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EXHIBIT 99.1

FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements. We have based these
forward-looking statements on our current expectations and projections about
future events based upon our knowledge of facts as of the date of this report
and our assumption about future events. These forward-looking statements are
subject to various risks and uncertainties that may be outside of our control,
including, among other things:

o governmental, statutory, regulatory or administrative
initiatives affecting us, our facilities or the United States
electricity industry generally;

o demand for electric capacity and energy in the markets served
by our facilities;

o competition from other power plants, including new plants that
may be developed in the future;

o operating risks, including equipment failure, dispatch levels,
availability, heat rate and output; and

o the cost and availability of fuel and fuel transportation
services for our facilities.

We use words like "believes," "expects," "anticipates," "intends,"
"may," "will," "should," "estimate," "projected" and similar expressions to help
identify forward-looking statements in this current report.

In light of these and other risks, uncertainties and assumptions,
actual events or results may be very different from those expressed or implied
in the forward-looking statements in this report or may not occur. We have no
obligation to publicly update or revise any forward-looking statement, whether
as a result of new information, future events or otherwise.

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MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

GENERAL

We are a Pennsylvania limited partnership which is a partnership among
Chestnut Ridge Energy Company, as a limited partner with a 99% interest, and
Mission Energy Westside Inc., as a general partner with a 1% interest. Both
Chestnut Ridge Energy and Mission Energy Westside are wholly-owned subsidiaries
of Edison Mission Holdings. We were formed on October 31, 1998 for the purpose
of acquiring, owning and operating the facilities. Although we were formed on
October 31, 1998, we had no significant activity before the acquisition of the
facilities.

On March 18, 1999, we completed the acquisition of the facilities and
assumed specified liabilities of the former owners. The facilities consist of
three coal-fired steam turbine units, one coal preparation facility, an
1,800-acre dam site and associated support facilities. Units 1 and 2 are
essentially identical steam turbine generators with net summer capacities of 620
MW and 614 MW, respectively. Units 1 and 2 began commercial operation in 1969.
Unit 3 is also a steam turbine generator with a net summer capacity of 650 MW.
Unit 3 began commercial operations in 1977. We benefit from direct transmission
access into both the Pennsylvania-New Jersey-Maryland power market (PJM) and the
New York independent system operator (NYISO.) The acquisition was financed
through a capital contribution of $273 million from our partners and a loan from
our affiliate, Edison Mission Finance Co.

We believe there may be opportunities to derive revenue from the sale
of installed capacity and ancillary services. We also have the option to sell
non-contracted capacity in PJM and NYISO. We believe the facilities should be
capable of producing revenues from the sale of voltage support based on their
previous utilization.

Related Party Transactions

Certain administrative services such as payroll, employee benefit
programs, insurance and information technology are shared among all affiliates
of our ultimate parent company, Edison International ("EIX"), and the costs of
these corporate support services are allocated to all affiliates. The cost of
services provided by EIX, including those related to us, are allocated to Edison
Mission Energy ("EME") based on one of the following formulas: percentage of the
time worked, equity in investment and advances, number of employees, or
multi-factor (operating revenues, operating expenses, total assets and total
employees). We participate in a common payroll and benefit program with all EIX
employees. In addition, EIX bills EME for any direct labor and out-of-pocket
expenses for services directly requested for our benefit. We believe the
allocation methodologies are reasonable.

We derive revenue from the sale of energy and capacity into PJM and
NYISO and from bilateral contracts with power marketers and load serving
entities within PJM, NYISO and the surrounding markets. We have entered into a
hedging contract with a marketing affiliate, which was formed by EME on November
20, 1998, for the sale of energy and capacity produced by the facilities, which
enables this marketing affiliate to engage in forward sales and hedging. Under
this hedging contract, we pay the marketing affiliate fees of $0.02/MWh plus
emission allowance fees. The net fees earned by the marketing affiliate were
$1.5 million and $0.2 million for the years ended December 31, 2000 and 1999,
respectively.

During 2001, we entered into three (3) transactions for unforced
capacity with our marketing affiliate as follows: 450 MW for the period of
June-December

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2001, 150 MW for the period of January-December 2002, and 125 MW for the period
January-May 2002. Each was at fair market value for such unforced capacity at
the time. Total payments for the three transactions will amount to approximately
$25,506,000.

