJM Manuals.
1.3.32a Spot Market Backup.
"Spot Market Backup" shall mean the purchase of energy from, or the
delivery of energy to, the PJM Interchange Energy Market in quantities
sufficient to complete the delivery or receipt obligations of a bilateral
contract that has been curtailed or interrupted for any reason.
Revised: June 26, 1998
Effective: September 17, 1998
5
<PAGE>
1.3.33 Spot Market Energy.
"Spot Market Energy" shall mean energy bought or sold by Market
Participants through the PJM Interchange Energy Market at Locational Marginal
Prices determined as specified in Section 2 of this Schedule.
1.3.34 Transmission Congestion Charge.
"Transmission Congestion Charge" shall mean a charge attributable to
the increased cost of energy delivered at a given load bus when the transmission
system serving that load bus is operating under constrained conditions, which
shall be calculated and allocated as specified in Section 5.1 of this Schedule.
Revised: June 26, 1998
Effective: September 17, 1998
5a
<PAGE>
1.3.35 Transmission Congestion Credit.
"Transmission Congestion Credit" shall mean the allocated share of
total Transmission Congestion Charges credited to each holder of Fixed
Transmission Rights, calculated and allocated as specified in Section 5.2 of
this Schedule.
1.3.36 Transmission Customer.
"Transmission Customer" shall mean an entity using Point-to-Point
Transmission Service.
1.3.37 Transmission Forced Outage.
"Transmission Forced Outage" shall mean an immediate removal from
service of a transmission facility by reason of an Emergency or threatened
Emergency, unanticipated failure, or other cause beyond the control of the owner
or operator of the transmission facility, as specified in the relevant portions
of the PJM Manuals. A removal from service of a transmission facility at the
request of the Office of the Interconnection to improve transmission capability
shall not constitute a Forced Transmission Outage.
1.3.37a Transmission Loading Relief.
"Transmission Loading Relief" shall mean NERC's procedures for
preventing operating security limit violations, as implemented by PJM as the
security coordinator responsible for maintaining transmission security for the
PJM Control Area.
1.3.37b Transmission Loading Relief Customer.
"Transmission Loading Relief Customer" shall mean an entity that, in
accordance with Section 1.10.6A, has elected to pay Transmission Congestion
Charges during Transmission Loading Relief in order to continue energy schedules
over contract paths outside the PJM Control Area that are increasing the cost of
energy in the PJM Control Area.
1.3.38 Transmission Planned Outage.
"Transmission Planned Outage" shall mean any transmission outage
scheduled in advance for a pre-determined duration and which meets the
notification requirements for such outages specified in the PJM Manuals.
1.4 Market Buyers.
1.4.1 Qualification.
(a) To become a Market Buyer, an entity shall submit an application to
the Office of the Interconnection, in such form as shall be established by the
Office of the Interconnection.
(b) An applicant that is a Load Serving Entity or that will purchase
on behalf of or for ultimate delivery to a Load Serving Entity shall establish
to the satisfaction of the Office of the Interconnection that the end-users that
will be served through energy and related services purchased in the PJM
Interchange Energy Market, are located electrically within the PJM Control Area,
or will be brought within the PJM Control Area prior to any purchases from the
PJM Interchange Energy Market. Such applicant shall further demonstrate that:
Fourth Revised: February 12, 1999
Effective: January 19, 1999
6
<PAGE>
i) The Load Serving Entity for the end users is obligated to meet
the requirements of the Reliability Assurance Agreement; and
ii) The Load Serving Entity for the end users has arrangements in
place for Network Transmission Service or Point-To-Point
Transmission Service for all PJM Interchange Energy Market
purchases.
(c) An applicant that is not a Load Serving Entity or purchasing on
behalf of or for ultimate delivery to a Load Serving Entity shall demonstrate
that:
i) The applicant has obtained or will obtain Network Transmission
Service or
Revised: November 19, 1998
Effective: January 19, 1999
6a
<PAGE>
Point-to-Point Transmission Service for all PJM Interchange
Energy Market purchases; and
ii) The applicant's PJM Interchange Energy Market purchases will
ultimately be delivered to a load in another Control Area that
is recognized by NERC and that complies with NERC's standards
for operating and planning reliable bulk electric systems.
(d) All applicants shall demonstrate that:
i) The applicant is capable of complying with all applicable
metering, data storage and transmission, and other reliability,
operation, planning and accounting standards and requirements
for the operation of the PJM Control Area and the PJM
Interchange Energy Market;
ii) The applicant meets the creditworthiness standards established
by the Office of the Interconnection, or has provided a letter
of credit or other form of security acceptable to the Office of
the Interconnection; and
iii) The applicant has paid all applicable fees and reimbursed the
Office of the Interconnection for all unusual or extraordinary
costs of processing and evaluating its application to become a
Market Buyer, and has agreed in its application to subject any
disputes arising from its application to the PJM Dispute
Resolution Procedures.
(e) The applicant shall become a Market Buyer upon a final favorable
determination on its application by the Office of the Interconnection as
specified below, and execution by the applicant of counterparts of this
Agreement.
1.4.2 Submission of Information.
The applicant shall furnish all information reasonably requested by
the Office of the Interconnection in order to determine the applicant's
qualification to be a Market Buyer. The Office of the Interconnection may waive
the submission of information relating to any of the foregoing criteria, to the
extent the information in the Office of the Interconnection's possession is
sufficient to evaluate the application against such criteria.
1.4.3 Fees and Costs.
The Office of the Interconnection shall require all applicants to
become a Market Buyer to pay a uniform application fee, initially in the amount
of $1,500, to defray the ordinary costs of processing such applications. The
application fee shall be revised from time to time as the Office of the
Interconnection shall determine to be necessary to recover its ordinary costs of
processing applications. Any unusual or extraordinary costs incurred by the
Office of the Interconnection in processing an application shall be reimbursed
by the applicant.
7
<PAGE>
1.4.4 Office of the Interconnection Determination.
Upon submission of the information specified above, and such other
information as shall reasonably be requested by the Office of the
Interconnection, the Office of the Interconnection shall undertake an evaluation
and investigation to determine whether the applicant meets the criteria
specified above. As soon as practicable, but in any event not later than 60
days after submission of the foregoing information, or such later date as may be
necessary to satisfy the requirements of the Reliability Assurance Agreement,
the Office of the Interconnection shall notify the applicant and the members of
the Members Committee of its determination, along with a written summary of the
basis for the determination. The Office of the Interconnection shall respond
promptly to any reasonable and timely request by a Member for additional
information regarding the basis for the Office of the Interconnection's
determination, and shall take such action as it shall deem appropriate in
response to any request for reconsideration or other action submitted to the
Office of the Interconnection not later than 30 days from the initial
notification to the Members Committee.
1.4.5 Existing Participants.
Any entity that was qualified to participate as a Market Buyer in the
PJM Interchange Energy Market under the Operating Agreement of PJM
Interconnection L.L.C. in effect immediately prior to the Effective Date shall
continue to be qualified to participate as a Market Buyer in the PJM Interchange
Energy Market under this Agreement.
1.4.6 Withdrawal.
(a) An Internal Market Buyer that is a Load Serving Entity may
withdraw from this Agreement by giving written notice to the Office of the
Interconnection specifying an effective date of withdrawal not earlier than the
effective date of (i) its withdrawal from the Reliability Assurance Agreement,
or (ii) the assumption of its obligations under the Reliability Assurance
Agreement by an agent that is a Market Buyer.
(b) An External Market Buyer or an Internal Market Buyer that is
not a Load Serving Entity may withdraw from this Agreement by giving written
notice to the Office of the Interconnection specifying an effective date of
withdrawal at least one day after the date of the notice.
(c) Withdrawal from this Agreement shall not relieve a Market Buyer
of any obligation to pay for electric energy or related services purchased from
the PJM Interchange Energy Market prior to such withdrawal, to pay its share of
any fees and charges incurred or assessed by the Office of the Interconnection
prior to the date of such withdrawal, or to fulfill any obligation to provide
indemnification for the consequences of acts, omissions or events occurring
prior to such withdrawal; and provided, further, that withdrawal from this
Agreement shall not relieve any Market Buyer of any obligations it may have
under, or constitute withdrawal from, any other Related PJM Agreement.
(d) A Market Buyer that has withdrawn from this Agreement may
reapply to become a Market Buyer in accordance with the provisions of this
Section 1.4, provided it is not in default of any obligation incurred under this
Agreement.
Revised: June 26, 1998
Effective: September 17, 1998
8
<PAGE>
1.5 Market Sellers.
1.5.1 Qualification.
A Member that demonstrates to the Office of the Interconnection that
the Member meets the standards for the issuance of an order mandating the
provision of transmission service under section 211 of the Federal Power Act, as
amended by the Energy Policy Act of 1992, may become a Market Seller upon
execution of this Agreement and submission to the Office of the Interconnection
of the applicable Offer Data in accordance with the provisions of this Schedule.
All Members that are Market Buyers shall become Market Sellers upon submission
to the Office of the Interconnection of the applicable Offer Data in accordance
with the provisions of this Schedule.
1.5.2 Withdrawal.
(a) A Market Seller may withdraw from this Agreement by giving
written notice to the Office of the Interconnection specifying an effective date
of withdrawal at least one day after the date of the notice; provided, however,
that withdrawal shall not relieve a Market Seller of any obligation to deliver
electric energy or related services to the PJM Interchange Energy Market
pursuant to an offer made prior to such withdrawal, to pay its share of any fees
and charges incurred or assessed by the Office of the Interconnection prior to
the date of such withdrawal, or to fulfill any obligation to provide
indemnification for the consequences of acts, omissions, or events occurring
prior to such withdrawal; and provided, further, that withdrawal shall not
relieve any entity that is a Market Seller and is also a Market Buyer of any
obligations it may have as a Market Buyer under, or constitute withdrawal as a
Market Buyer from, this Agreement or any other Related PJM Agreement.
(b) A Market Seller that has withdrawn from this Agreement may
reapply to become a Market Seller at any time, provided it is not in default
with respect to any obligation incurred under this Agreement.
1.6 Office of the Interconnection.
1.6.1 Operation of the PJM Interchange Energy Market
The Office of the Interconnection shall operate the PJM Interchange
Energy Market in accordance with this Agreement.
1.6.2 Scope of Services.
The Office of the Interconnection shall, on behalf of the Market
Participants, perform the services pertaining to the PJM Interchange Energy
Market specified in this Agreement, including but not limited to the following:
i) Administer the PJM Interchange Energy Market as part of the PJM
Control Area, including scheduling and dispatching of
generation resources, accounting for transactions, rendering
bills to the Market Participants, receiving payments from and
disbursing payments to the Market Participants, maintaining
appropriate records, and monitoring the compliance of Market
Participants with the provisions of this Agreement, all in
accordance with applicable provisions of the Office of the
Interconnection Agreement, and the Schedules to this Agreement;
Revised: June 26, 1998
Effective: September 17, 1998
9
<PAGE>
ii) Review and evaluate the qualification of entities to be Market
Buyers or Market Sellers under applicable provisions of this
Agreement;
iii) Coordinate, in accordance with applicable provisions of this
Agreement, the Reliability Assurance Agreement, and the
Transmission Owners Agreement, maintenance schedules for
generation and transmission resources operated as part of the
PJM Control Area;
iv) Provide or coordinate the provision of ancillary services
necessary for the operation of PJM Control Area or the PJM
Interchange Energy Market;
v) Determine and declare that an Emergency is expected to exist,
exists, or has ceased to exist, in all or any part of the PJM
Control Area, or in another Control Area interconnected directly
or indirectly with the PJM Control Area, and serve as a primary
point of contact for interested state or federal agencies;
vi) Enter into (a) agreements for the transfer of energy in
conditions constituting an Emergency in the PJM Control Area or
in a Control Area interconnected with it, and the mutual
provision of other support in such Emergency conditions with
other Control Areas interconnected with the PJM Control Area,
and (b) purchases of Emergency energy offered by Members from
resources that are not Capacity Resources in conditions
constituting an Emergency in the PJM Control Area;
vii) Coordinate the curtailment or shedding of load, or other
measures appropriate to alleviate an Emergency, in order to
preserve reliability in accordance with NERC and MAAC
principles, guidelines and standards, and to ensure the
operation of the PJM Control Area in accordance with Good
Utility Practice and the this Agreement;
viii) Protect confidential information as specified in this
Agreement; and
ix) Send a representative to meetings of the Members Committee or
other Committees, subcommittees, or working groups specified in
this Agreement or formed by the Members Committee when requested
to do so by the chair or other head of such committee or other
group.
1.6.3 Records and Reports.
The Office of the Interconnection shall prepare and maintain such
records and prepare such reports, including, but not limited to quarterly budget
reports, as are required to document the performance of its obligations to the
Market Participants hereunder in a form adopted by the Office of the
Interconnection upon consideration of the advice and recommendations of the
Members Committee. The Office of the Interconnection shall also produce special
reports reasonably requested by the Members Committee and consistent with FERC's
standards of conduct; provided, however, the Market Participants shall reimburse
the Office of the Interconnection for the costs of producing any such report.
Notwithstanding the foregoing, the Office of the Interconnection shall not be
required to disclose confidential or commercially sensitive information in any
such report.
Revised: January 30, 1998
Effective: April 17, 1998
10
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1.6.4 PJM Manuals.
The Office of the Interconnection shall prepare, maintain and update
the PJM Manuals consistent with this Agreement. The PJM Manuals shall be
available for inspection by the Market Participants, regulatory authorities with
jurisdiction over the LLC or any Member, and the public.
1.7 General.
1.7.1 Market Sellers.
Only Market Sellers shall be eligible to submit offers to the Office
of the Interconnection for the sale of electric energy or related services in
the PJM Interchange Energy Market. Market Sellers shall comply with the prices,
terms, and operating characteristics of all Offer Data submitted to and accepted
by the PJM Interchange Energy Market.
1.7.2 Market Buyers.
Only Market Buyers shall be eligible to purchase energy or related
services in the PJM Interchange Energy Market. Market Buyers shall comply with
all requirements for making purchases from the PJM Interchange Energy Market.
1.7.3 Agents.
A Market Participant may participate in the PJM Interchange Energy
Market through an agent, provided that the Market Participant informs the Office
of the Interconnection in advance in writing of the appointment of such agent.
A Market Participant participating in the PJM Interchange Energy Market through
an agent shall be bound by all of the acts or representations of such agent with
respect to transactions in the PJM Interchange Energy Market, and shall ensure
that any such agent complies with the requirements of this Agreement.
1.7.4 General Obligations of the Market Participants.
(a) In performing its obligations to the Office of the
Interconnection hereunder, each Market Participant shall at all times (i) follow
Good Utility Practice, (ii) comply with all applicable laws and regulations,
(iii) comply with the applicable principles, guidelines, standards and
requirements of FERC, NERC and MAAC, (iv) comply with the procedures established
for operation of the PJM Interchange Energy Market and PJM Control Area and (v)
cooperate with the Office of the Interconnection as necessary for the operation
of the PJM Control Area in a safe, reliable manner consistent with Good Utility
Practice.
(b) Market Participants shall undertake all operations in or
affecting the PJM Interchange Energy Market and the PJM Control Area, including
but not limited to compliance with all Emergency procedures, in accordance with
the power and authority of the Office of the Interconnection with respect to the
operation of the PJM Interchange Energy Market and the PJM Control Area as
established in this Agreement, and as specified in the Schedules to this
Agreement and the PJM Manuals. Failure to comply with the foregoing operational
requirements shall subject a Market Participant to such reasonable charges or
other remedies or sanctions for non-compliance as may be established by the PJM
Board, including legal or regulatory proceedings as authorized by the PJM Board
to enforce the obligations of this Agreement.
(c) The Office of the Interconnection may establish such committees
with a
11
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representative of each Market Participant, and the Market Participants agree to
provide appropriately qualified personnel for such committees, as may be
necessary for the Office of the Interconnection to perform its obligations
hereunder.
(d) All Market Participants shall provide to the Office of the
Interconnection the scheduling and other information specified in the Schedules
to this Agreement, and such other information as the Office of the
Interconnection may reasonably require for the reliable and efficient operation
of the PJM Control Area and the PJM Interchange Energy Market, and for
compliance with applicable regulatory requirements for posting market and
related information. Such information shall be provided as much in advance as
possible, but in no event later than the deadlines established by the Schedules
to this Agreement, or by the Office of the Interconnection in conformance with
such Schedules. Such information shall include, but not be limited to,
maintenance and other anticipated outages of generation or transmission
facilities, scheduling and related information on bilateral transactions and
self-scheduled resources, and implementation of active load management,
interruption of load, and other load reduction measures. The Office of the
Interconnection shall abide by appropriate requirements for the non-disclosure
and protection of any confidential or proprietary information given to the
Office of the Interconnection by a Market Participant. Each Market Participant
shall maintain or cause to be maintained compatible information and
communications systems, as specified by the Office of the Interconnection,
required to transmit scheduling, dispatch, or other time-sensitive information
to the Office of the Interconnection in a timely manner.
(e) Each Market Participant shall install and operate, or shall
otherwise arrange for, metering and related equipment capable of recording and
transmitting all voice and data communications reasonably necessary for the
Office of the Interconnection to perform the services specified in this
Agreement. A Market Participant that elects to be separately billed for its PJM
Interchange shall, to the extent necessary, be individually metered in
accordance with Section 14 of this Agreement, or shall agree upon an allocation
of PJM Interchange between it and the Market Participant through whose meters
the unmetered Market Participant's PJM Interchange is delivered. The Office of
the Interconnection shall be notified of the allocation by the foregoing Market
Participants.
(f) Each Market Participant shall operate, or shall cause to be
operated, any generating resources owned or controlled by such Market
Participant that are within the PJM Control Area or otherwise supplying energy
to or through the PJM Control Area in a manner that is consistent with the
standards, requirements or directions of the Office of the Interconnection and
that will permit the Office of the Interconnection to perform its obligations
under this Agreement; provided, however, no Market Participant shall be required
to take any action that is inconsistent with Good Utility Practice or applicable
law.
(g) Each Market Participant shall follow the directions of the Office
of the Interconnection to take actions to prevent, manage, alleviate or end an
Emergency in a manner consistent with this Agreement and the procedures of the
PJM Control Area as specified in the PJM Manuals.
(h) Each Market Participant shall obtain and maintain all permits,
licenses or approvals required for the Market Participant to participate in the
PJM Interchange Energy Market in the manner contemplated by this Agreement.
Revised: June 26, 1998
Effective: September 17, 1998
12
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1.7.5 Market Operations Center.
Each Market Participant shall maintain a Market Operations Center, or
shall make appropriate arrangements for the performance of such services on its
behalf. A Market Operations Center shall meet the performance, equipment,
communications, staffing and training standards and requirements specified in
this Agreement for the scheduling and completion of transactions in the PJM
Interchange Energy Market and the maintenance of the reliable operation of the
PJM Control Area, and shall be sufficient to enable (i) a Market Seller to
perform all terms and conditions of its offers to the PJM Interchange Energy
Market, and (ii) a Market Buyer to conform to the requirements for purchasing
from the PJM Interchange Energy Market.
1.7.6 Scheduling and Dispatching.
(a) The Office of the Interconnection shall schedule and dispatch
generation economically on the basis of least-cost, security-constrained
dispatch and the prices and operating characteristics offered by Market Sellers,
continuing until sufficient generation is dispatched to serve the PJM
Interchange Energy Market energy purchase requirements under normal system
conditions of the Market Buyers, as well as the requirements of the PJM Control
Area for ancillary services provided by such generation, in accordance with this
Agreement. Scheduling and dispatch shall be conducted in accordance with this
Agreement.
(b) The Office of the Interconnection shall undertake to identify
any conflict or incompatibility between the scheduling or other deadlines or
specifications applicable to the PJM Interchange Energy Market, and any relevant
procedures of another Control Area, or any tariff (including the PJM Tariff).
Upon determining that any such conflict or incompatibility exists, the Office of
the Interconnection shall propose tariff or procedural changes, and undertake
such other efforts as may be appropriate, to resolve any such conflict or
incompatibility.
1.7.7 Pricing.
The price paid for energy bought and sold in the PJM Interchange
Energy Market will reflect the hourly Locational Marginal Price at each load and
generation bus, determined by the Office of the Interconnection in accordance
with this Agreement. Transmission Congestion Charges, which shall be determined
by differences in Locational Marginal Prices in an hour caused by transmission
constraints, shall be calculated and collected, and the revenues therefrom shall
be disbursed, by the Office of the Interconnection in accordance with this
Schedule.
1.7.8 Generating Market Buyer Resources.
A Generating Market Buyer may elect to self-schedule its generation
resources up to that Generating Market Buyer's Equivalent Load, in accordance
with and subject to the procedures specified in this Schedule, and the
accounting and billing requirements specified in Section 3 to this Schedule.
1.7.9 Delivery to an External Market Buyer.
A purchase of Spot Market Energy by an External Market Buyer shall be
delivered to a bus or busses at the border of the PJM Control Area specified by
the Office of the Interconnection, or to load in the Control Area that is not
served by Network Transmission Service, using Point-to-Point Transmission
Service paid for by the External Market Buyer. Further delivery of such energy
shall be the responsibility of the External Market Buyer.
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1.7.10 Other Transactions.
(a) Market Participants may enter into bilateral contracts for the
purchase or sale of electric energy to or from each other or any other entity,
subject to the obligations of Market Participants to make Capacity Resources
available for dispatch by the Office of the Interconnection. Bilateral
arrangements that contemplate the physical transfer of energy to or from a
Market Participant shall be reported to and coordinated with the Office of the
Interconnection in accordance with this Schedule.
(b) Market Participants shall have Spot Market Backup with respect
to all bilateral transactions that are not dynamically scheduled pursuant to
Section 1.12 and that are curtailed or interrupted for any reason (except for
curtailments or interruptions through active load management for load located
within the PJM Control Area).
(c) To the extent the Office of the Interconnection dispatches a
Generating Market Buyer's generation resources, such Generating Market Buyer may
elect to net the output of such resources against its hourly Equivalent Load.
Such a Generating Market Buyer shall be deemed a buyer from the PJM Interchange
Energy Market to the extent of its PJM Interchange Imports, and shall be deemed
a seller to the PJM Interchange Energy Market to the extent of its PJM
Interchange Exports.
1.7.11 Emergencies.
The Office of the Interconnection, with the assistance of the Members'
dispatchers as it may request, shall be responsible for monitoring the operation
of the PJM Control Area, for declaring the existence of an Emergency, and for
directing the operations of Market Participants as necessary to manage,
alleviate or end an Emergency. The standards, policies and procedures of the
Office of the Interconnection for declaring the existence of an Emergency,
including but not limited to a Minimum Generation Emergency, and for managing,
alleviating or ending an Emergency, shall apply to all Members on a non-
discriminatory basis. Actions by the Office of the Interconnection and the
Market Participants shall be carried out in accordance with this Agreement, the
NERC Operating Policies, MAAC reliability principles and standards, Good Utility
Practice, and the PJM Manuals. A declaration that an Emergency exists or is
likely to exist by the Office of the Interconnection shall be binding on all
Market Participants until the Office of the Interconnection announces that the
actual or threatened Emergency no longer exists. Consistent with existing
contracts, all Market Participants shall comply with all directions from the
Office of the Interconnection for the purpose of managing, alleviating or ending
an Emergency. The Market Participants shall authorize the Office of the
Interconnection to purchase or sell energy on their behalf to meet an Emergency,
and otherwise to implement agreements with other Control Areas interconnected
with the PJM Control Area for the mutual provision of service to meet an
Emergency, in accordance with this Agreement.
1.7.12 Fees and Charges.
Each Market Participant shall pay all fees and charges of the Office
of the Interconnection for operation of the PJM Interchange Energy Market as
determined by and allocated to the Market Participant by the Office of the
Interconnection in accordance with Schedule 3.
Revised: June 16, 1999
Effective: August 16, 1999
14
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1.7.13 Relationship to PJM Control Area.
The PJM Interchange Energy Market operates within and subject to the
requirements for the operation of the PJM Control Area.
Revised: June 26, 1998
Effective: September 17, 1998
14a
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1.7.14 PJM Manuals.
The Office of the Interconnection shall be responsible for
maintaining, updating, and promulgating the PJM Manuals as they relate to the
operation of the PJM Interchange Energy Market. The PJM Manuals, as they relate
to the operation of the PJM Interchange Energy Market, shall conform and comply
with this Agreement, NERC operating policies, and MAAC reliability principles,
guidelines and standards, and shall be designed to facilitate administration of
an efficient energy market within industry reliability standards and the
physical capabilities of the PJM Control Area.
1.7.15 Corrective Action.
Consistent with Good Utility Practice, the Office of the
Interconnection shall be authorized to direct or coordinate corrective action,
whether or not specified in the PJM Manuals, as necessary to alleviate unusual
conditions that threaten the integrity or reliability of the PJM Control Area or
the regional power system.
1.7.16 Recording.
Subject to the requirements of applicable State or federal law, all
voice communications with the Office of the Interconnection Control Center may
be recorded by the Office of the Interconnection and any Market Participant
communicating with the Office of the Interconnection Control Center, and each
Market Participant hereby consents to such recording.
1.7.17 Operating Reserves.
(a) The following procedures shall apply to any generation unit
subject to the dispatch of the Office of the Interconnection for which
construction commenced before July 9, 1996.
(b) The Office of the Interconnection shall schedule to the Operating
Reserve and load-following objectives of the PJM Control Area and the PJM
Interchange Energy Market in scheduling resources pursuant to this Schedule. A
table of Operating Reserve objectives is calculated seasonally for various peak
load levels and eight weekly periods and is published in the PJM Manuals.
Reserve levels are probabilistically determined based on the season's historical
load forecasting error and expected generation mix (including typical Planned
and Forced/Unplanned Outages). Generating Units with quick start capability, as
specified in the PJM Manuals, that are dispatched to maintain reliability by
providing or maintaining spinning reserves or providing load following
capability shall receive energy payments at the levels specified below. The
energy payments specified below shall be considered the offered price for Spot
Market Energy for purposes of Section 3.2.3(b) of this Schedule. The price
offered or paid for the energy of units so dispatched shall not be considered in
determining Locational Marginal Prices.
Second Revised: April 27, 1999
Effective: April 1, 1999
15
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(c) Payments for energy produced by a quick start generating unit
dispatched as specified above shall be at the higher of the applicable
Locational Marginal Price or one of the amounts specified below, as specified in
advance by the Market Seller for the affected unit:
(i) The weighted average Locational Marginal Price at the generation
bus at which energy from the capped resource was delivered
during a specified number of hours during which the resource was
dispatched for energy in economic merit order, the specified
number of hours to be determined by the Office of the
Interconnection and to be a number of hours sufficient to result
in a price cap that reflects reasonably contemporaneous
competitive market conditions for that unit;
(ii) The incremental operating cost of the generation resource as
determined in accordance with Schedule 2 of this Agreement and
the PJM Manuals, plus 10% of such costs; or
(iii) An amount determined by agreement between the Office of the
Interconnection and the Market Seller.
1.7.18 Regulation.
(a) Regulation shall be supplied from generators located within the
metered electrical boundaries of the PJM Control Area. Generating Market
Buyers, and Market Sellers offering Regulation, shall comply with applicable
standards and requirements for Regulation capability and dispatch specified in
the PJM Manuals.
(b) The Office of the Interconnection shall obtain and maintain an
amount of Regulation equal to the PJM Control Area Regulation objective as
specified in the PJM Manuals.
(c) The Regulation range of a unit shall be at least twice the amount
of Regulation assigned.
(d) A unit capable of automatic energy dispatch that is also
providing Regulation shall have its energy dispatch range reduced by twice the
amount of the Regulation provided. The amount of Regulation provided by a unit
shall serve to redefine the Normal Minimum Generation and Normal Maximum
Generation energy limits of that unit, in that the amount of Regulation shall be
added to the unit's Normal Minimum Generation energy limit, and subtracted from
its Normal Maximum Generation energy limit.
Revised: April 27, 1999
Effective: April 1, 1999
15a
<PAGE>
(e) Qualified Regulation must satisfy the verification tests
described in the PJM Manuals.
1.7.19 Ramping.
A generator dispatched by the Office of the Interconnection pursuant
to a control signal appropriate to increase or decrease the generator's megawatt
output level shall be able to change output at the ramping rate specified in the
Offer Data submitted to the Office of the Interconnection for that generator.
1.7.20 Communication and Operating Requirements.
(a) Market Participants. Each Market Participant shall have, or shall
arrange to have, its transactions in the PJM Interchange Energy Market subject
to control by a Market Operations Center, with staffing and communications
systems capable of real-time communication with the Office of the
Interconnection during normal and Emergency conditions and of control of the
Market Participant's relevant load or facilities sufficient to meet the
requirements of the Market Participant's transactions with the PJM Interchange
Energy Market, including but not limited to the following requirements as
applicable.
(b) Market Sellers selling from resources within the PJM Control Area
shall: report to the Office of the Interconnection sources of energy available
for operation; supply to the Office of the Interconnection all applicable Offer
Data; report to the Office of the Interconnection units that are self-scheduled;
report to the Office of the Interconnection bilateral sales transactions to
buyers not within the PJM Control Area; confirm to the Office of the
Interconnection bilateral sales to Market Buyers within the PJM Control Area;
respond to the Office of the Interconnection's directives to start, shutdown or
change output levels of generation units, or change scheduled voltages or
reactive output levels; continuously maintain all Offer Data concurrent with on-
line operating information; and ensure that, where so equipped, generating
equipment is operated with control equipment functioning as specified in the PJM
Manuals.
(c) Market Sellers selling from resources outside the PJM Control
Area shall: provide to the Office of the Interconnection all applicable Offer
Data, including offers specifying amounts of energy available, hours of
availability and prices of energy and other services; respond to Office of the
Interconnection directives to schedule delivery or change delivery schedules;
and communicate delivery schedules to the Market Seller's Control Area.
(d) Market Participants that are Load Serving Entities or purchasing
on behalf of Load Serving Entities shall: provide to the Office of the
Interconnection forecasts of load to be served as required by the Office of the
Interconnection; respond to Office of the Interconnection directives for load
management steps; report to the Office of the Interconnection Capacity Resources
to satisfy capacity obligations that are available for pool operation; report to
the Office of the Interconnection all bilateral purchase transactions; respond
to other Office of the Interconnection directives such as those required during
Emergency operation.
(e) Market Participants that are not Load Serving Entities or
purchasing on behalf of Load Serving Entities shall: provide to the Office of
the Interconnection requests to purchase specified amounts of energy for each
hour of the Operating Day during which it intends to purchase from the PJM
Interchange Energy Market, along with Dispatch Rate levels above which it does
not desire to purchase; respond to other Office of the Interconnection
directives such as those required during Emergency operation.
Revised: June 26, 1998
Effective: September 17, 1998
16
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1.7.21 Multi-settlement System.
The PJM Interchange Energy Market shall be enhanced by an amendment to
this Schedule, to be filed with FERC not later than December 31, 1997, that will
provide for the implementation of a multi-settlement system as soon thereafter
as shall be determined by the Office of the Interconnection to be reasonably
practical. Such a system will provide an opportunity for Market Participants to
commit and obtain commitments to energy prices and transmission congestion
charges at certain specified deadlines in advance of the Office of the
Interconnection's real-time dispatch. The Members specified in Section 11.5(c)
of the Agreement, working with the Office of the Interconnection, shall develop
the details of the implementation of such a multi-settlement system.
