SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to ___________
COMMISSION FILE NUMBER: 1-16077
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ORION POWER HOLDINGS, INC.
(EXACT NAME OF THE REGISTRANT AS SPECIFIED IN ITS CHARTER)
Delaware 52-2087649
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
c/o Reliant Resources, Inc.
1111 Louisiana Street
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (410) 230-3500
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
Indicate by check mark whether the Registrant (1) has 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
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No ___
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 the Registrant's 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. [X]
ON MARCH 1, 2002, THERE WERE 1,000 SHARES OF COMMON STOCK OF THE REGISTRANT
OUTSTANDING, ALL OF WHICH WERE HELD BY RELIANT RESOURCES, INC.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION
(I)(1)(A) AND (B) OF FORM 10-K AND IS THEREFORE FILING THIS FORM WITH THE
REDUCED DISCLOSURE PERMITTED THEREBY.
ORION POWER HOLDINGS, INC.
TABLE OF CONTENTS
PART I
Item 1. Business............................................................1
Item 2. Properties.........................................................13
Item 3. Legal Proceedings..................................................14
Item 4. Submission of Matters to a Vote of Security Holders................14
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters............................................................14
Item 6. Selected Financial Data............................................14
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations..........................................14
Item 7A...................................................................28
Item 8. Financial Statements and Supplementary Data........................28
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure...............................................29
PART III
Item 10. Directors and Executive Officers of the Registrant................29
Item 11. Executive Compensation............................................29
Item 12. Security Ownership of Certain Beneficial Owners and Management....29
Item 13. Certain Relationships and Related Transactions....................29
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...29
Financial Statements......................................................F-1
PART I
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
We have made, and may continue to make, various forward-looking statements
with respect to our financial position, business strategy, projected costs,
projected savings, and plans and objectives of management. Such forward-looking
statements are identified by the use of forward-looking words or phrases such as
"anticipates," "intends," "expects," "plans," "believes," "estimates," or words
or phrases of similar import. These forward-looking statements are subject to
numerous assumptions, risks, and uncertainties, and the statements looking
forward beyond 2002 are subject to greater uncertainty because of the increased
likelihood of changes in underlying factors and assumptions. Actual results
could differ materially from those anticipated by the forward-looking
statements.
Factors that could cause actual results to differ materially include, but
are not limited to, those described below:
o political, legal and economic conditions and developments in the
United States;
o state, federal and other legislative and regulatory initiatives
affecting the electric utility industry, including rate regulation,
deregulation and restructuring initiatives;
o changes in the environmental and other laws and regulations to which
we are subject, or the application thereof;
o the extent and timing of the entry of additional competition in our
markets;
o the performance of projects undertaken;
o our ability to execute our strategy of developing and constructing
power generating facilities;
o our ability to obtain the necessary financing that our business may
require;
o the ability of Reliant to integrate our operations with its wholesale
energy business;
o fluctuations in the prices for electric products and services; and
o financial market conditions, changes in commodity prices and interest
rates, and weather and other natural phenomena.
In addition to factors previously disclosed by us, Reliant Resources, Inc.
("Reliant Resources"), and factors identified elsewhere herein, certain other
factors could cause actual results to differ materially from such
forward-looking statements. All subsequent written and oral forward-looking
statements attributable to us, or persons acting on our behalf, are expressly
qualified in their entirety by reference to such factors.
Our forward-looking statements represent our judgment only on the dates
such statements are made. By making any forward-looking statements, we assume no
duty to update them to reflect new, changed, or unanticipated events or
circumstances.
ITEM 1. BUSINESS.
MERGER
On February 19, 2002, Orion Power was acquired by merger by a wholly owned
subsidiary of Reliant Resources. As a result, Orion Power became a wholly owned
subsidiary of Reliant Resources, which files reports with the Securities and
Exchange Commission.
Reliant Resources provides electricity and energy services with a focus on
the competitive wholesale and retail segments of the electric power industry in
the United States. Reliant Resources acquires, develops and operates electric
power generating facilities that are not subject to traditional cost-based
regulation and therefore can generally sell power at prices determined by the
market. Reliant Resources also trades and markets power, natural gas and other
energy-related commodities and provides related risk management services.
Reliant Resources intends to continue Orion Power's business and to integrate it
with Reliant Resources' operations.
OVERVIEW
We are an electric power generating company committed to delivering a broad
range of wholesale energy and related products and services to independent
system operators, utilities, municipalities, cooperatives, retail aggregators
and other wholesale customers. Prior to our merger with a subsidiary of Reliant
Resources, we grew our business by strategically acquiring, developing and
modernizing non-nuclear electric generating facilities located in critical
locations in regions across the United States. We continue to approach our
business with financial discipline, applying a rigorous and multi-faceted
approach. We currently own 81 plants with an aggregate capacity of 5,644
megawatts. We also have two projects under construction with a total capacity of
804 megawatts, which are expected to be in operation in 2002.
Our facilities in operation are diversified by fuel type and
geographically. The tables below set forth the assets owned by our regional
operating companies:
ORION POWER NEW YORK, L.P. FACILITIES SUMMARY
CAPACITY PRIMARY
ASSET (MW) FUEL TYPE LOCATION SERVED
- ----- ----- --------- ---------------
Hydroelectric Assets.................... 650 Water Central/Northern New York
Assets Located in New York City:
Astoria Generating Station.......... 1,265 Natural Gas / New York City - Queens
Oil
Gowanus Generating Station.......... 494 Oil New York City - Brooklyn
Narrows Generating Station.......... 280 Natural Gas New York City - Brooklyn
Carr Street Generating Station.......... 94 Natural Gas East Syracuse, NY
-----
Total...................... 2,783
=====
ORION POWER MIDWEST, L.P. FACILITIES SUMMARY
CAPACITY PRIMARY
ASSET (MW) FUEL TYPE LOCATION SERVED
- ----- ----- --------- ---------------
Avon Lake Generating Station............ 754 Coal Cleveland, OH
Brunot Island Generating Station........ 54 Oil Pittsburgh, PA
Ceredo Generating Station............... 500 Natural Gas Ceredo WV
Cheswick Generating Station............. 562 Coal Pittsburgh, PA
Elrama Generating Station............... 457 Coal Pittsburgh, PA
New Castle Generating Station........... 318 Coal West Pittsburg, PA
Niles Generating Station................ 216 Coal Youngstown, OH
-----
Total.......................... 2,861
=====
In order to provide a broad range of energy products and services and to
better manage electric and fuel commodity risk, we operate facilities that are
diversified by fuel type as set forth in the table below:
FUEL TYPE SUMMARY
-----------------
CAPACITY
PRIMARY FUEL (MEGAWATTS) PERCENTAGE
- ------------ ----------- ----------
Coal.......................................... 2,307 41%
Natural Gas / Oil (Dual fuel capability)...... 1,265 22%
Natural Gas................................... 874 15%
Fuel Oil...................................... 548 10%
Water......................................... 650 12%
----- ----
Total................................ 5,644 100%
===== ====
In addition, we manage electric and fuel commodity price risk by attempting
to sell a majority of our output forward through long term and short term
contracts and purchase in advance the associated fuel to match the term of those
sales.
CORPORATE OPERATIONS
As of December 31, 2001, our corporate headquarters were located in
Baltimore, Maryland. With the completion of our merger on February 19, 2002, we
are currently combining our headquarters into Reliant Resources' headquarters at
1111 Louisiana Street, Houston, Texas. The corporate office is focused on
selected activities, including corporate administration, accounting, financing,
power sales, fuel procurement, asset management, risk management and business
development. As of February 28, 2002, there were 71 employees located in the
corporate office, including all of the executive officers. We conduct our
day-to-day operations by subsidiaries, which are wholly-owned either by us or by
another one of our subsidiaries.
We have centralized some aspects of asset management, risk management,
power sales, and fuel procurement. The combined power sales and fuel procurement
group, which, as of February 28, 2002, totaled 23 employees, focuses on
optimizing the net margin earned on sales of energy, capacity, and ancillary
services after taking out the cost of fuel and limiting the amount of risk in
our activities. This group is being integrated in Reliant's operations in
Houston with each function becoming a part of the appropriate section of
Reliant's business structure.
ORION POWER NEW YORK, L.P.
FACILITIES. Our regional operating company, Orion Power New York, L.P.,
which is headquartered outside Syracuse, New York manages our assets located in
New York State. Orion Power New York manages a total of 74 power generation
facilities of which 72 are currently operational. Total aggregate capacity of
these facilities is approximately 2,783 megawatts. The facilities consist of 70
hydroelectric facilities, of which 68 are active, three facilities located in
New York City and the Carr Street Generating Station in East Syracuse. As of
December 31, 2001, Orion Power New York employed 375 people as direct employees.
We have not owned these facilities for a substantial period of time, and
therefore, our historical financial and operating results do not provide a
longer term perspective on the operation of the assets located in New York.
ASSETS LOCATED IN NEW YORK CITY. We currently bid the energy produced by
the assets located in New York City into the energy and ancillary services
markets operated by the New York Independent System Operator, Inc. (NY-ISO).
Because our assets located in New York City serve a transmission-constrained
area, bids for energy produced by these facilities are subject to market power
mitigation measures as implemented by the NY-ISO. The market power mitigation
measures provide that if the energy bid price for our assets located in New York
City exceeds the market price at a specified location reference point outside
New York City by 5% or more, our bid price is replaced with an energy reference
price that approximates our cost of production. All units that are dispatched
will then receive the market clearing price. Due to the fact that our units are
located in critical areas in New York City and are often dispatched for
uneconomic reasons, we receive the greater of the market clearing price or the
cost of production. We also currently bid capacity and certain ancillary
services from these assets into the NY-ISO capacity market. Prices for this
capacity and ancillary services are also subject to mitigation measures that cap
the prices.
HYDROELECTRIC ASSETS. We have sold all of the output of the hydroelectric
assets, including energy, capacity, and ancillary services, to Niagara Mohawk
Power Corporation on a bilateral basis under a contract through September 30,
2001. Under this contract, we received an annual fixed payment, totaling $73.6
million for the period October 2000 through September 2001 and a variable
payment of approximately $20 per megawatt hour for all generation above
approximately 2.2 million megawatt hours. We extended this contract with Niagara
Mohawk Power Corporation though September 30, 2004. Under the extended contract,
we receive an entirely variable payment. The actual price we receive is
dependent upon our water flows and our ability to optimize production during
peak periods. Based on the hydroelectric assets' performance and available
historical data on average water flows over the last ten years, we would expect
the variable payment to generate a significantly higher revenue stream than the
original contract.
CARR STREET. We have entered into a gas tolling agreement with
Constellation Power Source covering the Carr Street Generating Station, which
continues until November 2003. Under this agreement, Constellation Power Source
has the exclusive right to all energy, capacity and ancillary services produced
by the plant. Constellation Power Source pays for, and is responsible for, all
fuel used by the plant during the term of the gas tolling agreement. We are
currently paid a fixed fee monthly and variable payment per megawatt hour
generated, both of which escalate annually. We have guaranteed certain aspects
of the plant's operating performance and failure to meet these guarantees could
result in penalties.
ORION POWER MIDWEST, L.P.