Historically, we have not been charged for an allocation of the Chicago
Office of EME's Americas Region since its inception in later 1999 due to its
principal focus on power plants in Illinois. The Chicago Office has technical
and managerial responsibility for our operations. However, we may be charged in
the future for a share of these costs. If these costs were allocated to us, they
would be recorded as a non-cash charge against our operations as an in-kind
contribution of services through our parent. Accordingly, there would be no cash
impact of an allocation of such costs on our operations. We do not believe that
we would incur a material amount of additional costs to operate the Homer City
plant on the basis of an unaffiliated relationship with Edison Mission Energy.

RESULTS OF OPERATIONS

As indicated above, we acquired the facilities on March 18, 1999 and,
accordingly, our 1999 results of operations included only nine-and-a-half months
of activity from our facilities, compared to a full twelve months in 2000.

INTERIM RESULTS

OPERATING REVENUES

Operating revenues increased $2.7 million and $33.6 million for the
second quarter and six months ended June 30, 2001, respectively, compared to the
corresponding periods in 2000 primarily due to higher energy prices. Energy and
capacity sales were made through contracts with a marketing affiliate. We
generated 2,663 GWhr and 6,160 GWhr of electricity during the second quarter and
six months ended June 30, 2001, respectively, compared to generating 2,683 GWhr
and 6,070 GWhr of electricity in the corresponding periods in 2000. The
availability factor for the six months ended June 30, 2001 was 83.3%, compared
to 79.3% for the corresponding period in 2000. The availability factor is
determined by the number of megawatt hours we are available to generate
electricity divided by the number of hours in the period. The availability
factor is reduced from 100% by planned maintenance outages that are within our
control and by unplanned maintenance outages (generally referred to as forced
outages) that are outside of our control. During the six months ended June 30,
2001, our planned maintenance rate was 13.2% and our forced outage rate was 3.5%
compared to a planned maintenance rate of 15.6% and a forced outage rate of 5.1%
during the corresponding period in 2000.

The weighted average price for energy was $33.92/MWh during the second
quarter of 2001, compared to $33.12/MWh for the same period in 2000. The
weighted average price for energy was $33.64/MWh during the first six months of
2001, compared to $29.82/MWh for the same period in 2000. The increase in the
weighted average price for energy is due to higher PJM market prices and higher
hedge prices.

OPERATING EXPENSES

Operating expenses decreased $3.5 million and increased $1.6 million
for the second quarter and six months ended June 30, 2001, respectively,
compared to the corresponding periods in 2000. Operating expenses consisted of
expenses for fuel, plant operations, depreciation and amortization and
administrative and general expenses. The change in components of operating
expenses are discussed below.

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Fuel costs decreased $1.8 million for the second quarter ended June 30,
2001, compared to the corresponding period in 2000. Fuel costs increased $1.9
million for the six months ended June 30, 2001, compared to the same period in
2000. The change in fuel costs is due to changes in electrical generation and
the price of fuel. The average price of coal per ton was $27.76 for the six
months ended June 30, 2001, compared to $28.71 for the same period in 2000. The
average price decreased due to changes in the type of coal used in operations.
The facilities benefit from access by truck to significant native coal reserves
located within the western Pennsylvania portion of the North Appalachian region.
Up to 95% of the coal used by Units 1 and 2 is supplied under existing contracts
with regional mines that are located within approximately 100 miles of the
facilities, while the remainder is purchased on the spot market. The coal for
these units that is purchased from local mines is cleaned by the coal-cleaning
facility to reduce sulfur and ash content. Unit 3 currently utilizes lower
sulfur coal that is blended at an on-site coal blending facility. As we complete
the Environmental Improvements, we plan to eliminate the lower sulfur coal at
Unit 3 (as our sulfur emissions will be reduced through use of the Environmental
Improvements) that will reduce our fuel costs. The lower fuel costs will be
partially offset by higher depreciation expense from the Environmental
Improvements and interest expense (currently being capitalized).

Plant operations costs decreased $2.3 million and $3.7 million in the
second quarter and six months ended June 30, 2001, respectively, compared to the
same periods in 2000. Plant operations costs include labor and overhead,
contract services, parts and supplies, and other administrative costs. Plant
operations costs were lower in the second quarter and six months ended June 30,
2001 than costs for the same periods in 2000 due to lower maintenance expenses.
Our planned maintenance expense will vary based on a number of factors including
timing of our maintenance on major pieces of equipment including the boiler and
turbine on each unit (generally planned for three and six year cycles). Our
expenditures for maintenance of major pieces of equipment are expected to be
similar during the next several years.

