Orion Power Holdings, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In Thousands) (Unaudited)
The accompanying notes are an integral part of these consolidated financial statements.
Orion Power Holdings, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
September 30, 2001
1. Organization and Operations of the Company:
Orion Power Holdings, Inc., a Delaware corporation, and its subsidiaries (the Company) own, operate, acquire, and develop non-nuclear electric power generating facilities in North America.
2. Summary of Significant Accounting Policies:
Basis of Interim Presentation
The accompanying interim consolidated financial statements of the Company have been prepared by the Company, without audit by independent public accountants, pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the consolidated financial statements include the adjustments necessary to present fairly the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted from these unaudited consolidated financial statements pursuant to such rules and regulations and, accordingly, should be read in conjunction with the consolidated financial statements and related notes and management's discussion and analysis of financial condition and results of operations, included in the Annual Report on Form 10-K for the fiscal year ended December 31, 2000. The results of interim periods are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2001.
Derivatives
Derivative financial 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 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. The Company enters into interest rate swap agreements and commodity forward contracts for purposes other than trading. Derivatives used for purposes other than trading are related to hedging variable cash flows on floating rate debt and hedging the purchase and sale price of various commodities.
Interest rate swaps are contractual agreements to exchange periodic interest payments at specified intervals. The notional amounts of interest rate swaps are not exchanged; they are used in conjunction with the agreed-upon fixed and/or floating interest rates to calculate the periodic interest payments.
Commodity swaps are contractual commitments to exchange the fixed price of a commodity for a floating price. Commodity forwards are privately negotiated agreements to purchase or sell a specific amount of a commodity at an agreed-upon price and settlement date.
The Company accounts for its derivative instruments as either cash flow hedges or no hedging designation. To qualify for cash flow hedge accounting, the hedge relationship must be formally documented at inception and be anticipated to be highly effective. If the requirements for hedge accounting are not met, the Company accounts for derivatives through the statement of operations on a mark to market basis.
The Company reports interest rate swaps at fair value with changes in the swap fair value reported in either other comprehensive income (OCI) or earnings as determined by the accounting method applied. For swaps qualifying for hedge accounting, the gains/losses on the swaps that are deemed effective are deferred in OCI. Deferred gains and losses from effective hedge relationships will be reclassified into earnings as adjustments to interest expense over the life of the hedged debt. If the swap does not qualify for hedge accounting, any change in fair value is reported currently in earnings.
The Company accounts for the commodity forwards at fair value, with the change in fair value reported in OCI. The effective portion of the derivative fair value change for those swaps that qualify as cash flow hedges are deferred as part of OCI. The deferred gains/losses on the commodity forward contracts are reclassified from OCI to earnings in the same period as the hedged sale of the commodity impacts earnings. If hedge accounting is not applied, any fair value changes in the commodity forwards are reported currently in earnings.
The Company also has certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business. These derivatives are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and thus are not reflected on the balance sheet at fair value.
The Company classifies its fuel swap contracts and financial tolling arrangements as no hedging designation under Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activity." These contracts are reported at fair value with any changes in fair value reported currently in earnings.
In October 2001, the Financial Accounting Standards Board (FASB) approved two interpretations issued by the Derivatives Implementation Group (DIG) that change the definition of normal purchase and sales for certain power and commodity contracts. Certain of our derivative commodity contracts may no longer be exempt from the requirements of SFAS No. 133. We are evaluating the impact of the implementation guidance on our financial statements, and will implement this guidance, as applicable, on a prospective basis.
Comprehensive Income
The Company's comprehensive income consists of net income and other items recorded directly to the equity accounts. The objective is to report a measure of all changes in equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. The Company's other comprehensive income consists principally of gains and losses on derivative instruments that qualify for cash flow hedge treatment.
Reclassifications
Some 2000 balances have been reclassified to conform with the current year financial statement presentation.
Recent Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 141, "Business Combinations." This standard prohibits the use of pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and applies to all business combinations accounted for under the purchase method that are completed after June 30, 2001. We do not expect that implementation of this standard will have a significant impact on our financial statements.