FACILITIES. Our regional operating company, Orion Power MidWest, L.P.,
which is headquartered near Pittsburgh, Pennsylvania, manages our assets located
in Ohio, Pennsylvania and West Virginia. The assets consist of eight power
generating facilities, six of which are active, located in western Pennsylvania
and Ohio, and one in West Virginia. Our West Virginia facility, the Ceredo
Generating Station, a 500 megawatt gas-fired peaking facility, commenced
commercial operations in June 2001. The remaining seven facilities were acquired
from Duquesne Light Company in April 2000, three of which Duquesne had recently
acquired in an asset swap with FirstEnergy Corp. The other four (including the
retired facility) have historically been owned and operated by Duquesne Light
Company. The seven operating facilities have a total aggregate capacity of
approximately 2,861 megawatts, with five of such facilities using coal as their
primary fuel source, one using oil and one using natural gas.
The majority of the coal units operate as baseload units because of their
low production costs per megawatt hour. Our oil- and gas-fired units operate as
intermediate and peaking facilities, respectively. In addition, in connection
with the Duquesne acquisition we entered into the provider of last resort
contract with Duquesne Light Company, which we subsequently extended. As of
December 31, 2001, we employed 470 people in the direct operation of the eight
facilities managed by Orion Power MidWest.
We have not owned these facilities for a substantial period of time, and
therefore, our historical financial and operating results do not provide a
longer term perspective on the operation of these assets.
PROVIDER OF LAST RESORT CONTRACTS. As part of our acquisition of seven
facilities located in Ohio and western Pennsylvania in April 2000, we entered
into two provider of last resort contracts with Duquesne Light Company, which we
have subsequently extended. Under the contracts, we are obligated for a specific
period to provide energy to Duquesne Light Company to meet its obligations to
satisfy the demands of any customer in the Duquesne Light Company service area
that does not elect to buy energy from a competitive supplier as allowed by the
Pennsylvania state deregulatory initiatives or that elects to return to Duquesne
Light Company as the designated provider of last resort. Under these contracts,
we must provide all of the energy necessary to meet the contractual requirements
with no minimum and no maximum quantity and Duquesne Light Company must buy all
of the energy needed to satisfy its provider of last resort obligation from us.
The provider of last resort contracts are wholesale contracts between us
and Duquesne Light Company, and we have no responsibility for selling energy
directly to the related retail customers. Therefore, we have no involvement in
billing retail customers or collecting amounts owed by retail customers.
The Duquesne Light Company service area covers approximately 580,000 retail
customers. According to information provided by Duquesne Light Company, the peak
demand for the Duquesne Light Company control area was approximately 2,771
megawatts, and the total amount of electricity consumed was approximately
13,908,091 megawatt hours in 2001. As of December 31, 2001, approximately 81% of
the customers in the Duquesne Light Company control area, as measured by energy
consumption, received energy from Duquesne Light Company as the provider of last
resort. The peak provider of last resort load was approximately 2,306 megawatts
for 2001. The total amount of electricity consumed by provider of last resort
customers was approximately 10,885,190 megawatt hours for 2001.
Under the initial provider of last resort contract (the "POLR I
Agreement"), the prices we receive are a specified portion of Duquesne Light
Company's current retail rates, which have been approved by the Pennsylvania
Public Utility Commission. From this amount, Duquesne Light Company deducts the
Pennsylvania gross receipts tax of 4.4%, $1 per megawatt hour for certain
ancillary services and a pro rata share transmission line losses in the Duquesne
Light Company control area. Such amount excludes any generation rate adjustment
payments received by Duquesne Light Company from its retail customers whose
energy is secured by the POLR I Agreement.
The POLR I Agreement continues in effect for each rate class until the
amount of Duquesne Light Company's stranded costs allocated to that rate class
have been recovered through the surcharge being added to each customer's monthly
bill. For three rate classes, all stranded costs have already been recovered,
and therefore the provider of last resort obligation under the POLR I Agreement
is satisfied for these rate classes. The remaining rate classes are projected to
complete stranded cost recovery between 2001 and 2004, with most rate classes
expected to have completed stranded cost recovery before the summer of 2002.
Accordingly, we expect the majority of the original provider of last resort
contract obligations under POLR I Agreement to end during mid 2002.
Upon completion of stranded cost recovery for any rate class, the energy
requirements of such rate class are then provided under the second provider of
last resort contract (the "POLR II Agreement") between Duquesne Light Company
and us until December 31, 2004. The POLR II Agreement becomes effective for each
Duquesne Light Company retail customer class as that class comes off the retail
tariff that relates to the POLR I Agreement. The POLR II Agreement differs from
the originally applicable tariff and the POLR I Agreement in certain respects,
including:
o The penalty for failures to deliver energy which cause Duquesne Light
Company to reduce energy provided to consumers will be reduced from
$1,000 to $100 per megawatt hour of shortfall under most circumstances
(which penalty is still in addition to imbalance charges payable by us
under both POLR Agreements with respect to such shortfall based on the
applicable tariff rates);
o We will be paid rates that are approximately nine percent higher per
megawatt hour, although the actual increase depends on actual demand
in each rate class.
Given the expected demand for energy from provider of last resort customers
and the historic energy generation from our assets located in Ohio and
Pennsylvania and our peaking power plant under construction in West Virginia, we
generally expect to produce more energy than needed to meet our provider of last
resort obligations under both the POLR I and POLR II Agreements. We will attempt
to sell this excess energy into the market and will receive the prevailing
market price at the time. The provider of last resort demand, however, will
fluctuate on a continuous, real-time basis, and will likely peak during summer
and winter, on weekdays, and during some hours of the day. This could cause the
provider of last resort demand to be greater than the amount of energy we are
able to generate at any given moment. As a result, we may need to purchase
energy from the market to cover our contractual obligations. This is likely to
occur at times of higher market prices, although the price we receive will be
determined as described above and will not fluctuate with the market. This
situation could also arise or worsen if we have operational problems at one or
more of our generating facilities that reduce their ability to produce energy.
Failure to provide sufficient energy could give rise to penalties under both the
POLR I and POLR II Agreements. A severe under-delivery of energy that forces
Duquesne Light Company to deny some customers energy could give rise to
penalties of $1,000 per megawatt hour under the POLR I Agreement or $100 or
$1,000 per megawatt hour under the POLR II Agreement, depending upon the
circumstances of such under-delivery. As the number of rate classes eligible for
provider of last resort service under the POLR I Agreement decreases, we will be
potentially entitled to the reduced damages of $100 per megawatt hour under the
POLR II Agreement with respect to more rate classes, so we believe that the risk
of $1,000 per megawatt hour damages will decrease appreciably as more rate
classes transition to the POLR II Agreement.
ECAR does not recognize capacity as a separate product from energy, and we
are not obligated under either of the POLR Agreements to provide capacity; our
supply obligations under such agreements relate solely to energy.
In addition to providing energy to Duquesne Light Company under the POLR I
and POLR II Agreements, we provide certain ancillary services to Duquesne Light
Company under a separate ancillary services agreement. We provide the amount of
such services necessary to meet Duquesne Light Company's pro rated share of its
service territory's load at fixed rates per kilowatt per month for each such
service. Failure to provide the required amount of such services obligates us to
pay certain market damages with respect to any shortfall.
In the fourth quarter of 2001, Duquesne Light Company announced that it
intended to join a newly created wholesale energy services market in western
Pennsylvania called PJM-West. This market could be created and operational as
early as May 2002. In the PJM-West system, capacity will be recognized as a
separate product from energy, and load serving entities in PJM West, such as
Duquesne Light Company, will be required to demonstrate their ability to provide
certain required levels of capacity. Following Duquesne Light Company's
announcement, we began negotiations with Duquesne Light Company regarding the
terms and price at which we would provide their capacity requirements, as well
as modifications to the POLR I and II Agreements, ancillary services agreement,
and other related documents that would be necessary to allow such agreements to
function mechanically within the PJM West structure.
Recent Developments.
On February 15, 2002, we executed with Duquesne Light Company a capacity
agreement, amendments to the POLR I and II Agreements, and an amended and
restated ancillary services agreement, as well as amendments to certain related
agreements as necessary to allow such agreements to function mechanically within
the PJM West structure. Effectiveness of all of the foregoing is conditioned
upon receipt of the consent of our lenders as well as the satisfaction of
multiple other conditions precedent, including without limitation Federal Energy
Regulatory Commission (FERC) approval of certain changes to Duquesne Light
Company's retail and supplier tariffs to allow Duquesne Light Company to pass on
to the applicable customers amounts payable by Duquesne Light Company under the
capacity agreement and additional amounts under the amended and restated
ancillary services agreement. If such conditions are not satisfied within 180
days of the execution date, the new agreements and amendments do not become
effective and will terminate automatically. A brief summary of certain of the
principal economic terms of the foregoing amendments and agreements follows.
Capacity Agreement:
Under the capacity agreement, we will provide 106% of the capacity
requirements of Duquesne Light Company's zone (subject to our right to swap up
to 65% of such obligation as described below) in return for a fixed monthly
payment. If we fail to provide the required amount of capacity, Duquesne Light
Company is not permitted to withhold any portion of the capacity payment;
instead, we must reimburse Duquesne Light Company for the corresponding
deficiency charges assessed by PJM West against Duquesne Light Company. Assuming
that we designate the required level of megawatts of installed capacity (the
greater of (a) the summer net demonstrated capacities of the Cheswick, Elrama,
and Brunot Island plants plus any qualified interruptible load and (b) (i) 1,220
megawatts (prior to the repowering of Brunot Island) or (ii) 1,360 megawatts
(after such repowering)) from certain qualified units, Duquesne Light Company is
(and therefore we are) entitled to alternative deficiency charges, which are
currently assessed by PJM West at $176.80 MW/day, with respect to such required
level. For any deficiency in excess of such required level, non-alternate
deficiency charges, currently $12,908 MW/day, would be assessed by PJM West.
Deficiency charges assessable by PJM West are capped at $64,542 MW/year per
unit.
Pursuant to a swap feature embedded in the capacity agreement and a
corresponding feature in a separate capacity agreement between FirstEnergy Corp.
and Duquesne Light Company, we can elect for 0 - 65% of Duquesne Light Company's
daily capacity requirements to be provided by FirstEnergy Corp., with no
corresponding reduction of the monthly capacity payment due to us from Duquesne
Light Company.
Amendments to POLR Agreements:
Many of the modifications to the POLR Agreements (e.g., changes to
scheduling requirements) reflect mechanical adjustments necessary in the PJM
West operating construct. Also, because we have units in FirstEnergy Corp's
control area and FirstEnergy Corp. has units in Duquesne Light Company's zone,
we have agreed with FirstEnergy Corp. to swap a portion of Duquesne Light
Company's forecasted energy requirements with FirstEnergy Corp., in a percentage
corresponding to the swap percentage under the capacity agreement. We will
deliver to FirstEnergy Corp's control area from our units in such control area
the swapped amount of energy (which delivery satisfies our delivery obligations
under the POLR Agreements with respect to such amounts), and FirstEnergy Corp.
will deliver the same amount of energy to Duquesne Light Company from
FirstEnergy Corp.'s units in Duquesne Light Company's zone.