Depreciation and amortization increased $0.7 million and $1.4 million
in the second quarter and six months ended June 30, 2001, respectively, compared
to the same periods in 2000. Depreciation expense primarily relates to the
acquisition of the facilities, which are being depreciated over 39 years from
the date of acquisition.

Administrative and general expenses were ($1.9) million in the six
months ended June 30, 2000 due to a reduction in our accrual for Pennsylvania
state capital tax.

OTHER INCOME (EXPENSE)

Interest and other income (expense) decreased $2.2 million and $3.4
million for the second quarter and six months ended June 30, 2001, respectively,
compared to the same prior year periods. The decrease was primarily due to
losses related to removal of equipment in connection with completing our capital
improvement program.

PROVISION FOR INCOME TAXES

The effective income tax rate in the first six months of 2001 was 41%
compared to a rate of 33% for the same period in 2000. The effective tax rates
are higher than the federal statutory rate of 35% due to state income taxes.

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ANNUAL RESULTS

OPERATING REVENUES

Operating revenues increased $96.1 million in 2000 compared to 1999
primarily as a result of having nine-and-a-half months of activity in 1999.
Energy and capacity sales were made through a contract with a marketing
affiliate. We generated 12,468 and 9,823 GWhr of electricity during 2000 and
1999, respectively, and had an availability factor of 80.2% and 86.8% during
these periods. The availability factor is determined by the number of megawatt
hours we are available to generate electricity divided the number of hours in
the period. We are not available during periods of planned and unplanned
(generally referred to as forced outages) maintenance. During 2000, our forced
outage rate was 6.1% compared to 5.9% during 1999. The availability factor
decreased in 2000 from 1999 due to higher planned outages that were needed to
complete our environmental improvements. The weighted average price for energy
was $30/MWh during 2000 and 1999.

Due to higher electric demand resulting from warmer weather during the
summer months, electric revenues generated from the facilities are substantially
higher during the third quarter.

OPERATING EXPENSES

Operating expenses increased $71.8 million primarily as a result of
only having nine-and-a-half months of activity in 1999. Operating expenses
consisted of expenses for fuel, plant operations, depreciation and amortization
and administrative and general expenses. The change in components of operating
expenses are discussed below.

Fuel costs increased to $164.1 million in 2000 from $124.8 million in
1999, primarily as a result of only having nine-and-a-half months of activity in
1999. The average price of coal per ton was $28.95 and $31.12 during 2000 and
1999, respectively. The facilities benefit from access by truck to significant
native coal reserves located within the western Pennsylvania portion of the
North Appalachian region. Up to 95% of the coal used by Units 1 and 2 is
supplied under existing contracts with regional mines that are located within
approximately 100 miles of the facilities, while the remainder is purchased on
the spot market. The coal for these units that is purchased from local mines is
cleaned by the coal-cleaning facility to reduce sulfur and ash content. Unit 3
utilizes lower sulfur coal that is blended at an on-site coal blending facility.

Plant operations costs increased to $79.1 million during 2000 from
$56.8 million during 1999. Plant operations costs include labor and overhead,
contract services, parts and supplies, and other administrative costs. Plant
operations costs in 2000 were higher than 1999 costs due to a full year of
operations of the facilities in 2000 and higher maintenance expenses during
planned outages.

Depreciation increased to $47.3 million during 2000 from $37.2 million
during 1999. Depreciation expense primarily relates to the acquisition of the
facilities, which are being depreciated over 39 years from the date of
acquisition.

OTHER INCOME (EXPENSE)

Interest expense from affiliates was $138.7 million during 2000
compared to $103.8 million during 1999. The average interest rate on outstanding
indebtedness was approximately 8.4% during both 2000 and 1999.

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Interest and other income was $3.7 million and $1.0 million during 2000
and 1999, respectively. Interest and other income primarily relates to interest
earned on cash and cash equivalents.

PROVISION (BENEFIT) FOR INCOME TAXES

We had an effective tax provision (benefit) rate before extraordinary
item of (11)% during 2000 compared to a rate of 52% during 1999. The effective
tax rates are higher than the federal statutory rate of 35% due to state income
taxes.

EXTRAORDINARY LOSS

The early repayment of the $800 million term loan in May 1999 resulted
in an extraordinary loss of $2.9 million, net of income tax benefit of $2.1
million, attributable to the write-off of unamortized debt issue costs.