Also in June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This standard eliminates the amortization of goodwill, and requires goodwill to be reviewed periodically for impairment. This standard also requires the useful lives of previously recognized intangible assets to be reassessed and the remaining amortization periods to be adjusted accordingly. This standard is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangibles assets recognized on our balance sheet at that date, regardless of when the assets were initially recognized. We have not yet determined the effects of this standard on our financial statements.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for asset retirement obligations associated with tangible long-lived assets. We have not yet determined the effects of this standard on our financial statements.
3. Commitments and Contingencies:
Turbine Purchases
In February and March 2001, the Company entered into two letters of intent for delivery of turbine generators for the Company's development projects for a total of approximately $281.2 million. We signed purchase contracts in August 2001 for turbines within these letters of intent related to the Kelson Ridge facility. The Company has made approximately $86.6 million in turbine payments for the nine months ended September 30, 2001, including $8 million in deposits.
Letters of Credit
As of September 30, 2001, the Company had $63.5 million of outstanding letters of credit. These letters of credit are purchased guarantees that ensure the Company's performance or payment to third parties in accordance with unspecified terms and conditions. As of September 30, 2001, no amounts had been drawn against these letters of credit.
4. Long-Term Debt:
On June 6, 2001, the Company completed a $200 million offering of 4.50 percent convertible senior notes, which mature on June 1, 2008. The notes are convertible into shares of the Company's common stock at a conversion price of $34.19 per share, representing a 25 percent conversion premium and are first subject to call by the Company on June 4, 2004. Concurrently with this offering, the Company and certain selling stockholders completed a $355.6 million common stock offering, comprised of approximately 10.4 million shares sold by the Company and approximately 2.6 million shares sold by the selling stockholders at a per share price of $27.35 (see Note 7). A portion of the proceeds from these offerings was used to repay approximately $100 million of outstanding debt held by the Company's subsidiaries.
5. Earnings Per Share:
Basic earnings per share (EPS) is computed by dividing net income by the weighted-average number of common shares outstanding during the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method.
Diluted EPS assumes the issuance of common stock pursuant to stock options and warrants at the beginning of the year.
The following table shows the computation of the Company's basic and diluted EPS for 2000 and 2001 (in thousands, except share data):
2000 2001
---------------------------------- -----------------------------------
Per Share Per Share
Net Income Shares Amount Net Income Shares Amount
---------- ------ --------- ---------- ------ ---------
For the three months ended
September 30:
Basic EPS- $3,921 68,816,894 $64,874 103,499,109
Less: accretion of common stock (383)
subject
to put rights
Net income attributable to common $3,538 $0.05 64,874 $0.63
stockholders
Effect of dilutive securities 3,114,695 1,327 10,191,855
------- ---------- -------- -----------
Diluted EPS- $3,538 71,931,589 $0.05 $66,201 113,690,964 $0.58
======= ========== ====== ======== =========== ======
For the nine months ended
September 30:
Basic EPS- $17,671 55,289,366 $101,325 97,552,958
Less: accretion of common stock (654)
subject
to put rights
Net income attributable to common 17,017 $0.31 101,325 97,552,958 $1.04
stockholders
Effect of dilutive securities 2,654,091 1,327 6,996,492
------- ---------- -------- -----------
Diluted EPS- $17,017 57,943,457 $0.29 $102,652 104,549,450 $0.98
======= ========== ====== ======== =========== ======
Equivalent shares of options and convertible securities that were excluded from diluted earnings per share due to their antidilutive effect were 0, 1,608,522, and 36,146 for the three months ended March 31, 2001, June 30, 2001, and September 30, 2001, respectively.
6. Income Taxes
Reconciliation of the statutory federal income tax rate to the Company's effective tax rate is as follows:
2001 2000
---- ----
THREE MONTHS ENDING SEPTEMBER 30,
---------------------------------
Statutory federal tax rate 35.0% 35.0%
State and local taxes,
net of federal tax benefit 0.5% 6.5%
State tax credits (4.0%) 0.4%
---------------------------
Effective tax rate 31.5% 41.9%
===========================
NINE MONTHS ENDING SEPTEMBER 30,
--------------------------------
Statutory federal tax rate 35.0% 35.0%
State and local taxes,
net of federal tax benefit 3.3% 6.5%
State tax credits (2.4%) (0.3%)
---------------------------
Effective tax rate 35.9% 41.2%
===========================
The rate reductions for the three and nine months ended September 30, 2001 are related to the implementation of several tax planning strategies, including utilization of several tax savings incentive programs, primarily focused on the high tax jurisdictions in which the Company has substantial operations.