1.8 Selection, Scheduling and Dispatch Procedure Adjustment Process.
1.8.1 PJM Dispute Resolution Agreement.
Subject to the condition specified below, any Member adversely
affected by a decision of the Office of the Interconnection with respect to the
operation of the PJM Interchange Energy Market, including the qualification of
an entity to participate in that market as a buyer or seller, make seek such
relief as may be appropriate under the PJM Dispute Resolution Procedures on the
grounds that such decision does not have an adequate basis in fact or does not
conform to the requirements of this Agreement.
1.8.2 Market or Control Area Hourly Operational Disputes.
(a) Market Participants shall comply with all determinations of the
Office of the Interconnection on the selection, scheduling or dispatch of
resources in the PJM Interchange Energy Market, or to meet the operational
requirements of the PJM Control Area. Complaints arising from or relating to
such determinations shall be brought to the attention of the Office of the
Interconnection not later than the end of the fifth business day after the end
of the Operating Day to which the selection or scheduling relates, or in which
the scheduling or dispatch took place, and shall include, if practicable, a
proposed resolution of the complaint. Upon receiving notification of the
dispute, the Office of the Interconnection and the Market Participant raising
the dispute shall exert their best efforts to obtain and retain all data and
other information relating to the matter in dispute, and to notify other Market
Participants that are likely to be affected by the proposed resolution. Subject
to confidentiality or other non-disclosure requirements, representatives of the
Office of the Interconnection, the Market Participant raising the dispute, and
other interested Market Participants, shall meet within three business days of
the foregoing notification, or at such other or further times as the Office of
the Interconnection and the Market Participants may agree, to review the
relevant facts, and to seek agreement on a resolution of the dispute.
(b) If the Office of the Interconnection determines that the matter
in dispute discloses a defect in operating policies, practices or procedures
subject to the discretion of the Office of the Interconnection, the Office of
the Interconnection shall implement such changes as it deems appropriate and
shall so notify the Members Committee. Alternatively, the Office of the
Interconnection may notify the Members Committee of a proposed change and
solicit the comments or other input of the Members.
(c) If either the Office of the Interconnection, the Market
Participant raising
17
<PAGE>
the dispute, or another affected Market Participant believes that the matter in
dispute has not been adequately resolved, or discloses a need for changes in
standards or policies established in or pursuant to the Operating Agreement, any
of the foregoing parties may make a written request for review of the matter by
the Members Committee, and shall include with the request the forwarding party's
recommendation and such data or information (subject to confidentiality or other
non-disclosure requirements) as would enable the Members Committee to assess the
matter and the recommendation. The Members Committee shall take such action on
the recommendation as it shall deem appropriate.
(d) Subject to the right of a Market Participant to obtain correction
of accounting or billing errors, the LLC or a Market Participant shall not be
entitled to actual, compensatory, consequential or punitive damages, opportunity
costs, or other form of reimbursement from the LLC or any other Market
Participant for any loss, liability or claim, including any claim for lost
profits, incurred as a result of a mistake, error or other fault by the Office
of the Interconnection in the selection, scheduling or dispatch of resources.
1.9 Prescheduling.
The following procedures and principles shall govern the prescheduling
activities necessary to plan for the reliable operation of the PJM Control Area
and for the efficient operation of the PJM Interchange Energy Market.
1.9.1 Outage Scheduling.
The Office of the Interconnection shall be responsible for
coordinating and approving requests for outages of generation and transmission
facilities as necessary for the reliable operation of the PJM Control Area, in
accordance with the PJM Manuals. The Office of the Interconnection shall
maintain records of outages and outage requests of these facilities.
1.9.2 Planned Outages.
(a) A Generator Planned Outage shall be included in Generator Planned
Outage schedules established prior to the scheduled start date for the outage,
in accordance with standards and procedures specified in the PJM Manuals.
(b) The Office of the Interconnection shall conduct Generator Planned
Outage scheduling for Capacity Resources in accordance with the Reliability
Assurance Agreement and the PJM Manuals and in consultation with the Members
owning or controlling the output of Capacity Resources. A Market Participant
shall not be expected to submit offers for the sale of energy or other services,
or to satisfy delivery obligations, from all or part of a generation resource
undergoing an approved Generator Planned Outage. If the Office of the
Interconnection determines that approval of a Generator Planned Outage would
significantly affect the reliable operation of the PJM Control Area, the Office
of the Interconnection may withhold approval or withdraw a prior approval.
Approval for a Generator Planned Outage of a Capacity Resource shall be withheld
or withdrawn only as necessary to ensure the adequacy of reserves or the
reliability of the PJM Control Area in connection with anticipated
implementation or avoidance of Emergency procedures. If the Office of the
Interconnection withholds or withdraws approval, it shall coordinate with the
Market Participant owning or controlling the resource to reschedule the
Generator Planned Outage of the Capacity Resource at the earliest practical
time. The Office of the Interconnection shall if possible propose alternative
schedules with the intent of minimizing
18
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the economic impact on the Market Participant of a Generator Planned Outage.
(c) The Office of the Interconnection shall conduct Planned
Transmission Outage scheduling in accordance with procedures specified in the
Transmission Owners Agreement and the PJM Manuals. If the Office of the
Interconnection determines that transmission maintenance schedules proposed by
one or more Members would significantly affect the efficient and reliable
operation of the PJM Control Area, the Office of the Interconnection may propose
alternative schedules, but such alternative shall minimize the economic impact
on the Member or Members whose maintenance schedules the Office of the
Interconnection proposes to modify.
The Office of the Interconnection shall coordinate resolution of
outage or other planning conflicts that may give rise to unreliable system
conditions. The Members shall comply with all maintenance schedules established
by the Office of the Interconnection.
1.9.3 Generator Maintenance Outages
A Market Participant may request approval for a Generator Maintenance
Outage of any Capacity Resource from the Office of the Interconnection in
accordance with the timetable and other procedures specified in the PJM Manuals.
The Office of the Interconnection shall approve requests for Generator
Maintenance Outages for a Capacity Resource unless the outage would threaten the
adequacy of reserves in, or the reliability of, the PJM Control Area. A Market
Participant shall not be expected to submit offers for the sale of energy or
other services, or to satisfy delivery obligations, from a generation resource
undergoing an approved full or partial Generator Maintenance Outage.
1.9.4 Forced Outages
(a) Each Market Seller that owns or controls a pool-scheduled
resource, or Capacity Resource whether or not pool-scheduled, shall: (i) advise
the Office of the Interconnection of a Generator Forced Outage suffered or
anticipated to be suffered by any such resource as promptly as possible; (ii)
provide the Office of the Interconnection with the expected date and time that
the resource will be made available; and (iii) make a record of the events and
circumstances giving rise to the Generator Forced Outage. A Market Seller shall
not be expected to submit offers for the sale of energy or other services, or
satisfy delivery obligations, from a generation resource undergoing a Generator
Forced Outage. A Capacity Resource that does not deliver all or part of its
scheduled energy shall be deemed to have experienced a Generator Forced Outage
with respect to such undelivered energy, in accordance with standards and
procedures for full and partial Generator Forced Outages specified in the
Reliability Assurance Agreement and the PJM Manuals.
(b) The Office of the Interconnection shall receive notification of
Forced Transmission Outages, and information on the return to service, of
Transmission Facilities in the PJM Control Area in accordance with standards and
procedures specified in the Transmission Owners Agreement and the PJM Manuals.
19
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1.9.5 Market Participant Responsibilities.
Each Market Participant making a bilateral sale covering a period
greater than the following Operating Day from a generating resource located
within the PJM Control Area for delivery outside the PJM Control Area shall
furnish to the Office of the Interconnection, in the form and manner specified
in the PJM Manuals, information regarding the source of the energy, the load
sink, the energy schedule, and the amount of energy being delivered.
1.9.6 Internal Market Buyer Responsibilities.
Each Internal Market Buyer making a bilateral purchase covering a
period greater than the following Operating Day shall furnish to the Office of
the Interconnection, in the form an manner specified in the PJM Manuals,
information regarding the source of the energy, the load sink, the energy
schedule, and the amount of energy being delivered. Each Internal Market Buyer
shall provide the Office of the Interconnection with details of any load
management agreements with customers that allow the Office of the
Interconnection to reduce load under specified circumstances.
1.9.7 Market Seller Responsibilities
(a) Not less than 30 days before a Market Seller's initial offer to
sell energy from a given generation resource on the PJM Interchange Energy
Market, the Market Seller shall furnish to the Office of the Interconnection the
information specified in the Offer Data for new generation resources.
(b) Market Sellers authorized and intending to request market-based
start-up and no-load fees in their Offer Data shall submit a specification of
such fees to the Office of the Interconnection for each generating unit as to
which the Market Seller intends to request such fees. Any such specification
shall be submitted on or before March 31 for the period April 1 through
September 30, and on or before September 30 for the period October 1 through
March 31, and shall remain in effect without change throughout each such period
for which a specification was submitted. The Office of the Interconnection
shall reject any request for start-up and no-load fees in a Market Seller's
Offer Data that does not conform to the Market Seller's specification on file
with the Office of the Interconnection.
1.9.8 Office of the Interconnection Responsibilities
(a) The Office of the Interconnection shall perform seasonal
operating studies to assess the forecasted adequacy of generating reserves and
of the transmission system, in accordance with the procedures specified in the
PJM Manuals.
(b) The Office of the Interconnection shall maintain and update
tables setting forth Operating Reserve and other reserve objectives as specified
in the PJM Manuals.
(c) The Office of the Interconnection shall receive and process
requests for firm and non-firm transmission service in accordance with
procedures specified in the PJM Tariff.
(d) The Office of the Interconnection shall maintain such data and
information relating to generation and transmission facilities in the PJM
Control Area as may be necessary or appropriate to conduct the scheduling and
dispatch of the PJM Interchange Energy Market and PJM Control Area.
20
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(e) The Office of the Interconnection shall coordinate with other
interconnected Control Area as necessary to manage, alleviate or end an
Emergency.
1.10 Scheduling.
The following scheduling procedures and principles shall govern the
commitment of resources to the PJM Interchange Energy Market over a period
extending from one week to one day prior to the Operating Day that transactions
are to take place. Scheduling encompasses the day-ahead and hourly scheduling
process, through which the Office of the Interconnection determines, based on
changing forecasts of conditions and actions by Market Participants and system
constraints, a plan to serve the hourly energy and reserve requirements of the
Internal Market Buyers and the purchase requests of the External Market Buyers
in the least costly manner, subject to maintaining the reliability of the PJM
Control Area. Scheduling shall be conducted as specified below, subject to the
following condition. If the Office of the Interconnection's forecast for the
next seven days projects a likelihood of Emergency conditions, the Office of the
Interconnection may commit, for all or part of such seven day period, to the use
of generation resources with notification or start-up times greater than one day
as necessary in order to alleviate or mitigate such Emergency, in accordance
with the Market Sellers' offers for such units for such periods and the
specifications in the PJM Manuals.
1.10.1 Day-Ahead Scheduling.
The following actions shall occur not later than 12:00 noon on the day
before the Operating Day for which transactions are being scheduled.
(a) Each Market Participant that is a Load Serving Entity or
purchasing on behalf of a Load Serving Entity shall submit to the Office of the
Interconnection forecasts of its customer loads for the next Operating Day as
required by the PJM Manuals. If a Market Participant expects to curtail load at
a specific Dispatch Rate, it should specify the Dispatch Rate and estimated load
curtailment.
(b) Each Market Participant that is not a Load Serving Entity or
purchasing on behalf of a Load Serving Entity shall submit to the Office of the
Interconnection requests to purchase specified amounts of energy for each hour
of the Operating Day during which it intends to purchase from the PJM
Interchange Energy Market, along with Dispatch Rate levels above which it does
not desire to purchase, in accordance with the specifications set forth in the
PJM Manuals.
(c) Each Generating Market Buyer shall submit to the Office of the
Interconnection: (i) hourly schedules for resource increments, including
hydropower units, self-scheduled by the Market Buyer to meet its Equivalent
Load; and (ii) the Dispatch Rate at which each such self-scheduled resource will
disconnect or reduce output, or confirmation of the Market Buyer's intent not to
reduce output.
(d) All Market Participants shall submit to the Office of the
Interconnection schedules for any bilateral transactions involving use of
generation or Transmission Facilities as specified below, and shall inform the
Office of the Interconnection if the parties to the transaction are not willing
to incur Transmission Congestion Charges in order to complete any such scheduled
bilateral transaction. Scheduling of bilateral transactions shall be conducted
in accordance with the specifications in the PJM Manuals and the following
requirements:
Revised: June 26, 1998
Effective: September 17, 1998
21
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i) Internal Market Buyers shall submit schedules for all bilateral
purchases for delivery within the PJM Control Area, whether from
generation resources inside or outside the PJM Control Area;
ii) Market Sellers shall submit schedules for bilateral sales to
entities outside the PJM Control Area from generation within the
PJM Control Area that is not dynamically scheduled to such
entities pursuant to Section 1.12; and
iii) In addition to the foregoing schedules for bilateral
transactions, Market Participants shall submit confirmations of
each scheduled bilateral transaction from each other party to the
transaction in addition to the party submitting the schedule, or
the adjacent Control Area.
(e) Market Sellers wishing to sell on the PJM Interchange Energy
Market shall submit offers for the supply of energy (including energy from
hydropower units), Regulation, Operating Reserves or other services for the
following Operating Day. Offers shall be submitted to the Office of the
Interconnection in the form specified by the Office of the Interconnection and
shall contain the information specified in the Office of the Interconnection's
Offer Data specification, as applicable. Market Sellers owning or controlling
the output of a Capacity Resource that has not been rendered unavailable by a
Generation Planned Outage, a Generator Maintenance Outage, or a Generation
Forced Outage shall submit offers for the available capacity of such Capacity
Resource, including any portion that is self-scheduled by the Generating Market
Buyer claiming the resource as a Capacity Resource. The submission of offers for
resource increments that are not Capacity Resources shall be optional, but any
such offers must contain the information specified in the Office of the
Interconnection's Offer Data specification, as applicable. Energy offered from
generation resources that are not Capacity Resources shall not be supplied from
resources that are included in or otherwise committed to supply the Operating
Reserves of another Control Area. The foregoing offers:
i) Shall specify the generation resource and energy for each hour in
the offer period;
ii) Shall specify the amounts and prices for the entire Operating Day
for each resource component offered by the Market Seller to the
Office of the Interconnection;
iii) If based on energy from a specific generating unit, may specify
start-up and no-load fees equal to the specification of such fees
for such unit on file with the Office of the Interconnection;
iv) Shall set forth any special conditions upon which the Market
Seller proposes to supply a resource increment, including any
curtailment rate specified in a bilateral contract for the output
of the resource, or any cancellation fees;
Second Revised: June 16, 1999
Effective: August 16, 1999
22
<PAGE>
v) May include a schedule of offers for prices and operating data
contingent on acceptance by the deadline specified in this
Schedule, with a second schedule applicable if accepted after the
foregoing deadline;
vi) Shall constitute an offer to submit the resource increment to the
Office of the Interconnection for scheduling and dispatch in
accordance with the terms of the offer, which offer shall remain
open through the Operating Day for which the offer is submitted;
Revised: June 26, 1998
Effective: September 17, 1998
22a
<PAGE>
vii) Shall be final as to the price or prices at which the Market
Seller proposes to supply energy or other services to the PJM
Interchange Energy Market, such price or prices being guaranteed
by the Market Seller for the period extending through the end of
the following Operating Day; and
viii) Shall not exceed an energy offer price of $1,000/megawatt-hour.
(f) A Market Seller that wishes to sell Regulation service shall
submit an offer for Regulation that shall specify the MW of Regulation being
offered and the Regulation Class from which such Regulation is being offered.
The range of costs defining Regulation Classes, and the average cost for each
Regulation Class, shall be determined periodically by the Office of the
Interconnection on the basis of prior energy bid prices and appropriate fuel
indices, in accordance with procedures specified in the PJM Manuals. Qualified
Regulation capability must satisfy the verification tests specified in the PJM
Manuals.
(g) Each Market Seller owning or controlling the output of a
Capacity Resource shall submit a forecast of the availability of each such
Capacity Resource for the next seven days. A Market Seller (i) may submit a non-
binding forecast of the price at which it expects to offer a generation resource
increment to the Office of the Interconnection over the next seven days, and
(ii) shall submit a binding offer for energy, along with start-up and no-load
fees, if any, for the next seven days or part thereof, for any generation
resource with minimum notification or start-up requirement greater than 24
hours.
(h) Each offer by a Market Seller of a Capacity Resource shall remain
in effect for subsequent Operating Days until superseded or canceled.
(i) The Office of the Interconnection shall post on the PJM Open
Access Same-time Information System its estimate of the combined hourly load of
the Market Buyers for the next four days, and peak load forecasts for an
additional three days.
1.10.2 Pool-Scheduled Resources.
Pool-scheduled resources shall be governed by the following principles
and procedures.
(a) Pool-scheduled resources shall be selected by the Office of the
Interconnection on the basis of the prices offered for energy and related
services, start-up, no-load and cancellation fees, and the specified operating
characteristics, offered by Market Sellers to the Office of the Interconnection
by the 12:00 noon offer deadline.
(b) A resource that is scheduled by a Market Participant to support a
bilateral sale, or that is self-scheduled by a Generating Market Buyer, shall
not be selected by the Office of the Interconnection as a pool-scheduled
resource except in an Emergency.
(c) Market Sellers offering energy from hydropower or other
facilities with fuel or environmental limitations may submit data to the Office
of the Interconnection that is sufficient to enable the Office of the
Interconnection to determine the available operating hours of such facilities.
(d) The Market Seller of a resource selected as a pool-scheduled
resource shall receive payments or credits for energy or related services, or
for start-up and no-load fees, from the Office of the Interconnection on behalf
of the Market Buyers in accordance with Section 3
Revised: March 17, 1998
Effective: April 1, 1998
23
<PAGE>
of this Schedule 1. Alternatively, the Market Seller shall receive, in lieu of
start-up and no-load fees, its actual costs incurred, if any, up to a cap of the
resource's start-up cost, if the Office of the Interconnection cancels its
selection of the resource as a pool-scheduled resource and so notifies the
Market Seller before the resource is synchronized.
(e) Market Participants shall make available their pool-scheduled
resources to the Office of the Interconnection for coordinated operation to
supply the needs of the PJM Control Area for Operating Reserves.
1.10.3 Self-scheduled Resources.
Self-scheduled resources shall be governed by the following principles
and procedures.
(a) Each Generating Market Buyer shall use all reasonable efforts,
consistent with Good Utility Practice, not to self-schedule resources in excess
of its Equivalent Load.
(b) The offered prices of resources that are self-scheduled, or
otherwise not following the dispatch orders of the Office of the
Interconnection, shall not be considered by the Office of the Interconnection in
determining Locational Marginal Prices.
(c) Market Participants shall make available their self-scheduled
resources to the Office of the Interconnection for coordinated operation to
supply the needs of the PJM Control Area for Operating Reserves.
1.10.4 Capacity Resources.
(a) A Capacity Resource selected as a pool-scheduled resource shall
be made available for scheduling and dispatch at the direction of the Office of
the Interconnection. A Capacity Resource that does not deliver energy as
scheduled shall be deemed to have experienced a Generator Forced Outage to the
extent of such energy not delivered.
(b) Energy from a Capacity Resource that has not been selected as a
pool-scheduled resource may be sold on a bilateral basis by the Market Seller,
or may be self-scheduled. A Capacity Resource that has not been selected as a
pool-scheduled resource and that has been sold on a bilateral basis must be made
available upon request to the Office of the Interconnection for scheduling and
dispatch if the Office of the Interconnection declares a Maximum Generation
Emergency. Any such resource so scheduled and dispatched shall receive the
applicable Locational Marginal Price for energy delivered.
(c) A Capacity Resource that has been self-scheduled shall not
receive payments or credits for start-up or no-load fees.
Revised: March 17, 1998
Effective: April 1, 1998
24
<PAGE>
1.10.5 External Resources.
(a) External Resources may submit offers to the PJM Interchange Energy
Market, in accordance with the day-ahead scheduling process specified above. An
External Resource selected as a pool-scheduled resource shall be made available
for scheduling and dispatch at the direction of the Office of the
Interconnection, and except as specified below shall be compensated on the same
basis as other pool-scheduled resources. External Resources that are not capable
of dynamic dispatch shall, if selected by the Office of the Interconnection on
the basis of the Market Seller's Offer Data, be block loaded on an hourly
scheduled basis. Market Sellers shall offer External Resources to the PJM
Interchange Energy Market on either a resource-specific or an aggregated
resource basis.
(b) Offers for External Resources from an aggregation of two or more
generating units shall so indicate, and shall specify, in accordance with the
Offer Data requirements specified by the Office of the Interconnection: (i)
energy prices; (ii) hours of energy availability; (iii) a minimum dispatch
level; (iv) a maximum dispatch level; and (v) unless such information has
previously been made available to the Office of the Interconnection, sufficient
information, as specified in the PJM Manuals, to enable the Office of the
Interconnection to model the flow into the PJM Control Area of any energy from
the External Resources scheduled in accordance with the Offer Data. If a Market
Seller submits more than one offer on an aggregated resource basis, the
withdrawal of any such offer shall be deemed a withdrawal of all higher priced
offers for the same period.
(c) Offers for External Resources on a resource-specific basis shall
specify the resource being offered, along with the information specified in the
Offer Data as applicable.
Second Revised: November 19, 1998
Effective: December 1, 1998
25
<PAGE>
1.10.6 External Market Buyers.
(a) Deliveries to an External Market Buyer not subject to dynamic
dispatch by the Office of the Interconnection shall be delivered on a block
loaded basis to the load bus or busses at the border of the PJM Control Area, or
in the PJM Control Area with respect to an External Market Buyer's load within
the PJM Control Area not served by Network Service, at which the energy is
delivered to or for the External Market Buyer. External Market Buyers shall be
charged the Locational Marginal Price for energy at the foregoing load bus or
busses.
(b) An External Market Buyer's hourly schedules for energy purchased
from the PJM Interchange Energy Market shall conform to the ramping and other
applicable requirements of the interconnection agreement between the PJM Control
Area and the Control Area to which, whether as an intermediate or final point of
delivery, the purchased energy will initially be delivered.
(c) The Office of the Interconnection shall curtail deliveries to an
External Market Buyer if necessary to maintain appropriate reserve levels for
the PJM Control Area as defined in the PJM Manuals, or to avoid shedding load in
the PJM Control Area.
1.10.6A Transmission Loading Relief Customers.
(a) An entity that desires to elect to pay Transmission Congestion
Charges in order to continue its energy schedules during an Operating Day over
contract paths outside the PJM Control Area in the event that PJM initiates
Transmission Loading Relief that otherwise would cause PJM to request security
coordinators to curtail such Member's energy schedules shall:
(i) enter its election on OASIS by 12:00 p.m. of the day before
the Operating Day, in accordance with procedures established
by PJM, which election shall be applicable for the entire
Operating Day; and
(ii) if PJM initiates Transmission Loading Relief, provide to
PJM, at such time and in accordance with procedures
established by PJM, the hourly integrated energy schedules
that impacted the PJM Control Area (as indicated from the
NERC Interchange Distribution Calculator) during the
Transmission Loading Relief.
Third Revised: February 12, 1999
Effective: January 19, 1999
26
<PAGE>
(b) If an entity has made the election specified in Section (a), then
PJM shall not request security coordinators to curtail such entity's energy
transactions, except as may be necessary to respond to Emergencies.
(c) In order to make elections under this Section 1.10.6A, an entity
must (i) have met the creditworthiness standards established by the Office of
the Interconnection or provided a letter of credit or other form of security
acceptable to the Office of the Interconnection, and (ii) have executed either
the Agreement, a Service Agreement under the PJM Tariff, or other agreement
committing to pay all Transmission Congestion Charges incurred under this
Section.
1.10.7 Bilateral Transactions.
Bilateral transactions as to which the parties have notified the
Office of the Interconnection by 12:00 p.m. of the day before the Operating Day
that they are not willing to incur Transmission Congestion Charges shall be
curtailed by the Office of the Interconnection as necessary to reduce or
alleviate transmission congestion. Bilateral transactions willing to incur
congestion charges shall continue to be implemented during periods of
congestion, except as may be necessary to respond to Emergencies.
Second Revised: February 12, 1999
Effective: January 19, 1999
26a
<PAGE>
1.10.8 Office of the Interconnection Responsibilities.
(a) The Office of the Interconnection shall use its best efforts to
determine the least-cost means of satisfying the projected hourly requirements
for energy, Operating Reserves, and other ancillary services of the Market
Buyers, including the reliability requirements of the PJM Control Area. In
making this determination, the Office of the Interconnection shall take into
account: (i) the Office of the Interconnection's forecasts of PJM Interchange
Energy Market and PJM Control Area energy requirements, giving due consideration
to the energy requirement forecasts and purchase requests submitted by Market
Buyers; (ii) the offers submitted by Market Sellers; (iii) the availability of
limited energy resources; (iv) the capacity, location, and other relevant
characteristics of self-scheduled resources; (v) the objectives of the PJM
Control Area for Operating Reserves, as specified in the PJM Manuals; (vi) the
requirements of the PJM Control Area for Regulation and other ancillary
services, as specified in the PJM Manuals; (vii) the benefits of avoiding or
minimizing transmission constraint control operations, as specified in the PJM
Manuals; and (viii) such other factors as the Office of the Interconnection
reasonably concludes are relevant to the foregoing determination. The Office of
the Interconnection shall develop a schedule of generation resources based on
the foregoing determination. The Office of the Interconnection shall report the
planned schedule for a hydropower resource to the operator of that resource as
necessary for plant safety and security, and legal limitations on pond
elevations.
(b) Not later than 4:00 p.m. of the day before each Operating Day, or
such earlier deadline as may be specified by the Office of the Interconnection
in the PJM Manuals, the Office of the Interconnection shall: (i) post on the
PJM Open Access Same-time Information System its forecast of the location and
duration of any expected transmission congestion, and of the range of
differences in Locational Marginal Prices between major subareas of the PJM
Control Area expected to result from such transmission congestion; and (ii)
inform each Market Seller whether its offer or offers have been accepted.
(c) The Office of the Interconnection shall revise its schedule of
generation resources to reflect updated projections of load, conditions
affecting electric system operations in the PJM Control Area, the availability
of and constraints on limited energy and other resources, transmission
constraints, and other relevant factors. The Office of the Interconnection
shall post on the PJM Open Access Same-time Information System at times
specified in the PJM Manuals a revised forecast of the location and duration of
any expected transmission congestion, and of the range of differences in
Locational Marginal Prices between major subareas of the PJM Control Area
expected to result from such transmission congestion.
1.10.9 Hourly Scheduling
(a) Following the initial posting of the Office of the
Interconnection's transmission congestion forecast, and subject to the right of
the Office of the Interconnection to schedule and dispatch pool-scheduled
resources and to direct that schedules be changed in an Emergency, a Market
Participant may adjust the schedule of a resource under its dispatch control on
an hour-to-hour basis beginning at 10:00 p.m. of the day before each Operating
Day, provided that the Office of the Interconnection is notified not later than
60 minutes prior to the hour in which the adjustment is to take effect, as
follows:
i) A Generating Market Buyer may self-schedule any of its resource
27
<PAGE>
increments, including hydropower resources, not previously
designated as self-scheduled and not selected as a pool-
scheduled resource;
ii) A Market Participant may request the scheduling of a non-firm
bilateral transaction; or
iii) A Market Participant may request the scheduling of deliveries
or receipts of Spot Market Energy; or
iv) A Generating Market Buyer may remove from service a resource
increment, including a hydropower resource, that it had
previously designated as self-scheduled, provided that the
Office of the Interconnection shall have the option to
schedule energy from any such resource increment that is a
Capacity Resource at the price offered in the scheduling
process, with no obligation to pay any start-up fee.
(b) An External Market Buyer may refuse delivery of some or all of
the energy it requested to purchase by notifying the Office of the
Interconnection of the adjustment in deliveries not later than 60 minutes prior
to the hour in which the adjustment is to take effect.
1.11 Dispatch.
The following procedures and principles shall govern the dispatch of the
resources available to the Office of the Interconnection.
1.11.1 Resource Output.
The Office of the Interconnection shall have the authority to direct
any Market Seller to adjust the output of any pool-scheduled resource increment
within the operating characteristics specified in the Market Seller's offer.
The Office of the Interconnection may cancel its selection of, or otherwise
release, pool-scheduled resources, subject to an obligation to pay any
applicable start-up, no-load or cancellation fees. The Office of the
Interconnection shall adjust the output of pool-scheduled resource increments as
necessary: (a) to maintain reliability, and subject to that constraint, to
minimize the cost of supplying the energy, reserves, and other services required
by the Market Buyers and the operation of the PJM Control Area; (b) to balance
load and generation, maintain scheduled tie flows, and provide frequency support
within the PJM Control Area; and (c) to minimize unscheduled interchange not
frequency related between the PJM Control Area and other Control Areas.
1.11.2 Operating Basis.
In carrying out the foregoing objectives, the Office of the
Interconnection shall conduct the operation of the PJM Control Area in
accordance with the PJM Manuals, and shall: (i) utilize available generating
reserves and obtain required replacements; and (ii) monitor the availability of
adequate reserves.
Revised: November 19, 1998
Effective: December 1, 1998
28
<PAGE>
1.11.3 Pool-dispatched Resources
(a) The Office of the Interconnection shall implement the dispatch
of energy from pool-scheduled resources with limited energy by direct request.
In implementing mandatory or economic use of limited energy resources, the
Office of the Interconnection shall use its best efforts to select the most
economic hours of operation for limited energy resources, in order to make
optimal use of such resources consistent with the dynamic load-following
requirements of the PJM Control Area and the availability of other resources to
the Office of the Interconnection.
(b) The Office of the Interconnection shall implement the dispatch
of energy from other pool-dispatched resource increments, including generation
increments from Capacity Resources the remaining increments of which are self-
scheduled, by sending appropriate signals and instructions to the entity
controlling such resources, in accordance with the PJM Manuals. Each Market
Seller shall ensure that the entity controlling a pool-dispatched resource
offered or made available by that Market Seller complies with the energy
dispatch signals and instructions transmitted by the Office of the
Interconnection.
1.11.3a Maximum Generation Emergency
If the Office of the Interconnection declares a Maximum Generation
Emergency, all deliveries to load that is served by Point-to-Point Transmission
Service outside the PJM Control Area from Capacity Resources may be interrupted
in order to serve load in the PJM Control Area.
1.11.4 Regulation
(a) A Market Buyer may satisfy its Regulation obligation from its
own resources capable of performing Regulation service, by contractual
arrangements with other Market Participants able to provide Regulation service,
or by purchases from the PJM Interchange Energy Market.
(b) The Office of the Interconnection shall obtain Regulation
service from the least-cost alternatives available from either pool-scheduled or
self-scheduled resources as needed to meet PJM Control Area requirements not
otherwise satisfied by the Market Buyers.
(c) The Office of the Interconnection shall dispatch resources for
Regulation by sending Regulation signals and instructions to resources from
which Regulation service has been offered by Market Sellers, in accordance with
the PJM Manuals. Market Sellers shall comply with Regulation dispatch signals
and instructions transmitted by the Office of the Interconnection and, in the
event of conflict, Regulation dispatch signals and instructions shall take
precedence over energy dispatch signals and instructions. Market Sellers shall
exert all reasonable efforts to operate, or ensure the operation of, their
resources supplying load in the PJM Control Area as close to desired output
levels as practical, consistent with Good Utility Practice.