LIQUIDITY AND CAPITAL EXPENDITURES

At June 30, 2001, we had cash and cash equivalents of $50.2 million.
Net cash provided by operating activities totaled $44.7 million during the six
months ended June 30, 2001, compared to $17.0 million for the corresponding
period of the prior year. The increase of $27.7 million is a result of the
increase in net income and the collection of receivables from our marketing
affiliate.

Net cash provided by operating activities was $17.0 million and $84.6
million for the years ended December 31, 2000 and 1999, respectively. Net cash
flow provided by operating activities decreased $67.6 million from 1999 as a
result of timing of working capital requirements. Net working capital was $107.6
million and $73.0 million at December 31, 2000 and 1999, respectively.

In March 1999, we completed the acquisition of the facilities from GPU,
Inc., New York State Electric & Gas Corporation and their respective affiliates.
Consideration for the purchase was a cash payment of approximately $1.8 billion.

The acquisition was financed through a capital contribution of $273
million from our partners and a loan from our affiliate, Edison Mission Finance
Co. A portion of the loan was subsequently replaced by $830 million of senior
secured bonds.

In order to effect the acquisition, Edison Mission Holdings entered
into an $800 million initial financing, which we refer to as the acquisition
facility, a $250 million construction loan that would be drawn as needed, which
we refer to as the environmental capital improvements facility, and a $50
million line of credit, which we refer to as the working capital facility.
Amounts borrowed under the acquisition facility, the environmental capital
improvements facility and the working capital facility bear interest at variable
Eurodollar rates or Base rates, at our option. If Edison Mission Holdings elects
to pay Eurodollar rates, interest costs include a margin of 0.85% to 2.25%
depending on Edison Mission Holdings' current debt rating. At December 31, 2000,
the margin was 1.00%. Additionally, Edison Mission Holdings pays a facility fee
of 0.15% to 0.50%, depending on Edison Mission Holdings' current debt rating, on
the total outstanding commitment, irrespective of usage. At December 31, 2000,
the facility fee was 0.25%. The financing received by Edison Mission Holdings
under the acquisition facility and the environmental capital improvements
facility due 2004 were loaned to Edison Mission Finance under a subordinated
loan agreement. Edison Mission Finance then loaned the same amounts to us under
a subordinated loan agreement. Interest rates and other charges as well as
maturity dates associated with the subordinated loan to us mirror the associated
debt at Edison Mission Holdings. The acquisition facility was replaced on May
27, 1999 with $300 million aggregate principal amount of 8.137% Senior Secured
Bonds due 2019 and

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$530 million aggregate principal amount of 8.734% Senior Secured Bonds due 2026,
which we refer to collectively in this section as the senior secured bonds.
Proceeds from the senior secured bonds were loaned by Edison Mission Holdings to
Edison Mission Finance, and from Edison Mission Finance to us, under the
subordinated loan. These proceeds were then used by us to repay $800 million
under the subordinated loan and make a $30 million distribution to Chestnut
Ridge Energy and Mission Energy Westside. The total amount outstanding under the
subordinated loan was $1.012 billion and $907 million at December 31, 2000 and
1999, respectively. The weighted average interest rate under this borrowing was
8.4% at December 31, 2000 and 1999, respectively.

The remaining cost of the acquisition, as well as initial operating
cash, totaling $1.1 billion, was funded through an equity contribution from
Edison Mission Energy to Edison Mission Holdings. Edison Mission Holdings later
contributed approximately the same amount to Edison Mission Finance, which then
loaned the amount to us under a subordinated revolving loan agreement. The
revolving loan agreement bears interest at 8.0% on outstanding amounts and
terminates on March 18, 2014. We owed approximately $789 million and $794
million under the revolving loan agreement at December 31, 2000 and 1999,
respectively.

We intend to invest approximately $281 million for environmental
capital improvements to the units, including a selective catalytic reduction
system on all three units and a flue gas desulfurization system on Unit 3, under
a fixed price, turnkey engineering, procurement and construction contract. These
improvements are scheduled to be installed during 2001. Capital expenditures for
the year ended December 31, 2000 were $141.6 million, primarily related to the
flue gas desulfurization system on Unit 3 and the selective catalytic reduction
systems. The environmental improvements will enhance the economics of the units
by reducing fuel costs, nitrogen oxide allowance purchases and sulfur dioxide
allowance purchases. We expect to spend approximately $67 million during 2001 on
capital expenditures for environmental capital improvements to the facilities.
These capital expenditures are currently being funded by cash flow from
operations.