7. Accounting Change:
Effective January 1, 2001, the Company adopted SFAS No. 133, (the Statement) as amended by SFAS Nos. 137 and 138. This Statement establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. All derivatives, whether designated in hedging relationships or not, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in OCI and are recognized in the income statement when the hedged item affects earnings. Ineffective portions of changes in fair value of cash flow hedges are recognized as earnings.
The adoption of the Statement resulted in a pre-tax reduction to OCI of $57.0 million ($33.3 million after taxes). The reduction to OCI for the nine months ended September 30, 2001 is mostly attributable to valuation losses of approximately $29.0 million on our interest rate swaps and reclassifications out of OCI of $4.7 million in gains, respectively. The net derivative losses included in OCI will be reclassified into earnings as these derivative contracts settle.
At September 30, 2001, the Company had net derivative assets of approximately $28.6 million, derivative liabilities of approximately $111.1 million and OCI of approximately $(57.6) million, after tax, related to fair values of the Company's derivatives.
The Company uses derivative instruments to manage exposures to interest rate and commodity price risks. The Company's objectives for holding derivatives are to minimize the variability in the Company's cash flow using the most effective methods to eliminate or reduce the impacts of these risks. The Company does not use derivative financial instruments for speculative or trading purposes.
Interest Rate Risk
The Company's credit facilities are subject to interest rate risk. The interest rate swaps are derivative instruments used to mitigate the risk of increasing interest rates for the Company's floating rate debt. These derivatives represent the Company's attempt to hedge its exposure to interest rate risk in the event of significant increases in interest rates.
Commodity Price Risk
The Company attempts to hedge some aspects of its operations against inflation, rising fuel costs, and flat or decreasing energy prices. The Company engages in 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, with the exception of one long-term contract, which is treated as a derivative. The forward purchase and financial tolling contracts are treated as derivatives with gains and losses recorded in earnings. The net gain attributable to the change in these derivative contracts included in the operating expenses on the accompanying consolidated statements of operations was $16.4 million for the nine months ended September 30, 2001. The Company's use of derivative financial instruments, whether considered and treated as a hedge or not, is designed to lock in sale prices and the associated fuel costs to create a fixed and less variable energy margin.
8. Stockholders' equity and comprehensive income:
Stockholders' equity and comprehensive income amounted to the following as of and for the nine months ended September 30, 2001 (in thousands, except share data):
Notes Accumulated
Additional Receivable Other
Common Stock Paid-In Deferred From Comprehensive Retained Comprehensive
Shares Amount Capital Compensation Officers Income Earnings Total Income
-----------------------------------------------------------------------------------------------------
Balance,
December 31,
2000 93,095,926 $ 931 $1,230,467 $ (3,359) $ (5,916) $ - $ 32,659 $1,254,782 $ -
Sale of
common stock,
net of fees 10,404,260 104 271,012 271,116
Net income 101,325 101,325 101,325
Change in
notes
receivable 1,837 1,837
Amortization
of deferred
compensation 1,197 1,197
Derivative
transition
adjustment (33,330) (33,330) (33,330)
Change in
valuation of
cash flow
hedges (24,271) (24,271) (24,271)
---------
Comprehensive income $43,724
-----------------------------------------------------------------------------------------------------
Balance,
September
30, 2001 $103,500,186 $1,035 $1,501,479 $ (2,162) $ (4,079) $ (57,601) $ 133,984 $1,572,656
============ ====== ========== ======== ========= ============ ========= ==========
On June 6, 2001, the Company completed a $355.6 million common stock offering, comprised of 10.4 million shares sold by the Company and 2.6 million shares sold by certain selling stockholders at a gross per share offering price of $27.35, resulting in net proceeds to the Company of approximately $270.7 million. Concurrently with this offering, the Company completed a $200 million offering of 4.50% convertible senior notes (see Note 4). The net proceeds from these offerings is being used by the Company to repay debt and to fund the development of a generating station. Additionally, excess proceeds will be used to fund future acquisitions.