1.11.5 PJM Open Access Same-time Information System.
The Office of the Interconnection shall update the information posted
on the PJM Open Access Same-time Information System to reflect its dispatch of
generation resources.
Revised: June 26, 1998
Effective: September 17, 1998
29
<PAGE>
1.12 Dynamic Scheduling.
(a) An entity that owns or controls a generating resource in the PJM
Control Area may electrically remove all or part of the generating resource's
output from the PJM Control Area through dynamic scheduling of the output to
load outside the PJM Control Area. Such output shall not be available for
economic dispatch by the Office of the Interconnection.
(b) An entity requesting dynamic scheduling shall be responsible for
arranging for the provision of signal processing and communications from the
generator to the Office of the Interconnection and the other participating
control area and complying with any other procedures established by the Office
of the Interconnection regarding dynamic scheduling as set forth in the PJM
Manuals.
(c) An entity requesting dynamic scheduling shall be responsible for
reserving amounts of firm transmission service necessary to deliver the range of
the dynamic transfer and any required ancillary services.
Revised: June 16, 1999
Effective: August 16, 1999
29a
<PAGE>
2. CALCULATION OF LOCATIONAL MARGINAL PRICES
2.1 Introduction.
The Office of the Interconnection shall calculate the price of energy at
the load busses and generation busses in the PJM Control Area and at the
interface busses between the PJM Control Area and adjacent Control Areas on the
basis of Locational Marginal Prices. Locational Marginal Prices determined in
accordance with this Section shall be calculated every five minutes and
integrated hourly values of such calculations shall be the basis of sales and
purchases of energy in the PJM Interchange Energy Market and of Transmission
Congestion Charges under the PJM Tariff.
2.2 General.
The Office of the Interconnection shall determine the least cost security-
constrained dispatch, which is the least costly means of serving load at
different locations in the PJM Control Area based on actual operating conditions
existing on the power grid and on the prices at which Market Sellers have
offered to supply energy in the PJM Interchange Energy Market. Locational
Marginal Prices for the generation and load busses in the PJM Control Area,
including interconnections with other Control Areas, will be calculated based on
the actual economic dispatch and the prices of energy offers. The process for
the determination of Locational Marginal Prices shall be as follows:
(a) To determine actual operating conditions on the power grid in the PJM
Control Area, the Office of the Interconnection shall use a computer model of
the interconnected grid that uses available metered inputs regarding generator
output, loads, and power flows to model remaining flows and conditions,
producing a consistent representation of power flows on the network. The
computer model employed for this purpose, referred to as the State Estimator
program, is a standard industry tool and is described in Section 2.3 below. It
will be used to obtain information regarding the output of generation supplying
energy to the PJM Control Area, loads at buses in the PJM Control Area,
transmission losses, and power flows on binding transmission constraints for use
in the calculation of Locational Marginal Prices. Additional information used
in the calculation, including Dispatch Rates and real time schedules for
external transactions between PJM and other Control Areas, will be obtained from
the Office of the Interconnection's dispatchers.
(b) Using the prices at which energy is offered by Market Sellers to the
PJM Interchange Energy Market, the Office of the Interconnection shall determine
the offers of energy that will be considered in the calculation of Locational
Marginal Prices. As described in Section 2.4 below, every offer of energy by a
Market Seller from a resource that is following economic dispatch instructions
of the Office of the Interconnection will be utilized in the calculation of
Locational Marginal Prices.
(c) Based on the system conditions on the PJM power grid, determined as
described in (a), and the eligible energy offers, determined as described in
(b), the Office of the Interconnection shall determine the least costly means of
obtaining energy to serve the next increment of load at each bus in the PJM
Control Area, in the manner described in Section 2.5 below. The result of that
calculation shall be a set of Locational Marginal Prices based on the system
conditions at the time.
30
<PAGE>
2.3 Determination of System Conditions Using the State Estimator.
Power system operations, including, but not limited to, the determination
of the least costly means of serving load, depend upon the availability of a
complete and consistent representation of generator outputs, loads, and power
flows on the network. In calculating Locational Marginal Prices, the Office of
the Interconnection shall obtain a complete and consistent description of
conditions on the electric network in the PJM Control Area by using the most
recent power flow solution produced by the State Estimator, which is also used
by the Office of the Interconnection for other functions within power system
operations. The State Estimator is a standard industry tool that produces a
power flow model based on available real-time metering information, information
regarding the current status of lines, generators, transformers, and other
equipment, bus load distribution factors, and a representation of the electric
network, to provide a complete description of system conditions, including
conditions at busses for which real-time information is unavailable. The
current version of the State Estimator includes over 1600 busses in the PJM
Control Area, as well as interface busses with adjacent Control Areas. The
Office of the Interconnection shall obtain a State Estimator solution every five
minutes, which shall provide the megawatt output of generators and the loads at
busses in the PJM Control Area, transmission line losses, and actual flows or
loadings on constrained transmission facilities. External transactions between
PJM and other Control Areas shall be included in the Locational Marginal Price
calculation on the basis of the real time transaction schedules implemented by
the Office of the Interconnection's dispatcher.
2.4 Determination of Energy Offers Used in Calculating Locational
Marginal Prices.
(a) To determine the energy offers submitted to the PJM Interchange
Energy Market that shall be used to calculate the Locational Marginal Prices,
the Office of the Interconnection shall determine which resources are following
its economic dispatch instructions. A resource will be considered to be
following economic dispatch instructions and shall be included in the
calculation of Locational Marginal Prices if:
i) the price bid by a Market Seller for energy from the resource is
less than or equal to the Dispatch Rate for the area of the PJM
Control Area in which the resource is located; or
ii) the resource is specifically requested to operate by the Office
of the Interconnection's dispatcher.
(b) In determining whether a resource satisfies the condition described in
(a), the Office of the Interconnection will determine the bid price associated
with an energy offer by comparing the actual megawatt output of the resource
with the Market Seller's offer price curve. Because of practical generator
response limitations, a resource whose megawatt output is not ten percent more
than the megawatt level specified on the offer price curve for the applicable
Dispatch Rate shall be deemed to be following economic dispatch instructions,
but the energy price offer used in the calculation of Locational Marginal Prices
shall not exceed the applicable Dispatch Rate. Units that must be run for local
area protection shall not be considered in the calculation of Locational
Marginal Prices.
31
<PAGE>
2.5 Calculation of Locational Marginal Prices.
(a) The Office of the Interconnection shall determine the least costly
means of obtaining energy to serve the next increment of load at each bus in the
PJM Control Area represented in the State Estimator and each interface bus
between the PJM Control Area and an adjacent Control Area, based on the system
conditions described by the most recent power flow solution produced by the
State Estimator program and the energy offers determined to be eligible for
consideration under Section 2.4. This calculation shall be made by applying an
incremental linear optimization method to minimize energy costs, given actual
system conditions, a set of energy offers, and any binding transmission
constraints that may exist. In performing this calculation, the Office of the
Interconnection shall calculate the cost of serving an increment of load at each
bus from each resource associated with an eligible energy offer as the sum of:
(1) the price at which the Market Seller has offered to supply an additional
increment of energy from the resource, and (2) the effect on transmission
congestion costs (whether positive or negative) associated with increasing the
output of the resource, based on the effect of increased generation from that
resource on transmission line loadings. The energy offer or offers that can
serve an increment of load at a bus at the lowest cost, calculated in this
manner, shall determine the Locational Marginal Price at that bus.
(b) The calculation set forth in (a) shall be performed every five
minutes, using the Office of the Interconnection's Locational Marginal Price
program, producing a set of Locational Marginal Prices based on system
conditions during the preceding interval. The prices produced at five-minute
intervals during an hour will be integrated to determine the Locational Marginal
Prices for that hour, which will determine prices in the PJM Interchange Energy
Market and Transmission Congestion Costs under the PJM Tariff.
2.6 Performance Evaluation.
The Office of the Interconnection shall undertake an evaluation of the
foregoing procedures for the determination of Locational Marginal Prices, as
well as the procedures for determining and allocating Fixed Transmission Rights
and associated Transmission Congestion Charges and Credits, not less often than
every two years, in accordance with the PJM Manuals. To the extent practical,
the Office of the Interconnection shall retain all data needed to perform
comparisons and other analyses of locational marginal pricing. The Office of
the Interconnection shall report the results of its evaluation to the Market
Participants, along with its recommendations, if any, for changes in the
procedures.
32
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3. ACCOUNTING AND BILLING
3.1 Introduction.
This schedule sets forth the accounting and billing principles and
procedures for the purchase and sale of services on the PJM Interchange Energy
Market and for the operation of the PJM Control Area.
3.2 Market Buyers.
3.2.1 Spot Market Energy.
(a) At the end of each hour during an Operating Day, the Office of
the Interconnection shall calculate the load payment for each Market Buyer's
load bus. The load payment at each bus shall be the product of the Market
Buyer's megawatts of load at such load bus in the hour times the Locational
Marginal Price at the bus. The megawatts of load at each load bus shall be the
sum of the megawatts of load for that bus of that Market Buyer as determined by
the State Estimator, plus an allocated share of transmission losses, plus any
megawatts of that Market Buyer's bilateral sales to purchasers outside the PJM
Control Area attributable to that bus. The total load payment for each Market
Buyer shall be the sum of the load payments for each of a Market Buyer's load
busses.
(b) At the end of each hour during an Operating Day, the Office of
the Interconnection shall calculate the generation revenue for each Generating
Market Buyer's generation bus. The generation revenue at each generation bus
shall be the product of the Generating Market Buyer's megawatts of generation at
such generation bus in the hour times the Locational Marginal Price at the bus.
The megawatts of generation at each generation bus shall be the sum of the
megawatts of generation for that bus of that Generating Market Buyer as
determined by the State Estimator, plus any megawatts of bilateral purchases of
that Generating Market Buyer from sellers outside the PJM Control Area
attributable to that bus. The total generation revenue for each Generating
Market Buyer shall be the sum of the generation revenues for each of the
Generating Market Buyer's generation busses.
(c) At the end of each hour during an Operating Day, the Office of
the Interconnection shall calculate a net bill for each Market Buyer, determined
as the difference between its total load payment and its total generation
revenue. The portions of the net bill attributable to net hourly PJM Interchange
and to Transmission Congestion Charges shall be determined as set forth below.
(d) At the end of each hour during an Operating Day, the Office of
the Interconnection shall calculate the total amount of net hourly PJM
Interchange for each Market Buyer, including Generating Market Buyers, in
accordance with the PJM Manuals. For Internal Market Buyers that are Load
Serving Entities or purchasing on behalf of Load Serving Entities, this
calculation shall include determination of the net energy flows from: (i) tie
lines; (ii) any generation resource the output of which is controlled by the
Market Buyer but delivered to it over another entity's Transmission Facilities;
(iii) any generation resource the output of which is controlled by another
entity but which is directly interconnected with the Market Buyer's transmission
system; (iv) deliveries pursuant to bilateral energy sales; (v) receipts
pursuant to bilateral energy purchases; and (vi) the Market Buyer's allocated
share of energy purchased from another Control Area in connection with a Minimum
Generation
Second Revised: September 24, 1998
Effective: January 1, 1999
33
<PAGE>
Emergency in such other Control Area as specified in Section 3.2.6(c). For
Electric Distributors that report hourly net energy flows from metered tie
lines, this calculation also shall include 500 kV transmission losses and
Inadvertent Interchange allocated to the Electric Distributor and shall exclude
the energy delivered to load of other Network Customers and Transmission
Customers. For External Market Buyers and Internal Market Buyers that are not
Load Serving Entities or purchasing on behalf of Load Serving Entities, this
calculation shall determine the energy delivered pursuant to the Market Buyer's
purchase requests.
(e) The Office of the Interconnection shall calculate Locational
Marginal Prices for each load and generation bus in the PJM Control Area, in
accordance with Section 2 of this Schedule.
(f) An Internal Market Buyer shall be charged for Spot Market
Energy purchases to the extent of its hourly net PJM Interchange Imports,
determined as specified above. An External Market Buyer shall be charged for its
Spot Market Energy purchases based on the energy delivered to it, determined as
specified above. The Office of the Interconnection shall calculate an hourly
weighted average Locational Marginal Price for each such Market Buyer, based on
the Locational Marginal Price at each load bus and the Market Buyer's load at
that bus. The total charge shall be the Market Buyer's total net PJM Interchange
Imports times the weighted average Locational Marginal Price.
(g) A Generating Market Buyer shall be credited as a Market Seller
for sales of Spot Market Energy to the extent of its hourly net PJM Interchange
Exports, determined as specified above. The total credit shall be the sum of the
credits determined by the product of (i) the hourly net amount of energy of PJM
Interchange Exports at the applicable generation bus from each of the Generating
Market Buyer's generation resources determined to be making such deliveries,
times (ii) the hourly Locational Marginal Price at that generation bus. The
generation resources determined to be making deliveries into PJM Interchange of
such Generating Market Buyer shall be those that have the highest Locational
Marginal Prices of the Market Seller's generation resources.
3.2.2 Regulation.
(a) Each Internal Market Buyer that is a Load Serving Entity shall
have an hourly Regulation objective equal to its pro rata share of the PJM
Control Area Regulation requirements for the hour, based on the Market Buyer's
total load in the PJM Control Area for the hour.
(b) A Generating Market Buyer supplying Regulation at the direction
of the Office of the Interconnection in excess of its hourly Regulation
obligation shall be credited for each increment of such Regulation at the price
in that hour for the Regulation Class from which
Third Revised: November 19, 1998
Effective: December 1, 1998
34
<PAGE>
the Regulation was supplied, as determined by the Office of the Interconnection
in accordance with procedures specified in the PJM Manuals. An Internal Market
Buyer that does not meet its hourly Regulation obligation shall be charged for
Regulation dispatched by the Office of the Interconnection to meet such
obligation at the average price paid by the Office of the Interconnection for
Regulation.
3.2.3 Operating Reserves.
(a) A Market Seller's pool-scheduled resources capable of providing
operating reserves shall be credited as specified below based on the prices
offered for the operation of such resource, provided that the resource was
available for the entire time specified in the Offer Data for such resource.
(b) At the end of each Operating Day, the following determination
shall be made for each synchronized pool-scheduled resource of each Market
Seller: the total offered price for start-up and no-load fees and Spot Market
Energy, determined on the basis of the resource's actual output or available and
requested time and type of operation, shall be compared to the total value of
that resource's Spot Market Energy. If the total offered price exceeds the
total value, the difference shall be credited to the Market Seller. Market
Sellers shall also be credited on the basis of their offered prices for
synchronized condensing for any hydropower or combustion turbine units operated
as synchronous condensers at the request of Office of the Interconnection but
producing no energy.
(c) A Market Seller's pool scheduled resource the output of which
is reduced or suspended at the request of the Office of the Interconnection for
the purpose of maintaining reliability within the PJM Control Area, shall be
credited in an amount equal to (PAG - AG) x LT x (ULMP - UB) where:
PAG equals the actual generation of the unit for the five minute
period preceding the request;
AG equals the actual generation of the unit until PJM cancels the
request to reduce output;
LT equals the length of time that the request to reduce output was
effective;
ULMP equals the LMP at the unit's bus;
UB equals the unit bid for that unit whose output is reduced or
suspended; and
where ULMP - UB shall not be negative.
(d) The sum of the foregoing credits, plus any cancellation fees
paid in accordance with Section 1.10.2(d), less any payments received from
another Control Area for Operating Reserves, shall be the cost of Operating
Reserves for the PJM Control Area for each Operating Day.
Fifth Revised: September 3, 1999
Effective: September 4, 1999
35
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(e) The cost of Operating Reserves for each Operating Day shall be
allocated and charged to each Market Participant in proportion to the sum of its
(i) deliveries of energy to load in the PJM Control Area in megawatt-hours
during that Operating Day; and (ii) deliveries of energy sales from within the
PJM Control Area to load outside the PJM Control Area in megawatt-hours during
that Operating Day, but not including its bilateral transactions that are
dynamically scheduled to load outside the PJM Control Area pursuant to Section
1.12.
3.2.4 Transmission Congestion.
Each Market Buyer shall be charged or credited for Transmission
Congestion Charges as specified in Section 5 of this Schedule.
3.2.5 Transmission Losses.
(a) Whenever the Office of the Interconnection has in place
appropriate computer hardware, software, and other necessary resources to
account for marginal losses in the dispatch of energy and the calculation of
Locational Marginal Prices, loss accounting shall be determined on that basis,
and the provisions of this Section shall be revised accordingly. Until such
time, the following accounting provisions for losses shall apply.
(b) Each Internal Market Buyer that is a Load Serving Entity or
purchasing on behalf of a Load Serving Entity shall be credited in an amount
equal to its pro rata share of the hourly total amounts collected from
Transmission Customers either as charges for transmission losses in the PJM
Control Area as specified in Section 3.4.2 or for transmission losses supplied
in kind in accordance with Section 3.4.2(c) based on the Locational
Marginal
Second Revised: September 3, 1999
Effective: September 4, 1999
35a
<PAGE>
Price at the interface where such losses were delivered. This credit shall be
determined by the ratio of the Internal Market Buyer's total hourly load,
divided by the total hourly load in the PJM Control Area.
(c) PJM Control Area 500 kV losses shall be allocated to each
Electric Distributor that reports hourly net energy flows from metered tie lines
in proportion to its hourly load in the PJM Control Area.
3.2.6 Emergency Energy.
(a) Internal Market Buyers shall be allocated a proportionate share
of the net cost of Emergency energy purchased by the Office of the
Interconnection. Such allocated share shall be determined in proportion to the
amount of net PJM Interchange Imports by each Internal Market Buyer during the
hour of each such energy purchase.
(b) Net revenues in excess of Locational Marginal Prices
attributable to sales of energy in connection with Emergencies to other Control
Areas shall be credited to Internal Market Buyers in proportion to the amount of
net PJM Interchange Imports by each Internal Market Buyer during each hour of
such energy sales.
(c) The costs, revenues, and energy associated with hourly energy
purchased from another Control Area in connection with a Minimum Generation
Emergency in such other Control Area, shall be allocated to each Internal Market
Buyer in proportion to its load in the PJM Control Area during the hour of such
purchases.
3.2.7 Billing.
(a) The Office of the Interconnection shall prepare a billing
statement each billing cycle for each Market Buyer in accordance with the
charges and credits specified in Sections 3.2.1 through 3.2.6 of this Schedule,
and showing the net amount to be paid or received by the Market Buyer. Billing
statements shall provide sufficient detail, as specified in the PJM Manuals, to
allow verification of the billing amounts and completion of the Market Buyer's
internal accounting.
(b) If deliveries to a Market Buyer that has PJM Interchange meters
in accordance with Section 14 of the Operating Agreement include amounts
delivered for a Market Participant that does not have PJM Interchange meters
separate from those of the metered Market Buyer, the Office of the
Interconnection shall prepare a separate billing statement for the unmetered
Market Participant based on the allocation of deliveries agreed upon between the
Market Buyer and the unmetered Market Participant specified by them to the
Office of the Interconnection.
3.3 Market Sellers.
Except as provided in the following sentence, the accounting and billing
principles and procedures applicable to Generating Market Buyers functioning as
Market Sellers shall be as set forth in Section 3.2. This Section sets forth
the accounting and billing principles and procedures applicable to all other
Market Sellers, and to Generating Market Buyers functioning as Market Sellers
with respect to any matters not specified in Section 3.2.
Second Revised: September 24, 1998
Effective: January 1, 1999
36
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3.3.1 Spot Market Energy.
(a) At the end of each hour during an Operating Day, the Office of
the Interconnection shall determine the total net amount of hourly energy
delivered to the PJM Control Area by each pool-scheduled or pool-dispatched
resource of each Market Seller, in accordance with the PJM Manuals and the
calculation described in Section 3.2.1(d).
(b) The Office of the Interconnection shall calculate Locational
Marginal Prices for each generation and load bus in the PJM Control Area,
including the bus at each point of interconnection between the PJM Control Area
and each adjacent Control Area, in accordance with Section 2 of this Schedule.
(c) A Market Seller shall be credited for sales of Spot Market
Energy to the extent of its hourly net deliveries of energy to the PJM Control
Area from the Market Seller's pool-scheduled or pool-dispatched resources. For
pool-scheduled resources that are External Resources, the Office of the
Interconnection shall model, based on an appropriate flow analysis, the hourly
amounts delivered from each such resource to the corresponding interface point
between the PJM Control Area and adjacent Control Areas. The total credit for
each Market Seller shall be the sum of its credits determined by the product of
(i) the hourly net amount of energy delivered to the PJM Control Area at the
applicable generation or interface bus from each of the Market Seller's pool-
scheduled or pool-dispatched resources, times (ii) the hourly Locational
Marginal Price at that bus.
3.3.2 Regulation.
Each Market Seller that is also an Internal Market Buyer shall have an
hourly Regulation objective as specified in Section 3.2.2(a), and shall be
credited or charged in connection therewith as specified in Section 3.2.2(b).
All other Market Sellers supplying Regulation at the direction of the Office of
the Interconnection shall be credited for each increment of such Regulation at
the price in that hour for the Regulation Class from which the Regulation was
supplied, as determined by the Office of the Interconnection in accordance with
procedures specified in the PJM Manuals.
3.3.3 Operating Reserves.
A Market Seller shall be credited for its pool-scheduled resources
based on the prices offered for the operation of such resource, provided that
the resource was available for the entire time specified in the Offer Data for
such resource, in accordance with the procedures set forth in Section 3.2.3(b).
3.3.4 Emergency Energy.
The costs and net revenues associated with hourly energy sales to
other Control Areas in connection with a Minimum Generation Emergency in the PJM
Control Area shall be allocated to Market Sellers in proportion to their sales
to the PJM Interchange Energy Market from generation resources within the
metered boundaries of the PJM Control Area in each hour in which such energy was
sold to other Control Areas.
Revised: November 19, 1998
Effective: November 1, 1998
37
<PAGE>
3.3.5 Billing.
The Office of the Interconnection shall prepare a billing statement
each billing cycle for each Market Seller in accordance with the charges and
credits specified in Sections 3.3.1 through 3.3.4 of this Schedule, and showing
the net amount to be paid or received by the Market Seller. Billing statements
shall provide sufficient detail, as specified in the PJM Manuals, to allow
verification of the billing amounts and completion of the Market Seller's
internal accounting.
3.4 Transmission Customers.
3.4.1 Transmission Congestion.
Each Transmission Customer shall be charged and credited for
Transmission Congestion Charges as specified in Section 5 of this Schedule.
3.4.2 Transmission Losses
(a) Whenever the Office of the Interconnection has in place
appropriate computer hardware, software, and other necessary resources to
account for marginal losses in the dispatch of energy and the calculation of
Locational Marginal Prices, loss accounting shall be determined on that basis,
and the provisions of this Section shall be revised accordingly. Until such
time, the following accounting provisions for losses shall apply.
(b) Transmission Customers shall be charged for transmission losses
in an amount equal to the product of (i) the Transmission Customer's megawatt-
hours of deliveries using Point-to-Point Transmission Service, times (ii) the
appropriate loss factor for deliveries using Point-to-Point Transmission
Service, times (iii) the weighted average Locational Marginal Price for all load
busses in the PJM Control Area. The foregoing average hourly loss factor shall
be: (i) determined by the Office of the Interconnection from time to time as
conditions affecting losses shall warrant; and (ii) calculated separately for
on-peak and off-peak hours on the basis of the average ratio of losses to load
served in each such period.
(c) A Transmission Customer may elect to pay for losses in kind,
rounded off to the nearest whole megawatt, rather than as specified above if its
total deliveries in an hour using Point-to-Point Transmission Service are
greater than 200 megawatts. If it so elects, the Transmission Customer's
specified source for the energy to be delivered using Point-to-Point
Transmission Service may be scheduled to supply to the PJM Control Area boundary
an amount of energy equal to the delivery schedule plus the amount of losses
determined by applying the appropriate hourly loss factor as specified above to
the delivered amount.
3.4.3 Billing.
The Office of the Interconnection shall prepare a billing statement
each billing cycle for each Transmission Customer in accordance with the charges
and credits specified in Sections 3.4.1 through 3.4.2 of this Schedule, and
showing the net amount to be paid or received by the Transmission Customer.
Billing statements shall provide sufficient detail, as specified in the PJM
Manuals, to allow verification of the billing amounts and completion of the
Transmission Customer's internal accounting.
Revised: June 26, 1998
Effective: September 1, 1998
38
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3.5 Other Control Areas.
3.5.1 Energy Sales.
To the extent appropriate in accordance with Good Utility Practice,
the Office of the Interconnection may sell energy to an interconnected Control
Area as necessary to alleviate or end an Emergency in that Control Area. Such
sales shall be made (i) only to Control Areas that have undertaken a commitment
pursuant to a written agreement with the LLC to sell energy on a comparable
basis to the PJM Control Area, and (ii) only to the extent consistent with the
maintenance of reliability in the PJM Control Area. The Office of the
Interconnection may decline to make such sales to a Control Area that the Office
of the Interconnection determines does not have in place and implement Emergency
procedures that are comparable to those followed in the PJM Control Area. If
the Office of the Interconnection sells energy to an interconnected Control Area
as necessary to alleviate or end an Emergency in that Control Area, such energy
shall be sold at 150% of the Locational Marginal Price at the bus or busses at
the border of the PJM Control Area at which such energy is delivered.
3.5.2 Operating Margin Sales.
The extent appropriate in accordance with Good Utility Practice, the
Office of the Interconnection may sell Operating Margin to an interconnected
Control Area as requested to alleviate an operating contingency resulting from
the affect of the purchasing Control Area's operations on the dispatch of
resources in the PJM Control Area. Such sales shall be made only to Control
Areas that have undertaken a commitment pursuant to a written agreement with the
Office of the Interconnection (i) to purchase Operating Margin whenever the
purchasing Control Area's operations will affect the dispatch of resources in
the PJM Control Area, and (ii) to sell Operating Margin on a comparable basis to
the LLC.
3.5.3 Transmission Congestion.
Each Control Area purchasing Operating Margin shall be assessed
Transmission Congestion Charges as specified in Section 5.1.5 of this Schedule.
3.5.4 Billing.
The Office of the Interconnection shall prepare a billing statement
each billing cycle for each Control Area to which Emergency energy or Operating
Margin was sold, and showing the net amount to be paid by such Control Area.
Billing statements shall provide sufficient detail, as specified in the PJM
Manuals, to allow verification of the billing amounts.
3.6 Metering Reconciliation.
3.6.1 Meter Correction Billing.
Metering errors and corrections will be reconciled at the end of each
month by a meter correction charge or credit. The monthly meter correction
charge or credit shall be determined by the product of the positive or negative
deviation in energy amounts, times the weighted average Locational Marginal
Price for all load busses in the PJM Control Area.
Revised: March 17, 1998
Effective: April 1, 1998
39
<PAGE>
3.6.2 Meter Corrections Between Market Participants.
If a Market Participant or the Office of the Interconnection discovers
a meter error affecting an interchange of energy with another Market Participant
and makes the error known to such other Market Participant prior to the
completion by the Office of the Interconnection of the accounting for the
interchange, and if both Market Participants are willing to adjust hourly load
records to compensate for the error and such adjustment does not affect other
parties, an adjustment in load records may be made by the Market Participants in
order to correct for the meter error, provided corrected information is
furnished to the Office of the Interconnection in accordance with the Office of
the Interconnection's accounting deadlines. No such adjustment may be made if
the accounting for the Operating Day in which the interchange occurred has been
completed by the Office of the Interconnection.
3.6.3 500 kV Meter Errors.
Billing cycle accounting for 500 kV transmission losses shall be
adjusted to account for errors in meters on 500 kV Transmission Facilities.
3.6.4 Meter Corrections Between Control Areas.
An error between accounted for and metered interchange between a Party
in the PJM Control Area and an entity in another Control Area shall be corrected
by adjusting the hourly meter readings. If this is not practical, the error
shall be accounted for by a correction at the end of the billing cycle. The
Market Participant with ties to such other Control Area experiencing the error
shall account for the full amount of the discrepancy and an appropriate debit or
credit shall be applied equally among all Market Buyers. The Office of the
Interconnection will adjust the actual interchange between the PJM Control Area
and the other Control Area to maintain a proper record of inadvertent energy
flow. Meter corrections on the 500 kV system between the PJM Control Area and
other Control Areas shall be accounted for through the internal 500 kV system
meter error allocation at the end of the billing cycle.
3.6.5 Meter Correction Data.
Meter error data shall be submitted to the Office of the
Interconnection not later than noon on the second working day of the Office of
the Interconnection after the end of the billing cycle applicable to the meter
correction.
3.6.6 Correction Limits.
A Market Participant may not assert a claim for an adjustment in
billing as a result of a meter error for any error discovered more than two
years after the date on which the metering occurred. Any claim for an
adjustment in billing as a result of a meter error shall be limited to bills for
transactions occurring in the most recent annual accounting period of the
billing Market Participant in which the meter error occurred, and the prior
annual accounting period.
40
<PAGE>
4. RATE TABLE
4.1 Offered Price Rates.
Spot Market Energy, Regulation, Operating Reserve, and Transmission
Congestion are based on offers to the Office of the Interconnection specified in
this Agreement.
4.2 Transmission Losses.
Average loss factors shall be as specified in the PJM Tariff.
4.3 Emergency Energy Purchases.
The pricing for Emergency energy purchases will be determined by the Office
of the Interconnection and: (a) an adjacent Control Area, in accordance with an
agreement between the Office of the Interconnection and such adjacent Control
Area, or (b) a Member, in accordance with arrangements made by the Office of
Interconnection to purchase energy offered by such Member from resources that
are not Capacity Resources.
Revised: January 30, 1998
Effective: April 1, 1998
41
<PAGE>
5. CALCULATION OF TRANSMISSION CONGESTION CHARGES AND CREDITS
5.1 Transmission Congestion Charge Calculation
5.1.1 Calculation by Office of the Interconnection.
When the transmission system is operating under constrained
conditions, the Office of the Interconnection shall calculate Transmission
Congestion Charges for each Network Service User, the PJM Interchange Energy
Market, and each Transmission Customer.
5.1.2 General.
The basis for the Transmission Congestion Charges shall be the
Locational Marginal Prices determined in accordance with Section 2 of this
Schedule.
5.1.3 Network Service User Calculation.
Each Network Service User shall be charged for the increased cost of
energy incurred by it during each constrained hour to deliver the output of its
firm Capacity Resources or other owned or contracted for resources, its firm
bilateral purchases, and its non-firm bilateral purchases as to which it has
elected to pay Transmission Congestion Charges. The Transmission Congestion
Charge for deliveries from each such source shall be the Network Service User's
hourly net bill less its hourly net PJM Interchange payments or sales as
determined in accordance with Section 3.2.1 or Sections 3.3 and 3.3.1 of this
Schedule.