Our principal source of liquidity is cash on hand and future cash flow
from operations. In addition, a portion of our Subordinated Loan with Edison
Mission Finance indirectly relates to $50 million working capital facility
maintained by Edison Mission Holdings and was fully available at June 30,
2001. The covenants contained in the senior secured bonds, which we have
guaranteed, restrict our ability to incur indebtedness other than
subordinated indebtedness or other specified types of indebtedness not to
exceed $15 million. We believe, based on our historical experience and
projected cash flow from operations under current market conditions (see
discussion of Market Risk Exposures below), that we will have adequate
liquidity to meet our obligations as they become due in the next twelve
months and over the period of the senior secured bonds. However, conditions
may change, including items that are beyond our control, which could result
in a shortfall of cash available to meet payments due under our Subordinated
Loan, which are indirectly used to pay debt service on the senior secured
bonds. Furthermore, covenants under the senior secured bonds would limit our
ability to secured additional indebtedness to provide liquidity in such
circumstance.

OTHER COMMITMENTS AND CONTINGENCIES

We have entered into several fuel purchase agreements with various
third-party suppliers for the purchase of bituminous steam coal. These contracts
call for the purchase of a minimum quantity of coal over the term of the
contracts, which extend from one to seven years from December 31, 2000, with an
option at our discretion to purchase additional amounts of coal as stated in the
agreements. Our contractual commitments for the purchase of coal are currently
estimated to aggregate $533 million

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during the next five years, summarized as follows: $142 million in 2001; $141
million in 2002; $103 million in 2003; $106 million in 2004; and $41 million in
2005.

MARKET RISK EXPOSURES

Prior to March 18, 1999, we had engaged in no operations since our
formation in October 1998. There are no separate financial statements available
with regard to the operations of the facilities prior to our taking ownership
because their operations were fully integrated with, and their results of
operations were consolidated into, the former owners of the facilities. In
addition, the electric output of the units was sold based on rates set by
regulatory authorities. As a result of the above factors and because electricity
rates are now set by the operation of market forces, the historical financial
data with respect to the facilities are not meaningful or indicative of our
future results. Our results of operations in the future will depend primarily on
revenues from the sale of energy, capacity and other related products and the
level of our operating expenses.

COMMODITY PRICE RISK

With the exception of revenue generated by the Pennsylvania Electric
Company (Penn Elec) transition contract, which expired in May 2001, the New York
State Electric & Gas (NYSEG) transition contract, which has been superseded by a
transaction agreement between our marketing affiliate and NYSEG, where our
marketing affiliate passes payments through to us from NYSEG minus a small fee
and which expires in December 2001, the Reactive Power Compensation Agreement
between Penn Elec and us entered into March 19, 2001, several transactions for
the sale of unforced capacity with our marketing affiliate entered into in 2001,
the last one of which expires in December 2002, and from bilateral contracts for
the sale of electricity with third-party load serving entities and power
marketers, our revenues and results of operations are dependent upon prevailing
market prices for energy, capacity and ancillary services in PJM, NYISO and
other competitive markets. Among the factors that influence the market prices
for energy, capacity and ancillary services in PJM and NYISO are:

o prevailing market prices for fuel oil, coal and natural gas
and associated transportation costs;

o the extent of additional supplies of capacity, energy and
ancillary services from current competitors or new market
entrants, including the development of new generation
facilities that may be able to produce electricity at a lower
cost;

o transmission congestion in PJM and/or NYISO;

o the extended operation of nuclear generating plants in PJM and
NYISO beyond their presently expected dates of
decommissioning;

o weather conditions prevailing in PJM and NYISO from time to
time; and

o the possibility of a reduction in the projected rate of growth
in electricity usage as a result of factors including regional
economic conditions and the implementation of conservation
programs.

Our risk management policy allows for the use of derivative financial
instruments through our marketing affiliate to limit financial exposure to
energy prices for non-trading purposes. Our marketing affiliate's risk
management activities give rise to commodity price risk, which represents the
potential loss that can be caused by a change in the market value of a
particular commodity. Commodity price risks are actively monitored to ensure
compliance with our risk management policies. Policies are in place which limit
the amount of total net exposure we may enter into at any point in time.
Procedures exist which allow for monitoring of all commitments and positions
with daily reporting to senior management. Our marketing affiliate performs a
"value at risk" analysis in our daily business to measure, monitor and control
our overall market risk exposure. The use of value at risk allows management to
aggregate overall

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risk, compare risk on a consistent basis and identify the drivers of the risk.
Value at risk measures the worst expected loss over a given time interval, under
normal market conditions, at a given confidence level. Given the inherent
limitations of value at risk and relying on a single risk measurement tool, our
marketing affiliate supplements this approach with industry "best practice"
techniques, including the use of stress testing and worst-case scenario
analysis, as well as stop limits and counterparty credit exposure limits.