9. Merger with Reliant Resources, Inc.
On September 26, 2001, Reliant Resources, Inc. (Reliant), a wholly owned subsidiary of Reliant and the Company entered into an Agreement and Plan of Merger pursuant to which such wholly owned subsidiary will be merged into the Company, and the Company will become a wholly owned subsidiary of Reliant. Under the terms of the agreement, each of the outstanding shares of the Company's stock will be converted into $26.80 in cash.
The companies anticipate the merger will be completed in early 2002. The merger is conditioned upon, among other things, the approval of the stockholders of the Company and various regulatory approvals.
10. Subsequent Event:
In October 2001, the Company purchased one combined-cycle power project located in Florida from Competitive Power Ventures Holdings, LLC, a subsidiary of Competitive Power Ventures, Inc. This is a 250 MW project near Palm Beach with substantial expansion capability. The initial phase of 250 MW for the project is scheduled for completion in 2004. Construction on the gas-fired, baseload facility will commence in early 2002. GE Frame 7FA turbines have been procured for the project. The capital cost is anticipated at $175 million for the first phase.
| Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations. |
This report contains "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements include, among others, statements concerning the Company's outlook for 2001 and beyond, the Company's expectations, beliefs, future plans and strategies, anticipated events or trends, and similar expressions concerning matters that are not historical facts. The forward-looking statements in this report are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by the statements.
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 five separate acquisitions, we directly or through our wholly-owned subsidiaries acquired our facilities with a total electric generating capacity of 5,926 megawatts in operation and an additional 5,000 megawatts in construction and various stages of development.
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.
Recent Developments
On July 12, 2001, the Federal Energy Regulatory Commission announced that it would facilitate a process designed to create a Northeast Regional Transmission Organization, (Northeast RTO), which would likely be comprised of all entities under the governance of the New England Independent Systems Operator (NEISO), the New York Independent Systems Operator, (NY-ISO), and the Pennsylvania-New Jersey-Maryland Interconnection (PJM) markets. This process is at a very early stage and is being challenged by some organizations. We are unable to determine what impact, if any, implementation of a Northeast RTO would have on us.
In July 2001, we executed a Purchase and Consulting Agreement with Signal Development, L.P. for Fork Shoals Energy, LLC including a land purchase option in Fork Shoals, South Carolina and some consulting services related to developing the land into a viable power plant.
In August 2001, we received a Certificate of Public Convenience and Need for the 1,650 megawatt, gas-fired Kelson Ridge Generating Station (Kelson Ridge). The facility will be located in Waldorf, Maryland. We expect the initial phase of 1,100 megawatts to be completed in two stages of 550 megawatts by 2004, with a potential second phase of an additional 550 megawatts to be completed in 2005. We have entered into a purchase contract to purchase the four combustion turbines and two steam turbines from Siemens Westinghouse Power Corporation for the initial phase. The output will be committed under contract and/or made available for the regional wholesale energy market, currently the PJM.
In August 2001, Duquesne Light Company indicated that it may join PJM-West, a newly created wholesale market covering the Mid-Atlantic region of the country. This market could be created and operational as early as January 2002. We may sell all or part of our capacity as well as ancillary services into this new market.
On September 26, 2001 Reliant and our Board of Directors approved a definitive merger agreement. Under the terms of the agreement, each outstanding share of our stock will be converted into $26.80 in cash. The merger is conditioned upon, among other things, the approval of our stockholders and various regulatory approvals.
The four primary approvals are:
| | • | Antitrust Review by the Federal Government. Under the provisions of the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act) and the rules and regulations promulgated under the HSR Act, the merger may not be completed until we and Reliant have made filings with the U.S. Federal Trade Commission and the U.S. Department of Justice and the applicable waiting periods have expired or been terminated. We and Reliant filed the requisite notification reports with the DOJ on October 19, 2001. |
| | • | FERC. The merger is subject to the approval of the Federal Energy Regulatory Commission (FERC) under Section 203 of the Federal Power Act. We and Reliant filed our application with the FERC on October 22, 2001. |
| | • | NY-PSC. The New York Public Service Commission (NY-PSC) reserves the right to review any proposed business combination that could lead to an adverse effect to ratepayers in the state. We and Reliant believe that the NY-PSC will not review the merger because there will be no adverse effect on competition or rates. Nevertheless, we and Reliant are asking the NY-PSC to either declare that it will not review the merger or, in the alternative, approve the merger. We and Reliant filed an application with the NY-PSC on October 26, 2001. |
| | • | Orion Power Stockholders. The merger is subject to the approval of our stockholders at a special meeting of stockholders to be held later this year or early in 2002. Stockholders who, collectively, own approximately 60% of our outstanding shares have agreed to vote in favor of the merger. |
We anticipate the merger will be completed in early 2002.