5.1.4 Transmission Customer Calculation.
Each Transmission Customer using Firm Point-to-Point Transmission
Service (as defined in the PJM Tariff), and each Transmission Customer using
Non-Firm Point-to-Point Transmission Service (as defined in the PJM Tariff) that
has elected to pay Transmission Congestion Charges, shall be charged for the
increased cost of energy during constrained hours for the delivery of energy
using Point-to-Point Transmission Service. The Transmission Congestion Charge
for each such delivery shall be the delivery amount multiplied by the difference
between the Locational Marginal Price at the delivery interface and the
Locational Marginal Price at the source interface, or for Market Sellers using
point-to-point transmission service for deliveries out of the PJM Control Area
from generating resources within the PJM Control Area shall be the amount of its
net bill less its net hourly PJM Interchange payments or sales as determined in
accordance with Section 3.3 of this Schedule.
5.1.5 Operating Margin Customer Calculation.
Each Control Area purchasing Operating Margin shall be assessed
Transmission Congestion Charges for any the increase in the cost of energy
resulting from the provision of Operating Margin. The Transmission Congestion
Charge shall be the amount of Operating Margin purchased in an hour multiplied
by the difference in the Locational Marginal Price at what would be the delivery
interface and the Locational Marginal Price at what would be the source
interface, if the operating contingency that was the basis for the purchase of
Operating Margin had occurred in that hour. Operating Margin may be allocated
among multiple source and delivery interfaces in accordance with an applicable
load flow study.
42
<PAGE>
5.1.6 Transmission Loading Relief Customer Calculation
(a) Each Transmission Loading Relief Customer shall be assessed
Transmission Congestion Charges for any increase in the cost of energy in the
PJM Control Area resulting from its energy schedules over contract paths outside
the PJM Control Area during Transmission Loading Relief.
(b) The Transmission Congestion Charge shall be the total amount of energy
specified in such energy schedules multiplied by the difference between a
Locational Marginal Price calculated by the Office of the Interconnection for
the energy schedule source location specified in the NERC Interchange
Distribution Calculator and a Locational Marginal Price calculated by the Office
of the Interconnection for the energy schedule sink location specified in the
NERC Interchange Distribution Calculator. Transmission Congestion Charges that
are less than zero shall be set equal to zero for Transmission Loading Relief
Customers.
(c) The Office of the Interconnection will determine the Locational
Marginal Prices at the energy schedule source and sink locations external to PJM
with reference to and based solely on the prices of energy in the PJM Control
Area and at the interface buses between the PJM Control Area and adjacent
Control Areas and the system conditions and actual power flow distributions as
described by the PJM State Estimator program. The Office of the Interconnection
will determine the Locational Marginal Prices at the external energy schedule
source and sink locations and the resulting Congestion Charge based on the
portion of the energy schedule that flows through the PJM Control Area as
reflected by the flow distributions from the PJM State Estimator program.
5.1.7 Total Transmission Congestion Charges.
The total Transmission Congestion Charges collected by the Office of
the Interconnection each hour will be the sum of the amounts determined as
specified in this Schedule. The Office of the Interconnection shall collect
Transmission Congestion Charges for each hour the transmission system operates
under constrained conditions.
5.2 Transmission Congestion Credit Calculation.
5.2.1 Eligibility.
Each holder of a Fixed Transmission Right shall receive as a
Transmission Congestion Credit a proportional share of the total Transmission
Congestion Charges collected for each constrained hour.
5.2.2 Fixed Transmission Rights.
(a) Transmission Congestion Credits will be calculated based upon the
Fixed Transmission Rights held at the time of the constrained hour. Initial
assignments of Fixed Transmission Rights shall be made to each Network Service
User and Transmission Customer as specified below.
43
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(b) On a periodic schedule established by the Office of the
Interconnection, each Network Service User shall designate a subset of its
Network Resources for which Fixed Transmission Rights will be assigned. Fixed
Transmission Rights shall be assigned for each Network Resource in a number of
megawatts equal to or less than the installed capacity summer megawatt rating of
each designated Network Resource, determined at the PJM Control Area
transmission bus at which the designated Network Resource is connected. Each
Fixed Transmission Right shall be to the aggregate load busses of the Network
Service User in a Zone or, with respect to Non-Zone Network Load, to the border
of the PJM Control Area. The sum of each Network Service User's assigned Fixed
Transmission Rights for a Zone must be equal to or less than the Network Service
User's peak load for that Zone as determined under Section 34.1 of the Tariff.
The sum of each Network Service User's Fixed Transmission Rights for Non-Zone
Network Load must be equal to or less than the Network Service User's
transmission responsibility for Non-Zone Network Load as determined under
Section 34.1 of the Tariff.
(c) Each Transmission Customer receiving firm Point-to-Point
Transmission Service shall be assigned Fixed Transmission Rights; provided,
however, that a Transmission Customer may notify the Office of Interconnection
that it does not wish to receive any FTRs or wishes to receive FTRs only for
certain Point or Points of Receipt and Point or Points of Delivery, in which
event no FTRs or such reduced amount of FTRs shall be issued to the Transmission
Customer. The Fixed Transmission Right for each instance of Point-to-Point
Transmission Service shall be a number of megawatts equal to the megawatts of
firm service being provided between the receipt and delivery points as to which
the Transmission Customer has firm Point-to-Point Transmission Service.
(d) A Fixed Transmission Right, or the right to Transmission
Congestion Credits attributable to a Fixed Transmission Right, may be sold or
otherwise transferred by agreement, subject to compliance with such procedures
as may be established by the Office of the Interconnection for verification of
the rights of the purchaser or transferee.
43a
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5.2.4 Target Allocation for Network Service Users.
A target allocation of Transmission Congestion Credits for each
Network Service User shall be determined for each of its Fixed Transmission
Rights. Each Fixed Transmission Right shall be multiplied by the percent of the
Network Service User's annual peak load assigned to each load bus multiplied by
the difference calculated as the Network Service User's load bus Locational
Marginal Price minus the generation bus Locational Marginal Price of the Network
Resource associated with the Fixed Transmission Right. The total target
allocation for each Fixed Transmission Right is the sum of the target
allocations for each load bus. The total target allocation for each Network
Service User for each hour is the sum of the total target allocations for each
of the Network Service User's Fixed Transmission Rights.
5.2.4 Target Allocation for other Holders.
A target allocation of Transmission Congestion Credits for each
Transmission Customer or entity holding an FTR acquired by other means shall be
determined for each Fixed Transmission Right. Each Fixed Transmission Right
shall be multiplied by the hourly Locational Marginal Price differences for the
receipt and delivery points associated with the Fixed Transmission Right,
calculated as the Locational Marginal Price at the delivery point(s) minus the
Locational Marginal Price at the receipt point(s). The total target allocation
for the Transmission Customer for each hour shall be the sum of the target
allocations associated with all of the Transmission Customer's Fixed
Transmission Rights.
5.2.5 Calculation of Transmission Congestion Credits
(a) The total of all the target allocations determined as specified
above shall be compared to the total Transmission Congestion Charges in each
hour. If the total of the target allocations is less than the total of the
Transmission Congestion Charges, the Transmission Congestion Credit for each
Network Service User and Transmission Customer shall be equal to its target
allocation. All remaining Transmission Congestion Charges shall be distributed
as described below in Section 5.2.6 "Distribution of Excess Congestion Charges."
(b) If the total of the target allocations is greater than the total
Transmission Congestion Charges for the hour, each holder of Fixed Transmission
Rights shall receive a share of the total Transmission Congestion Charges in
proportion to its target allocations.
5.2.6 Distribution of Excess Congestion Charges
(a) Excess Transmission Congestion Charges accumulated in a month
shall be distributed to each holder of Fixed Transmission Rights in proportion
to, but not more than, any deficiency in the share of Transmission Congestion
Charges received by the holder during that month as compared to its total target
allocations for the month.
(b) Any excess Transmission Congestion Charges remaining at the end
of a month shall be distributed to Network Service Users and Transmission
Customers purchasing Firm Point-to-Point Transmission Service in proportion to
their Demand Charges for Network Service and their charges for Reserved Capacity
for Firm Point-to-Point Transmission Service.
44
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5.3 Unscheduled Transmission Service (Loop Flow)
(a) When there are agreements between the Members (or the Office of
the Interconnection on behalf of the Members) and others for compensation to be
paid or received for unscheduled transmission service (loop flow) into or out of
the PJM Control Area, the net compensation received shall be included in the
total Transmission Congestion Charges that are distributed in accordance with
Section 5.2.
(b) With respect to payments by the Office of the Interconnection to
the New York Power Pool for the installation and operation of phase angle
regulating facilities at Ramapo to control or limit unscheduled transmission
service (loop flow), each Transmission Owner with revenue requirements under the
PJM Tariff shall pay a share of the charges on a transmission revenue
requirements ratio share basis.
44a
<PAGE>
6. "MUST-RUN" FOR RELIABILITY GENERATION
6.1 Introduction.
The following procedures shall apply to any generation resource subject to
the dispatch of the Office of the Interconnection that (a) is a generation
resource for which construction commenced before July 9, 1996, and (b) as a
result of transmission constraints, the Office of the Interconnection
determines, in the exercise of Good Utility Practice, must be run in order to
maintain the reliability of service in the PJM Control Area. The provisions of
this Schedule shall otherwise apply to the scheduling, dispatch, operation and
accounting treatment of such resources, to the extent not inconsistent with the
provisions of this Section 6.
6.2 Identification of Facility Outages.
Not later than one hour prior to the deadline specified in Section 1.10.1
of this Schedule, the Office of the Interconnection shall identify on the PJM
Open Access Same-Time Information System any facility outage or other system
condition which it has determined may give rise to a transmission constraint
that may require, in order to maintain system reliability, the dispatch of one
or more generation resources that otherwise would not be dispatched based on the
merits of their offers to the PJM Interchange Energy Market.
6.3 Dispatch for Local Reliability.
6.3.1 Request and Dispatch.
In addition to the dispatch of generation by the Office of the
Interconnection to maintain reliability on transmission facilities directly
monitored by it, a Member that owns or leases with rights equivalent to
ownership Transmission Facilities as defined in this Agreement or the
Transmission Owners Agreement and that operates a local control center in
accordance with Section 11.3.3 of this Agreement or a Market Operations Center
in accordance with Section 1.7.5 of this Schedule, may request the Office of the
Interconnection to dispatch generation in order to maintain reliability on any
such Transmission Facilities that are not then directly monitored by the Office
of the Interconnection, subject to the rules and procedures in Section 6.3.2.
The Office of the Interconnection shall dispatch generation to maintain
reliability on such Transmission Facilities by incorporating the facilities in
the State Estimator program described in Section 2.3 as set forth below, unless
the Office of the Interconnection determines that such dispatch would adversely
affect reliability in the PJM Control Area or would otherwise not be in
accordance with Good Utility Practice.
45
<PAGE>
6.3.2 Designation of Facilities.
The following rules and procedures shall apply to a Member request
that the Office of the Interconnection dispatch generation on one or more
Transmission Facilities that are not then directly monitored by the Office of
the Interconnection.
a) The Transmission Facilities that are the subject of the request must
be among the facilities that comprise the Transmission System under
the PJM Tariff;
b) The Member shall provide modeling information for such Transmission
Facilities and provide sufficient telemetry to the Office of the
Interconnection such that power flows are observable by the State
Estimator program described in Section 2.3; provided, however, that if
an unreliable constrained condition exists and time does not permit
such modeling and telemetry, the Member and the Office of the
Interconnection may agree to use a representative surrogate for such
Transmission Facilities in order to allocate the costs of the dispatch
of generation using Locational Marginal Prices to maintain reliability
on such Transmission Facilities, provided further that the Member
shall expeditiously provide the modeling data and install the
necessary facilities to incorporate the Transmission Facilities into
the State Estimator program;
c) The request shall constitute a request that such Transmission
Facilities become and remain monitored by the Office of the
Interconnection and subject to its dispatch control for a period of
not less than ninety (90) days;
d) The Member shall comply with all other operating procedures
established by the Office of the Interconnection regarding dispatch
for local reliability as set forth in the PJM Manuals.
6.4 Price Caps.
6.4.1 Applicability.
(a) Except as specified below, if in the day-ahead schedule
determined by the Office of the Interconnection in accordance with
Sections 1.10.8(a) and (b) of this Schedule any generation resource may be
dispatched out of economic merit order to maintain system reliability as a
result of limits on transmission capability, the prices for energy offered by
such resource shall be capped at the levels specified below. If the Office of
the Interconnection is able to do so, such prices shall be capped only during
each hour when the transmission limit affects the schedule of the affected
resource, and otherwise shall be capped for the entire Operating Day. The energy
prices as capped shall be used to determine any Locational Marginal Price
affected by the price of such resource.
45a
<PAGE>
(b) The energy bid price offered by any generation resource
requested to be dispatched in accordance with Section 6.3 of this Schedule shall
be capped at the levels specified below. If the Office of the Interconnection is
able to do so, such prices shall be capped only during each hour when the
affected resource is so scheduled, and otherwise shall be capped for the entire
Operating Day. The energy prices as capped shall be used to determine any
Locational Marginal Price affected by the price of such resource.
(c) Generation resources subject to a price cap shall be paid for
energy at the applicable Locational Marginal Price.
(d) Price caps shall not be applicable to generation resources used
to relieve the Western, Central and Eastern reactive limits in the PJM Control
Area. In addition, price caps shall not be applicable to generation resources
used to relieve any other transmission limit as to which the FERC has authorized
the use of market based rates.
6.4.2 Level.
The price cap shall be one of the amounts specified below, as
specified in advance by the market Seller for the affected unit:
(i) The weighted average Locational Marginal Price at the generation
bus at which energy from the capped resource was delivered
during a specified number of hours during which the resource was
dispatched for energy in economic merit order, the specified
number of hours to be determined by the Office of the
Interconnection and to be a number of hours sufficient to result
in a price cap that reflects reasonably contemporaneous
competitive market conditions for that unit;
(ii) The incremental operating cost of the generation resource as
determined in accordance with Schedule 2 of this Agreement and
the PJM Manuals, plus 10% of such costs; or
(iii) An amount determined by agreement between the Office of the
Interconnection and the Market Seller.
45b
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7. FIXED TRANSMISSION RIGHTS AUCTIONS
7.1 Auctions of Fixed Transmission Rights.
Periodic auctions to allow Market Participants to acquire or sell Fixed
Transmission Rights shall be conducted by the Office of the Interconnection in
accordance with the provisions of this Section.
7.1.1 Auction Period and Scope of Auctions.
The period covered by an auction shall be the one-month period next
following the date that the auction is conducted. The Office of the
Interconnection shall offer for sale in the auction any remaining Fixed
Transmission Rights capability for the month after taking into account all of
the Fixed Transmission Rights already outstanding at the time of the auction. In
addition, any holder of a Fixed Transmission Right for the period covered by an
auction may offer such Fixed Transmission Right for sale in such auction. Each
monthly auction will consist of a separate auction for on-peak Fixed
Transmission Rights and a separate auction for off-peak Fixed Transmission
Rights. Market Participants may bid for and acquire any number of Fixed
Transmission Rights, provided that all Fixed Transmission Rights awarded are
simultaneously feasible with each other and with all Fixed Transmission Rights
outstanding at the time of the auction and not sold into the auction.
7.1.2 Frequency and Time of Auctions.
Fixed Transmission Rights auctions shall be held monthly. The bid and
offer period shall open at 12:00 midnight (Eastern Prevailing Time) on the
fifteenth (15th) business day preceding the month for which Fixed Transmission
Rights are being auctioned and shall close at 12:00 midnight (Eastern Prevailing
Time) on the tenth (10th) business day preceding the month for which Fixed
Transmission Rights are being auctioned.
7.1.3. Duration of Fixed Transmission Rights.
Each Fixed Transmission Right acquired in a Fixed Transmission Rights
auction shall entitle the holder to credits of Transmission Congestion Charges
for the one-month period for which the Fixed Transmission Rights were auctioned.
46
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7.2 Fixed Transmission Rights Characteristics.
7.2.1 Reconfiguration of Fixed Transmission Rights.
Through an appropriate linear programming model, the Office of the
Interconnection shall reconfigure the Fixed Transmission Rights offered or
otherwise available for sale in any auction to maximize the value to the bidders
of the Fixed Transmission Rights sold, provided that any Fixed Transmission
Rights acquired at auction shall be simultaneously feasible in combination with
those Fixed Transmission Rights outstanding at the time of the auction and not
sold in the auction. The linear programming model shall, while respecting
transmission constraints and the maximum MW quantities of the bids and offers,
select the set of simultaneously feasible Fixed Transmission Rights with the
highest net total auction value as determined by the bids of buyers and taking
into account the reservation prices of the sellers.
7.2.2 Specified Buses.
Auction bids for Fixed Transmission Rights may specify any combination
of receipt and delivery buses represented in the State Estimator model for which
the Office of the Interconnection calculates and posts Locational Marginal
Prices. Auction bids may specify receipt and delivery points from locations
outside of the PJM Control Area to locations inside the PJM Control Area, from
locations within the PJM Control Area to locations outside of the PJM Control
Area, or to and from locations within the PJM Control Area.
7.2.3 Transmission Congestion Charges.
Fixed Transmission Rights, whether acquired at auction or otherwise,
shall entitle holders thereof to credits only for Transmission Congestion
Charges, and shall not confer a right to credits for payments arising from or
relating to transmission congestion made to any entity other than the Office of
the Interconnection.
7.3 Auction Procedures.
7.3.1 Role of the Office of the Interconnection.
Fixed Transmission Rights auctions shall be conducted by the Office of
the Interconnection in accordance with standards and procedures set forth in the
PJM Manuals, such standards and procedures to be consistent with the
requirements of this Schedule.
47
<PAGE>
7.3.2 Notice of Offer.
A holder of a Fixed Transmission Right wishing to offer the Fixed
Transmission Right for sale shall notify the Office of the Interconnection of
any Fixed Transmission Rights to be offered. Each Fixed Transmission Right sold
in an auction shall, at the end of the period for which the Fixed Transmission
Rights were auctioned, revert to the offering holder or the entity to which the
offering holder has transferred such Fixed Transmission Right, subject to the
term of the Fixed Transmission Right itself and to the right of such holder or
transferee to offer the Fixed Transmission Right in the next or any subsequent
auction during the term of the Fixed Transmission Right.
7.3.3 Pending Applications for Firm Service.
(a) Prior to the start of each auction bidding period, the Office
of the Interconnection shall exert reasonable effort to complete its review of
pending applications for Network Transmission Service and Firm Point-to-Point
Transmission Service and to ascertain the corresponding Fixed Transmission
Rights to be assigned to the entities receiving such service, subject to
compliance with all applicable deadlines and other procedures by the applicant.
Fixed Transmission Rights so assigned shall be included in the simultaneous
feasibility test performed by the Office of the Interconnection for the auction.
(b) Fixed Transmission Rights may be assigned to entities
requesting Network Transmission Service or Firm Point-to-Point Transmission
Service only if such Fixed Transmission Rights are simultaneously feasible with
all outstanding Fixed Transmission Rights, including Fixed Transmission Rights
effective for the then-current auction period. If an assignment of Fixed
Transmission Rights pursuant to a pending application for Network Transmission
Service or Firm Point-to-Point Transmission Service cannot be completed prior to
an auction, Fixed Transmission Rights attributable to such transmission service
shall not be assigned for the then-current auction period. If a Fixed
Transmission Right cannot be assigned for this reason, the applicant may
withdraw its application, or request that the Fixed Transmission Right be
assigned effective with the start of the next auction period.
7.3.4 On-Peak and Off-Peak Periods.
The Office of the Interconnection will conduct separate auctions
simultaneously for on-peak and off-peak periods. On-Peak Fixed Transmission
Rights shall cover the periods from 7:00 a.m. up to the hour ending at 11:00
p.m. on Mondays through Fridays, except holidays as defined in the PJM Manuals.
Off-Peak Fixed Transmission Rights shall cover the periods from 11:00 p.m. up to
the hour ending 7:00 a.m. on Mondays through Fridays and all hours on Saturdays,
Sundays, and holidays as defined in the PJM Manuals. Each bid shall specify
whether it is for an on-peak or off-peak period.
48
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7.3.5 Offers and Bids.
(a) Offers to sell and bids to purchase Fixed Transmission Rights
shall be submitted during the period set forth in Section 7.1.2, and shall be in
the form specified by the Office of the Interconnection in accordance with the
requirements set forth below.
(b) Offers to sell shall identify the specific Fixed Transmission
Right, by megawatt quantity and receipt and delivery points, offered for sale.
An offer to sell a specified megawatt quantity of Fixed Transmission Rights
shall constitute an offer to sell a quantity of Fixed Transmission Rights equal
to or less than the specified quantity. An offer to sell may not specify a
minimum quantity being offered. Each offer may specify a reservation price,
below which the offeror does not wish to sell the Fixed Transmission Right.
Offers submitted by entities holding rights to Fixed Transmission Rights
acquired other than by assignment in connection with reservations of Network
Transmission Service or Firm Point-to-Point Transmission Service shall be
subject to such reasonable standards for the verification of the rights of the
offeror as may be established by the Office of the Interconnection. Offers shall
be subject to such reasonable standards for the creditworthiness of the offeror
or for the posting of security for performance as the Office of the
Interconnection shall establish.
(c) Bids to purchase shall specify the megawatt quantity, price per
megawatt, and receipt and delivery points of the Fixed Transmission Right that
the bidder wishes to purchase. A bid to purchase a specified megawatt quantity
of Fixed Transmission Rights shall constitute a bid to purchase a quantity of
Fixed Transmission Rights equal to or less than the specified quantity. A bid to
purchase may not specify a minimum quantity that the bidder wishes to purchase.
A bid may specify as receipt or delivery points any bus for which the Office of
the Interconnection calculates and posts Locational Marginal Prices in
accordance with Section 2 of this Schedule and may include Fixed Transmission
Rights for which the associated Transmission Congestion Credits may have
negative values. Bids shall be subject to such reasonable standards for the
creditworthiness of the bidder or for the posting of security for performance as
the Office of the Interconnection shall establish.
(d) Bids and offers shall be specified to the nearest tenth of a
megawatt and shall be greater than zero.
49
<PAGE>
7.3.6 Determination of Winning Bids and Clearing Price.
(a) At the close of the bidding period each month, the Office of the
Interconnection will create a base Fixed Transmission Rights power flow model
that includes all outstanding Fixed Transmission Rights that have been approved
and confirmed for any portion of the month for which the auction was conducted
and that were not offered for sale in the auction. The base Fixed Transmission
Rights model also will include estimated uncompensated parallel flows into each
interface point of the PJM Control Area and estimated scheduled transmission
outages.
(b) In accordance with the requirements of Section 7.4 of this
Schedule and subject to all applicable transmission constraints and reliability
requirements, the Office of the Interconnection shall determine the simultaneous
feasibility of all outstanding Fixed Transmission Rights not offered for sale in
the auction and of all Fixed Transmission Rights that could be awarded in the
auction for which bids were submitted. The winning bids shall be determined from
an appropriate linear programming model that, while respecting transmission
constraints and the maximum MW quantities of the bids and offers, selects the
set of simultaneously feasible Fixed Transmission Rights with the highest net
total auction value as determined by the bids of buyers and taking into account
the reservation prices of the sellers. In the event that there are two or more
identical bids for the selected Fixed Transmission Rights and there are
insufficient Fixed Transmission Rights to accommodate all of the identical bids,
then each such bidder will receive a pro rata share of the Fixed Transmission
Rights that can be awarded.
(c) Fixed Transmission Rights shall be sold at the market-clearing
price for Fixed Transmission Rights between specified pairs of receipt and
delivery points, as determined by the bid value of the marginal Fixed
Transmission Right that could not be awarded because it would not be
simultaneously feasible. The linear programming model shall determine the
clearing prices of all Fixed Transmission Rights paths based on the bid value of
the marginal Fixed Transmission Rights, which are those Fixed Transmission
Rights with the highest bid values that could not be awarded fully because they
were not simultaneously feasible, and based on the flow sensitivities of each
Fixed Transmission Rights path relative to the marginal Fixed Transmission
Rights paths flow sensitivities on the binding transmission constraints.
7.3.7 Announcement of Winners and Prices.
Within two (2) business days after the close of an auction, the Office
of the Interconnection shall post the winning bidders, the megawatt quantity,
and the receipt and delivery points for each Fixed Transmission Right awarded in
the auction and the price at which each Fixed Transmission Right was awarded.
Results of the on-peak auction and off-peak auction will be posted separately.
The Office of the Interconnection shall not disclose the price specified in any
bid to purchase or the reservation price specified in any offer to sell.
50
<PAGE>
7.3.8 Auction Settlements.
All buyers and sellers of Fixed Transmission Rights between the same
points of receipt and delivery shall pay or be paid the market-clearing price,
as determined in the auction, for such Fixed Transmission Rights.
7.3.9 Allocation of Auction Revenues.
All auction revenues, net of payments to entities selling Fixed
Transmission Rights into the auction, shall be allocated among the Regional
Transmission Owners in proportion to their respective transmission revenue
requirements.
7.4 Simultaneous Feasibility.
The Office of the Interconnection shall make the simultaneous feasibility
determinations specified herein using appropriate powerflow models of
contingency-constrained dispatch. Such determinations shall take into account
outages of both individual generation units and transmission facilities and
shall be based on reasonable assumptions about the configuration and
availability of transmission capability during the period covered by the auction
that are not inconsistent with the determination of the deliverability of
Capacity Resources under the Reliability Assurance Agreement. The goal of the
simultaneous feasibility determination shall be to ensure that there are
sufficient revenues from Transmission Congestion Charges to satisfy all Fixed
Transmission Rights obligations for the auction period under expected
conditions.
51
<PAGE>
SCHEDULE 2
----------
Revision No. 2
COMPONENTS OF COST
------------------
Issued: June 2, 1997
Effective: January 1, 1998
(a) Each Market Participant obligated to sell operating capacity on the
PJM Interchange Energy Market at cost-based rates shall include the following
components or their equivalent in the determination of costs for operating
capacity supplied to or from the Interconnection:
(1) Boilers
-------
Firing-up cost;
No-load cost during period of operation;
Peak-prepared-for maintenance cost;
Incremental labor cost; and
Other incremental operating costs.
(2) Machines
--------
Starting cost from cold to synchronized operation;
No-load cost during period of operation;
Incremental labor cost; and
Other incremental operating costs.
(b) Each Member obligated to sell energy on the PJM Interchange Energy
Market at cost-based rates shall include the following components or their
equivalent in the determination of costs for energy supplied to the
Interconnection:
Incremental fuel cost;
Incremental maintenance cost;
Incremental labor cost; and
Other incremental operating costs.
(c) All fuel costs shall employ the marginal fuel price experienced by the
Member.
(d) The PJM Board, upon consideration of the advice and recommendations of
the Members Committee, shall from time to time define in detail the method of
determining the costs entering into the said components, and the Members shall
adhere to such definitions in the preparation of incremental costs used on the
Interconnection.
1
<PAGE>
SCHEDULE 2 -- EXHIBIT A
---------- ---------
EXPLANATION OF THE TREATMENT OF THE COSTS OF
--------------------------------------------
EMISSION ALLOWANCES
-------------------
Issued: June 2, 1997
Effective: January 1, 1998
The cost of emission allowances is included in "Other Incremental Operating
Costs" pursuant to Schedule 2. The replacement cost of emission allowances will
be used to recover the cost of emission allowances consumed as a result of
producing energy for the Interconnection.
Index
- -----
Consistent with definitions promulgated by the PJM Board upon consideration
of the advice and recommendations of the Members Committee under Schedule 2,
each Member subject to Schedule 2 will determine and provide to the
Interconnection its replacement cost of emission allowances, such cost to be an
amount not exceeding the market price index published by Cantor-Fitzgerald
Environmental Brokerage Services ("EBS"), or a PJM Board approved index in the
event that EBS should cease publication of such index. As with all other
components of cost required for accounting under this Agreement, each Member
subject to Schedule 2 will use the same replacement cost of emissions
allowances, so determined, as it uses for coordinating operation of its
generating facilities hereunder.
For each Member subject to Schedule 2, the cost of emissions allowances is
included in the cost of energy supplied to or received from the Interconnection.
Payment
- -------
The Members subject to Schedule 2 waive the right of payment-in-kind for
emission allowances for transactions wholly between the parties. Cash payments
for emission allowances consumed in providing energy for the Interconnection
shall be incorporated into and conducted pursuant to the billing procedures for
energy prescribed by this Agreement.
Calculation of Emission Allowance Amount and Cost
- -------------------------------------------------
Pursuant to the letter from the PJM Interconnection to FERC dated June 26,
1995, the calculation of an annual average for the cost of emission allowances,
described below, is required due to the profile of the PJM physical system and
PJM Energy Management software system. Approximately five hundred and forty
generating units comprise the PJM system, of which 9 units are Phase I units.
Current real-time operational software and hardware tools used in the
transaction of energy do not identify individual units, and therefore do not
identify Phase I units. (The pool has contracted with a vendor to supply a new
Energy Management System to be installed over the next several years.) It is
currently not possible for system operators to provide actual individual unit
emission allowance costs in real time transaction quotations.
An average emission allowance cost based on a standard production cost
study case will be used to calculate the average cost of emission allowances for
each pool megawatt produced. This cost for the current year is less than 0.2
dollars per megawatt-hour.
In summary, for the above-mentioned reasons, it is not practical nor cost
effective to provide actual individual emission allowance costs in real-time
transaction quotations. Therefore,
1
<PAGE>
the annual average method is proposed.
The Emission Allowances (Tons of SO\\2\\) associated with a transaction
will be calculated by multiplying the magnitude of a transaction (MWhr) by an
Emissions per MWHr Factor (Tons of SO\\2\\ per MWhr):
Emission Transaction Emissions
Allowances = Magnitude x per MWhr
Used Factor
(Tons of S0\\2\\) (MWhr) (Tons of S0\\2\\ per MWhr)
The Emissions per MWHr Factor will be calculated by dividing the forecast
annual emissions from all Phase I units (Tons of S0\\2\\) by the Forecast Annual
Total PJM Energy Production (MWhr):
Emissions
per MWhr = Forecast Annual Phase I Unit Emissions (Tons of S0\\2\\)
-------------------------------------------------------
Factor Forecast Annual Total PJM Energy Production (MWhr)
(Tons of S0\\2\\
per MWhr)
Likewise, the cost (Dollars) of the Emission Allowances for a transaction
will be calculated by multiplying the transaction magnitude (MWhr) by a Charge
per MWhr Factor (Dollars per MWHr).
Cost of Emission Transaction Charge
Allowances Used = Magnitude x per MWhr Factor
(Dollars) (MWhr) (Dollars per MWhr)
The Charge per MWhr Factor will be calculated by multiplying, for each
Member subject to Schedule 2, its Forecast Annual Emissions (Tons of S0\\2\\) by
its respective Emissions Allowance Replacement Cost (Dollars per Ton of S0\\2\\)
to yield each the forecasted annual cost of emissions (Dollars). Then, the
total of forecasted annual cost of emissions for each Member subject to Schedule
2 is divided by the Forecast Annual Total PJM Energy Production (MWhr) to
determine the Charge per MWHr Factor (Dollars per MWHr).
Charge per
MWhr Factor = the sum of(A x B) , where:
-------
C
A = Member's Forecasted Annual Emissions, (Tons of S0\\2\\)
B = Emission Allowance Replacement Cost, (Dollars per Ton of SO\\2\\,
per company)
C = Forecast Annual PJM Energy Production, (MWhr)
2
<PAGE>
SCHEDULE 3
----------
Revision No. 6
ALLOCATION OF THE COST AND EXPENSES
-----------------------------------
OF THE OFFICE OF THE INTERCONNECTION
------------------------------------
Issued: June 2, 1997
Effective: January 1, 1998
(a) Each group of Affiliates, each group of Related Parties, and each
Member that is not in such a group shall pay an annual membership fee, the
proceeds of which shall be used to defray the costs and expenses of the LLC,
including the Office of the Interconnection. The amount of the annual fee as of
the Effective Date shall be $5,000. The amount of the annual membership fee
shall be adjusted from time to time by the PJM Board to keep pace with
inflation.