For any shortfall in energy required to be delivered under the POLR
Agreements, we must pay Duquesne Light Company the amount of the charge assessed
by PJM West against Duquesne Light Company with respect to such shortfall (which
will be the then-applicable LMP), plus the $100 or $1,000 per megawatt hour
penalty currently required under the POLR Agreement if such failure requires
Duquesne Light Company to reduce energy provided to consumers. Because (a) the
amount of the charge assessable by PJM West is capped at $999 per MWh, unlike
the current situation in ECAR where no cap is provided, (b) the safe harbor
entitling us to the reduced $100 per megawatt hour penalty is now available
under both POLR Agreements, and (c) such safe harbor has been expanded slightly,
thus potentially lessening the likelihood of such penalties being imposed, our
liability for deficiencies under the POLR Agreements may be reduced compared to
those under the current POLR Agreements. Such penalties and charges for failure
to deliver energy under the POLR Agreements are separate from any damages
payable by us under the capacity agreement for failure to deliver capacity.
Under the amended POLR II Agreement, in return for additional consideration
under the capacity agreement, we will assume responsibility for payment of
certain transmission congestion charges applicable to energy delivered by us to
Duquesne Light Company which may arise due to PJM West's nodal based pricing
system that creates pricing variations within Duquesne Light Company's service
territory. In order to hedge against this difference, load serving entities
(such as Duquesne Light Company) will have access to Firm Transmission Rights
("FTR's"). In this case, PJM West will allocate FTR's associated with Duquesne
Light Company 's load to Duquesne Light Company. Duquesne Light Company is
contractually obligated to assign those rights to us if we so request. These
FTR's have the effect of a financial hedge by "matching up" generating assets to
the load zone price . Properly managed, these FTR's should have the effect of
managing the cost risk associated with such congestion. Energy delivered by us
to FirstEnergy Corp. pursuant to the swap described above is intended to be
provided from our units located in the FirstEnergy Corp. control area and can be
delivered anywhere within such area. There is not a nodal based pricing system
in the FirstEnergy Corp. control that creates pricing variations within such
area, so we do not consider transmission congestion charges to be an issue with
respect to the energy delivered to FirstEnergy Corp. pursuant to the swap
arrangement. Finally, FirstEnergy Corp. will bear any transmission congestion
charges applicable to energy delivered by FirstEnergy Corp. to Duquesne Light
Company pursuant to the swap arrangement in return for a fixed payment from
Duquesne Light Company of $0.10 per megawatt hour so delivered. We have agreed
to reimburse Duquesne Light Company for the amount of such charges paid to
FirstEnergy Corp.
Amended and Restated Ancillary Services Agreement:
Under the amended and restated ancillary services agreement, we will
provide the amount of ancillary services required by the Duquesne Light Company
zone. The consideration we will receive under the amended and restated agreement
will be a fixed amount per megawatt hour of the Duquesne Light Company zone's
load and is roughly double the consideration received under the existing
agreement (in return for an increase in quantity of services provided of
approximately 19% from the existing agreement, based on an historical average).
This significant price increase is due to the fact that in the PJM West market,
the market price of these services will be higher. The prices under the amended
and restated agreement were determined based upon comparisons with proxy markets
and discussions with PJM West; we therefore anticipate that they should be
reflective of market prices in the PJM West territory.
If we fail to provide any ancillary services required to be delivered under
the amended and restated agreement, we will be responsible for the charges
assessed by PJM West against Duquesne Light Company for such failure, which
would be the then-applicable PJM West clearing price for the amount of the
deficiency. However, if such failure is excused under the PJM West Protocols due
to force majeure, no such charges would be assessed.
ORION POWER DEVELOPMENT COMPANY, INC.
Orion Power Development Company, Inc. manages our assets under construction
and development. Our development company's primary objective was to
strategically grow our portfolio of generating assets in a timely manner by
developing efficient generating facilities that can provide wholesale customers
with reliable, low-cost electricity and related products and services. As of
February 28, 2002, Orion Power Development Company, Inc. had no direct
employees. Consequently, some of the employees of Orion Power Holdings, Inc.
managed the daily business of and the development projects owned by Orion Power
Development Company, Inc.
CONSTRUCTION AND DEVELOPMENT
A primary facet of our strategy was to grow by developing additional
capacity at our facilities by repowering or adding units at existing facilities
and by building new facilities throughout the U.S. and Canada. In June 2001, we
completed the construction of Ceredo Electric Generating Station, which was a
project included in our acquisition of Columbia Electric Corporation in December
2000.
We currently have two projects that are under construction:
o Liberty Electric Generating Station (Liberty), located south of
Philadelphia, Pennsylvania, is a 550 megawatt, natural gas fired
facility under construction, which will consist of two General
Electric model 7FA class combustion turbine-generators supplying steam
to a single Toshiba steam turbine-generator. We expect that this
facility will operate as a baseload facility. The output of this
facility is contracted under a tolling agreement for a term of
approximately 14 years. Under this agreement, the counterparty will
have the exclusive right to receive all energy, capacity and ancillary
services produced by the plant. The counterparty will pay for, and be
responsible for, all fuel used by the plant under the tolling
agreement. This facility is scheduled for completion in April 2002.
o Brunot Island Generating Station, located near downtown Pittsburgh,
Pennsylvania, is currently a 254 megawatt peaking facility. We have
begun the conversion of many of the existing simple cycle, oil fired
units on site back to their original combined cycle operation and the
upgrade of the on-site natural gas pipeline to allow for natural gas
to become the primary fuel. We will also upgrade environmental control
equipment to reduce our emissions. Our objective is to increase
capacity at Brunot Island by 140 megawatts and significantly reduce
production costs. This project is scheduled for final completion by
the summer of 2002.
Prior to our merger with Reliant Resources, Orion Power was evaluating
additional development projects to further the company's growth. These include
the Kelson Ridge Generating Station in Waldorf, MD, Atlantic Generating Station
in Port St. Lucie, FL, the repowering of Astoria Generating Station and many
other repowerings of operating facilities. Given the early stage of all the
aforementioned projects, the recent shift in market fundamentals and Reliant
Resources' own development plans and capital requirements, we may elect not to
pursue these activities or we may otherwise not be able to do so. Reliant is
currently evaluating any potential costs for changes in projects including
turbine purchase obligations.
RECENT MARKET DEVELOPMENTS
NEW YORK MARKET FRAMEWORK. The New York wholesale energy market has been in
operation for over two years. The NY-ISO has responsibility for daily operation
of the transmission system and the administration of bid-based markets for
wholesale energy, capacity, and ancillary services. The day-ahead and real-time
wholesale energy and ancillary services markets started on November 18, 1999.
The capacity market began with an auction in early April 2000 for the summer
2000 six-month capacity period.
Under the NY-ISO, generators like us are able to sell energy to any
wholesale customer in the state. These sales may be done under bilateral
contracts, in which pricing and other provisions are determined through private
negotiation, or by bidding into the day-ahead and real-time energy and ancillary
services markets.
Over the course of the last year, the rate of changes in market rules has
slowed, however, several key changes did occur. For example, the implementation
of many programs now allow energy demand, commonly referred to as "load", to
respond to high prices in emergency and non-emergency situations.
Additionally, FERC directed the NY-ISO to expand the price mitigation rules
that applied to utility-divested units to include all units in New York City for
the summer of 2001. FERC also imposed similar market mitigation measures for the
real-time market as were already in place in the day ahead market. However, the
NY-ISO was unable to implement the real-time market mitigation measures until
late in the summer, and the period of real-time mitigation lapsed at the end of
September. Under a subsequent FERC order, the NY-ISO was directed to incorporate
a market monitoring plan consistent with the "in city" mitigation in the
day-ahead and real-time markets. This order also required Consolidated Edison to
remove the mitigation authority from its tariff. The NY-ISO filed the revised
mitigation plan on March 20, 2002. It is too early in the proceeding to assess
fully the impact of the revised mitigation plan on us.
Finally, the NY-ISO implemented a change in the method of determining how
the installed capacity of a generating unit is calculated, by taking into
account a unit's availability to operate. Specifically, generators now sell
unforced capacity, which is their installed capacity discounted by their forced
outage rates. The change will also financially penalize a generator for
"unforced outages". The capacity market ensures that there is enough generation
capacity to meet retail energy demand and ancillary services requirements. All
power retailers are required to demonstrate commitments for capacity sufficient
to meet their peak forecasted load plus a reserve requirement, currently set at
18%. As an extra reliability measure, power retailers located in New York City
are required to procure the majority of this capacity (currently 80% of their
peak forecasted load) from generating units located in New York City. Because
New York City is currently short of this capacity requirement and the existing
capacity is owned by only a few entities, a price cap of $105 per kilowatt-year
divided by the "in city" average forced outage rate for all the units has been
instituted for in-city generators. In 2001, in two separate auctions, we sold
all of our available capacity at or near the price cap in effect at that time.
There can be no assurance that changes to New York's competitive wholesale
energy markets will not adversely affect our operations. The NY-ISO has the
ability to revise prices, which could lead to delayed or disputed collection of
amounts due to us for sales of energy and ancillary services. The NY-ISO also
has the ability, in some cases subject to FERC approval, to impose cost-based
pricing and/or price caps. Moreover, FERC is considering imposing an overall
refund condition in all market-based rate authorizations, which could allow FERC
to revisit prices.
MIDWEST MARKET FRAMEWORK. The assets managed by Orion Power MidWest, L.P.
are located in the ECAR region. The ECAR region covers part or all of the
following states: Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania,
Virginia and West Virginia. There is no ISO or similar entity in place for the
entire ECAR region, although the utilities in the region are proposing several
competing plans for an independent system operator and/or a regional
transmission operator. The ECAR market is characterized by substantial costs for
transmitting power from one location to another, because each independent
utility charges a tariff to use its transmission facilities. Therefore, moving
power across multiple utility systems becomes expensive and may become difficult
or impossible at times of high demand.
The current market in the ECAR region is relatively illiquid and is
dominated by private bilateral contracts between parties. Notwithstanding the
general lack of liquidity, markets do exist in several areas within the ECAR
region. The ECAR region also lacks a specific capacity market and well-developed
markets for ancillary services.
Given the competing ISO and RTO proposals currently under consideration and
the many divergent interests which exist in the ECAR region, we expect that any
adoption of ISOs or similar entities will be gradual. Some entities, including
Duquesne Light Company, have considered joining the PJM-West market, a newly
created wholesale market that would cover the western portion of the
Mid-Atlantic region as early as May 2002. If Duquesne Light Company, our primary
customer in the ECAR Region, joins the PJM-West market, we may well enter the
newly created wholesale market as well. We are unable to determine what impact,
if any, joining the PJM-West market would have on our business or financial
prospects. See "Orion Power MidWest, L.P. - Recent Developments" for a
discussion of Duquesne Light Company's recent announcement of its intention to
join the PJM West market and certain contractual arrangements that have been
executed between Orion Power MidWest, L.P. and of Duquesne Light Company in
February 2002 in anticipation thereof.
REGULATION
We are subject to complex and stringent energy, environmental, and other
governmental laws and regulations at the federal, state, and local levels in
connection with the development, ownership, and operation of our electric
generation facilities. The federal and state energy laws and regulations create
burdens and risks for our operations, as well as opportunities for further
acquisitions of facilities at attractive prices.