Our marketing affiliate has the following energy price hedges
outstanding on the dates presented:

December 31,
--------------------------------------------
2000 1999
---- ----
Notional Contract Notional Contract
(in thousands) Amount Expires Amount Expires
------ ------- ------ -------

Energy contracts:
Forwards................................. $456,564 2002 -- --
Options.................................. 3,456 2001 $47,328 2001
Swaps.................................... 800 2001 -- --
</Table>

The following table summarizes the fair values for outstanding financial
instruments used for price risk management activities by instrument type:

December 31,
-------------------------------------------------
2000 1999
---- ----
Carrying Fair Carrying Fair
Amount Value Amount Value
------ ----- ------ -----

Commodity price:
Forwards............................... -- $(117,803) -- --
Options................................ $594 1,811 $3,533 $3,533
Swaps.................................. -- (892) -- --
</Table>

A 10% increase in electricity forward prices would result in an $11.7
million decrease in the fair market value of energy contracts at December 31,
2000 entered into by our marketing affiliate. A 10% decrease in electricity
forward prices would result in an $11.7 million increase in the fair market
value of energy contracts at December 31, 2000 entered into by our marketing
affiliate.

Our indirect parent, Edison Mission Holdings, provides credit support
for an affiliate that enters into various electric energy transactions,
including futures and swap agreements. At December 31, 2000, guarantees provided
by Edison Mission Holdings totalled $178.4 million as credit support for
financial and energy contracts entered into by affiliates. These guarantees
provide that Edison Mission Holdings will perform the obligations of affiliates
in the event of non-performance by them. We have not guaranteed or otherwise
supported Edison Mission Holdings' obligations under its credit support
guarantees.

INTEREST RATE RISK

We have mitigated the risk of interest rate fluctuations by arranging
for fixed rate financing for the majority of our project financings. Interest
rate changes affect the borrowings under our working capital

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and capital improvement credit facilities that are utilized to fund cash
needs of the facilities. We do not believe that interest rate fluctuations
will have a materially adverse effect on our financial position or results of
operations.

ENVIRONMENTAL MATTERS OR REGULATIONS

We are subject to environmental regulation by federal, state and local
authorities in the United States. We believe that as of the date of this consent
solicitation statement, we are in substantial compliance with environmental
regulatory requirements and that maintaining compliance with current
requirements will not materially affect our financial position or results of
operations.

We expect that the implementation of the Clean Air Act Amendments of
1990 will result in increased capital expenditures and operating expenses. We
expect to spend approximately $67 million during 2001 to install upgrades to the
environmental controls at the facilities to control sulfur dioxide and nitrogen
oxide emissions.

On November 3, 1999, the United States Department of Justice filed suit
against a number of electric utilities for alleged violations of the Clean Air
Act's "new source review" requirements related to modifications of air emissions
sources at electric generating stations located in the southern and midwestern
regions of the United States. Several states have joined these lawsuits. In
addition, the United States Environmental Protection Agency has also issued
administrative notices of violation alleging similar violations at additional
power plants owned by some of the same utilities named as defendants in the
Department of Justice lawsuit, as well as other utilities, and also issued an
administrative order to the Tennessee Valley Authority for similar violations at
some of its power plants. The Environmental Protection Agency has also issued
requests for information under the Clean Air Act to numerous other electric
utilities, including the prior owners of the facilities, seeking to determine
whether these utilities also engaged in activities that may have been in
violation of the Clean Air Act's new source review requirements.

To date, one utility, the Tampa Electric Company, has reached a formal
agreement with the United States to resolve alleged new source review
violations. Two other utilities, the Virginia Electric & Power Company and
Cinergy Corp., have reached agreements in principle with the Environmental
Protection Agency. In each case, the settling party has agreed to incur over $1
billion in expenditures over several years for the installation of additional
pollution control, the retirement or repowering of coal-fired generating units,
supplemental environmental projects and civil penalties. These agreements
provide for a phased approach to achieving required emission reductions over the
next 10 to 15 years. The settling utilities have also agreed to pay civil
penalties ranging from $3.5 million to $8.5 million.