(b) All remaining costs of the operation of the LLC and the Office of the
Interconnection and the expenses, including, without limitation, the costs of
any insurance and any claims not covered by insurance, associated therewith as
provided in this Agreement shall be costs of Scheduling, System Control and
Dispatching Service under the PJM Tariff and shall be recovered pursuant to the
PJM Tariff.
(c) An entity accepted for membership in the LLC shall pay all costs and
expenses associated with additions and modifications to its own metering,
communication, computer, and other appropriate facilities and procedures needed
to effect the inclusion of the entity in the operation of the Interconnection.
1
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SCHEDULE 4
----------
Revision No. 1
STANDARD FORM OF AGREEMENT TO BECOME A MEMBER OF THE LLC
--------------------------------------------------------
Issued: June 2, 1997
Effective: January 1, 1998
Any entity which wishes to become a Member of the LLC shall, pursuant to
Section 11.6 of this Agreement, tender to the President an application, upon the
acceptance of which it shall execute a supplement to this Agreement in the
following form:
Additional Member Agreement
---------------------------
1. This Additional Member Agreement (the "Supplemental Agreement"), dated as
of __________________, is entered into among _____________ and the President of
the LLC acting on behalf of its Members.
2. _____________ has demonstrated that it meets all of the qualifications
required of a Member to the Operating Agreement. If expansion of the PJM
Control Area is required to integrate ____________________'s facilities, a copy
of Attachment J from the PJM Tariff marked to show changes in Control Area
boundaries is attached hereto. ____________________ agrees to pay for all
required metering, telemetering and hardware and software appropriate for it to
become a member.
3. ______________________ agrees to be bound by and accepts all the terms of
the Operating Agreement as of the above date.
4. _________________________ hereby gives notice that the name and address of
its initial representative to the Members Committee under the Operating
Agreement shall be:
__________________________________________________________________
5. The President of the LLC is authorized under the Operating Agreement to
execute this Supplemental Agreement on behalf of the Members and to file it with
regulatory authorities having jurisdiction.
6. The Operating Agreement is hereby amended to include ___________ as a
Member of the LLC thereto, effective as of ___________________, _____.
IN WITNESS WHEREOF, _______________________ and the Members of the LLC have
caused this Supplemental Agreement to be executed by their duly authorized
representatives.
1
<PAGE>
Members of the LLC
By:
Name:
Title: President
By:
Name:
Title:
2
<PAGE>
SCHEDULE 5
-----------
Revision No. 1
PJM DISPUTE RESOLUTION PROCEDURES
---------------------------------
Issued: June 2, 1997
Effective: January 1, 1998
1. DEFINITIONS
1.1 Alternate Dispute Resolution Committee.
"Alternate Dispute Resolution Committee" shall mean the Committee
established pursuant to Section 5 of this Schedule.
1.2 MAAC Dispute Resolution Committee.
"MAAC Dispute Resolution Committee" shall mean the committee established by
the Mid-Atlantic Area Council to administer its industry-specific mechanism for
resolving certain types of wholesale electricity disputes.
1.3 Related PJM Agreements.
"Related PJM Agreements" shall mean this Agreement, the Transmission Owners
Agreement, and the Reliability Assurance Agreement.
2. PURPOSES AND OBJECTIVES
2.1 Common and Uniform Procedures.
The PJM Dispute Resolution Procedures are intended to establish common and
uniform procedures for resolving disputes arising under the Related PJM
Agreements. To the extent any of the foregoing agreements or the PJM Tariff
contain dispute resolution provisions expressly applicable to disputes arising
thereunder, however, this Agreement shall not supplant such provisions, which
shall apply according to their terms.
2.2 Interpretation.
To the extent permitted by applicable law, the PJM Dispute Resolution
Procedures are to be interpreted to effectuate the objectives set forth in
Section 2.1. To the extent permitted by these PJM Dispute Resolution
Procedures, the Alternate Dispute Resolution Committee shall coordinate with the
MAAC Dispute Resolution Committee, where appropriate, in order to conserve
administrative resources and to avoid duplication of dispute resolution
staffing.
<PAGE>
NEGOTIATION AND MEDIATION
3.1 When Required.
The parties to a dispute shall undertake good-faith negotiations to resolve
any dispute as to a matter governed by one of the Related PJM Agreements. Each
party to a dispute shall designate an executive with authority to resolve the
matter in dispute to participate in such negotiations. Any dispute as to a
matter governed by one of the Related PJM Agreements that has not been resolved
through good-faith negotiation shall be subject to non-binding mediation prior
to the initiation of arbitral, regulatory, judicial, or other dispute resolution
proceedings as may be appropriate as provided by these PJM Dispute Resolution
Procedures.
3.2 Procedures.
3.2.1 Initiation.
If a dispute that is subject to the mediation procedures specified
herein has not been resolved through good-faith negotiation, a party to the
dispute shall notify the Alternate Dispute Resolution Committee in writing of
the existence and nature of the dispute prior to commencing any other form of
proceeding for resolution of the dispute. The Alternate Dispute Resolution
Committee shall have ten calendar days from the date it first receives
notification of the existence of a dispute from any of the parties to the
dispute in which to distribute to the parties a list of mediators.
3.2.2 Selection of Mediator.
The Chair of the Alternate Dispute Resolution Committee shall
distribute to the parties by facsimile or other electronic means a list
containing the names of seven mediators with mediation experience, or with
technical or business experience in the electric power industry, or both, as it
shall deem appropriate to the dispute. The Chair of the Alternate Dispute
Resolution Committee may draw from the lists of mediators maintained by the MAAC
Dispute Resolution Committee, as the Chair shall deem appropriate. The persons
on the proposed list of mediators shall have no official, financial, or personal
conflict of interest with respect to the issues in controversy, unless the
interest is fully disclosed in writing to all participants in the mediation
process and all such participants waive in writing any objection to the
interest. The parties shall alternate in striking names from the list with the
last name on the list becoming the mediator. The determination of which party
shall have the first strike off the list shall be determined by lot. The
parties shall have ten calendar days to complete the mediator selection process,
unless the time is extended by mutual agreement.
3.2.3 Advisory Mediator.
If the Alternate Dispute Resolution Committee deems it appropriate, it
shall distribute two lists, one containing the names of seven mediators with
mediation experience, and one containing the names of seven mediators with
technical or business experience in the electric power industry. In connection
with circulating the foregoing lists, the Alternate Dispute Resolution Committee
shall specify one of the lists as containing the proposed mediators, and the
other as a list of proposed advisors to assist the mediator in resolving the
dispute. The parties shall then utilize the alternative strike procedure set
forth above until one name remains on each list, with the last named persons
serving as the mediator and advisor.
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3.2.4 Mediation Process.
The disputing parties shall attempt in good faith to resolve their
dispute in accordance with procedures and a timetable established by the
mediator. In furtherance of the mediation efforts, the mediator may:
(a) Require the parties to meet for face-to-face discussions, with or
without the mediator;
(b) Act as an intermediary between the disputing parties;
(c) Require the disputing parties to submit written statements of
issues and positions;
(d) If requested by the disputing parties at any time in the mediation
process, provide a written recommendation on resolution of the dispute
including, if requested, the assessment by the mediator of the merits of the
principal positions being advanced by each of the disputing parties; and
(e) Adopt, when appropriate, the Center for Public Resources Model ADR
Procedures for the Meditation of Business Disputes (as revised from time to
time) to the extent such Procedures are not inconsistent with any rule,
standard, or procedure adopted by the Alternate Dispute Resolution Committee or
with any provision of this Agreement.
3.2.5 Mediator's Assessment.
(a) If a resolution of the dispute is not reached by the thirtieth day
after the appointment of the mediator or such later date as may be agreed to by
the parties, if not previously requested to do so the mediator shall promptly
provide the disputing parties with a written, confidential, non-binding
recommendation on resolution of the dispute, including the assessment by the
mediator of the merits of the principal positions being advanced by each of the
disputing parties. The recommendation may incorporate or append, if and as the
mediator may deem appropriate, any recommendations or any assessment of the
positions of the parties by the advisor, if any. Upon request, the mediator
shall provide any additional recommendations or assessments the mediator shall
deem appropriate.
(b) At a time and place specified by the mediator after delivery of
the foregoing recommendation, the disputing parties shall meet in a good faith
attempt to resolve the dispute in light of the recommendation of the mediator.
Each disputing party shall be represented at the meeting by a person with
authority to settle the dispute, along with such other persons as each disputing
party shall deem appropriate. If the disputing parties are unable to resolve
the dispute at or in connection with this meeting, then: (i) any disputing party
may commence such arbitral, judicial, regulatory or other proceedings as may be
appropriate as provided in the PJM Dispute Resolution Procedures; and (ii) the
recommendation of the mediator, and any statements made by any party in the
mediation process, shall have no further force or effect, and shall not be
admissible for any purpose, in any subsequent arbitral, administrative,
judicial, or other proceeding.
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3.3 Costs.
Except as specified in Section 4.13, the costs of the time, expenses, and
other charges of the mediator and any advisor, and of the mediation process,
shall be borne by the parties to the dispute, with each side in a mediated
matter bearing one-half of such costs, and each party bearing its own costs and
attorney's fees incurred in connection with the mediation.
4. ARBITRATION
4.1 When Required.
Any dispute as to a matter: (i) governed by one of the Related PJM
Agreements that has not been resolved through the mediation procedures specified
herein, (ii) involving a claim that one or more of the parties owes or is owed a
sum of money, and (iii) the amount in controversy is less than $1,000,000.00,
shall be subject to binding arbitration in accordance with the procedures
specified herein. If the parties so agree, any other disputes as to a matter
governed by a Related PJM Agreement may be submitted to binding arbitration in
accordance with the procedures specified herein.
4.2 Binding Decision.
Except as specified in Section 4.1, the resolution by arbitration of any
dispute under this Agreement shall not be binding.
4.3 Initiation.
A party or parties to a dispute which is subject to the arbitration
procedures specified herein shall send a written demand for arbitration to the
Chair of the Alternate Dispute Resolution Committee with a copy to the other
party or parties to the dispute. The demand for arbitration shall state each
claim for which arbitration is being demanded, the relief being sought, a brief
summary of the grounds for such relief and the basis for the claim, and shall
identify all other parties to the dispute.
4.4 Selection of Arbitrator(s).
The parties to a dispute for which arbitration has been demanded may agree
on any person to serve as a single arbitrator, or shall endeavor in good faith
to agree on a single arbitrator from a list of arbitrators prepared for the
dispute by the Alternate Dispute Resolution Committee and delivered to the
parties by facsimile or other electronic means promptly after receipt by the
Alternate Dispute Resolution Committee of a demand for arbitration. The
Alternate Dispute Resolution Committee may draw from the lists of arbitrators
maintained by the MAAC Dispute Resolution Committee, as the Alternate Dispute
Resolution Committee deems appropriate. If the parties are unable to agree on a
single arbitrator by the fourteenth day following delivery of the foregoing list
of arbitrators or such other date as agreed to by the parties, then not later
than the end of the seventh business day thereafter the party or parties
demanding arbitration on the one hand, and the party or parties responding to
the demand for arbitration on the other, shall each designate an arbitrator from
a list for the dispute prepared by the Alternate Dispute Resolution Committee.
The arbitrators so chosen shall then choose a third arbitrator.
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4.5 Procedures.
The Alternate Dispute Resolution Committee shall compile and make available
to the arbitrator(s) and the parties standard procedures for the arbitration of
disputes, which procedures (i) shall include provision, upon good cause shown,
for intervention or other participation in the proceeding by any party whose
interests may be affected by its outcome, (ii) shall conform to the requirements
specified in these PJM Dispute Resolution Procedures, and (iii) may be modified
or adopted for use in a particular proceeding as the arbitrator(s) deem
appropriate. To the extent deemed appropriate by the Alternate Dispute
Resolution Committee, the procedures adopted by the Alternate Dispute Resolution
Committee shall be based on the American Arbitration Association Rules, to the
extent such Rules are not inconsistent with any rule, standard or procedure
adopted by the Alternate Dispute Resolution Committee, or with any provision of
these PJM Dispute Resolution Procedures. Upon selection of the arbitrator(s),
arbitration shall go forward in accordance with applicable procedures.
4.6 Summary Disposition and Interim Measures.
4.6.1 Lack of Good Faith Basis.
The procedures for arbitration of a dispute shall provide a means for
summary disposition of a demand for arbitration, or a response to a demand for
arbitration, that in the reasoned opinion of the arbitrator(s) does not have a
good faith basis in either law or fact. If the arbitrator(s) determine(s) that
a demand for arbitration or response to a demand for arbitration does not have a
good faith basis in either law or fact, the arbitrator(s) shall have discretion
to award the costs of the time, expenses, and other charges of the arbitrator(s)
to the prevailing party.
4.6.2 Discovery Limits.
The procedures for the arbitration of a dispute shall provide a means
for summary disposition without discovery of facts if there is no dispute as to
any material fact, or with such limited discovery as the arbitrator(s) shall
determine is reasonably likely to lead to the prompt resolution of any disputed
issue of material fact.
4.6.3 Interim Decision.
The procedures for the arbitration of a dispute shall permit any party
to a dispute to request the arbitrator(s) to render a written interim decision
requiring that any action or decision that is the subject of a dispute not be
put into effect, or imposing such other interim measures as the arbitrator(s)
deem necessary or appropriate, to preserve the rights and obligations secured by
any of the Related PJM Agreements during the pendency of the arbitration
proceeding. The parties shall be bound by such written decision pending the
outcome of the arbitration proceeding.
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4.7 Discovery of Facts.
4.7.1 Discovery Procedures.
The procedures for the arbitration of a dispute shall include adequate
provision for the discovery of relevant facts, including the taking of testimony
under oath, production of documents and other things, and inspection of land and
tangible items. The nature and extent of such discovery shall be determined as
provided herein and shall take into account (i) the complexity of the dispute,
(ii) the extent to which facts are disputed, and (iii) the amount in
controversy. The forms and methods for taking such discovery shall be as
described in the Federal Rules of Civil Procedure, except as modified by the
procedures established by the Alternate Dispute Resolution Committee, the
arbitrator(s) or agreement of the parties.
4.7.2 Procedures Arbitrator.
The sole arbitrator, or the arbitrator selected by the arbitrators
chosen by the parties, as the case may be (such arbitrator being hereafter
referred to as the "Procedures Arbitrator"), shall be responsible for
establishing the timing, amount, and means of discovery, and for resolving
discovery and other pre-hearing disagreement. If a dispute involves contested
issues of fact, promptly after the selection of the arbitrator(s) the Procedures
Arbitrator shall convene a meeting of the parties for the purpose of
establishing a schedule and plan of discovery and other pre-hearing actions.
4.8 Evidentiary Hearing.
The procedures for the arbitration of a dispute shall provide for an
evidentiary hearing, with provision for the cross-examination of witnesses,
unless all parties consent to the resolution of the matter on the basis of a
written record. The forms and methods for taking evidence shall be as described
in the Federal Rules of Evidence, except as modified by the procedures
established by the Alternate Dispute Resolution Committee, the arbitrator(s) or
agreement of the parties. The arbitrator(s) may require such written or other
submissions from the parties as shall be deemed appropriate, including
submission of the direct testimony of witnesses in written form. The
arbitrator(s) may exclude any evidence that is irrelevant, immaterial, unduly
repetitious or prejudicial, or privileged. Any party or parties may arrange for
the preparation of a record of the hearing, and shall pay the costs thereof.
Such party or parties shall have no obligation to provide or agree to the
provision of a copy of the record of the hearing to any party that does not pay
an equal share of the cost of the record. At the request of any party, the
arbitrator(s) shall determine a fair and equitable allocation of the costs of
the preparation of a record between or among the parties to the proceeding
willing to share such costs.
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4.9 Confidentiality.
4.9.1 Designation.
Any document or other information obtained in the course of an
arbitral proceeding and not otherwise available to the receiving party,
including any such information contained in documents or other means of
recording information created during the course of the proceeding, may be
designated "Confidential" by the producing party. The party producing documents
or other information marked "Confidential" shall have twenty days from the
production of such material to submit a request to the Procedures Arbitrator to
establish such requirements for the protection of such documents or other
information designated as "Confidential" as may be reasonable and necessary to
protect the confidentiality and commercial value of such information and the
rights of the parties, which requirements shall be binding on all parties to the
dispute. Prior to the decision of the Procedures Arbitrator on a request for
confidential treatment, documents or other information designated as
"Confidential" shall not be used by the receiving party or parties, or the
arbitrator(s), or anyone working for or on behalf of any of the foregoing, for
any purpose other than the arbitration proceeding, and shall not be disclosed in
any form to any person not involved in the arbitration proceeding without the
prior written consent of the party producing the information or as permitted by
the Procedures Arbitrator.
4.9.2 Compulsory Disclosure.
Any party receiving a request or demand for disclosure, whether by
compulsory process, discovery request, or otherwise, of documents or information
obtained in the course of an arbitration proceeding that have been designated
"Confidential" and that are subject to a non-disclosure requirement under these
PJM Dispute Resolution Procedures or a decision of the Procedures Arbitrator,
shall immediately inform the party from which the information was obtained, and
shall take all reasonable steps, short of incurring sanctions or other
penalties, to afford the person or entity from which the information was
obtained an opportunity to protect the information from disclosure. Any party
disclosing information in violation of these PJM Dispute Resolution Procedures
or requirements established by the Procedures Arbitrator shall thereby waive any
right to introduce or otherwise use such information in any judicial,
regulatory, or other legal or dispute resolution proceeding, including the
proceeding in which the information was obtained.
4.9.3 Public Information.
Nothing in the Related PJM Agreements shall preclude the use of
documents or information properly obtained outside of an arbitral proceeding, or
otherwise public, for any legitimate purpose, notwithstanding that the
information was also obtained in the course of the arbitral proceeding.
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4.10 Timetable.
Promptly after the selection of the arbitrator(s), the arbitrator(s) shall
set a date for the issuance of the arbitral decision, which shall be not later
than eight months (or such earlier date as may be agreed to by the parties to
the dispute) from the date of the selection of the arbitrator(s), with other
dates, including the dates for an evidentiary hearing or other final submissions
of evidence, set in light of this date. The date for the evidentiary hearing or
other final submission of evidence shall not be changed absent extraordinary
circumstances. The arbitrator(s) shall have the power to impose sanctions,
including dismissal of the proceeding for dilatory tactics or undue delay in
completing the arbitral proceedings.
4.11 Advisory Interpretations.
Except as to matters subject to decision in the arbitration proceeding, the
arbitrator(s) may request as may be appropriate from any committee or
subcommittee established under a Related PJM Agreement or by the Office of the
Interconnection, an interpretation of any Related PJM Agreements, or of any
standard, requirement, procedure, tariff, Schedule, principle, plan or other
criterion or policy established by any committee or subcommittee. Except to the
extent that the Office of the Interconnection is itself a party to a dispute,
the arbitrator(s) may request the advice of the Office of the Interconnection
with respect to any matter relating to a responsibility of the Office of the
Interconnection under the Agreement or with respect to any of the Related PJM
Agreements, or to the PJM Manuals. Any such interpretation or advice shall not
relieve the arbitrator(s) of responsibility for resolving the dispute or
deciding the arbitration proceeding in accordance with the standards specified
herein.
4.12 Decisions.
The arbitrator(s) shall issue a written decision, including findings of
fact and the legal basis for the decision. The arbitral decision shall be based
on (i) the evidence in the record, (ii) the terms of the Related PJM Agreements,
as applicable, (iii) applicable United States federal and state law, including
the Federal Power Act and any applicable FERC regulations and decisions, and
international treaties or agreements as applicable, and (iv) relevant decisions
in previous arbitration proceedings. The arbitrator(s) shall have no authority
to revise or alter any provision of the Related PJM Agreements. Any arbitral
decision issued pursuant to these PJM Dispute Resolution Procedures that affects
matters subject to the jurisdiction of FERC under Section 205 of the Federal
Power Act shall be filed with FERC.
4.13 Costs.
Unless the arbitrator(s) shall decide otherwise, the costs of the time,
expenses, and other charges of the arbitrator(s) shall be borne by the parties
to the dispute, with each side on an arbitrated issue bearing its pro-rata share
of such costs, and each party to an arbitral proceeding shall bear its own costs
and fees. The arbitrator(s) may award all or a portion of the costs of the
time, expenses, and other charges of the arbitrator(s), the costs of
arbitration, attorney"s fees, and the costs of mediation, if any, to any party
that substantially prevails on an issue determined by the arbitrator(s) to have
been raised without a substantial basis.
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4.14 Enforcement.
If the decision of the arbitrator(s) is binding, the judgment may be
entered on such arbitral award by any court having jurisdiction thereof;
provided, however, that within one year of the issuance of the arbitral decision
any party affected thereby may request FERC or any other federal, state,
regulatory or judicial authority having jurisdiction to vacate, modify, or take
such other action as may be appropriate with respect to any arbitral decision
that is based upon an error of law, or is contrary to the statutes, rules, or
regulations administered or applied by such authority. Any party making or
responding to, or intervening in proceedings resulting from, any such request,
shall request the authority to adopt the resolution, if not clearly erroneous,
of any issue of fact expressly or necessarily decided in the arbitral
proceeding, whether or not the party participated in the arbitral proceeding.
5. ALTERNATE DISPUTE RESOLUTION COMMITTEE
5.1 Membership.
5.1.1 Representatives.
The Alternate Dispute Resolution Committee shall be composed of two
representatives selected by each of the following: (i) the Office of the
Interconnection; (ii) the Members Committee; (iii) the parties to the
Reliability Assurance Agreement; and (iv) the parties to the Transmission Owners
Agreement.
5.1.2 Term.
Representatives on the Alternate Dispute Resolution Committee shall
serve for terms of three years and may serve additional terms.
5.2 Voting Requirements.
Approval or adoption of measures by the Alternate Dispute Resolution
Committee shall require two-thirds of the votes of the representatives present
and voting. Two-thirds of the representatives on the Alternate Dispute
Resolution Committee shall constitute a quorum for the conduct of business.
5.3 Officers.
At the first meeting of the Alternate Dispute Resolution Committee, the
representatives to the Alternate Dispute Resolution Committee shall choose a
Chair and Vice Chair from among the representatives on the Committee. The Chair
of the Alternate Dispute Resolution Committee shall preside at meetings of the
Committee, and shall have the power to call meetings of the Committee and to
exercise such other powers as are specified in this Agreement or are authorized
by the Alternate Dispute Resolution Committee. The Vice Chair shall preside at
meetings of the Alternate Dispute Resolution Committee in the absence of the
Chair, and shall exercise such other powers as are delegated by the Chair.
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5.4 Meetings.
The Alternate Dispute Resolution Committee shall meet at such times and
places as determined by the Committee, or at the call of the Chair. The Chair
shall call a meeting of the Alternate Dispute Resolution Committee upon the
request of two or more representatives on the Alternate Dispute Resolution
Committee.
5.5 Responsibilities.
The duties of the Alternate Dispute Resolution Committee include but are
not limited to the following:
i) Maintain a list of persons qualified by temperament and
experience, and with technical or legal expertise in matters
likely to be the subject of disputes, to serve as mediators or
arbitrators under these PJM Dispute Resolution Procedures;
ii) Determine the rates and other costs and charges that shall be
paid to mediators, advisors and arbitrators for or in connection
with their services;
iii) Determine whether mediation is not warranted in a particular
dispute;
iv) Provide to disputing parties lists of mediators, advisors or
arbitrators to resolve particular disputes;
v) Compile and make available to parties to disputes, arbitrators,
and other interested persons suggested procedures for the
arbitration of disputes in accordance with Section 4.5;
vi) Maintain and make available to parties to disputes, mediators,
advisors, arbitrators, and other interested persons the written
decisions required by Section 4.12;
vii) Establish such procedures and schedules, in addition to those
specified herein, as it shall deem appropriate to further the
prompt, efficient, fair and equitable resolution of disputes;
and
viii) Provide such oversight and supervision of the dispute resolution
processes and procedures instituted pursuant to the Related PJM
Agreements as may be appropriate to facilitate the prompt,
efficient, fair and equitable resolution of disputes.
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SCHEDULE 6
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Revision No. 1
REGIONAL TRANSMISSION EXPANSION PLANNING PROTOCOL
-------------------------------------------------
Issued: June 2, 1997
Effective: January 1, 1998
1. REGIONAL TRANSMISSION EXPANSION PLANNING PROTOCOL
Purpose and Objectives
This Regional Transmission Expansion Planning Protocol shall govern
the process by which the Members shall rely upon the Office of the
Interconnection to prepare a plan for the enhancement and expansion of the
Transmission Facilities in order to meet the demands for firm transmission
service in the PJM Control Area. The Regional Transmission Expansion Plan to be
developed shall enable the transmission needs in the PJM Control Area to be met
on a reliable, economic and environmentally acceptable basis.
1.2 Conformity with NERC and MAAC Criteria
(a) NERC establishes Planning Principles and Guides to promote the
reliability and adequacy of the North American bulk power supply as related to
the operation and planning of electric systems.
(b) MAAC is responsible for ensuring the adequacy, reliability and security
of the bulk electric supply systems in the MAAC region through coordinated
operations and planning of generation and transmission facilities. Toward that
end, it has adopted the NERC Planning Principles and Guides and has established
detailed Reliability Principles and Standards for Planning the Bulk Electric
Supply System of the MAAC Group.
(c) The Regional Transmission Expansion Plan shall conform with the
applicable reliability principles, guidelines and standards of NERC and MAAC in
accordance with the procedures detailed in the PJM Manuals.
1.3 Establishment of Committees
(a) The Regional Transmission Owners shall supply representatives to the
Planning Committee to provide the data, information, and analysis support
necessary to perform studies as required. As used herein, "Regional
Transmission Owner" shall be defined as it is in the PJM Open Access
Transmission Tariff ("PJM Tariff").
(b) The Transmission Expansion Advisory Committee established by the Office
of the Interconnection will provide input to the development of the Regional
Transmission Expansion Plan. The Transmission Expansion Advisory Committee will
invite participation by: (i) all Transmission Customers, as that term is
defined in the PJM Tariff, and applicants for transmission service; (ii) any
other entity proposing to provide Transmission Facilities to be integrated into
the
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PJM Control Area; (iii) all Members; (iv) the agencies and offices of consumer
advocates of the States in the PJM Control Area exercising regulatory authority
over the rates, terms or conditions of electric service or the planning, siting,
construction or operation of electric facilities and (v) any other interested
entities or persons.
1.4 Contents of the Regional Transmission Expansion Plan
(a) The Office of the Interconnection shall prepare the Regional
Transmission Expansion Plan, which shall consolidate the transmission needs of
the region into a single plan which is assessed on the basis of maintaining the
PJM Control Area"s reliability in an economic and environmentally acceptable
manner.
(b) The Regional Transmission Expansion Plan shall reflect transmission
enhancements and expansions, load and capacity forecasts and generation
additions and retirements for the ensuing ten years.
(c) The Regional Transmission Expansion Plan shall, as a minimum, include a
designation of the Regional Transmission Owner or Owners or other entity that
will own a transmission facility and how all reasonably incurred costs are to be
recovered.
(d) The Regional Transmission Expansion Plan shall (i) avoid unnecessary
duplication of facilities; (ii) avoid the imposition of unreasonable costs on
any Regional Transmission Owner or any user of Transmission Facilities; (iii)
take into account the legal and contractual rights and obligations of the
Regional Transmission Owners; (iv) provide, if appropriate, alternative means
for meeting transmission needs in the PJM Control Area; and (v) provide for
coordination with existing transmission systems and with appropriate
interregional and local expansion plans.
1.5 Procedure for Development of the Regional Transmission Expansion Plan
1.5.1 Commencement of the Process
(a) The Office of the Interconnection shall initiate the enhancement
and expansion study process if (i) required as a result of a need for transfer
capability identified by the Office of the Interconnection in its evaluation of
requests for firm transmission service with a term of one year or more or as a
result of the Office of the Interconnection's on-going evaluation of
transmission system adequacy and performance; (ii) identified as a result of the
MAAC reliability assessment or more stringent local reliability criteria, if
any; (iii) constraints or available transfer capability shortage are identified
by the Office of the Interconnection as a result of generation additions or
retirements, evaluation of load forecasts or proposals for the addition of
Transmission Facilities in the PJM Control Area; or (iv) expansion of the
transmission system is proposed by the Regional Transmission Owners or others.
(b) The Office of the Interconnection shall notify the Transmission
Expansion Advisory Committee of the commencement of an enhancement and expansion
study. The Transmission Expansion Advisory Committee shall notify the Office of
the Interconnection in writing of any additional transmission considerations to
be included.
Revised: September 24, 1998
Effective: January 1, 1999
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1.5.2 Development of Scope, Assumptions and Procedures
Once the need for an enhancement and expansion study has been
established, the Office of the Interconnection shall consult with the
Transmission Expansion Advisory Committee to prepare the study"s scope,
assumptions and procedures.
1.5.3 Scope of Studies
In general, enhancement and expansion studies shall include:
(a) An identification of existing and projected electric system
limitations, with accompanying simulations to identify the costs of controlling
those limitations. Potential enhancements and expansions will be proposed to
mitigate limitations controlled by non-economic means.
(b) Evaluation and analysis of potential enhancements and
expansions, including alternatives thereto, needed to mitigate such limitations.
(c) Engineering studies needed to determine the effectiveness and
compliance (with reliability criteria) of recommended enhancements and
expansions.
1.5.4 Supply of Data
(a) The Regional Transmission Owners shall provide to the Office of
the Interconnection on an annual basis a 10-year forecast of summer and winter
load and resources expected to be served by, or use, their Transmission
Facilities. The forecast shall include to the extent known or reasonably
capable of forecast: (i) a description of the total load to be served from each
substation; (ii) the amount of any interruptible loads included in the total
load (including conditions under which an interruption can be implemented and
any limitations on the duration and frequency of interruptions); and (iii) a
description of all generation resources to be located in the geographic region
encompassed by the Regional Transmission Owner"s transmission facilities,
including unit sizes, VAR capability, operating restrictions, and any must-run
unit designations required for system reliability or contract reasons. The data
required under this section shall be provided in the form and manner specified
by the Office of the Interconnection.
(b) In addition to the foregoing, the Regional Transmission Owners,
those entities requesting transmission service and any other entities proposing
to provide Transmission Facilities to be integrated into the PJM Control Area
shall supply any other information and data reasonably required by the Office of
the Interconnection to perform the enhancement and expansion study.
1.5.5 Coordination of the Regional Transmission Expansion Plan
(a) The Regional Transmission Expansion Plan shall be developed in
coordination with the transmission systems of the surrounding regional
reliability councils and with the local transmission providers.
(b) The Regional Transmission Expansion Plan shall be developed by
the Office of the Interconnection in consultation with the Transmission
Expansion Advisory Committee during the enhancement and expansion study process.