FEDERAL ENERGY REGULATION
FERC, is an independent agency within the Department of Energy that
regulates the transmission and wholesale sale of electricity in interstate
commerce under the authority of the Federal Power Act. FERC is also responsible
for licensing and inspecting private, municipal and state-owned hydroelectric
projects. FERC determines whether a public utility qualifies for exempt
wholesale generator status under the Public Utility Holding Company Act, which
was amended by the Energy Policy Act of 1992.
FEDERAL POWER ACT. The Federal Power Act gives FERC exclusive rate-making
jurisdiction over wholesale sales of electricity and transmission of electricity
in interstate commerce. FERC can exercise this authority to require refunds if
it determines that rates are unjust and unreasonable and is considering imposing
an overall refund condition in all market based rate authorizations, which could
allow FERC to revisit market prices. FERC regulates the owners of facilities
used for the wholesale sale of electricity and its transmission in interstate
commerce as "public utilities" under the Federal Power Act. The Federal Power
Act also gives FERC jurisdiction to review certain transactions and numerous
other activities of public utilities.
FERC is also encouraging the voluntary restructuring of transmission
operations through the use of independent system operators and regional
transmission groups. The result of establishing these entities typically is to
eliminate or reduce transmission charges imposed by successive transmission
systems. The full effect of these changes on us is uncertain at this time, in
part, because it has not been determined which of these entities will control
the transmission systems connected to certain of our generating facilities.
The Federal Power Act also gives FERC exclusive authority to license
non-federal hydroelectric projects on navigable waterways and federal lands.
FERC hydroelectric licenses are issued for 30 to 50 years. Our hydroelectric
assets are licensed by FERC from 2004 through 2036. Individual hydroelectric
facilities, representing approximately 90 megawatts of our capacity, have
licenses that expire over the next ten years. Facilities representing
approximately 160 megawatts of our capacity have new or initial license
applications pending before FERC. Upon expiration of a FERC license, the federal
government can take over the project and compensate the licensee, or FERC can
issue a new license to either the existing licensee or a new licensee. In
addition, upon license expiration, FERC can decommission an operating project
and even order that it be removed from the river at the owner's expense. In
deciding whether to issue a license, FERC gives equal consideration to a full
range of licensing purposes related to the potential value of a stream or river.
It is not uncommon for the relicensing process to take between four and ten
years to complete. Generally, the relicensing process begins at least five years
before the license expiration date and FERC issues annual licenses to permit a
hydroelectric facility to continue operations pending conclusion of the
relicensing process. We expect that FERC will issue us new or initial
hydroelectric licenses for all the facilities with pending applications.
Presently, there are no applications for competing licenses and there is no
indication that FERC will decommission or order any of the projects to be
removed.
Nonetheless, there remains the possibility that FERC will not issue new or
initial licenses for our projects, which could have a material adverse effect on
our operations and revenue. In addition, several interested parties have
intervened or are likely to intervene in our licensing proceedings. These
interested parties may be able to impose conditions and affirmative obligations
on our hydropower operations, which could add significant costs to our
operations or reduce revenues. In the past, FERC has issued licenses with
conditions that have rendered the operation of the relevant projects uneconomic.
Therefore, there is no guarantee that the hydroelectric licenses issued by FERC
will permit us to operate the projects profitably. Finally, the relicensing
process itself is costly, time consuming, and could affect adversely our
hydroelectric revenues.
The remainder of our hydroelectric assets have licenses that expire over an
approximate 30 year period, are exempt from licensing because they are small
facilities with five megawatts or less or are not within FERC's jurisdiction
because they are not located on navigable waterways or federal land. Many of the
existing licenses contain conditions that have one or more operational
constraints, including restricting energy production, impacting the time of year
or day in which generation occurs, raising operating costs, and requiring
certain minimum river flow releases, which directly affect our ability to
generate energy.
STATE ENERGY REGULATION
At the state level, public utility commissions are responsible for
approving rates and other terms and conditions under which public utilities
purchase electric power from independent producers and sell retail electric
power to consumers. In addition, most state laws require approval from the state
commission before an electric utility operating in the state may divest or
transfer electric generation facilities. These laws also give the commissions
authority to regulate the financial activities of electric utilities selling
electricity to consumers in their states.
State public utility commissions have authority to promulgate regulations
for implementing some federal laws. Power sales agreements, which we enter into,
are also potentially subject to review by state public utility commissions. In
particular, the state public utility commissions review the process by which the
utility has entered into power sales agreements. States may also assert
jurisdiction over the siting, construction, and operation of our facilities, as
well as the issuance of securities and the sale or other transfer of assets.
NEW YORK. In 1996, the New York Public Service Commission began proceedings
to introduce retail competition in New York State. These initiatives, in
conjunction with FERC's "open access" rules, led to the formation of an ISO
responsible for centralized control and operation of the state-wide electric
transmission grid. They also led to a spot market and a related competitive
electric energy auction. This auction is open on a non-discriminatory basis to
all electric service providers. Other aspects of New York's restructuring plan
include market power mitigation through utility divestiture of fossil fuel
generation plants, the unbundling and establishment of separate rates for
historic utility functions, and market mitigation measures at the wholesale
level.
Under the New York Public Service Law, the New York Public Service
Commission has jurisdiction over corporations engaged in the production of
electricity and transfers of electric generation facilities located in the
State. The New York Public Service Commission reviewed and approved each of our
transactions to acquire our assets located in New York, and made the necessary
findings to permit us to seek exempt wholesale generator status from FERC. We
are subject to "lightened regulation" in New York.
PENNSYLVANIA. In December 1996, Pennsylvania adopted the Electricity
Generation Customer Choice and Competition Act, which is now part of the Public
Utility Code. The Act is a comprehensive restructuring plan that allows direct
access to be phased in over a three-year period beginning January 1, 1999 and
culminating in full retail choice by January 1, 2001. Under this plan, one-third
of each customer class will be eligible for direct access each year.
The Act required each utility to submit its restructuring plan to the
Pennsylvania Public Utility Commission for approval. The Pennsylvania Public
Utility Commission is authorized to permit, but may not require, utilities to
divest their generation assets. We are not subject to the Pennsylvania Public
Utility Commission.
OHIO. The Ohio legislature passed a statute in 1999 providing for
implementation of retail competition beginning in 2001. The statute delegated to
the Ohio Public Utilities Commission the responsibility for developing certain
restructuring rules, including rules relating to market monitoring, stranded
cost recovery, and consumer protection. The restructuring plan for each
investor-owned utility has been approved by the Ohio Public Utilities
Commission. Similar to Pennsylvania, we do not expect to be subject to
regulation by the Ohio Public Utilities Commission. If we do become subject to
regulation by the Ohio Public Utilities Commission, however, additional costs
may be imposed on the operations of our assets located in Ohio and Pennsylvania.
WEST VIRGINIA. In 1998, the West Virginia Legislature enacted HB 4277,
which authorized the Public Service Commission to consider whether restructuring
was in the public interest and, if so, to submit a restructuring plan for
Legislative approval. In January 2000, the Commission issued an order finding
restructuring in the public interest and submitting a long-term plan for
transition to competitive power supply markets and consumer choice. The
implementation of retail electric choice has been delayed, however, pending
legislative action.
ENVIRONMENTAL REGULATIONS
The construction and operation of electric generating facilities are
subject to extensive environmental and land use regulation in the United States.
Those regulations applicable to us primarily involve the discharge of emissions
into the water and air as well as the use of water, but can also include
wetlands preservation, endangered species, waste disposal, and noise regulation.
These laws and regulations often require a lengthy and complex process of
obtaining and renewing licenses, permits, and approvals from federal, state, and
local agencies. If these laws and regulations are changed, modifications to our
facilities may be required.
CLEAN AIR ACT. In late 1990, Congress passed the Clean Air Act Amendments
of 1990, which affect existing facilities as well as new project development.
The act and many state laws require significant reductions in SO2 (sulfur
dioxide) and NOx (nitrogen oxide) emissions that result from burning fossil
fuels.
The 1990 Amendments create a marketable commodity called an SO2
"allowance." All non-exempt facilities over 25 megawatts that emit SO2 must hold
or obtain allowances in order to operate. Each allowance gives the owner the
right to emit one ton of SO2 annually. All non-exempt facilities that existed in
1990 have an assigned number of allowances. If additional allowances are needed,
they can be purchased from facilities having excess allowances. Our assets
located in New York currently have more allowances than needed, while our assets
located in Ohio and Pennsylvania require additional allowances or the
installation of SO2 controls. We believe that the additional costs of obtaining
the number of allowances needed for future projects should not materially affect
our ability to purchase and operate such facilities.
The 1990 Amendments also require states to impose annual operating permit
fees. While such permit fees may be substantial and will be greater for
coal-fired projects like our assets located in Ohio and Pennsylvania than for
those burning gas or other fuels, such fees are not expected to significantly
increase our costs.
The 1990 Amendments also contain other provisions that could materially
affect our projects. Various provisions may require permits, inspections, or
installation of additional pollution control technology.
The Ozone Transport Assessment Group, composed of state and local air
regulatory officials from the 37 eastern states, has recommended additional NOx
emission reductions that go beyond current federal standards. These
recommendations include reductions from utility and industrial boilers during
the summer ozone season.
The EPA recently granted several state petitions under Section 126 of the
Clean Air Act. Section 126 allows the EPA to set limits for specific sources of
emissions originating in other states. As a result, the EPA will require
reductions in NOx emissions at the majority of our fossil energy facilities at
levels consistent with those required under the EPA rule. Consistent with the
EPA's rule, reductions have been proposed which would need to be achieved by May
1, 2004 through the implementation of controls or the purchase of emission
allowances. We believe that our assets located in New York City are already in
compliance with these limits. We anticipate capital expenditures of
approximately $300 million at the assets located in Ohio and Pennsylvania
through 2010 to address these anticipated air emissions issues. We expect that
the majority of these expenditures under the EPA rule and the EPA's Section 126
initiative will occur between 2002 and 2008. However, particularly given the
trend towards more stringent environmental regulation, it is possible that the
amount we must spend to bring the facilities into compliance may change
materially. In addition, the time at which these capital expenditures must be
made could be accelerated, and operations could be halted at these facilities
until any necessary improvements are made.
In 1999, the EPA requested information relating to the Avon Lake Generating
Station and Niles Generating Station from the previous owner of these
facilities. This was part of the EPA's broader industry information request, and
forms the basis for the agency's new source review actions against coal-fired
power plants. Although there have not been any new source review-related suits
filed against the Avon Lake Generating Station or the Niles Generating Station,
there can be no assurance that either of them will not be the target of any such
action in the future. Based on the levels of emissions control that the EPA
and/or states are seeking in these new source review enforcement actions, we
believe that significant additional costs and penalties could be incurred,
planned capital expenditures could be accelerated, or operations could be halted
at these stations if they ever became targets of a new source review enforcement
action.
CLEAN WATER ACT. Our facilities are subject to a variety of state and
federal regulations governing existing and potential water /wastewater and
stormwater discharges from the facilities. Generally, federal regulations
promulgated through the Clean Water Act govern overall water/wastewater and
stormwater discharges through permits. Under current provisions of the Clean
Water Act, existing permits must be renewed at least every five years, at which
time permit limits come under extensive review and can be modified to account
for more stringent regulations. In addition, the permits can be modified at any
time. Many of our facilities need to renew their Clean Water Act permits over
the next two years. Major issues to be addressed when permits are renewed
include the impact of intake screens and cooling systems on fish, as well as the
adverse impact of discharging large quantities of warm water to public rivers
and lakes. The cost of addressing any of these environmental issues could be
substantial.