Prior to our purchase of the facilities, the Environmental Protection
Agency requested information from the prior owners of the plant concerning
physical changes at the plant. We have been in informal voluntary discussion
with the Environmental Protection Agency relating to these facilities, which may
also include payment of civil fines. We cannot assure you that we will reach a
satisfactory agreement or that these facilities will not be subject to
proceedings in the future. Depending on the outcome of the proceedings, we could
be required to invest in additional pollution control requirements, over and
above the upgrades we are planning to install, and could be subject to fines and
penalties. In May 2001, President Bush issued a directive for a 90-day review of
new source review "interpretation and implementation" by the Administrator of
the Environmental Protection Agency and the Secretary of the U.S. Department of
Energy. President Bush also directed the Attorney General to review ongoing new
source review legal actions to "ensure" they are "consistent with the Clean Air
Act and its regulations." Both actions were recommendations detailed within the
Bush Administration's "National Energy Policy Task Force Report."

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A new ambient air quality standard was adopted by the Environmental
Protection Agency in July 1997 to address emissions of fine particulate matter.
It is widely understood that attainment of the fine particulate matter standard
may require reductions in nitrogen oxides and sulfur dioxides, although under
the time schedule announced by the Environmental Protection Agency when the new
standard was adopted, non-attainment areas were not to have been designated
until 2002 and control measures to meet the standard were not to have been
identified until 2005. In May 1999, the United States Court of Appeals for the
District of Columbia Circuit held that Section 109(b)(l) of the Clean Air Act,
the section of the Clean Air Act requiring the promulgation of national ambient
air quality standards, as interpreted by the Environmental Protection Agency,
was an unconstitutional delegation of legislative power. The Court of Appeals
remanded both the fine particulate matter standard and the revised ozone
standard to allow the Environmental Protection Agency to determine whether it
could articulate a constitutional application of Section 109(b)(l). On February
27, 2001, the U.S. Supreme Court, in WHITMAN V. AMERICAN TRUCKING ASSOCIATIONS,
INC., reversed the Circuit Court's judgment on this issue and remanded the case
back to the Court of Appeals to dispose of any other preserved challenges to the
particulate matter and ozone standards. Accordingly, as the final application of
the revised particulate matter ambient air quality standard is potentially
subject to further judicial proceedings, the impact of this standard on our
facilities is uncertain at this time.

On December 20, 2000, the Environmental Protection Agency issued a
regulatory finding that it is "necessary and appropriate" to regulate emissions
of mercury, and other hazardous air pollutants, from coal-fired power plants.
The agency has added coal-fired power plants to the list of source categories
under Section 112(c) of the Clean Air Act for which "maximum available control
technology" standards will be developed. Eventually, unless overturned or
reconsidered, the Environmental Protection Agency will issue technology-based
standards that will apply to every coal-fired unit owned by us or our affiliates
in the United States. This section of the Clean Air Act provides only for
technology-based standards, and does not permit market-trading options although
emissions may be traded within a particular source. Until the standards are
actually promulgated, the potential cost of these control technologies cannot be
estimated, and we cannot evaluate the potential impact on the operations of our
facilities.

Since the adoption of the United Nations Framework on Climate Change in
1992, there has been worldwide attention with respect to greenhouse gas
emissions. In December 1997, the Clinton Administration participated in the
Kyoto, Japan negotiations, where the basis of a Climate Change treaty was
formulated. Under the treaty, known as the Kyoto Protocol, the United States
would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7%
from 1990 levels. However, because of opposition to the treaty in the United
States Senate, the Kyoto Protocol has not been submitted to the U.S. Senate for
ratification. Although legislative developments on the federal and state level
related to controlling greenhouse gas emissions are beginning, we are not aware
of any state legislative developments in the states in which we operate. If the
United States ratifies the Kyoto Protocol or we otherwise become subject to
limitations on emissions of carbon dioxide from our plants, these requirements
could have a significant impact on our operations.

The Environmental Protection Agency proposed rules establishing
standards for the location, design, construction and capacity of cooling water
intake structures at new facilities, including steam electric power plants.
Under the terms of a consent decree entered into by the U.S. District Court for
the Southern District of New York in RIVERKEEPER, INC. V. WHITMAN, these
regulations must be adopted by November 9, 2001. The consent decree also
requires the agency to propose similar regulations for existing facilities by
February 28, 2002, and finalize those regulations by August 28, 2003. Until the
final standards are promulgated, we cannot determine their impact on our
facilities or estimate the potential cost of compliance.