Revised: September 24, 1998
Effective: January 1, 1999
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1.5.6 Development of the Recommended Regional Transmission Expansion
Plan
(a) Upon completion of its studies and analysis, the Office of the
Interconnection shall prepare a recommended enhancement and expansion plan for
review by the Transmission Expansion Advisory Committee. The recommended plan
shall include recommendations for cost responsibility, except for directly
assigned costs, for any enhancement or expansion, based on the planning analysis
and other input from participants, including any indications of a willingness to
bear cost responsibility for an enhancement or expansion.
(b) For the purposes of Section 1.5.6(a), any allocation of costs
to all of the Regional Transmission Owners shall be proportional to the load
within the Zones. Load shall be measured consistent with the loads utilized to
develop the rates included in Attachment H to the PJM Tariff.
(c) Any Regional Transmission Owner and other participants on the
Revised: September 24, 1998
Effective: January 1, 1999
3a
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Transmission Expansion Advisory Committee may offer an alternative.
(d) If the Office of the Interconnection adopts the alternative,
based upon its review of the relative costs and benefits, the ability of the
alternative to supply the required level of transmission service, and its impact
on the reliability of the Transmission Facilities, the Office of the
Interconnection shall make any necessary changes to the recommended plan.
(e) If, based upon its review of the relative costs and benefits,
the ability of the alternative to supply the required level of transmission
service, and the alternative"s impact on the reliability of the Transmission
Facilities, the Office of the Interconnection does not adopt such alternative,
the Regional Transmission Owner or Owners whose alternative or alternatives have
not been accepted or to whom cost responsibility has been assigned and other
participants on the Transmission Expansion Advisory Committee may require that
its or their alternative(s) be submitted to Alternative Dispute Resolution.
1.6 Approval of the Final Regional Transmission Expansion Plan
(a) The PJM Board shall approve the final Regional Transmission Expansion
Plan, including any alternatives therein, in accordance with the requirements of
this Section 1.6.
(b) If the facilities to be provided in the Regional Transmission
Expansion Plan are acceptable, but the Regional Transmission Owners and other
entities who have indicated a willingness to bear some or all of the cost
responsibility cannot unanimously agree on the allocation of the costs of
enhancements or expansions, the cost responsibility shall be allocated (a) to
those entities who have indicated a willingness to bear some or all of the cost
of responsibility, and (b) among the Regional Transmission Owners in accordance
with the following guidelines :
i) All of the costs of Transmission Facilities (other than
transformers) with a nominal operating voltage of 500 kV or
higher shall be allocated to all of the Regional Transmission
Owners;
ii) One-half of the costs of Transmission Facilities (other than
transformers) with a nominal operating voltage of 230 kV or 345
kV shall be allocated to all Regional Transmission Owners and
one-half of the costs of such facilities shall be allocated to
the Regional Transmission Owners in whose Zone, as that term is
defined in the PJM Tariff, the enhancement or expansion is to be
located;
iii) All of the costs of Transmission Facilities (other than
transformers) with a nominal operating voltage below 230 kV shall
be allocated to the Regional Transmission Owner or Owners in
whose Zone the enhancement or expansion is located;
iv) One-half of the costs of transformers shall be allocated in
accordance with the methodology specified in (a), (b), or (c)
above, based upon the voltage at the high side of the transformer
and one-half of the costs shall be allocated in accordance with
the methodology specified in (a), (b), and (c) above based upon
the voltage at the low side of the transformer, unless the low
side of the transformer is less than 100 kV, in which case all of
the costs of the transformer shall be allocated to the Regional
Transmission Owner or
4
<PAGE>
Owners in whose Zone the transformer is located.
If a Regional Transmission Expansion Plan is not approved, or if the
transmission service requested by any entity is not included in an approved
Regional Transmission Expansion Plan, nothing herein shall limit in any way the
right of any entity to seek relief pursuant to the provisions of Section 211 of
the Federal Power Act.
(d) Following PJM Board approval, the final Regional Transmission
Expansion Plan shall be submitted to MAAC for verification that all enhancements
or expansions conform to all MAAC Reliability Principles and Standards.
1.7 Obligation to Build
(a) Subject to the requirements of applicable law, government regulations
and approvals, including, without limitation, requirements to obtain any
necessary state or local siting, construction and operating permits, to the
availability of required financing, to the ability to acquire necessary right-
of-way, and to the right to recover, pursuant to appropriate financial
arrangements and tariffs or contracts, all reasonably incurred costs, plus a
reasonable return on investment, Regional Transmission Owners designated as the
appropriate entities to construct and own or finance enhancements or expansions
specified in the Regional Transmission Expansion Plan shall construct and own or
finance such facilities or enter into appropriate contracts to fulfill such
obligations.
(b) Nothing herein shall prohibit any Regional Transmission Owner from
seeking to recover the cost of enhancements or expansions on an incremental cost
basis or from seeking approval of such rate treatment from any regulatory agency
with jurisdiction over such rates.
1.8 Relationship to the PJM Control Area Open Access Transmission PJM
Tariff
Nothing herein shall modify the rights and obligations of an Eligible
Customer or a Transmission Customer, as those terms are defined in the PJM
Tariff, with respect to required studies and completion of necessary
enhancements or expansions. An Eligible Customer or Transmission Customer
electing to follow the procedures in the PJM Tariff instead of the procedures
provided herein, shall also be responsible for the related costs. The
enhancement and expansion study process under this Protocol shall be funded as a
part of the operating budget of the Office of the Interconnection.
Revised: March 31, 1999
Effective: April 1, 1999
5
<PAGE>
SCHEDULE 7
----------
Revision No. 1
UNDERFREQUENCY RELAY OBLIGATIONS AND CHARGES
--------------------------------------------
Issued: June 2, 1997
Effective: January 1, 1998
1. UNDERFREQUENCY RELAY OBLIGATION
1.1 Application.
The obligations of this Schedule apply to each Member that is an Electric
Distributor, whether or not that Member participates in the Electric Distributor
sector on the Members Committee or meets the eligibility requirements for any
other sector of the Members Committee.
1.2 Obligations.
Each Electric Distributor shall install or contractually arrange for
underfrequency relays to interrupt at least 30 percent of its peak load with 10
percent of the load interrupted at each of three frequency levels: 59.3 Hz, 58.9
Hz and 58.5 Hz. Upon the request of the Reliability Committee, each Electric
Distributor shall document that it has complied with the requirement for
underfrequency load shedding relays.
2. UNDERFREQUENCY RELAY CHARGES
If an Electric Distributor is determined to not have the required
underfrequency relays, it shall pay an underfrequency relay charge of:
Charge = D x R x 365
where
D = the amount, in megawatts, the Electric Distributor is deficient;
and
R = the daily rate per megawatt, which shall be based on the annual
carrying charges for a new combustion turbine generator, installed
and connected to the transmission system, which daily deficiency
rate as of the Effective Date shall be $58.400/per kilowatt-year
or $160 per megawatt-day.
1
<PAGE>
3. DISTRIBUTION OF UNDERFREQUENCY RELAY CHARGES
3.1 Share of Charges.
Each Electric Distributor that has complied with the requirements for
underfrequency relays imposed by this Agreement during a Planning Period,
without incurring an underfrequency relay charge, shall share in any
underfrequency relay charges paid by any other Electric Distributor that has
failed to satisfy said obligation during such Planning Period. Such shares
shall be in proportion to the number of megawatts of a Electric Distributor"s
load in the most recently completed month at the time of the peak for the PJM
Control Area during that month rounded to the next higher whole megawatt, as
established initially on the Effective Date and as updated at the beginning of
each month thereafter.
3.2 Allocation by the Office of the Interconnection.
In the event all of the Electric Distributors have incurred underfrequency
relay charges during a Planning Period, the underfrequency relay charges shall
be distributed among the Electric Distributors on an equitable basis as
determined by the Office of the Interconnection.
2
<PAGE>
SCHEDULE 8
----------
Revision No. 1
DELEGATION OF RELIABILITY RESPONSIBILITIES
------------------------------------------
Issued: June 2, 1997
Effective: January 1, 1998
1. DELEGATION
The following responsibilities shall be delegated to the Office of the
Interconnection by the parties to the Reliability Assurance Agreement.
2. NEW PARTIES
With regard to the addition, withdrawal or removal of a party to the
Reliability Assurance Agreement, the Office of the Interconnection shall:
(a) Receive and evaluate the information submitted by entities that plan to
serve loads within the PJM Control Area, including entities whose participation
in the Agreement will expand the boundaries of the PJM Control Area, such
evaluation to be conducted in accordance with the requirements of the
Reliability Assurance Agreement; and
(b) Evaluate the effects of the withdrawal or removal of a party from the
Reliability Assurance Agreement.
3. IMPLEMENTATION OF RELIABILITY ASSURANCE AGREEMENT.
With regard to the implementation of the provisions of the Reliability
Assurance Agreement, the Office of the Interconnection shall:
(a) Receive all required data and forecasts from the parties to the
Reliability Assurance Agreement and other owners of Capacity Resources;
(b) Perform all calculations and analyses necessary to determine the
Forecast Pool Requirement and the capacity obligations imposed under the
Reliability Assurance Agreement, including periodic reviews of the capacity
benefit margin for consistency with the Reliability Principles and Standards, as
the foregoing terms are defined in the Reliability Assurance Agreement;
(c) Monitor the compliance of each party to the Reliability Assurance
Agreement with its obligations under the Reliability Assurance Agreement;
(d) Keep cost records, and bill and collect any costs or charges due from
the parties to the Reliability Assurance Agreement and distribute those charges
in accordance with the terms of the Reliability Assurance Agreement;
(e) Assist with the development of rules and procedures for determining and
Revised: November 19, 1998
Effective: September 1, 1998
1
<PAGE>
demonstrating the capability of Capacity Resources;
(f) Establish the capability and deliverability of Capacity Resources
consistent with the requirements of the Reliability Assurance Agreement;
(g) Collect and maintain generator availability data;
(h) Perform any other forecasts, studies or analyses required to administer
the Reliability Assurance Agreement;
(i) Coordinate maintenance schedules for generation resources operated as
part of the PJM Control Area;
(j) Determine and declare that an Emergency exists or has ceased to exist
in all or any part of the PJM Control Area or announce that an Emergency exists
or ceases to exist in a Control Area interconnected with the PJM Control Area;
(k) Enter into agreements for (i) the transfer of energy in Emergencies in
the PJM Control Area or in a Control Area interconnected with the PJM Control
Area and (ii) mutual support in such Emergencies with other Control Areas
interconnected with the PJM Control Area; and
(l) Coordinate the curtailment or shedding of load, or other measures
appropriate to alleviate an Emergency, to preserve reliability in accordance
with FERC, NERC or MAAC principles, guidelines, standards and requirements and
the PJM Manuals, and to ensure the operation of the PJM Control Area in
accordance with Good Utility Practice.
Revised: November 19, 1998
Effective: September 1, 1998
2
<PAGE>
SCHEDULE 9
----------
Revision No. 1
EMERGENCY PROCEDURE CHARGES
---------------------------
Issued: June 2, 1997
Effective: January 1, 1998
EMERGENCY PROCEDURE CHARGE
Following an Emergency, the compliance of each Member with the instructions
of the Office of the Interconnection shall be evaluated by the Office of the
Interconnection. If, based on such evaluation, it is determined that a Member
failed to comply with the instructions of the Office of the Interconnection to
implement voltage reductions or to drop load, that Member shall demonstrate that
it employed its best efforts to comply with such instructions. In the event a
Member failed to employ its best efforts to comply with the instructions of the
Office of the Interconnection, that Member shall pay an emergency procedure
charge as follows:
(a) For each megawatt of voltage reduction that was not implemented as
directed, the Member shall pay 365 times the daily deficiency rate per megawatt
based on the annual carrying charges for a new combustion turbine generator,
installed and connected to the transmission system, which daily deficiency rate
as of the Effective Date shall be $58.400/per kilowatt-year or $160 per
megawatt-day; and
(b) For each megawatt of load that was not dropped as directed, the Member
shall pay 730 times the daily deficiency rate per megawatt based on the annual
carrying charges for a new combustion turbine generator, installed and connected
to the transmission system, which daily deficiency rate as of the Effective Date
shall be $58.400/per kilowatt-year or $160 per megawatt-day.
2. DISTRIBUTION OF EMERGENCY PROCEDURE CHARGES
2.1 Complying Parties.
Each Member that has complied with the emergency procedures imposed by this
Agreement during an Emergency, without incurring an emergency procedure charge,
shall share in any emergency procedure charges paid by any other Member that has
failed to satisfy said obligation during such Emergency in an equitable manner
to be determined by the PJM Board.
2.2 All Parties.
In the event all of the Members have incurred emergency procedure charges
with respect to an Emergency, the emergency procedure charges related to that
Emergency shall be distributed in an equitable manner as directed by the PJM
Board.
<PAGE>
Effective through March 31, 1998 only.
Issued: January 30, 1998
Effective: January 1, 1998
SCHEDULE 10
ACCOUNTING FOR UNSCHEDULED TRANSMISSION SERVICE COMPENSATION
------------------------------------------------------------
(a) Allocation among the Members of compensation paid or received for
Unscheduled Transmission Service, as defined in agreements between the
Members and others, and the billing within the Interconnection in
connection therewith, shall be made in accordance with this schedule.
(b) When the Members provide Unscheduled Transmission Service to others, the
compensation received, either in dollars or in transmission service
availability, shall be allocated initially among the Members in proportion
to their Forecast Obligations determined under Schedule 5 to the
Reliability Assurance Agreement, dated June 2, 1997, as amended and in
effect at the same time the Unscheduled Transmission Service was provided.
Each Member shall receive from the billing agent its share of the payment
in dollars as so allocated.
(c) When the Members receive Unscheduled Transmission Service from others, each
Member shall pay to the billing agent its share of the charges by said
others or alternatively each Member shall make available its share of
transmission service availability due said others as determined in
accordance with the agreement between the Members and said others, such
shares being initially in proportion to each Member"s respective Forecast
Obligations determined under Schedule 5 to the Reliability Assurance
Agreement, dated June 2, 1997, as amended and in effect at the time the
Unscheduled Transmission Service was received.
(d) When the Members enter into a facility agreement with NYPP for the
installation and operation of phase angle regulating facilities at Ramapo
to control or limit Unscheduled Transmission Service, each Member shall pay
to the billing agent its share of the charges in proportion to their
Forecast Obligations determined under Schedule 5 to the Reliability
Assurance Agreement, dated June 2, 1997, as amended and in effect at the
time when such charges were incurred.
(e) The foregoing allocation of an accounting for compensation shall be
reviewed from time to time and shall be revised upon approval by the PJM
Board upon consideration of the advice and recommendations of the Members
Committee.
Effective through March 31, 1998 only.
<PAGE>
SCHEDULE 11
-----------
PJM CAPACITY CREDIT MARKETS
---------------------------
Issued: October 14, 1998
Effective: October 15, 1998
1. PURPOSES AND OBJECTIVES
1.1 PJM Capacity Credit Markets.
This Schedule sets forth the procedures applicable to the operation of the
PJM Capacity Credit Markets. The PJM Capacity Credit Markets will allow Market
Participants to buy and sell Capacity Credits at market clearing prices that are
established by the PJM Capacity Credit Markets and made public by the Office of
the Interconnection. The PJM Capacity Credit Markets shall be administered by
the Office of Interconnection in accordance with the principles and procedures
specified in this Schedule.
1.2 Voluntary Use of PJM Capacity Credit Market.
Except as provided in Section 7.4, participation in any PJM Capacity Credit
Market is voluntary.
1.3 Use of Capacity Credits.
An entity may use Capacity Credits to meet all or part of its capacity
obligations imposed under the Reliability Assurance Agreement. Such Capacity
Credits may be used by themselves, or along with any other options for meeting
capacity obligations imposed under the Reliability Assurance Agreement.
2. DEFINITIONS
Unless the context otherwise specifies or requires, capitalized terms used in
this Schedule shall have the respective meanings assigned herein or in the
Agreement for all purposes of this Schedule (such definitions to be equally
applicable to both the singular and the plural forms of the terms defined).
2.1 [Reserved.]
2.2 Buy Bid.
"Buy Bid" shall mean a bid to buy Capacity Credits in a PJM Capacity Credit
Market.
Revised: November 19, 1998
Effective: October 15, 1998
<PAGE>
2.3 Capacity Credit.
"Capacity Credit" shall, subject to the transition provision specified
below, mean an entitlement to a specified number of megawatts of Unforced
Capacity from a Capacity Resource for the purpose of satisfying capacity
obligations imposed under the Reliability Assurance Agreement, such entitlement
not to include any entitlement to the output of the Capacity Resource.
2.4 Capacity Credit Market Implementation Date.
"Capacity Credit Market Implementation Date" shall mean the date specified
in Section 7.1 of this Schedule.
2.5 Capacity Resources.
"Capacity Resources" shall have the meaning specified in the Reliability
Assurance Agreement.
2.6 Fixed Block.
"Fixed Block" shall mean a Sell Offer or Buy Bid for not more or less than
a specified quantity of Capacity Credits.
2.7 Holiday.
"Holiday" shall mean a federal or state holiday designated by the Office of
the Interconnection for recognition in the conduct of PJM Daily Capacity Credit
Markets.
2.8 PJM Capacity Credit Market.
"PJM Capacity Credit Market" shall mean the PJM Daily Capacity Credit
Market and the PJM Monthly Capacity Credit Market.
2.9 PJM Daily Capacity Credit Market.
"PJM Daily Capacity Credit Market" shall mean a competitive market,
administered by the Office of the Interconnection in accordance with the
provisions of this Schedule, for the purchase and sale of Capacity Credits for
the business day following the day on which the market is conducted and for each
of any intervening weekend days or Holidays if the market is conducted on a
Friday or the day before a Holiday.
2.10 PJM Monthly Capacity Credit Market.
"PJM Monthly Capacity Credit Market" shall mean a competitive market,
administered by the Office of the Interconnection in accordance with the
provisions of this Schedule, for the purchase and sale of Capacity Credits for
each or any of the twelve months following the month during which the market is
conducted.
2.11 Sell Offer.
"Sell Offer" shall mean an offer to sell Capacity Credits in a PJM Capacity
Credit Market.
Revised: November 19, 1998
Effective: October 15, 1998
2
<PAGE>
2.12 Unforced Capacity.
"Unforced Capacity" shall have the meaning specified in the Reliability
Assurance Agreement.
2.13 Up-To Block.
"Up-To Block" shall mean a Sell Offer or Buy Bid for a quantity of Capacity
Credits equal to or less than a specified quantity.
3. PARTICIPATION IN THE PJM CAPACITY CREDIT MARKET
3.1 Eligibility.
A Member shall become eligible to participate in any of the PJM Capacity
Credit Markets by becoming a Market Buyer or a Market Seller, or both as may be
appropriate, in accordance with the provisions of Schedule 1 of the Agreement.
In order to participate in any of the PJM Capacity Credit Markets, a Market
Buyer also either must be (a) an entity that is or will become a Load Serving
Entity in the PJM Control Area and a party to the Reliability Assurance
Agreement, or (b) have a contractual obligation to sell capacity (including
sales for resale) which will be used in the PJM Control Area. A Market Seller
may participate in any PJM Capacity Credit Market only to the extent that it has
Capacity Credits available to sell in excess of its capacity obligation imposed
under the Reliability Assurance Agreement and other contractual obligations to
sell capacity (including sales for resale), as determined in accordance with
Section 6.1.3.
3.2 Effect of Withdrawal.
Withdrawal from the Agreement shall not relieve a Market Participant of any
obligation to furnish or pay for Capacity Credits incurred in connection with
participation in a PJM Capacity Credit Market prior to such withdrawal, to pay
its share of any fees and charges incurred or assessed by the Office of the
Interconnection prior to the date of such withdrawal, or to fulfill any
obligation to provide indemnification for the consequences of acts, omissions or
events occurring prior to such withdrawal; and provided, further, that
withdrawal from this Agreement shall not relieve any Market Participant of any
obligations it may have under, or constitute withdrawal from, any Related PJM
Agreement.
4. RESPONSIBILITIES OF THE OFFICE OF THE INTERCONNECTION
4.1 Operation of the PJM Capacity Credit Market.
The Office of the Interconnection shall operate the PJM Capacity Credit
Markets in accordance with the provisions of this Schedule and applicable
provisions of the Agreement and the Reliability Assurance Agreement. Operation
of the PJM Capacity Credit Markets shall include, but not be limited to,
provision of the following services:
Second Revised: February 12, 1999
Effective: January 19, 1999
3
<PAGE>
i) Determining the qualification of entities to become Market
Participants;
ii) Administering the PJM Capacity Credit Markets;
iii) Accounting for PJM Capacity Credit Market transactions, including but
not limited to rendering bills to, receiving payments from, and
disbursing payments to, participants in the PJM Capacity Credit
Markets;
iv) Maintaining such records of Sell Offers and Buy Bids, clearing price
determinations, and other aspects of PJM Capacity Credit Market
transactions, as may be appropriate to the administration of the PJM
Capacity Credit Markets; and
v) Monitoring compliance of participants in the PJM Capacity Credit
Markets with the provisions of this Schedule and the Agreement.
4.2 Records and Reports.
The Office of the Interconnection shall prepare and maintain such records
as are required for the administration of the PJM Capacity Credit Markets. For
each day of operation of the PJM Capacity Credit Markets, the Office of the
Interconnection shall publish, as specified below: (i) the price, if
determined, at which the PJM Capacity Credit Market cleared; (ii) the total
volume of Capacity Credits purchased; and (iii) such other PJM Capacity Credit
Market data as may be appropriate to the efficient and competitive operation of
the PJM Capacity Credit Markets, consistent with preservation of the
confidentiality of commercially sensitive or proprietary information.
Publication of the foregoing information shall be by posting on the PJM web
site. Such information shall remain available on the PJM web site for twelve
months from the date of posting. The Office of the Interconnection shall not
disclose commercially sensitive or proprietary information in any report or web
site posting.
5. GENERAL PROVISIONS
5.1 Market Sellers.
Only Market Sellers shall be eligible to submit Sell Offers. Market
Sellers shall comply with the terms and conditions of all Sell Offers, as
established by the Office of the Interconnection in accordance with this
Schedule and the Agreement.
5.2 Market Buyers.
Only Market Buyers shall be eligible to submit Buy Bids. Market Buyers
shall comply with the terms and conditions of all Buy Bids, as established by
the Office of the Interconnection in accordance with this Schedule and the
Agreement.
Revised: November 19, 1998
Effective: October 15, 1998
4
<PAGE>
5.3 Agents.
A Market Participant may participate in the PJM Capacity Credit Markets
through an agent, provided that the Market Participant informs the Office of the
Interconnection in advance in writing of the appointment of such agent. A
Market Participant participating in the PJM Capacity Credit Markets through an
agent shall be bound by all of the acts or representations of such agent with
respect to transactions in the PJM Capacity Credit Markets, and shall ensure
that any such agent complies with the requirements of this Schedule and the
Agreement.
5.4 General Obligations of Market Participants.
Each Market Participant shall comply with all laws and regulations
applicable to the operation of the PJM Capacity Credit Markets and the use of
Capacity Credits, and shall comply with all applicable provisions of this
Schedule, the Agreement, and the Reliability Assurance Agreement, and all
procedures and requirements for the operation of the PJM Capacity Credit Markets
and the PJM Control Area established by the Office of the Interconnection in
accordance with the foregoing.
5.5 Relationship of Capacity Credits to Capacity Obligations Imposed Under
the Reliability Assurance Agreement.
A megawatt of Capacity Credit shall satisfy a megawatt of capacity
obligation imposed under the Reliability Assurance Agreement. Capacity Credits
purchased from a PJM Capacity Credit Market shall not be adjusted for forced
outages or other reasons. Because Capacity Credits are based on Capacity
Resources, no further capability or deliverability demonstrations beyond those
for the related Capacity Resource shall be required.
5.6 Deficiency Charges.
If the Office of the Interconnection determines that the first Market
Seller in a PJM Capacity Credit Market of a Capacity Credit did not have
sufficient Unforced Capacity to support the Capacity Credit transaction at the
time for which the Capacity Credit was applicable, any such deficiency shall be
satisfied through payment of deficiency charges by such first Market Seller
calculated as specified in the Reliability Assurance Agreement. Any amounts
collected from such deficiency charges shall be distributed in accordance with
the Reliability Assurance Agreement.
5.7 Fixed Transmission Rights.
Acquisition of a Capacity Credit shall not entitle the holder to a Fixed
Transmission Right.
Revised: November 19, 1998
Effective: October 15, 1998
5
<PAGE>
5.8 Confidentiality.
The following information submitted to the Office of the Interconnection in
connection with any PJM Capacity Credit Market shall be deemed confidential
information for purposes of Section 18.17 of the Agreement: (i) the terms and
conditions of all Sell Offers and Buy Bids; and (ii) the terms and conditions of
any bilateral transactions for capacity or Capacity Credits.
6. OPERATION OF THE PJM CAPACITY CREDIT MARKETS
6.1 Content of Sell Offers.
6.1.1 Specifications.
Sell Offers shall specify:
i) The quantity of Capacity Credits offered, in increments of 0.1
megawatt;
ii) The minimum price, in dollars and cents per megawatt per day,
that will be accepted by the seller;
iii) Whether the offer is for a Fixed Block or an Up-To Block;
iv) For a PJM Daily Capacity Credit Market conducted on a Friday or
the day before a Holiday, the dates on which the offered Capacity
Credits may be used; and
v) For a PJM Monthly Capacity Credit Market, the month or months for
which the offered Capacity Credits may be used.
6.1.2 Market-based Offers.
A Market Seller that is authorized by FERC to sell electric generating
capacity at market-based prices, or that is not required to have such
authorization, may submit Sell Offers to PJM Capacity Credit Markets that
specify market-based prices.
6.1.3 Availability of Capacity Credits for Sale.
i) The Office of the Interconnection shall determine the maximum
megawatts of Capacity Credits each Market Seller may offer in a
PJM Capacity Credit Market, through verification of the
availability of megawatts of capacity from: (a) Capacity
Resources owned by or under contract to the Market Seller; (b)
rights obtained in bilateral transactions; (c) the results of
prior PJM Capacity Credit Markets; and (d) such other information
as may be available to the Office of the Interconnection. The
Office of the Interconnection may reject Sell Offers or portions
of Sell Offers for Capacity Credits determined by it not to be
available for sale.
Revised: November 19, 1998
Effective: October 15, 1998
6
<PAGE>
ii) The Office of the Interconnection shall determine the maximum
amount of Capacity Credits available for sale in a PJM Capacity
Credit Market as of the beginning of the period during which Buy
Bids and Sell Offers are accepted for each market. To enable the
Office of the Interconnection to make this determination, no
bilateral transactions for capacity or Capacity Credits
applicable to the period covered by a PJM Capacity Credit Market
will be processed from the beginning of the period for submission
of Sell Offers and Buy Bids for that market until completion of
the clearing determination for that market. Processing of such
bilateral transactions will recommence once all sales for that
market are deemed final as specified below.
iii) In order for a bilateral transaction for the purchase and sale of
a Capacity Credit to be processed by the Office of the
Interconnection, both parties to the transaction must notify the
Office of the Interconnection of the transfer of the Capacity
Credit from the seller to the buyer in accordance with procedures
established by the Office of the Interconnection.
6.2 Content of Buy Bids.
Buy Bids shall specify:
i) The quantity of Capacity Credits desired, in increments of 0.1
megawatt;
ii) The maximum price, in dollars and cents per megawatt per day, that
will be paid by the buyer;
iii) Whether the bid is for a Fixed Block or an Up-To Block;
iv) For a PJM Daily Capacity Credit Market conducted on a Friday or the
day before a Holiday, the dates for which Capacity Credits are
desired; and
v) For a PJM Monthly Capacity Credit Market, the month or months for
which Capacity Credits are desired.
6.3 Submission of Sell Offers and Buy Bids.
The submission of Sell Offers and Buy Bids shall be subject to the
following requirements:
i) A Sell Offer or Buy Bid that fails to specify price or quantity, or
the date or months for which Capacity Credits are to be used if
applicable, shall be rejected by the Office of the Interconnection.
ii) A Sell Offer or Buy Bid that does not specify whether it is for a Full
Block or an Up-To Block shall be deemed a Sell Offer or Buy Bid for an
Up-To Block.
Revised: November 19, 1998
Effective: October 15, 1998
7
<PAGE>
iii) All Sell Offers and Buy Bids for a PJM Daily Capacity Market must be
received by the Office of the Interconnection during a specified
period, as determined by the Office of the Interconnection, on the day
on which the market will be conducted. A Sell Offer or Buy Bid may be
withdrawn by a notification of withdrawal received by the Office of
the Interconnection at any time during the foregoing period, but may
not be withdrawn after that period.
iv) Sell Offers or Buy Bids for a PJM Daily Capacity Credit Market
conducted on a Monday, Tuesday, Wednesday or Thursday that is not the
day before a Holiday shall be for Capacity Credits applicable to the
following day.
v) Sell Offers or Buy Bids for a PJM Daily Capacity Credit Market
conducted on a Friday or the day before a Holiday shall designate the
date, to and including the next business day, to which the Capacity
Credits are applicable. A separate PJM Daily Capacity Credit Market
shall be conducted on such Friday or day before a Holiday for Capacity
Credits applicable to each following day, to and including the next
business day.
vi) Sell Offers and Buy Bids for a PJM Monthly Capacity Credit Market must
be received by the Office of the Interconnection during a specified
period, as determined by the Office of the Interconnection, on the day
of each month designated by the Office of the Interconnection for the
conduct of a PJM Monthly Capacity Credit Market. A Sell Offer or Buy
Bid may be withdrawn by a notification of withdrawal received by the
Office of the Interconnection at any time during the foregoing period,
but may not be withdrawn after that period.
vii) Sell Offers and Buy Bids shall be submitted or withdrawn via the
Internet site designated by the Office of the Interconnection;
provided, however, that if that Internet site cannot be accessed at
any time during the period specified in the foregoing paragraph, a
Sell Offer or Buy Bid may be submitted or withdrawn by a facsimile
transmitted to the number specified by the Office of the
Interconnection.
6.4 Conduct of PJM Capacity Credit Markets.
6.4.1 PJM Daily Capacity Credit Markets.
Following the submission of Sell Offers and Buy Bids in accordance
with the specified deadline for PJM Daily Capacity Credit Markets, a PJM Daily
Capacity Credit Market will be conducted each business day. Each such PJM Daily
Capacity Credit Market will clear Sell Offers and Buy Bids for Capacity Credits
for use the next business day, and for each of any intervening weekend days or
Holidays.
Revised: November 19, 1998
Effective: October 15, 1998
8
<PAGE>
6.4.2 PJM Monthly Capacity Credit Markets.
Following the submission of Sell Offers and Buy Bids in accordance
with the specified deadline for PJM Monthly Capacity Credit Markets, a PJM
Monthly Capacity Credit Market will be conducted. Each such PJM Monthly
Capacity Credit Market will clear Sell Offers and Buy Bids for Capacity Credits
for use in each of the following twelve months.