In addition, changes to the environmental permits of our coal or other fuel
suppliers may increase the cost of fuel, which in turn could have a significant
impact on our operations.
EMERGENCY PLANNING AND COMMUNITY RIGHT-TO-KNOW ACT. In April 1997, the EPA
expanded the list of industry groups required to report the Toxic Release
Inventory under Section 313 of the Emergency Planning and Community
Right-to-Know Act to include electric utilities. Our operating facilities will
be required to complete a toxic chemical inventory release form for each listed
toxic chemical manufactured, processed, or otherwise used in excess of threshold
levels for the applicable reporting year. The purpose of this requirement is to
inform the EPA, states, localities, and the public about releases of toxic
chemicals to the air, water, and land that can pose a threat to the community.
EMPLOYEES
As of December 31, 2001, we employed approximately 908 people. Of these
employees, approximately 554 are covered by collective bargaining agreements.
The collective bargaining agreements expire at various dates between April 2003
and May 2006. We have never experienced a work stoppage, strike, or labor
dispute. We consider relations with our employees to be good.
ITEM 2. PROPERTIES.
The Orion Power corporate offices currently occupy approximately 15,340
square feet of leased office space in Baltimore, Maryland, which lease expires
in 2005, subject to renewal options. Upon expiration or earlier, this office
space will be vacated as the corporate headquarters is being transitioned to
Reliant's headquarters in Houston, Texas.
In addition to our corporate office space, we lease or own various real
property and facilities relating to our assets and development activities. Our
principal facilities are generally described under the descriptions of our three
operating subsidiaries contained elsewhere. We believe that we have title to our
facilities in accordance with standards generally accepted in the energy
industry, subject to exceptions which, in our opinion, would not have a material
adverse effect on the use or value of the facilities. Substantially all of our
assets are pledged to our bank lenders under our credit facilities.
Our total lease expense for all of our properties described above was
approximately $1.8 million for 2001.
ITEM 3. LEGAL PROCEEDINGS.
We are involved in various litigation matters in the ordinary course of our
business. We are not currently involved in any litigation that we expect, either
individually or in the aggregate, will have a material adverse effect on our
financial condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Omitted in reliance upon General Instruction I.1(a) and (b) for Form 10-K.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
All of the shares of common stock of Orion Power Holdings, Inc. are
beneficially owned by Reliant Resources and therefore, there is no trading
market in such shares.
ITEM 6. SELECTED FINANCIAL DATA.
Omitted in reliance upon General Instruction I.1(a) and (b) for Form 10-K.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
You should read the following discussion in conjunction with our audited
consolidated financial statements and the related notes included elsewhere in
this report.
OVERVIEW
We were incorporated in Delaware in March 1998 for the purpose of
acquiring, developing, owning, and operating non-nuclear electric power
generating facilities throughout North America. Commencing in November 1998, in
six separate acquisitions, we directly or through our wholly-owned subsidiaries
acquired our facilities with a total electric generating capacity of 5,644
megawatts in operation and an additional 804 megawatts in construction.
On February 19, 2002, Orion Power Holdings was acquired by merger by a
wholly-owned subsidiary of Reliant Resources, Inc. (Reliant).
Similar to other wholesale power generators, we typically sell three types
of products: energy, capacity, and ancillary services. Energy refers to the
actual electricity generated by our facilities and sold to intermediaries for
ultimate transmission and distribution to consumers of electricity. Capacity
refers to the physical capability of a facility to produce energy. Ancillary
services generally are support products used to ensure the safe and reliable
operation of the electric power supply system.
We typically sell our wholesale products to electric power retailers, which
are the entities that supply power to consumers. Power retailers include
independent service operators, regulated utilities, municipalities, energy
supply companies, cooperatives, and retail "load" or customer aggregators.
OUTLOOK
Reliant will fully integrate Orion Power's assets into the existing Reliant
business, fully utilizing Reliant's extensive trading, marketing and operational
experience. Reliant will improve Orion Power's assets through reduced operating
and maintenance costs as well as improved availability and reliability. This
integration will be rolled out during the third quarter of 2002. All
modernization, environmental, and development strategies will be integrated into
Reliant's regional operational strategy.
RESULTS OF OPERATIONS
GENERALLY. The principal factor affecting recent changes in our results has
been the timing of the acquisitions of our facilities. We acquired our
facilities on the following dates:
o Carr Street Generating Station - November 19, 1998;
o Hydroelectric assets - July 30, 1999;
o Assets located in New York City - August 20, 1999;
o Assets located in Cleveland, Pittsburgh, West Pittsburg, Youngstown
(Midwest Assets) - April 28, 2000;
o Assets under construction from Columbia Electric Corporation -
December 11, 2000; and
o Assets under development from Competitive Power Ventures (Atlantic) -
October 12, 2001.
One of the assets acquired from Columbia Electric Corporation, Ceredo
Electric Generating Station, was placed into commercial operation in June 2001.
CRITICAL ACCOUNTING POLICIES
Orion Power management has implemented several accounting policies and has
made certain judgements and estimates that are disclosed in the footnotes to our
consolidated financial statements. Several critical accounting policies,
judgments and estimates are discussed below.
REVENUE RECOGNITION
Revenues from the sale of electricity are recorded based on output
delivered and capacity provided at rates specified under contract terms or
received in the wholesale marketplace. The only portion of our revenue that
contains certain assumptions in its determination and measurement is the revenue
recognized from the Provider of Last Resort contract with Duquesne Light
Company. The revenue, per the contract, is based on the amount of charges billed
to Duquesne Light Company's customer base for the services provided. Since the
amount of the actual revenue is not known until it is remitted by Duquesne Light
Company subsequent to when they have read a customer's meter, we have
established a reasonable number of assumptions regarding multiple factors to
match the megawatts we produce to the revenue we record. These assumptions are
continuously reviewed and revised, as necessary. We have been and continue to
work with Duquesne Light Company to obtain the most accurate and timely data
available to minimize any violatility within our assumptions. Through December
31, 2001, there have been no significant revisions or changes to our revenue
recognition assumptions related to this contract.
DERIVATIVE INSTRUMENTS
Derivative instruments (Derivatives) are contracts which typically derive
value from changes in interest rates, foreign exchange rates, credit spreads,
prices of securities or financial or commodity price indices. The timing of cash
receipts and payments for derivatives is generally determined by contractual
agreement. Derivatives can be either standardized contracts that are traded on
an organized exchange or privately negotiated contracts. Futures contracts are
examples of standard exchange-traded derivatives. Privately negotiated
derivative contracts include forwards, interest rate swaps and certain option
contracts. Orion Power enters into interest rate swap agreements and commodity
forward contracts as an end user for purposes other than trading. Derivatives
used for purposes other than trading serve to economically hedge variable cash
flows on floating rate debt and hedge the purchase and sale price of various
commodities. For further information, see the footnotes to the Consolidated
Financial Statements.
Interest rate swaps are used to remove violatility in the floating interest
rate. They protect against increases in the interest rate. A determental value
is created when interest rates fall because the rate has become locked in.
Commodity swaps are used by Orion Power to stabilize future margins with
fixed forward purchases and sales thus removing the uncertainty of the daily or
real time prices incorporated in the market place as well as limit, or negate
the floating rates used in other sales and purchases. The risk is Orion Power
may have to purchase additional power at higher rates in order to fulfill these
contracts. An additional lost opportunity, or additional gains, would be not
having any commodity available for higher sale prices, or lower purchases, when
the market rates differ from the fixed rates.
INCOME TAXES
Orion Power accounts for income taxes under the asset and liability method
prescribed by Statement of Financial Accounting Standard (SFAS) No. 109,
"Accounting for Income Taxes," and, accordingly, deferred tax assets and
liabilities are recognized for the future tax consequences attributable to
temporary differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases and operating
loss and tax credit carry forwards. Deferred tax assets and liabilities are
measured using existing enacted tax rates. The effect on deferred tax assets and
liabilities of a change in tax rates would be recognized in income in the period
that includes the enactment date. We continuously review multiple tax strategies
for each individual subsidiary and for the consolidated entity, as a whole, in
an effort to continue to reduce our tax liability. We review acceptable tax
practices at the federal and state levels as well as any potential credits or
exemptions available to us. Part of this strategy focuses on the future
direction of the operating facilities as well as any future site development
including legal entity structuring. These tax positions are subject to review
and appeal and could result in a negative outcome having an adverse effect on
future earnings.
PROJECT DEVELOPMENT COSTS
Project development costs represent amounts incurred for professional
services, direct salaries, permits, options on real property and other direct
incremental costs related to the development of new property and equipment,
principally electric generating facilities. These costs are expensed as incurred
until development reaches a stage when it is probable that the project will be
completed. A project is considered probable of completion upon meeting one or
more milestones, which may include a power sales contract or securing
construction or operating permits, among others. Project development costs that
are incurred after a project is considered probable of completion but prior to
starting physical construction are capitalized. Project development costs are
included in construction in progress when physical construction begins. Orion
Power periodically assesses project development costs for impairment. Impairment
could occur with: significant increases in construction costs, including any
turbine commitments; loss of a critical trading partner or contract (ie - an
executed tolling agreement) through bankruptcy; or an inability to obtain the
necessary financing to complete the project.
YEAR ENDED DECEMBER 31, 2001 COMPARED TO THE YEAR ENDED DECEMBER 31, 2000
REVENUE. Our revenue was $1,178.4 million for the year ended December 31,
2001, as compared to revenue of $957.6 million for the year ended December 31,
2000. The overall increase in revenues was mainly attributable to a full period
of the Midwest assets in our portfolio for the year ended December 31, 2001. The
Midwest assets were acquired in April 2000. One factor was increased generation
in New York City through increased megawatt capacity, availability and
production. Energy and capacity prices were fairly comparable for the years
ended December 31, 2001 and 2000. Other factors in determining our revenue
stream are weather patterns and the seasonality of energy consumption, which is
often correlated with weather patterns. Extreme temperatures can cause
significant fluctuations in our revenue stream by significantly affecting energy
usage patterns. Plant outages, due to a variety of factors, can also lead to
changes in revenues of our own facilities, and those of other energy producers,
by affecting the volume or prices of our wholesale energy products. In early
August 2001, we had a significant outage in one of our main units, Avon Lake #9,
located in Cleveland, Ohio. This unit returned to service in mid August 2001 and
has operated normally since that time. No other such outages have occurred in
the periods described that have had a significant impact on our business.
OPERATING EXPENSES. Our operating expenses for the year ended December 31,
2001, consisted of fuel expense, gain on derivative instruments, operations and
maintenance expense, general and administrative expenses, taxes other than
income taxes (principally property taxes) and depreciation and amortization
expense.
We had fuel expenses of $470.4 million for the year ended December 31,
2001, compared with $437.8 million for the year ended December 31, 2000. The
increase in fuel expense was mainly attributable to a full period of the Midwest
assets in our portfolio for the year ended December 31, 2001, as well as our
Ceredo facility commencing operations in June 2001. Fuel expense for 2000 also
includes $57 million for the purchase of power from May 2000 through October
2000 to supplement our generating capacity to meet our obligations under the
Provider of Last Resort Contract. Excluding the purchased power of $57 million
from 2000 for our provider of last resort obligation, the fuel to revenue ratio
is very comparable at 40% for each period.