In October 2001, we purchased one combined-cycle power project located in Florida from Competitive Power Ventures Holdings, LLC, a subsidiary of Competitive Power Ventures, Inc. This is a 250 MW project near Palm Beach with substantial expansion capability. The initial phase of 250 MW for the project is scheduled for completion in 2004. Construction on the gas-fired, baseload facility will commence in early 2002. GE Frame 7FA turbines have been procured for the project. The capital cost is anticipated at $175 million for the first phase.
Results of Operations
The principal factor affecting recent changes in our results has been the timing of the acquisitions of our facilities. We acquired our significant assets on the following dates:
| | • | Carr Street Generating Station -- November 19, 1998; |
| | • | Hydroelectric assets -- July 30, 1999; |
| | • | Assets located in New York City -- August 20, 1999; |
| | • | Assets located in Cleveland, Pittsburgh, West Pittsburg, Youngstown -- April 28, 2000; and |
| | • | Assets under construction from Columbia Electric Corporation -- December 11, 2000. |
Set forth below are certain operating data which we believe indicate the general performance of our operations:
Three Months Three Months Nine Months Nine Months
Ended Ended Ended Ended
September September September 30, September 30,
---------- ---------- -------------- -------------
30, 2000 30, 2001 2000 2001
-------- -------- ----- ----
(Dollars in Thousands)
Consolidated EBITDA......................... $ 92,729 $ 173,393 $ 210,632 394,939
========== ========== =========== ===========
Megawatt hours produced during period....... 4,875,779 5,270,679 10,370,161 15,048,615
Net capacity owned at end of period
(Megawatts)................................. ( 5,396) (5,926) (5,396) (5,926)
Three Months and Nine Months Ended September 30, 2001 Compared to the Three and Nine Months Ended September 30, 2000
Revenue. Our revenue was $367.0 million and $946.8 million for the three months and nine months ended September 30, 2001, respectively, as compared to revenue of $343.0 million and $684.7 for the three months and nine months ended September 30, 2000, respectively. The increase for the three months ended September 30, 2001 as compared to the three months ended September 30, 2000 was primarily contributed having no financial hedge for the POLR load in the Midwest in 2001 as opposed to the $30 million pre-tax loss incurred in 2000 for the financial power purchased as a hedge in that period. The increase for the nine months ended September 30, 2001 as compared to the nine months ended September 30, 2000, was primarily due to the acquisition in April 2000 of our assets located in Cleveland, Pittsburgh, West Pittsburg and Youngstown as well as the commencement of operations of our Ceredo facility in Ceredo, West Virginia, in June 2001. 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. The loss of generation coupled with the cost of purchasing power to cover our POLR obligations reduced our fully diluted earnings per share for the three months ended September 30, 2001 between $0.03 to $0.05. 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 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 $147.6 million and $385.8 million for the three months and nine months ended September 30, 2001, respectively, compared with $189.5 million and $317.2 million for the three months and nine months ended September 30, 2000, respectively. The decrease from the three months ended September 30, 2001 compared to the three months ended September 30, 2000 was driven by lower fuel costs for natural gas and fuel oil. The increase for the nine months ended September 30, 2001 compared to the nine months ended September 30, 2000, was in part the result of our acquisition of our assets located in Cleveland, Pittsburgh, West Pittsburg and Youngstown in April 2000. Another component of our fuel expenses is purchased power, which is power that we buy rather than generate. Purchased power was $16.1 million and $30.5 million for the three months and nine months ended September 30, 2001, respectively, compared to $36.2 million and $42.7 million for the three months and nine months ended September 30, 2000, respectively; a decrease of 56% and 29%, respectively. Other factors that affect our fuel expenses include market fluctuations in the price of fuel and our ability to substitute one fuel type for another for economic or operating reasons.