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The Comprehensive Environmental Response, Compensation, and Liability
Act, which we refer to as CERCLA, and similar state statutes, require the
cleanup of sites from which there has been a release or threatened release of
hazardous substances. As of the date of this report, we are unaware of any
material liabilities besides what we disclose below. However, we cannot assure
you that we will not incur liability under CERCLA or similar state statutes in
the future.

In connection with our purchase of the facilities, we acquired the Two
Lick Creek Dam and Reservoir. Acid mine drainage discharges from the Penn Hill
No. 2 and Dixon Run No. 3 inactive deep mines were being collected and partially
treated on the reservoir property by Stanford Mining Company before being pumped
off the property for additional treatment at the nearby Chestnut Ridge Treatment
Plant. The mining company filed for bankruptcy and operated the collection and
treatment system until May 1999, when its assets were allegedly depleted.

The Pennsylvania Department of Environmental Protection, which we refer
to as PADEP, initially advised us that we were potentially liable for treating
the two discharges solely because of our ownership of the property on which the
discharges emanated. Without any admission of our liability, we voluntarily
entered into a letter agreement to fund the operation of the collection and
treatment system for an interim period until the agency completed its
investigation of potentially liable parties and alternatives for permanent
treatment of the discharges were evaluated. After examining property records,
PADEP concluded that we are only responsible for treating the Dixon Run No. 3
discharge. The agency has not completed its investigation of other potentially
responsible parties, particularly mining companies that previously operated the
two mines.

A draft consent agreement that addresses remedial responsibilities for
the two discharges has been prepared by PADEP. Under its terms, we are
responsible for designing and implementing a permanent system to collect and
treat the Dixon Run No. 3 discharge and the state will provide funding to a
local watershed association to develop and operate a collection and treatment
system for the other discharge. When the Dixon Run No. 3 treatment system
becomes operational, we will discontinue our funding of the existing collection
and treatment system. We will also be reimbursed a portion of the operational
costs of that system. The cost of operating the collection and treatment system
is approximately $15,000 per month. We are evaluating options for permanent
treatment of the Dixon Run No. 3 discharge, including a passive system involving
wetlands treatment. The cost of a passive treatment system is estimated to be $1
million, but its operational costs are considerably less than those of a
conventional chemical treatment system.

STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 133

Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The statement establishes accounting and reporting standards
requiring that derivative instruments be recorded in the balance sheet as either
an asset or liability measured at its fair value unless they meet an exception.
The statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. For
derivatives that qualify for hedge accounting, depending on the nature of the
hedge, changes in fair value are either offset by changes in the fair value of
the hedged assets, liabilities or firm commitments through earnings or
recognized in other comprehensive income until the hedged item is recognized in
earnings. The ineffective portion of a derivative's change in fair value is
immediately recognized in earnings.

Effective January 1, 2001, we recorded all derivatives at fair value
unless the derivatives qualified for the normal sales and purchases exception.
Our physical fuel contracts qualify under this exception. We did not use this
exception for forward sales contracts from our facilities due to the net
settlement

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procedures used by our marketing affiliate with counterparties for the period
between January 1, 2001 through June 30, 2001. Effective July 1, 2001, the
Derivative Implementation Group of the Financial Accounting Standards Board
extended the normal sales and purchases exception to include forward sales
contracts subject to net settlement procedures with counterparties. Accordingly,
we intend to use the normal sales and purchases exception for forward sales
contracts commencing July 1, 2001 and plan to record a cumulative change in the
accounting for derivatives during the quarter ended September 30, 2001.

For the period between January 1, 2001 through June 30, 2001, forward
sales contracts from the facilities qualify for treatment under SFAS No. 133 as
cash flow hedges with appropriate adjustments made to other comprehensive
income. The cumulative effect on prior periods' net income resulting from the
change in accounting for derivatives in accordance with SFAS No. 133 was not
material. We recorded a $69.3 million, after tax, unrealized holding loss upon
adoption of a change in accounting principle reflected in accumulated other
comprehensive loss in the balance sheet. We recorded a net loss of $146,000 and
a net gain of $482,000 from the ineffective portion of cash flow hedges during
the three months and six months ended June 30, 2001, respectively. The gain
(loss) is reflected in income (loss) from price risk management in the statement
of operations.