Our gain on derivative instruments was $11.9 million for the year ended
December 31, 2001, compared to $0 for the year ended December 31, 2000. This
gain reflects the change in market value for the derivative instruments (certain
electricity, natural gas, oil, and financial tolling agreements) that do not
qualify as hedges under generally accepted accounting principles. See discussion
of the "Accounting Change".
Our operations and maintenance expenses were $129.4 million for the year
ended December 31, 2001, as compared to $97.6 million for the year ended
December 31, 2000. The increase was mainly attributable to a full period of the
Midwest assets in our portfolio for the year ended December 31, 2001. As a
percentage of revenues, the periods are very comparable at 11% and 10% for the
years ended December 31, 2001 and 2000, respectively.
Our general and administrative expenses were $58.3 million for the year
ended December 31, 2001, as compared to $37.1 million for the year ended
December 31, 2000. The increase was the result of expanded corporate
infrastructure to support our growth along with a full year of the Midwest
regional office in 2001 as well as salary increases and incentive bonuses.
Taxes other than income taxes amounted to $57.4 million for the year ended
December 31, 2001, compared to $60.8 million for the year ended December 31,
2000. The decrease was due to approximately a $6.2 million reduction in taxes
other than income taxes in Orion Power NY due to the settlement of outstanding
property tax issues in several municipalities with favorable results and was
partially offset by increased taxes of approximately $1.7 million for our
Midwest assets due to a full year of ownership in 2001.
Depreciation and amortization expense was $137.9 million for the year ended
December 31, 2001, as compared to $103.2 million for the year ended December 31,
2000. The increase was mainly attributable to a full period of the Midwest
assets in our portfolio for the year ended December 31, 2001. The expense for
the year ended December 31, 2001 also includes partial year depreciation for
many capital projects completed during the year at several of our plants
including a major unit restart in one of our assets located in New York City as
well as some major upgrades to our older Midwest assets.
Our charge for buyout of operations and maintenance contracts was the
result of the acquisition of the subsidiaries of Constellation Operating
Services in April 2000. We incurred a one-time loss of $19.0 million,
principally a non-cash item. There was no such loss for the year ended December
31, 2001.
OPERATING INCOME. As a result of these factors, our operating income was
$336.8 million for the year ended December 31, 2001, as compared to operating
income of $202.2 million for the year ended December 31, 2000.
INTEREST INCOME. Our interest income was $21.5 million for the year ended
December 31, 2001, as compared to $15.3 million for the year ended December 31,
2000. This increase was due to more cash on hand for the year ended December 31,
2001, which included the proceeds from our initial public offering of
approximately $453 million in November 2000 as well as a follow-on equity and
debt offering in May 2001 for net proceeds of approximately $465 million.
INTEREST EXPENSE. Our interest expense was $202.8 million for the year
ended December 31, 2001, as compared to $168.7 million for the year ended
December 31, 2000. The increase was mainly attributable to a full period of
interest related to the debt entered into in April 2000, to acquire the Midwest
assets. The year ended December 31, 2001, also included a full year of interest
for the $400 million senior notes issued by Orion Power in April and May 2000.
Additional net debt was added during 2001 through withdrawals on various
revolvers and construction loans totaling approximately $249 million as well as
the addition of the $200 million convertible senior notes sold in May 2001,
which were offset by approximately $332 million in debt repayments.
INCOME TAX PROVISION. Our income tax provision was $54.9 million for the
year ended December 31, 2001, compared to $20.2 million for year ended December
31, 2000. The increase was due to higher taxable income for the equivalent
periods. Our effective tax rate decreased to 35.3% from 41.5% due to the
implementation of several strategies to reduce our taxable income in high tax
jurisdictions mostly attributable to selected state tax credits utilized during
2001.
YEAR ENDED DECEMBER 31, 2000 COMPARED TO THE YEAR ENDED DECEMBER 31, 1999
REVENUE. Our revenue was $957.6 million for the year ended December 31,
2000, as compared to revenue of $134.1 million for the year ended December 31,
1999. The increase was primarily due to a full year of operations in 2000 of our
hydroelectric assets and our assets located in New York City, and the
acquisition in April 2000 of our assets located in Cleveland, Pittsburgh, West
Pittsburg and Youngstown. The revenue from each facility was determined at least
in part in accordance with the various interim capacity and energy agreements
then in place, including the provider of last resort contract with Duquesne
Light Company. The provider of last resort contract has been revised and the
term extended through December 2004. Our capacity sale agreement for our assets
located in New York City with Consolidated Edison expired in April 2000, at
which time we began selling our capacity into the market.
OPERATING EXPENSES. Our operating expenses consisted of fuel expense,
operations and maintenance expense, taxes other than income taxes (principally
property taxes), general and administrative expenses and depreciation and
amortization expense.
We had fuel expenses of $437.8 million for the year ended December 31,
2000, compared with $20.5 million for the year ended December 31, 1999. The
increase in 2000 was the result of our acquisition of our assets located in
Cleveland, Pittsburgh, West Pittsburg and Youngstown, the full year of operation
of our assets located in New York City and higher per unit costs for natural gas
and oil in 2000. From the date of acquisition through November 18, 1999, the
assets located in New York City were being operated under a tolling agreement
where the party buying the power supplied the fuel. This contract terminated
when the NY-ISO began operations. Fuel expense for 2000 also includes $57
million for the purchase of power from May 2000 through October 2000 to
supplement our generating capacity to meet our obligations under the provider of
last resort contract.
Our operations and maintenance expenses were $97.6 million for the year
ended December 31, 2000, as compared to $22.7 million for the year ended
December 31, 1999. The increase was a result of the ownership and operation of
our hydroelectric assets and our assets located in New York City for a full year
in 2000 along with the acquisition in the more recent period of our assets
located in Cleveland, Pittsburgh, West Pittsburg and Youngstown. The year ended
December 31, 1999, reflects the Carr Street facility for the period with partial
periods for our hydroelectric assets and our assets located in New York City.
Taxes other than income taxes amounted to $60.8 million for the year ended
December 31, 2000, compared to $20.8 million for the year ended December 31,
1999. The increase was a result of the ownership and operation of our
hydroelectric assets and our assets located in New York City for a full year in
2000 along with the acquisition in the more recent period of our assets located
in Cleveland, Pittsburgh, West Pittsburg and Youngstown. The year ended December
31, 1999, reflects the Carr Street facility for the full year and a partial year
for our hydroelectric assets and our assets located in New York City.
Our general and administrative expenses were $37.1 million for the year
ended December 31, 2000, as compared to $16.8 million for the year ended
December 31, 1999. The increase was the result of expanded corporate
infrastructure to support our growth along with the creation of a regional
office for Orion Power MidWest, L.P.
Depreciation and amortization expense was $103.2 million for the year ended
December 31, 2000, as compared to $18.9 million for the year ended December 31,
1999. The increase was a result of the ownership and operation of our
hydroelectric assets and our assets located in New York City for a full year in
2000 along with the acquisition in the more recent period of our assets located
in Cleveland, Pittsburgh, West Pittsburg and Youngstown. We also added the
provider of last resort contract value as an intangible asset in 2000. The year
ended December 31, 1999, reflects the Carr Street facility for the period with
partial periods for our hydroelectric assets and our assets located in New York
City.
Our charge for buyout of operations and maintenance contracts was the
result of the acquisition of the subsidiaries of Constellation Operating
Services in April 2000. We incurred a one-time loss of $19.0 million,
principally a non-cash item. There was no such loss for the year ended December
31, 1999.
OPERATING INCOME. As a result of these factors, our operating income was
$202.2 million for the year ended December 31, 2000, as compared to operating
income of $34.4 million for the year ended December 31, 1999.
INTEREST EXPENSE. Our interest expense was $168.7 million for the year
ended December 31, 2000, as compared to $25.8 million for the year ended
December 31, 1999. The increase in interest expense was due to our new bank
credit agreement for the acquisition of our assets located in Cleveland,
Pittsburgh, West Pittsburg and Youngstown, the $400 million senior notes issued
in April and May 2000, and the revolving credit facility entered into in July
2000. Additionally, in 2000, we had a full year of interest expense under our
bank credit facility related to the acquisition of our hydroelectric assets and
our assets located in New York City during 1999. Interest expense also includes
amortization of deferred financing costs from the establishment of Orion Power
MidWest, L.P.'s credit facility, the senior notes and the revolving credit
facility, all occurring in 2000.
INTEREST INCOME. Our interest income was $15.3 million for the year ended
December 31, 2000, as compared to $1.8 million for the year ended December 31,
1999. The increase was due to the increase of cash on hand from operations
(excluding restricted cash) resulting from a full year of operations in 2000 of
our hydroelectric assets and our assets located in New York City, the
acquisition during 2000 of our assets located in Cleveland, Pittsburgh, West
Pittsburg and Youngstown, and the additional cash raised as part of our initial
public offering in November 2000.
LIQUIDITY AND CAPITAL RESOURCES
During the year ended December 31, 2001, we obtained cash from operations
and from borrowings under the credit facilities of our subsidiaries as well as
through our public offerings in June 2001 of common stock and convertible senior
notes. This cash was used to fund operations, service debt obligations, fund our
development and construction projects at Kelson Ridge, Astoria, Avon Lake,
Liberty, Ceredo, and Cheswick, and meet other cash and liquidity requirements.
For 2002, our principal sources of liquidity will be cash from operations
as well as fundings from our existing credit facilities including any
refinancing of our Orion Power Holdings revolving credit facility and of our New
York and MidWest credit facilities. Such refinancing may be provided by external
sources or via intercompany loans or equity injections provided by Reliant
Resources, Inc. The major risk to our liquidity sources for 2002 are significant
increases in interest rates as we refinance our existing facilities, or the
inability to refinance such facilities.
Depending on our performance and market conditions prevailing at the time
of the expiration of these credit facilities, Reliant may not be able to arrange
for the necessary replacement of these facilities on terms that are acceptable
to us. If we are unable to obtain financing to replace these facilities on terms
that are acceptable to us, our financial condition and future results of
operations would be materially adversely affected.
Operating activities for the year ended December 31, 2001, provided $171.2
million of cash. This resulted from a $36.2 million increase in operating
assets, including restricted cash and notes receivable balances, and a $31.0
million net decrease in deferred tax assets. This also included a $69.2 million
decrease in operating liabilities, $154.4 million of depreciation and
amortization, $100.6 million of net income, $2.5 million of deferred
compensation, including the tax benefit from the exercise and $11.9 million gain
on derivative instruments.
Investing activities for the year ended December 31, 2001, used
approximately $26.3 million of cash for the acquisition of our Atlantic project,
a 250 megawatt gas-fired baseload combined cycle facility to be constructed in
Florida, with the remaining $475.9 million being used for facilities upgrades
and improvements.
Financing activities for the year ended December 31, 2001, provided
approximately $378.9 million of cash. We received net proceeds of $448.4 million
on borrowings under the convertible senior notes and the Liberty credit
facility, and $272.6 million of net proceeds from the issuance of common stock.
Approximately $332.0 million of debt primarily related to our Midwest credit
facility was paid down with the funds from these offerings and operations.