6.5 Market Clearing Procedures.
i) For purposes of the rank ordering and market clearing procedures
described below, the Office of the Interconnection will: (a) evaluate
all Sell Offers for a Fixed Block at the same price as one Sell Offer
for a Fixed Block, with the quantity equal to the total quantity of
the equally-priced Sell Offers; (b) evaluate all Sell Offers for an
Up-To Block at the same price as one Sell Offer for an Up-to Block,
with the quantity equal to the total quantity of the equally-priced
Sell Offers; (c) evaluate all Buy Bids for a Fixed Block at the same
price as one Buy Bid for a Fixed Block, with the quantity equal to the
total quantity of the equally-priced Buy Bids; and (d) evaluate all
Buy Bids for an Up-To Block at the same price as one Buy Bid for an
Up-to Block, with the quantity equal to the total quantity of the
equally-priced Buy Bids.
ii) The Office of the Interconnection will rank order all Sell Offers and
Buy Bids by price. Sell Offers will be ranked by lowest price first
and then ranked in ascending price order. Buy Bids will be ranked by
highest price first and then ranked in descending price order. Sell
Offers or Buy Bids for Fixed Blocks will be given priority in the rank
order relative to Sell Offers or Buy Bids for Up-To Blocks of equal
price.
iii) For purposes of the market clearing procedures described below, the
Office of the Interconnection will not split or pro-rate: (a) a Sell
Offer for a Fixed Block; (b) a combined set of Sell Offers deemed a
single Sell Offer for a Fixed Block as specified above; (c) a Buy Bid
for a Fixed Block; or (d) a combined set of Buy Bids deemed a single
Buy Bid for a Fixed Block as specified above.
iv) The Office of the Interconnection will determine the largest quantity
of Sell Offers and Buy Bids for which the price of the marginal Sell
Offer is equal to or less than the price of the marginal Buy Bid. If
the marginal Sell Offer and the marginal Buy Bid are both for Up-to
Blocks, or if either or both are for Fixed Blocks that can be
satisfied without splitting or pro rating any such Fixed Block, the
market will clear at price specified in the marginal Sell Offer.
Revised: November 19, 1998
Effective: October 15, 1998
9
<PAGE>
v) If either the marginal Sell Offer or the marginal Buy Bid (including
Sell Offers or Buy Bids that are combined as specified above) is for a
Fixed Block that could not be purchased or sold in full, then that
Sell Offer or Buy Bid will be removed from the rank order and the
market clearing price redetermined as specified above. If both the
marginal Sell Offer and the marginal Buy Bid (including Sell Offers or
Buy Bids that are combined as specified above) are for Fixed Blocks
that could not be purchased or sold in full, then both blocks will be
removed from the rank order and the market clearing price redetermined
as specified above.
vi) If a marginal Sell Offer or Buy Bid is a combination of Sell Offers or
Buy Bids deemed to be a single Sell Offer or Buy Bid for an Up-To
Block as specified above, the quantity purchased or sold will be
allocated among the combined Sell Offers or Buy Bids in proportion to
the quantities offered in each of the combined Sell Offers or Buy
Bids.
vii) If all Sell Offers remaining in the rank order are at prices higher
than the highest price of any Buy Bid remaining in the rank order, the
market will be cleared with no transactions, and a market clearing
price will not be determined.
6.6 Settlement Procedures.
Upon determination of the market clearing price as specified above: (a)
all Sell Offers at a price equal to or less than the market clearing price and
not removed from the rank ordering and for which there is sufficient Buy Bid
demand at or above the market clearing price will be deemed sold at the market
clearing price, and all Buy Bids at a price equal to or greater than the market
clearing price and not removed from the rank ordering and for which there is
sufficient Sell Offer supply at or below the market clearing price will be
deemed satisfied at the market clearing price, with any Up-To Blocks split and
pro-rated as may be appropriate; and (b) the accounts of Market Sellers and
Market Buyers will be credited or debited accordingly. The foregoing
determinations shall be made, and all sales and purchases shall be deemed final,
as of specified times, as designated by the Office of the Interconnection, on
the day on which each PJM Capacity Market is conducted.
6.7 Billing.
The Office of the Interconnection shall prepare a billing statement for
each Market Participant in accordance with the charges and credits specified in
this Schedule, and showing the net amount to be paid or received by each Market
Participant. Billing statements for PJM Daily Capacity Markets shall be
rendered following the end of each month for Capacity Credits bought and sold in
the month just ended. Billing statements for PJM Monthly Capacity Credit
Markets shall be rendered following the end of the month for which the Capacity
Credit applies. Billing statements shall provide sufficient detail, as
specified in the PJM Manuals, to allow verification of the billing amounts and
completion of the Market Participant"s internal accounting. Payment of
statements shall be made in accordance with the Agreement.
Revised: November 19, 1998
Effective: October 15, 1998
10
<PAGE>
6.8 Time Standard.
All deadlines for the submission or withdrawal of Sell Offers or Buy Bids,
or for other purposes specified in this Schedule, shall be determined by the
time observed in the Eastern time zone.
7. EFFECTIVE DATE AND TRANSITION
7.1 Effective Date.
The Capacity Credit Market Implementation Date shall be October 15, 1998,
or as soon thereafter as the Office of the Interconnection can initiate trading
in the PJM Capacity Credit Market.
7.2 Transition Provisions.
To the extent that the Office of the Interconnection is not able to
administer a PJM Capacity Credit Market in accordance with the standards and
procedures specified above at the Capacity Credit Market Implementation Date,
the Office of the Interconnection shall implement the foregoing standards and
procedures if and to the extent practicable. The Office of the Interconnection
shall thereafter conform to each of the standards and procedures specified above
as soon as practicable.
7.3 Capacity Credit.
Prior to the effective date of the provisions for Unforced Capacity under
the Reliability Assurance Agreement, "Capacity Credit" shall mean an entitlement
to a specified number of megawatts of Capacity from a Capacity Resource for the
purpose of satisfying a capacity obligation imposed under the Reliability
Assurance Agreement, and deficiency charges shall be determined in accordance
with the then-current Reliability Assurance Agreement.
7.4 Mandatory Sell Offers and Buy Bids.
For the Daily Capacity Credit Markets conducted with respect to the
Operating Days between January 1, 1999 and May 31, 2000, there shall be the
following mandatory Sell Offers and Buy Bids:
i) Any Member that owns or has contracted for Capacity Credits or
Capacity Resources shall be required to make Sell Offers in each Daily
Capacity Credit Market to the full extent of the megawatts of capacity
that it has available to sell in excess of its capacity obligations
imposed under the Reliability Assurance Agreement and other
contractual obligations to sell capacity, as determined in accordance
with Section 6.1.3, as of the beginning of the period during which Buy
Bids and Sell Offers are accepted. To the extent that any such
megawatts of capacity available to a Member are not contained in such
Sell Offers, PJM automatically will place for that Member a Sell Offer
of an Up-To Block for such remaining amounts of capacity at a price of
zero.
Revised: May 11, 1999
Effective: June 1, 1999
11
<PAGE>
ii) A party to the Reliability Assurance Agreement shall be required to
make Buy Bids in each Daily Capacity Credit Market for the amount of
capacity that, as of the beginning of the period during which Buy Bids
and Sell Offers are accepted, it lacks for purposes of meeting its
capacity obligations imposed under the Reliability Assurance Agreement
for the Operating Day covered by the Daily Capacity Credit Market. To
the extent that a party to the Reliability Assurance Agreement does
not place such Buy Bids, PJM automatically will place for that party a
Buy Bid of an Up-To Block that, when added to its other Buy Bids,
would meet its capacity obligations imposed under the Reliability
Assurance Agreement, at a price equal to the then-current deficiency
charge under the Reliability Assurance Agreement.
iii) A party shall have only one position, either excess of or deficient of
capacity obligations imposed under the Reliability Assurance
Agreement, as determined by the Office of the Interconnection.
Revised: November 19, 1998
Effective: October 15, 1998
12
<PAGE>
EXHIBIT 10(g)
Power Sales Agreement
PP&L Sales to UGI Utilities, Inc.
Market-Based Rates
- --------------------------------------------------------------------------------
This POWER SALES AGREEMENT ("Agreement"), is made and entered into as of
May 25, 1999, by and between UGI Utilities, Inc., a Pennsylvania corporation,
having offices at 400 Stewart Road, P.O. Box 3200, Wilkes-Barre, PA 18773-3200,
hereinafter referred to as "UGI" or "Buyer," and PP&L, Inc., a Pennsylvania
corporation, having its principal business at Two North Ninth Street, Allentown,
PA 18101-1179, hereinafter referred to as "PP&L" or "Seller" (individually, the
"Party" and collectively, the "Parties"). The definitions set forth in the
Definitional Annex apply to this Agreement.
WHEREAS, on February 19, 1999, PP&L and UGI entered into an "Agreement in
Settlement of All Outstanding Litigation Between PP&L, Inc. and UGI Utilities,
Inc. - Electric Division" ("1999 Settlement Agreement") under which various
litigation between the Parties was settled in full; and
WHEREAS, pursuant to the 1999 Settlement Agreement, PP&L and UGI will enter
into a new interconnection agreement completely replacing the 1935
Interconnection Agreement between the parties; and
WHEREAS, UGI is not an end user of Power and UGI wishes to purchase Power
as a wholesale customer; and
WHEREAS, PP&L is authorized by FERC to engage in wholesale Power
Transactions at market based prices and such Transactions shall be made pursuant
to PP&L's FERC Electric Tariff, Volume No. 5; and
NOW THEREFORE, in consideration of the mutual agreements, covenants and
conditions herein contained, and intending to be legally bound, UGI and PP&L
hereby agree as follows:
ARTICLE 1
SALE OF CAPACITY CREDITS AND ENERGY
1.1 Capacity Credits. Beginning on the Effective Date, PP&L hereby agrees
----------------
to sell to UGI, and UGI agrees to purchase from PP&L, Capacity Credits in an
amount equal to its accounted-for obligation as determined daily by PJM in
accordance with Article 7 and Schedule 7 of the PJM Reliability Assurance
Agreement, less the PJM qualified Capacity Resource value of UGI's Hunlock Power
Station ("Hunlock"), UGI's share of the Conemaugh Power Station ("Conemaugh"),
and, through December 31, 1999, the qualified Capacity Resource value of UGI's
existing purchase of the output of
-1-
<PAGE>
the Montgomery County Resource Recovery Unit in Montgomery County, Maryland
("Montgomery County Facility"). If Hunlock, Conemaugh, or, prior to December 31,
1999, the Montgomery County Facility, cease to be qualified Capacity Resources
accredited to UGI, UGI shall not be obligated to purchase and PP&L shall not be
obligated to supply equivalent replacement Capacity Credits or Capacity
Resources under this Agreement.
1.2 Energy. PP&L hereby agrees to sell to UGI, and UGI agrees to purchase
------
from PP&L, 32 megawatt hours of energy during each hour commencing with the hour
beginning at 0000 hours on January 1, 2000 through the hour commencing at 2300
hours on December 31, 2000.
1.3 Release From Other Obligations. Other than the purchases and sales
-------------------------------
set forth in Article 1 of this Agreement, UGI is not obligated to purchase from
PP&L nor is PP&L required to sell to UGI any other quantity of Power at any
time.
ARTICLE 2
PRICES
2.1 Capacity Credits. For each Capacity Credit purchased pursuant to
----------------
Section 1.1, UGI shall pay PP&L at the rate of $110 per megawatt day prior to
June 1, 1999, and $121.00 per megawatt day beginning June 1, 1999 through
February 28, 2001.
2.2 Energy. UGI shall pay to PP&L $28.00 per megawatt hour for energy
------
purchased pursuant to Section 1.2.
ARTICLE 3
DELIVERY POINTS AND RELIABILITY GUIDELINES
3.1 Delivery Point(s). PP&L shall deliver the Power to the UGI points of
-----------------
interconnection with PP&L in the PP&L Zone; however UGI shall be responsible for
network transmission under the PJM Open Access Transmission Tariff and related
agreements.
3.2 Reliability Guidelines. Each Party agrees to adhere to accepted Good
----------------------
Utility Operating Practice and specifically adhere to the applicable operating
policies,
-2-
<PAGE>
criteria and/or guidelines of the North American Electric Reliability Council
("NERC") and any regional or subregional requirement.
3.3 Scheduling. The delivery of Power under this Agreement shall be
----------
Scheduled by UGI in accordance with the guidelines established by the PJM Office
of Interconnection.
3.4 Title Transfer. Title to, possession of, and risk of loss of Power
--------------
Scheduled and received or delivered hereunder shall transfer from PP&L to UGI at
the Delivery Point. PP&L warrants that at the time of delivery PP&L shall have
good title to the Power sold and delivered hereunder and the right to sell such
Power to UGI.
ARTICLE 4
CONDITIONS TO EFFECTIVENESS
4.1 Reliability Assurance Agreement. UGI shall become a party to and sign
-------------------------------
the PJM Reliability Assurance Agreement and become a Load Serving Entity under
that agreement.
4.2 1999 Interconnection Agreement. The 1999 Interconnection Agreement
------------------------------
shall have been permitted by the FERC to become effective.
4.3 FERC Approval of This Agreement. The FERC shall have permitted this
-------------------------------
Agreement to become effective.
ARTICLE 5
TERM OF AGREEMENT
5.1 Commencement. This Agreement shall commence on the first date upon
------------
which (1) this Agreement has been fully executed by the Parties, and (2) the
conditions to effectiveness set forth in Article 4 have been fulfilled ("the
Effective Date"). On the Effective Date of this Agreement, the 1992 Power Sales
Agreement shall terminate.
5.2 Termination. This Agreement shall terminate on February 28, 2001.
-----------
PP&L shall have no obligation to UGI to continue to provide any service
thereunder following that date, nor shall this Agreement be interpreted to
create in PP&L any obligation to serve UGI under the FPA or other legal or
regulatory authority. Following expiration of this Agreement UGI shall not be
obligated to continue purchases from
-3-
<PAGE>
PP&L under this Agreement or to compensate PP&L in any manner other than for
amounts owed for sales and service rendered under this Agreement.
ARTICLE 6
BILLING AND PAYMENT
6.1 Statements. PP&L shall render to UGI for each calendar month during
----------
the term of this Agreement a statement or statements setting forth the total
quantity of Power purchased under this Agreement during the preceding month and
the amounts due to PP&L from UGI under this Agreement. The first monthly
statement shall contain the total quantity of Power purchased under this
Agreement and all amounts due PP&L from UGI from the Effective Date through the
end of the preceding month.
6.2 Billing and Payments. Unless otherwise informed by PP&L by written
--------------------
notice providing at least three (3) days notice, statements shall be submitted
monthly within ten (10) days following the last day of the month in which sales
under this Agreement were made and shall be paid by UGI on or before the later
of fifteen (15) days after the date the bill is received or the 20th day of the
month. Payments shall be made by Automated Clearing House ("ACH") wire transfer
to designated bank account or other generally accepted electronic funds transfer
method as directed by PP&L in PP&L's discretion. Payment shall be deemed to
have been made when PP&L's financial institution either initiates the transfer
or receives the funds. If informed by PP&L by written notice of a different
statement and payment schedule, UGI agrees to follow such schedule. UGI will
pay all amounts set forth in such statements on or before the date that such
amounts are due. Except as provided in Section 6.3, if UGI fails to pay all of
the amount of any statement when that amount becomes due, UGI shall pay PP&L a
late charge on the unpaid balance that shall accrue on each calendar day from
the due date at the Interest Rate. Except in the case of a disputed bill, if
UGI fails to pay amounts due to PP&L by the date that such amounts are due, PP&L
may suspend performance pending receipt of full payment with interest (and shall
have no further duty to UGI as a result of such action). Disputed bills shall
be handled as stated below.
6.3 Billing Disputes. In the event any portion of any bill is in dispute,
----------------
the undisputed amount shall be paid to PP&L and a detailed written explanation
of the basis for the dispute shall be submitted by UGI within the time periods
specified for payment in Section 6.2. The Parties shall use their best efforts
to attempt to resolve such disputes on a timely basis. Upon determination of
the correct billing amount, the adjusted bill shall be paid promptly after such
determination with interest at the Interest
-4-
<PAGE>
Rate accrued in accordance with Section 6.2 and computed from the date payment
is received to the date the adjustment is made. If the Parties are unable to
resolve the dispute, either Party may exercise its available administrative or
legal remedies, including those set forth in Section 6.6 below.
6.4 Audit. Each Party or any third party representative of a Party has
-----
the right at its sole expense and during normal working hours, to examine the
records of the other Party to the extent reasonably necessary to verify the
accuracy of any statement, charge or computation made pursuant to the provisions
of this Agreement. If any such examination reveals any inaccuracy in any
statement, the necessary adjustments in such statement and the payments thereof
shall be made prior to the lapse of two years from the rendition of such
statement, and provided further that the rights set forth in the first sentence
of this Section 6.4 will survive until two years after termination of this
Agreement.
6.5 Records. Each Party shall keep such records as may be necessary to
-------
afford the other a clear history of all deliveries or receipts of capacity
credits and energy under this Agreement. Records shall be maintained for a
period necessary to comply with Section 6.4 and shall be made available as
necessary to verify the accuracy of statements submitted under this Agreement.
6.6 Dispute Resolution. (a) In the event of a dispute between the
------------------
Parties arising under this Agreement, the Parties will work together in good
faith to resolve the dispute. If the Parties are unable to resolve such dispute
between themselves within five days after written notification by one Party to
the other of the existence of such dispute, they shall immediately refer such
matter to their internal upper management for resolution. If the management of
the Parties is unable to resolve the dispute within ten days after the matter is
brought to their level for review, either Party may bring a claim or suit in
accordance with the provisions of Section 13.6 of this Agreement, and agrees
that service of process may be made upon it in any legal proceeding relating to
this Agreement at the address indicated in Section 13.4. Each Party shall pay
its own attorneys' fees and expenses, except that if the prevailing Party is
required to initiate proceedings to enforce the award or confirm judgment, the
prevailing Party shall be entitled to recover its costs and attorneys' fees
associated with such action. EACH PARTY HEREBY WAIVES ITS RIGHT TO A JURY
TRIAL.
(b) Notwithstanding the dispute procedure provided in this Section 6.6,
the Parties have no obligation to use such dispute resolution process where the
dispute involves confidentiality or the infringement of intellectual property
rights. In the event of a breach of confidentiality or a claim of infringement
under this Agreement, the Party
-5-
<PAGE>
seeking redress shall have the right to bring a claim or suit in accordance with
Section 13.6 immediately.
ARTICLE 7
LIQUIDATED DAMAGES
7.1 Scheduling. Scheduling of Power for delivery under this Agreement
----------
shall be subject to Section 3.3. Unless otherwise agreed to, PP&L and UGI shall
be responsible for any transmission and ancillary services relating to the
transmission of Power, in the case of PP&L, to the Delivery Point(s), and in the
case of UGI, at and from the Delivery Point(s).
7.2 In the event PP&L fails to deliver the Power, where such failure was
not excused by Force Majeure or by UGI's failure to perform, PP&L shall pay UGI
(on the date payment would otherwise be due under this Agreement) an amount for
each Mwhr of such deficiency equal to the positive difference, if any, between:
(i) the price at which UGI is able to purchase or otherwise receive such
deficiency quantity of Power acting in a commercially reasonable manner
(adjusted to reflect differences in transmission costs, if any) and (ii) the
Contract Price; provided, however, in no event shall such amounts include any
-------- -------
penalties, ratcheted demand or similar charges.
7.3 In the event UGI fails to Schedule and to receive the Power, where
such failure was not excused by Force Majeure or by PP&L's failure to perform,
UGI shall pay PP&L (on the date payment would otherwise be due under this
Agreement) an amount for each Mwhr of such deficiency equal to the positive
difference, if any, between: (i) the Contract Price and (ii) the price at which
PP&L is able to sell or otherwise dispose of such deficiency quantity of power
acting in a commercially reasonable manner (adjusted to reflect differences in
transmission costs, if any); provided, however, in no event shall such amounts
-------- -------
include any penalties, ratcheted demand or similar charges.
7.4 Both Parties hereby stipulate that the payment obligations set
forth above are reasonable in light of the anticipated harm and the difficulty
of estimation or calculation of actual damages and each Party hereby waives the
right to contest such payments as an unreasonable penalty. In the event either
Party fails to pay such amounts in accordance with this Article when due, the
aggrieved Party shall have the right to: (i) suspend performance until such
amounts plus interest at the Interest Rate have been paid, and/or (ii) exercise
any remedy available at law or in equity to enforce payment of such amount plus
interest at the Interest Rate. The remedy set forth herein
-6-
<PAGE>
shall be the sole and exclusive remedy of the aggrieved Party for the failure of
the other Party to sell or purchase Power hereunder and all other damages and
remedies are hereby waived.
7.5 As an alternative to the foregoing damages provisions, if the Parties
mutually agree in writing, the nonperforming Party may Schedule deliveries or
receipts, as the case may be, pursuant to such terms as the Parties agree in
order to discharge some or all of the obligation to pay damages. In the absence
of such agreement, the damages provisions of this Article shall apply.
ARTICLE 8
INDEMNIFICATION
8.1 PP&L's Indemnification of UGI. PP&L hereby agrees to indemnify,
-----------------------------
defend and hold harmless UGI, its agents, servants and Affiliates and the
respective officers, directors, employees and representatives (collectively,
"UGI's Indemnitees") of each, from and against any and all losses, claims,
damages or liabilities (including reasonable attorneys' fees actually incurred
including, without limitation, penalties or fines imposed by government
authorities) arising out of the fraud, negligence, or willful misconduct of PP&L
relating to Power delivered under this Agreement until such Power has been
delivered to UGI at the Delivery Points including, without limitation, the loss
of/or claims for loss or damage to property, except to the extent caused by the
fraud, negligence or the willful misconduct of UGI's Indemnitees and provided
that PP&L shall be promptly notified in writing of any such claim or suit
brought against any such UGI Indemnitee. The foregoing notwithstanding, PP&L's
obligations under this Agreement towards any UGI Indemnitee are conditioned upon
such UGI Indemnitee providing such cooperation as PP&L may reasonably request in
connection with its defense or settlement of the claim or suit against such UGI
Indemnitee.
8.2 UGI's Indemnification of PP&L. UGI hereby agrees to indemnify, defend
-----------------------------
and hold harmless PP&L, its agents, servants and Affiliates and the respective
officers, directors and employees and representatives (collectively, "PP&L's
Indemnitees") of each, from and against any and all losses, claims, damages or
liabilities to third parties (including reasonable attorneys' fees actually
incurred including, without limitation, penalties or fines imposed by government
authorities) arising out of the fraud, negligence, or willful misconduct of UGI
relating to Power delivered under this Agreement after such Power has been
delivered to UGI at and from the Delivery Points including, without limitation,
the loss of/or claims for loss or damage to property, except to the extent
caused by the fraud, negligence or the willful misconduct of PP&L's
-7-
<PAGE>
Indemnitees and provided that UGI shall be promptly notified in writing of any
such claim or suit brought against any such PP&L Indemnitee. The foregoing
notwithstanding, UGI's obligations under this Agreement towards any PP&L
Indemnitee are conditioned upon such PP&L Indemnitee providing such cooperation
as UGI may reasonably request in connection with its defense or settlement of
the claim or suit against such PP&L Indemnitee.
ARTICLE 9
ASSIGNMENT AND SUCCESSION
9.1 Assignment and Succession. Neither Party shall assign this
-------------------------
Agreement or its rights hereunder without the prior written consent of the other
Party, which consent shall not be unreasonably withheld or delayed. Upon any
assignment made in compliance with this Section, this Agreement shall inure to
and be binding upon the successors and permitted assigns of the assigning Party.
Notwithstanding the foregoing, either Party may, without the need for consent
from the other Party (and as long as such Party remains fully liable hereunder),
(a) transfer, pledge, or assign this Agreement as security for any financing
with financial institutions; or (b) transfer or assign this Agreement to an
Affiliate of such Party. Nothing in this Section shall preclude any party from
transferring or assigning this Agreement to any person or entity succeeding to
all or substantially all of the assets of such Party; provided, however, that
any such assignee shall agree to be bound by the terms and conditions hereof
pursuant to an agreement satisfactory to the nonassigning Party and that all the
persons obligated to fulfill the assigning Party's obligations under the
Agreement after the assignment shall have substantially equivalent financial
capability to that of all other persons obligated to fulfill the assigning
Party's obligations under the Agreement before the assignment. References to
any Party named herein shall include such Party's successors and permitted
assigns.
ARTICLE 10
LIMITATION OF LIABILITY AND FORCE MAJEURE
10.1 Force Majeure. In the event either Party is rendered unable, by an
-------------
event of Force Majeure, to carry out wholly or in part its obligations under
this Agreement and such Party gives notice and full particulars of such event of
Force Majeure to the other Party as soon as practicable after the occurrence of
the event relied on, then the obligations of the Party affected by such event of
Force Majeure pursuant to this Agreement, other than the obligation to make
payments then due or becoming due
-8-
<PAGE>
hereunder, shall be suspended from the inception and throughout the period of
continuance of any such inability so caused, but for no longer period, and such
event of Force Majeure shall, so far as and as soon as practicable, be remedied
by application of Good Utility Operating Practice; provided however, that no
provision of this Agreement shall be interpreted to require PP&L to deliver, or
UGI to receive, Power at points other than the Delivery Point(s) or to require
UGI to accept or PP&L to make delivery of any remaining amounts of Power under
this Agreement following resolution of the Force Majeure.
10.2 Limitation of Liability. FOR BREACH OF ANY PROVISION FOR WHICH AN
-----------------------
EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED IN THIS AGREEMENT, THE
LIABILITY OF THE DEFAULTING PARTY SHALL BE LIMITED AS SET FORTH IN SUCH
PROVISION, AND ALL OTHER DAMAGES OR REMEDIES HEREBY ARE WAIVED. IF NO REMEDY OR
MEASURE OF DAMAGES IS EXPRESSLY PROVIDED, THE LIABILITY OF THE DEFAULTING PARTY
SHALL BE LIMITED TO DIRECT DAMAGES ONLY AND ALL OTHER DAMAGES AND REMEDIES ARE
WAIVED. IN NO EVENT SHALL EITHER PARTY BE LIABLE TO THE OTHER PARTY FOR
CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES IN TORT, FOR
CONTRACT OR OTHERWISE.
ARTICLE 11
TAXES
11.1 Allocation of and Indemnity for Taxes. The Contract Price paid
-------------------------------------
hereunder includes full reimbursement for and PP&L is liable for and shall pay
or cause to be paid, or reimburse UGI if UGI shall have paid, all Taxes
applicable to the Power sold hereunder prior to the Delivery Point(s) ("PP&L's
Taxes"). In the event UGI is required to remit any of PP&L's Taxes, the amount
thereof shall be deducted from any sums becoming due to PP&L hereunder. PP&L
shall indemnify, defend and hold UGI harmless from any liability for all PP&L's
Taxes. The Contract Price does not include reimbursement for and UGI is liable
for and shall pay, cause to be paid or reimburse PP&L if PP&L shall have paid,
all Taxes applicable for the Power sold hereunder at and after the Delivery
Point(s) ("UGI's Taxes"). UGI shall indemnify, defend and hold PP&L harmless
from any liability for all UGI's Taxes.
11.2 Automatic Tax Adjustment. Only if agreed to by the Parties, an
------------------------
adjustment for tax changes shall apply, as appropriate, to the Contract Prices
as billed under this Agreement. In such case, the Contract Prices will be
adjusted, as required,
-9-
<PAGE>
by including an automatic pass-through of increases in federal, state, or local
taxes, including new environmental taxes, or tax rates applicable to the Power,
based on actual tax expense incurred by PP&L.
11.3 Cooperation. Both Parties shall use reasonable efforts to administer
-----------
this Agreement and implement the provisions in accordance with their intent to
minimize Taxes.
ARTICLE 12
DEFAULT, SECURITY AND RESPONSIBILITY
12.1 Default, Security and Responsibility Events. Except as otherwise
-------------------------------------------
provided in Article 7, in the event either Party ("Defaulting Party") (i) makes
an assignment or any general arrangement for the benefit of creditors; (ii)
defaults in payment or performance of any obligation to the other Party under
this Agreement provided that such default in payment or performance shall be
deemed a default under this Article if not cured within five (5) Business Days
following written notice by the non-defaulting Party of such default in payment
or performance; (iii) files a petition or otherwise commences, authorizes, or
acquiesces in commencement of a proceeding or cause under any bankruptcy or
similar law for the protection of creditors or have such petition filed or
proceedings commenced against it; (iv) otherwise becomes bankrupt or insolvent
(however evidenced); or (v) fails to give adequate security for or assurance of
its ability to perform its further obligation under this Agreement within
seventy-two (72) hours of a reasonable request by the other Party, then the non-
defaulting Party upon written notice has the right to withhold or suspend
deliveries or receipts or terminate this Agreement pursuant to Section 12.2.
Subsections (i) - (v) above shall each be considered an "Event of Default."
12.2 Early Termination.
-----------------
(a) If an Event of Default occurs with respect to a Party at any time
during the term of this Agreement, the other Party (the "Notifying Party") may
(i) upon written notice to the other Party, which notice shall be given no later
than sixty (60) days after the discovery of the occurrence of the Event of
Default, terminate this Agreement as of a date determined by the Notifying Party
("Early Termination Date"); (ii) withhold any payment due under this Agreement;
and/or (iii) suspend performance under this Agreement; provided, however, upon
the occurrence of any Event of Default listed in clause (i), (iii) or (iv) of
Section 12.1, this Agreement shall automatically terminate, without notice, and
without any other action by either Party as if an Early Termination
-10-
<PAGE>
Date had been declared immediately prior to such event. If an Early Termination
Date has been designated or deemed to occur, the Notifying Party shall in good
faith calculate its damages resulting from the termination of this Agreement
(the "Termination Payment") as set forth below.
(b) When the Notifying Party is PP&L, the Termination Payment will be the
positive difference, if any, between (i) the payments (discounted to the Early
Termination Date at a rate per annum equal to the average yield to maturity of
United States treasury obligations having comparable maturity dates) that PP&L
would have received under this Agreement at the agreed to quantity(ies) and
price(s) had the Agreement not been terminated; and (ii) the payments
(discounted in the same manner as set forth above), for the remaining term, as
either quoted by a bona fide third party offer or which are reasonably expected
to be available in the market under replacement contract for this Agreement.
(c) When the Notifying Party is UGI, the Termination Payment will be the
positive difference, if any, between (i) the payments (discounted to the Early
Termination Date at a rate per annum equal to the average yield to maturity of
United States treasury obligations having comparable maturity dates) that UGI
would make under replacement contract (with the same quantities and
substantially similar terms and conditions) for the remaining term of this
Agreement, as either quoted by a bona fide third party offer or which are
reasonably expected to be available in the market; and (ii) the payments
(discounted in the same manner as set forth above) that UGI would pay under the
Agreement for its remaining term at the agreed to quantity(ies) and price(s) had
the Agreement not been terminated.
(d) To ascertain the market prices of a replacement contract, the
Notifying Party may consider, among other valuations, quotations from leading
dealers in electric purchase and sale contracts for Power and other bona fide
third party offers, all adjusted for the length of the remaining term and
differences in transmission costs, if any.
(e) The Notifying Party shall give the Defaulting Party written notice of
the amount of the Termination Payment, along with a statement detailing the
calculation of such amount. The Defaulting Party shall pay the Termination
Payment to the Notifying Party immediately upon receipt of such notice. At the
time for payment of any amount due under this Section, each Party shall pay to
the other Party all additional amounts payable by it pursuant to this Agreement,
but all such amounts shall be netted and aggregated with any Termination Payment
payable hereunder. Any Party failing to
-11-
<PAGE>
make payment when due hereunder shall pay interest on the overdue balance from
the due date at the Interest Rate.
