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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:

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

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

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

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

- 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.

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 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 Edison Mission
Energy 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
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
$25,342,000.

We believe there may also 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.

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. Energy and capacity

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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 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 consisted of expenses for fuel, plant operations,
depreciation and amortization and administrative and general expenses. 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.

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.

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.

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

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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 consisted of expenses for fuel, plant operations,
depreciation and amortization and administrative and general expenses. 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 50 miles of
the facilities, while the remainder is purchased on the spot market. The coal
for these units is cleaned by the coal-cleaning facility to reduce sulfur
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.

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.

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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 $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 million 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

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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.

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, subject to
adjustment, are currently estimated to aggregate $533 million 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
NewYork 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:

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

- 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;

- transmission congestion in PJM and/or NYISO;

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

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

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- 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 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:

<Table>
<Caption>
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:

<Table>
<Caption>
DECEMBER 31,
---------------------------------------------
2000 1999
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR 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.

We provide credit support for an affiliate that enters into various electric
energy transactions, including futures and swap agreements. These credit support
guarantees are not subordinate to the senior secured bonds and are senior
unsecured obligations of Edison Mission Holdings. At December 31, 2000, we
provided guarantees totaling $178.4 million as credit support for financial and
energy contracts entered into by affiliates. These guarantees provide that we
will perform the obligations of affiliates in the event of non-performance by
them. We could be exposed to the risk of

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higher electric energy prices in the event of non-performance by a counterparty.
However, we do not anticipate non-performance by a counterparty and the
marketing affiliate.

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 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

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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."

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

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standards are promulgated, we cannot determine their impact on our facilities or
estimate the potential cost of compliance.

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

9
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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.