Additionally, we paid $12.7 million for financing costs under the senior
convertible notes and had proceeds of $2.5 million from officers' notes
receivable.
As of December 31, 2001, cash and cash equivalents were $183.7 million and
adjusted working capital was $628.3 million (adjusted working capital excludes
$1,614.3 million of the current portion of long-term debt). Of this working
capital, we had restricted cash of $336.7 million that can only be used pursuant
to our credit facilities in certain circumstances to fund the business
activities of the subsidiaries that hold our hydroelectric assets, our assets
located in New York City, our assets located in Cleveland, Pittsburgh, West
Pittsburg and Youngstown and the assets in development that we acquired in
connection with our purchase of Columbia Electric Corporation.
The credit facility of Orion Power New York, L.P. (Orion Power New York) is
a credit agreement between Orion Power New York and a group of lending
institutions. Under the credit facility agreement, Orion Power New York incurred
$700 million of indebtedness to finance the acquisition of our hydroelectric
assets and our assets located in New York City, of which $578.5 million was
outstanding at December 31, 2001. Amounts outstanding under the facility bear a
floating rate of interest. In addition, Orion Power New York has a $30 million
working capital revolving credit facility as part of the facility, of which $0
was outstanding as of December 31, 2001, and $10 million was used to provide a
letter of credit in favor of Consolidated Edison of New York. This credit
facility is available only to Orion Power New York and not for Orion Power
Holdings' operations. It provides, among other things, that the amount of
dividends and distributions that Orion Power New York may pay cannot exceed $100
million over the life of the facility. As of December 31, 2001, distributions of
$86.5 million had been paid. This credit facility contains various business
covenants that are typical for limited or non-recourse project financings. Such
covenants include, among others, restrictions on dividends, capital
expenditures, additional indebtedness, liens and investments, as well as
requirements regarding insurance, approval of operating budgets and commercial
contracts. The facility also includes a requirement that Orion Power New York
maintain a debt service coverage ratio of 1.5 to 1.0. These covenants are not
anticipated to materially restrict us from borrowing funds or obtaining letters
of credit under the working capital facility. The credit facility has a maturity
date of December 2002. Orion Power New York plans to refinance this credit
facility as described above.
The credit facility of Orion Power MidWest, L.P. is a credit agreement
between Orion Power MidWest and a group of lending institutions. Under the
credit facility, Orion Power MidWest incurred $1.11 billion of indebtedness to
finance the acquisition of our assets located in Cleveland, Pittsburgh, West
Pittsburg and Youngstown, $1.01 billion of which was outstanding at December 31,
2001. Amounts outstanding under the credit facility bear a floating rate of
interest. In addition, Orion Power MidWest has a $90 million working capital
facility, of which $10.0 million was outstanding as of December 31, 2001, and
$10 million was used to provide a letter of credit in favor of Duquesne Light
Company as well as an additional $5 million letter of credit to support various
services. This credit facility is available only to Orion Power MidWest and not
for Orion Power Holdings' operations. It provides, among other things, that the
cumulative amount of dividends and distributions that Orion Power MidWest may
pay cannot exceed $175 million over the life of the facility. As of December 31,
2001, no dividends or distributions had been paid. This credit facility contains
various business covenants that are typical for limited or non-recourse project
financings. Such covenants include, among others, restrictions on dividends,
capital expenditures, additional indebtedness, liens and investments, as well as
requirements regarding insurance, approval of operating budgets, fuel and power
marketing plans and commercial contracts. The facility also includes a
requirement that Orion MidWest maintain a debt service coverage ratio of 1.5 to
1.0; provided that, for the quarter ended March 31, 2002 we could alternatively
make a prepayment of $25,000,000, which was done on March 22, 2002. Orion Power
MidWest anticipates that it may not be able to meet this covenant and would need
to seek a waiver or amendment for the quarter ended June 30, 2002. If a waiver
or amendment is required, we have no assurance that Orion Power MidWest will be
able to obtain such a waiver or amendment from its lenders. The credit facility
has a maturity date of October 2002. Orion Power MidWest plans to refinance this
credit facility as described above.
Under the New York Credit Agreement and the MidWest Credit Agreement
(collectively, the "Credit Agreements"), Orion Power New York and Orion Power
MidWest are restricted from distributing cash to Orion Power. These credit
agreements provide for various accounts to be created, into which all operating
revenues and other cash receipts are deposited, and from which operating
expenses, repayments of the loan facilities and distributions to Orion Power may
be made.
The $400 million, 12% Senior Notes are due on May 1, 2010. The proceeds
were used to assist in the financing of the acquisition of the Midwest Assets.
Interest is paid semiannually in May and November of each year. The senior notes
are senior unsecured obligations and rank pari passu with all of Orion Power
Holdings' existing and future unsecured indebtedness. Before May 1, 2003, Orion
Power Holdings may redeem up to 35 percent of the notes issued under the
indenture at a redemption price of 112 percent of the principal amount of the
notes redeemed, plus accrued and unpaid interest and special interest, with the
net cash proceeds of an equity offering provided that certain provisions under
the indenture are met. Orion Power Holdings is not required to make any
mandatory redemption or sinking fund payments with respect to the Senior Notes.
Each holder of the Senior Notes has the right to require Orion Power Holdings to
repurchase the notes pursuant to a change of control offer as set forth in the
indenture. The indenture requires that Orion Power offer a cash payment
equivalent to 101% of the aggregate principal amount of the repurchased notes
plus any accrued or unpaid interest through the date of the repurchase upon
completion of the merger with Reliant. This offer was made to noteholders as the
merger with Reliant qualified as a change in control. The Senior Notes are not
guaranteed by any of Orion Power Holdings' subsidiaries. The senior notes
indenture contains covenants restricting our ability to pay dividends, incur
indebtedness, sell assets, transact with affiliates, enter into sale and
leaseback transactions, place liens on our property or change our line of
business.
Pursuant to certain change of control provisions, Orion Power Holdings
commenced an offer to repurchase the $400 million 12% senior notes on March 21,
2002. The offer to repurchase expires on April 18, 2002 and payment to holders
accepting the offer will be made on April 19, 2002. Orion Power Holdings does
not expect any note holders will accept the offer and that it will not
repurchase any of the $400 million 12% senior notes. To the extent that Orion
Power Holdings does not have sufficient cash with which to make such repurchase,
it is anticipated that Reliant Resources will make such repurchase with its own
cash.
The $75 million revolving senior credit facility matures in December 2002.
Amounts outstanding under the facility bear interest at a floating rate. The
facility is unsecured and ranks pari passu with all of Orion Power Holdings'
senior debt. As of December 31, 2001, there were no outstanding amounts borrowed
under this facility and $69.9 million in letters of credit were outstanding:
$46.0 million related to Liberty with the remaining $23.9 million for the
Atlantic project. This credit facility contains various business covenants. Such
covenants include, among others, restrictions on dividends, additional
indebtedness and indebtedness of subsidiaries, liens, investments, capital
expenditures and prepayment/redemption of debt. The facility also includes a
requirement that we maintain a consolidated leverage ratio of less than 5.0 to
1.0 (after April 1, 2002), a consolidated interest coverage ratio of 1.75 to
1.0, a minimum consolidated tangible net worth of $700,000,00, and a borrower
debt service coverage ratio of 1.4 to 1.0. The failure of Orion Power Holdings
to meet any of these financial covenants for two consecutive fiscal quarters
constitutes an event of default, which could lead to the requirement to pay any
outstanding borrowings prior to maturity and to cash collateralize outstanding
letters of credit. Orion Power Holdings did not meet the borrower debt service
coverage ratio for the quarter ended March 31, 2002; if Orion Power Holdings
needs to seek a waiver or amendment of this covenant because it has not been met
for the quarter ended June 30, 2002, there is no assurance that Orion Power
Holdings will be able to obtain such a waiver or amendment from its lenders.
The Liberty Electric Power, LLC (Liberty Electric) credit facility was
assumed by us in connection with our acquisition of Columbia Electric
Corporation in December of 2000. The credit facility provides for up to
approximately $334 million of borrowings under multiple tranches. With the
exception of $41 million, which is supported by a letter of credit issued under
Orion Power Holdings credit facility described above, the credit facility is
recourse only to the assets and cash flows of Liberty Electric and is
non-recourse to Orion Power Holdings. As of December 31, 2001, $282.8 million
was outstanding under the facility. The credit facility is available only to
Liberty Electric and not for Orion Power Holdings' operations. This credit
facility contains various business covenants that are typical for limited or
non-recourse project financings. Such covenants include, among others,
restrictions on distributions, capital expenditures, additional indebtedness,
liens and investments, as well as requirements regarding insurance, approval of
operating budgets, fuel and power marketing plans and commercial contracts.
The equity bridge loan matures on the earlier of October 1, 2002, or a date
on which the conditions precedent to conversion to a term loan are met. The debt
service reserve letter of credit becomes available for use when the conditions
precedent to conversion to a term loan are met and matures five years
thereafter. The working capital facility becomes available for use six months
prior to the scheduled conversion date and matures five years thereafter. The
construction/term loan matures on the earlier of October 1, 2002, or a date on
which the conditions precedent to conversion to a term loan are met and matures
10 years thereafter. The institutional term loan has a final maturity date of
April 15, 2026.
Liberty Electric Power Plant is expected to be completed in April 2002 at
which time we also expect to meet the conditions precedent to permit conversion
of the construction loan to a term loan. The output of this plant is contracted
under a tolling agreement for a term of approximately 14 years. Under this
agreement the counterparty will have the exclusive right to receive all energy,
capacity and ancillary services produced by the plant. The counterparty will pay
for, and be responsible for, all fuels used by the plant under the tolling
agreement.
On June 6, 2001, Orion Power Holdings issued $200 million aggregate
principal amount of 4.50 percent convertible senior notes, due on June 1, 2008.
The notes are convertible into shares of Orion Power Holdings' common stock at a
conversion price of $34.19 per share, and are first subject to redemption at a
premium by Orion Power Holdings on June 4, 2004. Upon completion of the merger
with Reliant, holders of the convertible senior notes have the right to require
Orion Power Holdings to repurchase some or all of the notes at a price equal to
100 percent plus accrued and unpaid interest. Concurrently with this offering,
Orion Power Holdings and certain selling stockholders completed a $355.6 million
common stock offering, comprised of approximately 10,400,000 shares sold by
Orion Power Holdings and approximately 2.6 million shares sold by the selling
stockholders at a per share price of $27.35. A portion of the proceeds from
these offerings was used to repay approximately $100 million of outstanding debt
held by Orion Power Holdings' subsidiaries. To the extent that Orion Power
Holdings does not have sufficient cash with which to make such repurchase, it is
anticipated that Reliant Resources will make such repurchase with its own cash.
Pursuant to certain change of control provisions, Orion Power Holdings
commenced an offer to repurchase the $200 million 4.5% convertible senior notes
on March 1, 2002. The offer to repurchase expires on April 10, 2002 and payment
to holders accepting the offer will be made on April 12, 2002. Orion Power
Holdings expects all note holders will accept the offer and that it will
repurchase the $200 million 4.5% convertible senior notes. To the extent that
Orion Power Holdings does not have sufficient cash with which to make such
repurchase, it is anticipated that Reliant Resources will make such repurchase
with its own cash.