Our gain in derivative financial instruments was $14.7 million and $16.4 million for the three months and nine months ended September 30, 2001, respectively, compared to $0 for the three months and nine months ended September 30, 2000. This gain reflects the change in market value during the three months and nine months ended September 30, 2001, for the derivative financial instruments (certain electricity, natural gas, oil, and financial tolling agreements) that do not qualify as hedges under generally accepted accounting principles. See the discussion of the "Accounting Change" below.
Our operations and maintenance expenses were $35.0 million and $92.7 million for the three months and nine months ended September 30, 2001, respectively, as compared to $32.6 million and $68.1 million for the three months and nine months ended September 30, 2000, respectively. The increase for the nine months ended September 30, 2001 compared to the nine months ended September 30, 2000, was in part a result of the acquisition of our assets located in Cleveland, Pittsburgh, West Pittsburgh and Youngstown in April 2000 and the commencement of operations in our Ceredo facility in June 2001. Another component of the increase was higher labor costs due to new labor agreements with several of our represented workforces that became effective in mid 2000. Other costs included in operations and maintenance expenses are for maintenance projects performed in conjunction with scheduled capital improvements or forced outages. These costs may be incurred at different times during the operating cycle as a result of system planning, forced outages, energy needs, and other external factors. These costs, as they relate to maintenance projects, follow the seasonal patterns of the energy industry with a higher concentration of costs in the early part of the second and fourth quarters of a fiscal year, traditionally the slower periods of energy demand.
Our general and administrative expenses were $15.2 million and $43.4 million for the three months and nine months ended September 30, 2001, respectively, as compared to $9.8 million and $24.3 million for the three months and nine months ended September 30, 2000, respectively. The increase was the result of expanded corporate and regional infrastructure to support our growth.
Taxes other than income taxes amounted to $10.5 million and $46.4 million for the three months and nine months ended September 30, 2001, respectively, compared to $18.3 million and $45.4 million for the three months and nine months ended September 30, 2000, respectively. The decrease for the three months ended September 30, 2001 compared to the three months ended September 30, 2000 was due to several property tax refunds received and the settlement of a pending assessment case from one of our hydroelectric generation facilities. The majority of these taxes stem from property taxes related to our facilities and their locations. A number of our facilities have come under reassessment which is customary following a transfer of ownership. We continue to attempt to control these costs through assessment hearings and negotiations with the appropriate authorities.
Depreciation and amortization expense was $34.4 million and $99.6 million for the three months and nine months ended September 30, 2001, respectively, as compared to $33.1 million and $75.4 million for the three months and nine months ended September 30, 2000, respectively. The increase for the nine months ended September 30, 2001 compared to the nine months ended September 30, 2000, was in part a result of the acquisition in April 2000 of our assets located in Cleveland, Pittsburgh, West Pittsburg and Youngstown. We have also completed several major capital projects in a number of our facilities, specifically our assets located in New York City during 2001, that led to increases in property and equipment costs and, accordingly, in depreciation expense. Capital projects and future acquisitions will continue to determine the amount and growth of these costs.
Operating Income. As a result of the above factors, our operating income was $139.0 million and $295.3 million for the three months and nine months ended September 30, 2001, respectively, as compared to operating income of $59.6 million and $135.2 million for the three months and nine months ended September 30, 2000, respectively.
Interest Expense. Our interest expense was $50.8 million and $154.7 million for the three months and nine months ended September 30, 2001, respectively, as compared to $56.5 million and $113.0 million for the three months and nine months ended September 30, 2000, respectively. The reduction in interest expense for the three months ended September 30, 2001 compared to the same period in 2000 was due to decreased interest rates thus reducing the costs of our floating rate debt. The increase in interest expense for the nine months ended September 30, 2001 compared to the same period in 2000 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, the revolving credit facility we entered into in July 2000 and the $200 million convertible senior notes issued in June 2001. Interest expense also includes amortization of deferred financing costs from the establishment of and any substantial modifications to our senior notes or credit facilities. We are currently contemplating refinancing the debt of our operating subsidiaries.
Interest Income. Our interest income was $6.4 million and $17.4 million for the three months and nine months ended September 30, 2001, respectively, as compared to $3.6 million and $7.8 million for the three months and nine months ended September 30, 2000, respectively. The increase is due to the increase in cash on hand raised as part of our public offerings in November 2000 and June 2001.