ARTICLE 13
MISCELLANEOUS
13.1 Regulatory. It is understood by the Parties that this Agreement and
----------
performance hereunder is subject to all present and future valid and applicable
laws, orders, statutes, and regulations of courts or regulatory bodies (state or
federal) having jurisdiction over UGI, PP&L, or this Agreement.
13.2 Authorizations. The Parties hereto represent that they have (or will
--------------
have upon the Effective Date of this Agreement) all appropriate authorizations
necessary or proper to consummate and carry out their obligations under this
Agreement.
13.3 Monitoring and Recording. Each Party acknowledges and consents to the
------------------------
monitoring and recording of all telephone conversations between its
representatives and the representatives of the other Party. Any recording of
such conversations may be introduced to prove the intent of this Agreement;
provided however, that nothing of such conversations herein shall be construed
as a waiver of any objection to the introduction of such evidence on the grounds
of relevance.
13.4 Notices. Any notice, request, demand, statement, or payment provided
-------
for in this Agreement shall be confirmed in writing, unless otherwise noted, and
shall be made as specified below; provided, however, that notices of
interruption and communications to Transmitting Utility(ies) may be provided
verbally, effective immediately and, upon request, confirmed in writing. A
notice sent by facsimile transmission shall be deemed received by the close of
the Business Day on which such notice was transmitted or such earlier time as
confirmed by the receiving Party and notice by overnight mail or courier shall
be deemed to have been received two (2) Business Days after it was sent or such
earlier time as is confirmed by the receiving Party unless it confirms a prior
verbal communication in which case any such notice shall be deemed received on
the day sent. Notices shall be addressed to the Parties as follows or to such
other address as UGI or PP&L shall from time to time designate by letter
properly addressed:
-12-
<PAGE>
<TABLE>
<CAPTION>
UGI Utilities, Inc.:
NOTICES & CORRESPONDENCE INVOICES
- ------------------------ --------
<S> <C>
UGI Utilities, Inc. - Electric Division UGI Utilities, Inc. - Electric Division
400 Stewart Road 400 Stewart Road
P.O. Box 3200 P.O. Box 3200
Wilkes-Barre, PA 18773-3200 Wilkes-Barre, PA 18773-3200
Attn: Vice President and General Manager Attn: Controller - Electric Division
FAX: (570) 830-1190 FAX: (570) 830-1192
PP&L, Inc.:
NOTICES & CORRESPONDENCE PAYMENTS
- ------------------------ --------
PP&L, Inc. PP&L, Inc.
Two North Ninth Street Two North Ninth Street
Allentown, PA 18101-1179 Allentown, PA 18101-1179
Attn: Energy Marketing Center Attn: Cash Receipts
FAX: (610) 774-6523 FAX: (610) 774-4446
</TABLE>
13.5 Entirety. This Agreement and any Exhibits hereto constitute the
--------
entire agreement between the Parties. In addition, there are no other prior or
contemporaneous agreements or representations affecting the same subject matter
other than those herein expressed. Except for those matters which, in
accordance with this Agreement, may be resolved by the Parties and documented
electronically, it is further agreed that no amendment, modification or change
herein shall be enforceable, except as specifically provided for in this
Agreement, unless produced in writing and executed by both Parties.
13.6 Governing Law and Venue. If any proceeding or action on or
-----------------------
respecting this Agreement is brought by one of the Parties against the other
Party including any counterclaims and cross claims asserted in any such
proceeding or action, this Agreement shall be governed by and construed in
accordance with the laws of the Commonwealth of Pennsylvania, without regard to
Conflict of Law principles. Venue shall be either at the FERC or the courts of
the Commonwealth of Pennsylvania. Any such proceeding shall be brought in the
Courts of the Commonwealth of Pennsylvania, except to the extent that the FERC
has exclusive jurisdiction over the subject matter of the proceeding.
-13-
<PAGE>
13.7 Confidentiality. Neither Party shall disclose the terms of this
---------------
Agreement to any third party absent the express written permission of the other
Party except where (1) necessary to comply with any applicable law, order,
regulation or exchange rule; provided, however, that each Party shall notify the
other Party promptly upon receipt of any request to it in any proceeding that
could result in an order requiring such disclosure and the Party subject to such
request shall use reasonable efforts to prevent or limit the disclosure; or (2)
necessary to effectuate transmission of electricity subject to this Agreement.
However, nothing herein shall prevent either Party from disclosing simple price
and volume terms to a third party solely for the purpose of it being used in
conjunction with other similar information for establishing electric price
indices by a qualified independent entity provided that such information cannot
be used to identify the Parties to this Agreement. The Parties shall be entitled
to all remedies available at law or in equity to enforce, or seek relief in
connection with, this confidentiality obligation; provided, however, that all
monetary damages shall be limited to actual direct damages and a breach of this
section shall not give rise to the right to suspend or terminate this Agreement.
13.8 Non-Waiver. No waiver by either Party hereto of any one or more
----------
defaults by the other in the performance of any of the provisions of this
Agreement shall be construed as a waiver of any other default or defaults
whether of a like kind or different nature.
13.9 Severability. Except as otherwise stated herein, any provision,
------------
article or section of this Agreement that is declared or rendered unlawful by a
court of law or regulatory agency with jurisdiction over the Parties, or deemed
unlawful because of statutory change, will not otherwise affect the lawfulness,
enforceability and applicability of the remaining provisions, articles or
sections of this Agreement, nor shall it affect the obligations that arise under
this Agreement.
13.10 Headings. The headings used for the Articles herein are for
--------
convenience and reference purposes only and shall in no way affect the meaning
or interpretation of the provisions of this Agreement.
-14-
<PAGE>
IN WITNESS WHEREOF, the Parties hereto have executed this Agreement in
duplicate originals to be effective as of the day and year first written above.
UGI Utilities, Inc. PP&L, Inc.
By: ________________________________ By: ___________________________
Name: Mark R. Dingman Name: ___________________________
--------------------------------
Title: Vice President Title: ___________________________
--------------------------------
and General Manager
-15-
<PAGE>
DEFINITIONAL ANNEX
All references to Articles, Sections, Exhibits and Annexes are to those set
forth in or appended to this Agreement. Reference to any document means such
document as amended from time to time and reference to any Party includes any
permitted successor or assignee thereof. The following definitions and any
terms defined internally in this Agreement shall apply to this Agreement and all
notices and communications made pursuant to this Agreement.
In addition to terms defined elsewhere in this Agreement, the following
definitions shall apply hereunder:
"Accounted-For Obligation" shall have the same meaning as under the
------------------------
Reliability Assurance Agreement.
"Affiliate" means with respect to any person, any other person (other than
---------
an individual) that, directly or indirectly, through one or more intermediaries,
controls, or is controlled by, or is under common control with, such person.
For purposes of the foregoing definition, "control" means the direct or indirect
ownership of more than five percent (5%) of the outstanding capital stock or
other equity interests having ordinary voting power.
"Capacity Credits" shall have the same meaning as set forth in Section 2.3
----------------
of Schedule 11 to the Operating Agreement of the PJM Interconnection, L.L.C.
"Capacity Resource" shall have the same meaning as under the Reliability
-----------------
Assurance Agreement.
"Contract Price" means the agreed price for the purchase and sale of Power
--------------
under this Agreement.
"Control Area" means an electric system or combination of electric systems
------------
to which a common automatic generation control scheme is applied in accordance
with Good Utility Operating Practices to:
(1) match, at all times, the power output of the generators within the
electric system(s) and Power purchased from entities outside the
electric system(s), with the load within the electric system(s);
(2) maintain scheduled interchange with other Control Areas;
(3) maintain the frequency of the electric system(s) within reasonable
limits; and
-16-
<PAGE>
(4) provide sufficient generating capacity to maintain spinning and
operating reserves.
"FERC" means the Federal Energy Regulatory Commission or any successor
----
agency.
"Force Majeure" means any cause which the Party claiming Force Majeure (the
-------------
"Claiming Party"), was unable, in the exercise of due diligence and Good Utility
Operating Practice, to avoid, did not intend, and which is beyond the control,
and without the fault or negligence, of the Claiming Party or the Claiming
Party's Power Resources, and which renders the Claiming Party or Claiming
Party's Power Resources unable to carry out wholly or in part its obligation
under this Agreement. Force Majeure includes, but is not restricted to: flood;
earthquake; geohydrolic subsidence; tornado; storm; fire; civil disturbance or
disobedience; labor dispute; labor or material shortage; sabotage; action or
restraint by court order or public or governmental authority (so long as the
Claiming Party has not applied for or assisted in the application for, and has
opposed where and to the extent reasonable, such government action); and
reductions or interruptions in services which, in a Claiming Party's reasonable
judgment, or in the reasonable judgment of Claiming Party's Power Resources, are
necessary to protect generating or transmission facilities or the reliability of
transmission facilities; including the integrity, safety, reliability or
operation of any interconnected electric grid or system; and government action
that results in the price at which Power may be made available under this
Agreement being fixed or established by any government authority at a level that
results in a price that may be charged under this Agreement that (i) in the case
of PP&L, is lower than the Contract Price and (ii) in the case of UGI, is higher
than the Contract Price; provided, however, that such government action does not
include the imposition of any Taxes. Nothing contained herein shall be
construed to require a Claiming Party to settle any strike or labor dispute.
"Good Utility Operating Practice" means the practices, methods and acts
-------------------------------
engaged in or approved by a significant portion of the electric power industry
during the relevant time period, or the practices, methods and acts which, in
the exercise of reasonable judgment in light of the facts known at the time the
decision was made, could have been expected to accomplish the desired result
consistent with reliability, safety, expedition, the requirements of
governmental agencies having jurisdiction and, if appropriate or relevant under
the Transaction in question, at the lowest reasonable cost; such term is not
intended to be limited to the optimum practice, method or act to the exclusion
of all others, but rather to constitute a spectrum of acceptable practices,
methods or acts.
-17-
<PAGE>
"Interest Rate" means the prime rate of interest published by Mellon Bank
-------------
of Philadelphia or any successor thereto plus two hundred basis points as in
effect from time to time; provided, however, that the Interest Rate shall not
exceed the maximum rate permitted by applicable law.
"Load Serving Entity" shall have the same meaning as under the Reliability
-------------------
Assurance Agreement.
"Power" means electric capacity credits or energy or any combination
-----
thereof. Energy delivered as a component of power shall be of the type commonly
known as three-phases sixty-cycle alternating current. Use of either a
reservation charge and associated energy charge or an as-delivered energy charge
is for economic and operational convenience, and does not change the nature of
the Power sold under this Agreement.
"Power Resources" means the sources of Power with which PP&L has made
---------------
arrangements in order to provide Power under this Agreement.
"PJM" means the Pennsylvania-New Jersey-Maryland Interconnection, L.L.C.
---
"PP&L Zone" shall mean the Pennsylvania Power and Light Company Group
-----------
transmission zone as described in and established by the PJM Open Access
Transmission Tariff and related agreements.
"Quantity" means the amount of Power to be contracted for under this
--------
Agreement.
"Regulatory Approvals" means, for any Transaction, all applicable state and
--------------------
federal regulatory authorizations, consents, or approvals required under this
Agreement.
"Reliability Assurance Agreement" means the Reliability Assurance Agreement
---------------------------------
Among Load Serving Entities in the PJM Control Area as amended and revised from
time-to-time.
"Schedule" or "Scheduling" means communicating with and confirming with all
-------- ----------
Transmitting Utilities as well as between UGI and PP&L that a particular amount
of Power is to be delivered or received and providing all such information and
satisfying all such requirements as may be necessary to cause such Parties to
recognize and confirm the delivery or receipt of the Power. All scheduling of
services with
-18-
<PAGE>
Transmitting Utility(s) and Control Area(s) shall be accomplished in compliance
with the scheduling rules of those Transmitting Utility(ies) and Control
Area(s). Between PP&L and UGI, scheduling shall be accomplished no later than
sixty (60) minutes before the start of the intended power flow or as per other
rules as UGI and PP&L may jointly agree from time to time.
"Taxes" means all ad valorem, property, occupation, utility, gross
-----
receipts, sales use, excise, and other taxes or governmental charges, licenses,
permits, and assessments, other than taxes based on net income or net worth.
"Transmitting Utility" means the utility or utilities and their respective
--------------------
Control Areas transmitting Power from the Power Resources to the Delivery
Point(s) as part of this Agreement.
"1935 Interconnection Agreement" shall mean the interconnection agreement
------------------------------
as supplemented and amended from time to time which covered the interconnection
and the coordinated operations of the electric systems of PP&L and UGI within
the PJM.
"1992 Power Sales Agreement" shall mean the 15 year partial requirements
--------------------------
power sales agreement entered into between PP&L and UGI on December 1, 1992.
-19-
<PAGE>
EXHIBIT 10(j)-3
AMENDMENT NO. 2
TO
PP&L, INC. SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
WHEREAS, PP&L, Inc. ("PP&L") adopted the PP&L, Inc. Supplemental Executive
Retirement Plan (the "Plan"), effective July 1, 1985, as amended and restated
from time to time, for certain of its employees; and
WHEREAS, the Plan was amended and restated effective January 1, 1998, and
subsequently amended by Amendment No. 1; and
WHEREAS, the Company desires to further amend the Plan;
NOW, THEREFORE, the Plan is hereby amended as follows:
I. Effective July 1, 1999 the definition of "Prior Plan" in Article 2 was
deleted.
II. Effective July 1, 1999, the following sections of Article 4 are amended
to read as follows:
4. Amount of Supplemental Executive Retirement Benefit.
(a) A Participant entitled to benefits under Article 3 will be paid a SERB
equal to an annual amount payable for the life of Participant
calculated pursuant to Sections (b) through (f) below:
(b) The amount calculated under Subsection (1) and/or (2), as appropriate:
(1) The sum of (A) plus (B):
(A) 2.0% of Participant's Supplemental Final Average Earnings
times his Years of Service up to 20, plus
(B) 1.5% of Participant's Supplemental Final Average Earnings
times his Years of Service in excess of 20 but not in excess
of 30.
(2) With respect only to Participants who were officers in positions
in PP&L Salary Groups I through IV on December 31, 1997:
-1-
<PAGE>
(A) the benefit determined under Subsection (4)(b)(1) shall be
calculated using Projected Years of Service instead of Years
of Service;
(B) such Participant's SERB shall not be less than the greater
of (I) or (II) below:
(I) (i) 2.7% of Participant's Supplemental Final Average
Earnings calculated as of the earlier of December 31,
2001 or the date Participant terminates employment
times his Years of Service up to 20, plus (ii) 1.0% of
Participant's Supplemental Final Average Earnings
calculated as of the earlier of December 31, 2001 or
the date Participant terminates employment, times his
Years of Service in excess of 20 but not more than 30
less (iii) the annual amount payable as the maximum
primary Social Security benefit payable to an
individual aged 65 in the year of Participant's
retirement whether or not received by Participant.
(II) (i) 2.7% of Participant's Supplemental Final Average
Earnings calculated as of the earlier of December 31,
2001 or the date Participant terminates employment,
times his Projected Years of Service up to 20, plus
(ii) 1.0% of Participant's Supplemental Final Average
Earnings calculated as of the earlier of December 31,
2001 or the date Participant terminates employment,
times his Projected Years of Service in excess of 20
but not more than 30, less (iii) the annual amount
payable as the maximum primary Social Security benefit
payable to an individual aged 65 in the year of
Participant's retirement whether or not received by
Participant
(f) In the event that a Participant's benefits under any plan to which
Section (d) or (e) of this Article refers are subject in whole or in
part to a domestic relations order, SERB payments shall be calculated
and paid without regard to such order.
-2-
<PAGE>
III. Except as provided for in this Amendment No. 2, all other provisions of
the Plan shall remain in full force and effect.
IN WITNESS WHEREOF, this Amendment No. 2 is executed this ____ day of
___________________1999.
PP&L, INC.
By:_______________________________
John R. Biggar
Senior Vice President and
Chief Financial Officer
-3-
<PAGE>
EXHIBIT 10(k)-2
AMENDMENT NO. 1
TO
PP&L RESOURCES
INCENTIVE COMPENSATION PLAN
WHEREAS, PP&L Resources, Inc. ("Resources") has adopted the PP&L Resources
Incentive Compensation Plan ("Plan") effective January 1, 1987; and
WHEREAS, the Plan was amended and restated effective January 1, 1999; and
WHEREAS, Resources desires to further amend the Plan;
NOW, THEREFORE, the Plan is hereby amended as follows:
I. Effective January 1, 1999, the following sections are amended to read:
SECTION 3. EFFECTIVE DATE AND DURATION.
Upon the approval of the predecessor plan by the holders of a majority
of the shares of 4 1/2% Preferred Stock, Series Preferred Stock, Preference
Stock and Common Stock of PP&L, Inc. present (either in person or by proxy) at
the 1987 Annual Meeting of shareowners, the predecessor plan became effective on
January 1, 1987. This Plan as amended and restated shall become effective as of
January 1, 1999 upon the approval of the Plan by the holders of a majority of
the shares of Resources Common Stock present (either in person or by proxy) at
the 1999 Annual Meeting of Shareowners. Awards of Incentive Stock Options may
be made under the Plan for a period of ten years after January 1, 1999. This
Plan shall continue in effect until all matters relating to the payment of
Awards and the administration of the Plan have been settled.
SECTION 5. GRANT OF AWARDS AND LIMITATION OF NUMBER OF SHARES AWARDED.
The Committee may, from time to time, grant Awards to one or more
Eligible Employees, provided that: (i) subject to any adjustment pursuant to
Section 10G and any limitation pursuant to Section 10H, the maximum number of
shares of Common Stock subject to Awards (including Incentive Stock Options)
shall not exceed annually 2% of the outstanding Common Stock of Resources on the
first day of each calendar year commencing on and after January 1, 1999; (ii)
the maximum number of Options awarded to any single Eligible Employee in any
calendar year shall not exceed 1.5 million shares; provided that any portion of
such maximum number of shares that has not been granted may be carried over and
used in any subsequent year; (iii) to the extent that an Award lapses or is
forfeited or the rights of the Participant to whom an Award was granted
terminate, any shares of Common Stock subject to such Award shall again be
available for the grant of an Award under the Plan; and (iv) shares delivered
under the Plan may
-1-
<PAGE>
be authorized and unissued Common Stock, Common Stock held in the treasury of
Resources or Common Stock purchased on the open market (including private
purchases) in accordance with applicable securities laws.
SECTION 10. MISCELLANEOUS PROVISIONS.
H. New York Stock Exchange Requirements. In accordance with the
requirements of the New York Stock Exchange (the "NYSE") for the listing of
newly issued shares of Common Stock subject to Awards, the Committee may not
grant Awards under the Plan to the extent that the aggregate number of shares
subject to Awards granted after approval of the Plan at the 1999 Annual Meeting
of shareowners of Resources would exceed 5% of the outstanding Common Stock of
Resources on the date of such Annual Meeting, unless the issuance of the shares
of Common Stock subject to any such additional Awards has been approved by the
shareowners of Resources to the extent required by the rules of the NYSE.
SECTION 11. OTHER STOCK-BASED AWARDS
(a) Generally. The Committee, in its sole discretion, may grant awards of
---------
Common Stock, awards of restricted shares and awards that are valued in whole or
in part by reference to, or are otherwise based on the Fair Market Value of,
Common Stock ("Other Stock-Based Awards"). Such Other Stock-Based Awards shall
be in such form, and dependent on such conditions, as the Committee shall
determine, including, without limitation, the right to receive one or more
shares of Common Stock (or the equivalent cash value of such Common Stock) upon
the completion of a specified period of service, the occurrence of an event
and/or the attainment of performance objectives. Other Stock-Based Awards may
be granted alone or in addition to any other Awards granted under the Plan.
Subject to the provisions of the Plan, the Committee shall determine to whom and
when Other Stock-Based Awards will be made; the amount of Common Stock to be
awarded under (or otherwise related to) such Other Stock-Based Awards; whether
such Other Stock-Based Awards shall be settled in cash, Common Stock or a
combination of cash and Common Stock; and all other terms and conditions of such
Awards (including, without limitation, the vesting provisions thereof).
(b) Performance-Based Awards. Notwithstanding anything to the contrary
------------------------
herein, certain Other Stock-Based Awards granted under this Section 11 may be
granted in a manner which is deductible by Resources under Section 162(m) of the
Code (or any successor section thereto)("Performance-Based Awards"). A
Participant's Performance-Based Award shall be determined based on the
attainment of written performance goals approved by the Committee for a
performance period established by the Committee (i) while the outcome for that
performance period is substantially uncertain and (ii) no more than 90 days
after the commencement of the performance period to which the performance goal
relates or, if less, the number of days which is equal to 25 percent of the
relevant performance period. The performance goals, which must be objective,
shall be based upon one or more of the following criteria: (i) earnings before
or after taxes (including earnings before interest, taxes, depreciation and
amortization); (ii) net income; (iii) operating income; (iv) earnings per share;
(v) book value per share; (vi) return on stockholders' equity; (vii) expense
management; (viii) return on investment before or after
-2-
<PAGE>
the cost of capital; (ix) improvements in capital structure; (x) profitability
of an identifiable business unit or product; (xi) maintenance or improvement of
profit margins; (xii) stock price; (xiii) market share; (xiv) revenues or sales;
(xv) costs; (xvi) cash flow; (xvii) working capital; (xviii) changes in net
assets (whether or not multiplied by a constant percentage intended to represent
the cost of capital); (xix) return on assets; and (xx) independent industry
ratings or assessments. The foregoing criteria may relate to Resources, one or
more of its subsidiaries or one or more of its divisions, units, minority
investments, partnerships, joint ventures, product lines or products or any
combination of the foregoing, and may be applied on an absolute basis and/or be
relative to one or more peer group companies or indices, or any combination
thereof, all as the Committee shall determine. In addition, to the degree
consistent with Section 162(m) of the Code (or any successor section thereto),
the performance goals may be calculated without regard to extraordinary items or
accounting changes. The maximum amount of a Performance-Based Award to any
Participant with respect to a fiscal year of Resources shall be 1.5 million
shares; provided that any portion of such maximum number of shares that has not
been granted may be carried over and used in any subsequent year. The Committee
shall determine whether, with respect to a performance period, the applicable
performance goals have been met with respect to a given Participant and, if they
have, to so certify and ascertain the amount of the applicable Performance-Based
Award. No Performance-Based Awards will be paid for such performance period
until such certification is made by the Committee. The amount of the
Performance-Based Award determined by the Committee for a performance period
shall be paid to the Participant at such time as determined by the Committee in
its sole discretion after the end of such performance period; provided, however,
-----------------
that a Participant may, if and to the extent permitted by the Committee and
consistent with the provisions of Section 162(m) of the Code, elect to defer
payment of a Performance-Based Award.
II. Except as provided for in this Amendment No. 1, all other provisions of the
Plan shall remain in full force and effect.
IN WITNESS WHEREOF, this Amendment No. 1 is executed this ____ day of
_____________, 1999.
PP&L RESOURCES, INC.
By:_____________________________________
John M. Chappelear
Vice President-Investments & Pension
-3-
<PAGE>
Exhibit 12(a)
PPL CORPORATION AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Millions of Dollars)
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Fixed charges, as defined:
Interest on long-term debt................................. $233 $203 $196 $207 $213
Interest on short-term debt and other interest............. 47 33 26 17 18
Amortization of debt discount, expense and premium - net... 4 2 2 2 2
Interest on capital lease obligations
Charged to expense..................................... 8 8 9 13 15
Capitalized............................................ 1 2 2 2 2
Estimated interest component of operating rentals.......... 20 18 15 8 8
Proportionate share of fixed charges
of 50-percent-or-less-owned persons...................... 1 1 1 1 1
---- ---- ---- ---- ----
Total fixed charges................................ $314 $267 $251 $250 $259
==== ==== ==== ==== ====
Earnings, as defined:
Net income (a)............................................. $478 $379 $296 $329 $323
Preferred and Preference Stock Dividend Requirements....... 26 25 24 28 28
Less undistributed income of less
than 50-percent-owned persons............................ -- -- -- -- --
---- ---- ---- ---- ----
504 404 320 357 351
Add (Deduct):
Income taxes............................................... 174 259 238 253 286
Amortization of capitalized interest on capital leases..... 2 2 2 4 5
Total fixed charges as above
(excluding capitalized interest
on capital lease obligations)............................ 313 265 248 248 257
---- ---- ---- ---- ----
Total earnings..................................... $993 $930 $808 $862 $899
==== ==== ==== ==== ====
Ratio of earnings to fixed charges (b)....................... 3.16 3.48 3.22 3.45 3.47
==== ==== ==== ==== ====
</TABLE>
(a) 1999 and 1998 net income excluding extraordinary items.
(b) Based on earnings excluding one-time adjustments, the ratio of earnings to
fixed charges are: 1999, 2.86; 1998, 3.10; 1997, 3.40; and 1995, 3.08.
<PAGE>
Exhibit 12(b)
PPL ELECTRIC UTILITIES CORPORATION AND SUBSIDIARIES, CONSOLIDATED
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Millions of Dollars)
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Fixed charges, as defined:
Interest on long-term debt..................................... $205 $188 $195 $207 $213
Interest on short-term debt and other interest................. 10 14 17 11 18
Amortization of debt discount, expense and premium - net....... 5 2 2 2 2
Interest on capital lease obligations
Charged to expense......................................... 9 8 9 13 15
Capitalized ............................................... 1 2 2 2 2
Estimated interest component of operating rentals.............. 19 18 15 8 8
Proportionate share of fixed charges
of 50-percent-or-less-owned persons ......................... 1 1 1 1 1
---- ---- ---- ---- ----
Total fixed charges.................................... $250 $233 $241 $244 $259
==== ==== ==== ==== ====
Earnings, as defined:
Net income (a)................................................. $444 $409 $348 $357 $352
Less undistributed income of less
than 50-percent-owned persons................................ -- -- -- -- --
---- ---- ---- ---- ----
444 409 348 357 352
Add (Deduct):
Income taxes .................................................. 151 273 248 251 287
Amortization of capitalized interest on capital leases......... 2 2 2 4 6
Total fixed charges as above
(excluding capitalized interest
on capital lease obligations)................................ 249 231 239 243 257
---- ---- ---- ---- ----
Total earnings......................................... $846 $915 $837 $855 $902
==== ==== ==== ==== ====
Ratio of earnings to fixed charges (b)........................... 3.38 3.93 3.47 3.50 3.48
==== ==== ==== ==== ====
</TABLE>
(a) 1999 and 1998 net income excluding extraordinary items.
(b) Based on earnings excluding one-time adjustments, the ratio of earnings to
fixed charges are: 1999, 3.09; 1998, 3.52; and 1995, 3.09.
<PAGE>
Exhibit 23
Consent of Independent Accountants
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-3 (Nos. 333-48781, 333-70101, 333-70101-01, 333-87847, 333-
87847-01 and 333-87847-02) of PPL Corporation and in the Registration Statements
on Form S-8 (Nos. 33-50031, 333-02003 and 333-95967) of PPL Corporation of our
report dated January 31, 2000 relating to the consolidated financial statements
and financial statement schedules, which appears in this Form 10_K.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
March 1, 2000
<PAGE>
PPL CORPORATION
PPL ELECTRIC UTILITIES CORPORATION.
1999 ANNUAL REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION
ON FORM 10-K
POWER OF ATTORNEY
-----------------
The undersigned directors of PPL Corporation and PPL Electric Utilities
Corporation, both Pennsylvania corporations, which are to file with the
Securities and Exchange Commission, Washington, D.C., under the provisions of
the Securities Exchange Act of 1934, as amended, their 1999 Annual Report on
Form 10-K, do hereby appoint William F. Hecht, John R. Biggar and Robert J. Grey
their true and lawful attorney, and each of them their true and lawful attorney,
with power to act without the other and with full power of substitution and
resubstitution, to execute for them and in their names said Form 10-K Report and
any and all amendments thereto, whether said amendments add to, delete from or
otherwise alter said Form 10-K Report, or add or withdraw any exhibits or
schedules to be filed therewith and any and all instruments in connection
therewith. The undersigned hereby grant to said attorneys and each of them full
power and authority to do and perform in the name of and on behalf of the
undersigned, and in any and all capacities, any act and thing whatsoever
required or necessary to be done in and about the premises, as fully and to all
intents and purposes as the undersigned might do, hereby ratifying and approving
the acts of said attorneys and each of them.
<PAGE>
IN WITNESS WHEREOF, the undersigned have hereunto set their hands and
seals this 25th day of February, 2000.
By: /s/ Frederick M. Bernthal L.S. By: /s/ Stuart Heydt L.S.
------------------------------- ------------------------------
Frederick M. Bernthal Stuart Heydt
By: /s/ E. Allen Deaver L.S. By: /s/ Frank A. Long L.S.
------------------------------- ------------------------------
E. Allen Deaver Frank A. Long
By: /s/ William J. Flood L.S. By: /s/ Norman Robertson L.S.
------------------------------- ------------------------------
William J. Flood Norman Robertson
By: /s/ Elmer D. Gates L.S. By: /s/ Marilyn Ware L.S.
------------------------------- ------------------------------
Elmer D. Gates Marilyn Ware
By: /s/ William F. Hecht L.S.
-------------------------------
William F. Hecht
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENT OF OPERATIONS AND CHANGES IN MEMBER'S EQUITY, THE STATEMENT OF CASH
FLOWS, AND THE BALANCE SHEET FOR THE FORM 10-K DATED DECEMBER 31, 1999, AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000317187
<NAME> PPL ELECTRIC UTILITIES CORPORATION
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,325
<OTHER-PROPERTY-AND-INVEST> 796
<TOTAL-CURRENT-ASSETS> 967
<TOTAL-DEFERRED-CHARGES> 3,004
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 9,092
<COMMON> 1,476
<CAPITAL-SURPLUS-PAID-IN> (599)<F1>
<RETAINED-EARNINGS> 419
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,296
47
50
<LONG-TERM-DEBT-NET> 3,403
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 183
<LONG-TERM-DEBT-CURRENT-PORT> 352
0
<CAPITAL-LEASE-OBLIGATIONS> 67
<LEASES-CURRENT> 58
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3,636
<TOT-CAPITALIZATION-AND-LIAB> 9,092
<GROSS-OPERATING-REVENUE> 3,952
<INCOME-TAX-EXPENSE> 151
<OTHER-OPERATING-EXPENSES> 3,203
<TOTAL-OPERATING-EXPENSES> 3,354
<OPERATING-INCOME-LOSS> 598
<OTHER-INCOME-NET> 97
<INCOME-BEFORE-INTEREST-EXPEN> 695
<TOTAL-INTEREST-EXPENSE> 214
<NET-INCOME> 435<F2>
37
<EARNINGS-AVAILABLE-FOR-COMM> 398
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 142
<CASH-FLOW-OPERATIONS> 645
<EPS-BASIC> 0.00
<EPS-DILUTED> 0.00
<FN>
<F1>NET OF $632 MILLION OF TREASURY STOCK
<F2>NET MILLION INCLUDES AN EXTRAORDINARY ITEM OF ($46) MILLION ($78 MILLION NET
OF $32 MILLION OF INCOME TAXES) REFLECTING THE EFFECTS OF THE EARLY
EXTINGUISHMENT OF DEBT AND A CREDIT RELATING TO WHOLESALE POWER ACTIVITY.
</FN>
</TABLE>