We will require cash to meet the debt service obligations under our notes
and credit facilities. Debt service obligations will fluctuate depending on
variations in the interest rate and the balance on the working capital portion
of the facilities. The following table summarizes the outstanding indebtedness
as of December 31, 2001:
SOURCE AMOUNT INTEREST RATE
- ------ ------ -------------
(dollars in millions)
Orion Power New York Credit Facility..................... $ 578 5.66%
Orion Power MidWest Credit Facility...................... 1,023 5.37
12% Senior Notes due 2010................................ 400 12.00
4.5% Convertible Senior Notes due 2008................... 200 4.50
Orion Power Holdings Revolving Senior Credit Facility.... -- N/A
Liberty Electric Credit Facility ........................ 283 6.55(a)
----- -----
Total............................................... $ 2,484 6.57%(a)
====== =====
_______________
(a) Weighted average interest rate.
Including the outstanding debt noted above, we have the following
contractual obligations for the next five years and beyond (in thousands):
Maturity Period
Contractual Obligations < 1 Year 1-3 years 4-5 years After 5 years Total
- ---------------------------------------------------------------------------------------------------------------------
Debt $1,614,334 $ - $ - $ 870,000 $2,484,334
Capital and Operating Lease Obligations 1,796 3,611 1,927 6,099 13,433
Turbine Purchase Obligations 200,100 364,100 5,800 - 570,000
Other Long-Term Obligations 3,238 4,687 - 4,175 12,100
--------------------------------------------------------------------
Total Contractual Obligations $1,819,468 $372,398 $ 7,727 $ 880,274 $3,079,867
====================================================================
Debt includes the senior notes and convertible senior notes held by Orion
Power Holdings as well as the three credit facilities held by the operating
subsidiaries, Orion Power New York, Orion Power Midwest and Liberty Electric. We
will attempt to refinance the Orion Power Holdings, Orion Power New York and
Orion Power Midwest credit facilities expire in 2002. We will attempt to
refinance the Orion Power Holdings, Orion Power New York and Orion Power Midwest
facilities as described above and below. The capital and operating leases relate
to various office space and other equipment. The turbine purchase obligations
are for contracts entered into by Orion Power Holdings for new development as
well as repowering projects currently under way or planned. These obligations
will be funded through operating funds and debt, as necessary. The other
long-term obligations relate to environmental liabilities assumed at acquisition
for the New York Assets as well as the Midwest Assets. These obligations are the
projected remediation costs to satisfy our environmental obligations and would
be funded through operating funds.
Additionally, Orion Power Holdings has other commercial commitments, in the
form of unused lines of credits, letters of credit, and purchase obligations
under its coal contracts. The following table highlights those costs and timing
of obligation (in thousands):
Other Commercial Amount of Commitment Expiration per period
Commitments < 1 Year 1-3 years 4-5 years After 5 years Total
- --------------------------------------------------------------------------------
Unused Lines of Credit $115,078 $ - $ - $ 5,000 $120,078
Letters of Credit 94,922 - - - 94,922
Fuel Contracts 144,742 51,765 9,118 - 205,625
---------------------------------------------------------
Total Commercial
Commitments $354,742 $ 51,765 $ 9,118 $ 5,000 $420,625
=========================================================
The unused lines of credits are part of the existing credit facilities and
expire in conjunction with each individual facility. The letters of credit are
part of and expire in conjunction with the existing credit facilities. The
long-term unused line of credit is part of the Liberty credit facility and
becomes due five years following conversion of the construction facility to a
term loan facility. The fuel contracts represent minimum purchase obligations at
contracted fixed rates under the current contracts for the operating facilities.
We, as a wholly-owned subsidiary of Reliant, will need to refinance our
indebtedness under the Orion Power New York credit facility, which becomes due
in December 2002, and the Orion Power MidWest credit facility, which becomes due
in October 2002. We are currently exploring financing alternatives to replace
and/or retire this debt. Entering into a new credit facility and issuing an
additional series of notes are among the alternatives being considered.
We, as a wholly-owned subsidiary of Reliant, review potential acquisition
and development opportunities on an on-going basis. In the near future, we may
seek to acquire and/or develop additional facilities, which, depending on the
size and structure of these acquisitions or development projects, may require
significant cash resources. We currently have not made any commitments or
entered into any binding agreements with respect to any such transaction. We may
incur substantial additional indebtedness to finance future acquisitions and
development opportunities. This indebtedness may be incurred by us or by one or
more of our subsidiaries. Any increase in the level of indebtedness will
increase the amount of interest paid.
In addition, we plan to improve the operational efficiency of our
generating facilities and, in some cases, to expand our facilities on-site. This
on-site expansion may come either through the construction of additional
generating plants at existing sites, referred to in the industry as "brownfield"
development, or through the repowering of existing plants. Our ability to expand
the capacity of our facilities is subject to numerous factors, including
restrictions imposed by environmental regulations. We anticipate capital
expenditure upgrades of between $30 and $40 million annually for the next
several years in connection with our assets. We also may incur significant
additional expenditures for capital improvements following 2002 for future major
maintenance projects as well as continued modernization of some of the older
facilities.
Additionally, we expect that capital expenditures on environmental projects
will total approximately $300 million over the next seven years, the majority of
which is expected to be expended between 2002 and 2006. We believe that a
substantial portion of this will be funded out of operating cash flow. This
amount may change, however, and the timing of any necessary capital expenditures
could be accelerated in the event of a change in environmental regulations or
any enforcement proceeding being commenced against us.
In order to execute our business strategy and finance our anticipated
capital expenditures, we may need to incur additional debt. If we incur
additional debt, we will refinance our existing indebtedness and/or incur new
debt in compliance with the restrictions of our existing indebtedness or with
the consent of our existing lenders. Any increase in our level of indebtedness
will increase the amount of interest we must pay.
We are restricted in our ability to incur additional indebtedness and make
acquisitions and capital expenditures by the terms and conditions of our senior
notes, our revolving credit facility and the credit facilities of our
subsidiaries. We may incur additional indebtedness under the terms of:
o the senior notes if the ratio of consolidated cash flow to fixed
charges is at least 2.0 times, taking into account the additional
indebtedness;
o the revolving credit facility if the amount outstanding at any time
does not exceed $5,000,000 and (i) the debt under the credit facility
ranks senior or pari passu with such debt and (ii) such debt does not
contain terms that are more restrictive than the provisions of the
revolving credit facility;
o the Orion Power New York, L.P. credit facility so long as the debt is
less than $1,000,000 or, if over $1,000,000, with the consent of
two-thirds of the Orion Power New York lenders;
o the Orion Power MidWest credit facility as long as the debt is less
than $5,000,000; if in excess of $5,000,000, the debt must have a
maturity date of longer than 36 months and must not limit or restrict
the lenders under the Orion Power MidWest credit facility in
exercising their rights thereunder in any way that is more limiting or
restrictive than the provisions of the senior notes.
The Liberty Electric credit facility has no limitations on Orion Power
Holdings' ability to incur additional indebtedness.
SEASONALITY
Our operations vary depending upon the season and regional weather
conditions, although the impact of seasonality can vary depending upon the
geographic location of our facilities. In many areas, the demand for electric
power peaks during the hot summer months, with energy and capacity prices
correspondingly being the highest at that time. We can earn a substantial amount
of our net income from a few days during the peak demand for electric power on
the hottest days of summer. In some areas, demand also increases during the
coldest winter months. Additionally, hydroelectric plants show seasonality
depending upon the availability of water flows, which generally will be high
during rainy months or as a result of snowmelt in the late winter and spring.
Prices will generally fluctuate with demand, being highest at times of greatest
demand. This fluctuation is currently somewhat mitigated by the existence of the
hydro-transition power sales agreement and the provider of last resort contract,
both of which have constant prices for the entire year. Our overall future
operating results may reflect different seasonal aspects, depending upon the
location and characteristics of any additional facilities we acquire.
RISK MANAGEMENT ACTIVITIES
Orion Power Holdings uses derivative instruments to manage exposures to
interest rate and commodity price risks. Orion Power's objectives for holding
derivatives are to minimize the variability in Orion Power's cash flow using the
most effective methods to eliminate or reduce the impacts of these risks. Orion
Power Holdings does not use derivative instruments for speculative or trading
purposes.
INTEREST RATE RISK
Orion Power's debt service payments from its credit facilities are subject
to interest rate risk resulting in variability in future cash flows. Orion Power
Holdings uses pay-fixed interest rate swaps to mitigate the risk of increasing
interest rates for a portion of Orion Power's floating rate debt. These
derivatives serve to hedge Orion Power's exposure to cash flow variability for
future interest payments in the event of significant changes in interest rates.
COMMODITY PRICE RISK
Orion Power Holdings executes both physical and financial commodity
contracts to serve as economic hedges of certain commodity purchase and sale
activity. These contracts serve to hedge price volatility for some aspects of
its operations due to inflation, rising fuel costs, and flat or decreasing
energy prices. Orion Power Holdings executes financial contracts for the forward
sale of electricity, the forward purchases of natural gas and oil as well as
financial tolling contracts. The forward sales of electricity are treated as
cash flow hedges of the forecasted electricity sales, with the exception of one
long-term contract, which is classified as no hedging designation. The fair
value changes of contracts that are not designated in qualifying hedge
accounting relationships are recorded in earnings in the period they occur. The
net gain attributable to the change in these derivative contracts included in
the operating expenses on the accompanying consolidated statements of operations
was approximately $11,919,000 for the year ended December 31, 2001. Orion
Power's use of derivative instruments, whether designated as an accounting hedge
or not, is designed to lock in energy sale prices and the associated fuel costs
to effectively create a fixed energy margin.
MARKET RISK
Market risk is the potential loss Orion Power Holdings may incur as a
result of changes in the market or fair value of a particular instrument or
commodity. All financial and commodities-related instruments, including
derivatives, are subject to market risk. Orion Power's exposure to market risk
is determined by a number of factors, including the size, duration, composition,
and diversification of positions held, the absolute and relative levels of
interest rates, as well as market volatility and illiquidity. The most
significant factor influencing the overall level of market risk to which Orion
Power Holdings is exposed is its use of hedging techniques to mitigate such
risk. Orion Power Holdings manages market risk by actively monitoring compliance
with stated risk management policies as well as monitoring the effectiveness of
its hedging policies and strategies. Orion Power's risk management policies
limit the amount of total net exposure and rolling net exposure during stated
periods. These policies, including related risk limits, are regularly assessed
to ensure their appropriateness given Orion Power's objectives. Subsequent to
the merger with Reliant, we will be subject to the risk management structure and
policies of Reliant.
CREDIT RISK
Orion Power Holdings is exposed to losses in the event of nonperformance by
counterparties to its derivative instruments. Credit risk is measured by the
loss Orion Power Holdings would record if its counterparties failed to perform
pursuant to terms of their contractual obligations and the value of collateral
held, if any, was not adequate to cover such losses. Orion Power Holdings has
established controls to determine and monitor the creditworthiness of
counterparties, as well as the quality of pledged collateral, and uses master
netting agreements whenever possible to mitigate Orion Power's exposure to
counterparty credit risk. Additionally, Orion Power Holdings may require
counterparties to pledge additional collateral when deemed necessary.
Concentrations of credit risk from financial instruments, including
contractual commitments, exist when groups of counterparties have similar
business character