Income Tax Provision. Our income tax provision was $29.8 million and $56.7 million for the three months and nine months ended September 30, 2001, respectively, as compared to $2.8 million and $12.4 million for the three months and nine months ended September 30, 2000, respectively. The increase was due to higher taxable income for the equivalent periods. Our effective tax rate decreased to 31.4% from 41.9% and 35.9% from 41.2% for the three and nine months ended September 30, 2001 and 2000, respectively, due to the implementation of several strategies to reduce our taxable income in high tax jurisdictions.
Net Income. As a result of the above factors, our net income was $64.9 million and $101.3 million for the three months and nine months ended September 30, 2001, respectively, as compared to $3.9 million and $17.7 million for the three months and nine months ended September 30, 2000, respectively.
Accounting Change
Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," (the "Statement") as amended by SFAS Nos. 137 and 138. This Statement establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. All derivatives, whether designated in hedging relationships or not, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in other comprehensive income and are recognized in the income statement when the hedged item affects earnings. Ineffective portions of changes in fair value of cash flow hedges are recognized into earnings.
The adoption of the Statement resulted in a pre-tax reduction to other comprehensive income of $57.0 million ($33.3 million after taxes). The reduction to other comprehensive income for the nine months ended September 30, 2001, is mostly attributable to valuation losses of approximately $29.0 million on our interest rate swaps and reclassifications out of other comprehensive income of $4.7 million in gains, respectively. The net derivative losses included in other comprehensive income will be reclassified into earnings as these derivative contracts settle.
Liquidity and Capital Resources
During the nine months ended September 30, 2001, we obtained cash from operations, from borrowings under the credit facilities of our subsidiaries and from the public offerings of equity and debt. This cash was used to fund operations, service debt obligations, fund construction of our Ceredo, Liberty Electric and Kelson Ridge generating stations, and meet other cash and liquidity requirements.
Operating activities for the nine months ended September 30, 2001, provided $198.9 million of cash compared to $22.9 million of cash used for the nine months ended September 30, 2000. The change in restricted cash was $32.9 million for the nine months ended September 30, 2001, compared to a change of $(101.0) for the nine months ended September 30, 2000. Investing activities for the nine months ended September 30, 2001, used $357.8 million of cash for facilities' upgrades and improvements as well as continued construction of our Ceredo, Liberty Electric and Kelson Ridge generating stations as compared to $67.9 million of cash used for similar upgrades and improvements in the nine months ended September 30, 2000, net of disposals of $5.6 million for the same period. Additionally, for the nine months ended September 30, 2000, investing activities used $1.7 billion for assets purchased through an acquisition. Financing activities for the nine months ended September 30, 2001, provided $443.0 million of cash, primarily through additional borrowings and issuance of common stock as compared to providing $1.8 billion in the nine months ended September 30, 2000.
As of September 30, 2001, cash and cash equivalents were $420.0 million and working capital was $780.3 million. Of this working capital, we had restricted cash of $250.5 million that can only be used pursuant to our credit facilities in certain circumstances to fund the business activities of our subsidiaries.
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. 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. However, we may incur additional indebtedness under a variety of scenarios.
We 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 believe we are currently in compliance with all of the covenants under our credit facilities and senior notes.
In addition, we plan to improve the operational efficiency of our generating facilities and, in some cases, to expand our facilities on-site. We anticipate maintenance capital expenditures of between $30 and $40 million annually for the next several years in connection with our assets. Additionally, we expect that capital expenditures on environmental projects will total approximately $350 million over the next seven years, the majority of which is expected to be expended between 2002 and 2006. We believe a substantial portion of this will be funded out of operating cash flow.
We will fund our operating activities, construction and maintenance and debt service requirements through a combination of operating cash flows, financing arrangements and the proceeds from our debt and equity offerings. We expect our future cash flows and cash sources will increase as a result of the new power supply agreement we entered into with Niagara Mohawk Power Corporation in March 2001, the revisions and extension to the provider of last resort contract agreed to with Duquesne Light Company in February 2001, the addition of Ceredo, which began commercial operations on June 14, 2001, and the proceeds from the equity and debt offerings completed in June 2001.
We expect our financing requirements beyond the offerings described above, will be driven by the refinancing of our operating subsidiaries credit facilities and additional acquisitions or development projects.
Recent Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 141, "Business Combinations." This standard prohibits the use of pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and applies to all business combinations accounted for under the purchase method that are completed after June 30, 2001. We do not expect that implementation of this standard will have a significant impact on our financial statements.
Also in June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This standard eliminates the amortization of goodwill, and requires goodwill to be reviewed periodically for impairment. This standard also requires the useful lives of previously recognized intangibles assets to be reassessed and the remaining amortization periods to be adjusted accordingly. This standard is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangibles assets recognized on our statement of financial position at that date, regardless of when the assets were initially recognized. We have not yet determined the effects of this standard on our financial statements.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for asset retirement obligations associated with tangible long-lived assets. We have not yet determined the effects of this standard on our financial statements.
| Item 3. | Quantitative and Qualitative Disclosures About Market Risk. |
We attempt to hedge some aspects of our operations against the effects of fluctuations in inflation, interest rates, and commodity prices. Because of the complexity and potential cost of hedging strategies and the diverse nature of our operations, our results, although hedged, will likely be somewhat materially affected by fluctuations in these variables and these fluctuations may result in material improvement or deterioration of operating results. Results would generally improve with lower interest rates and fuel costs, and with higher prices for energy, capacity, and ancillary services, except where we are subject to fixed price agreements such as the provider of last resort contract. Our operating results are also sensitive to the difference between inflation and interest rates, and would generally improve when increases in inflation are higher than increases in interest rates. We do not use derivative financial instruments for speculative or trading purposes.
As of September 30, 2001, we were party to four interest rate swap agreements designed to fix the variable rate of interest on $350 million of the credit facility of Orion Power New York, L.P. The weighted average fixed rate of interest for the related swap agreements is approximately 6.95%. In addition, we were party to four interest rate swap agreements designed to fix the variable rate of interest on $600 million of the credit facility of Orion Power MidWest, L.P. The weighted average fixed rate of interest for the related swap agreement is approximately 7.42%. As of September 30, 2001, if we sustained a 100 point basis change in interest rates for all variable rate debt, the change would have affected net pretax income by $8.0 million.
As of September 30, 2001, the fair value of our financial instruments, except for the fixed rate component of the Liberty Credit Facility, the senior notes, the convertible senior notes and our derivative financial instruments approximates their carrying value due to their short-term nature or due to the fact the interest rate paid on the debt is variable. The fair value of the senior notes, the fixed portion of the Liberty debt and the convertible senior notes was estimated using discounted cash flow analysis, based on the Company's incremental borrowing rate and the approximate carrying value based on the quoted market prices for similar types of borrowing arrangements. The fair value of the derivatives was determined using published market rates as of the nearest business day prior to September 30, 2001. The carrying values and fair values of these financial instruments are as follows as of September 30, 2001 (in thousands):
Carrying Fair
Value Value
----------------------------------
Senior Notes $400,000 $485,500
Liberty Debt - fixed portion 160,200 210,907
Convertible Senior Notes 200,000 196,760
Derivative Instruments:
Interest Rate Swaps -- (106,696)
Energy Sales -- 22,613
Oil -- (4,430)
Financial Tolling -- 5,968
As of September 30, 2001, we had sold forward 1.1 million total megawatt hours for 2001 - 2002, which we expect will produce a net margin of $35.7 million. We have entered into these financial derivative contracts to hedge our exposure to the impact of price fluctuations related to the forward price of power. We also enter into derivative commodity instruments to hedge our exposure to the impact of price fluctuations on gas and oil prices. While these derivative instruments related to the price of gas and oil do not qualify for hedge treatment under generally accepted accounting principles, we believe they provide a strong economic hedge of this risk. All hedge transactions are subject to our risk management policy, which does not permit speculative or trading positions.
PART II.
Item 6. | OTHER INFORMATION.
Exhibits and Reports on Form 8-K. |
| | (b) | The Company filed a Current Report on Form 8-K reporting on Items 5 and 7 an event which occurred on September 26, 2001. |
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
| | ORION POWER HOLDINGS, INC.
By: /s/ Scott B. Helm
Scott B. Helm
Executive Vice President and Chief Financial Officer
(principal financial officer of registrant) |
Dated: November 14, 2001
