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On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March 2001 Decision") proposing to change, on a prospective basis, the composition of the short run avoided cost ("SRAC") energy price formula, which is reset monthly, used by the California utilities in QF contracts. Prior to the March 2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50% Malin border gas indices. In the March 2001 Decision, the CPUC changed this formulation to eliminate the prices at Topock from the SRAC formula. The March 2001 Decision is subject to challenges at the CPUC and the Federal Energy Regulatory Commission.
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the "June 2001 Decision") that authorized the California utilities, including PG&E, to amend QF contracts to elect a fixed energy price component that averages 5.37 cents per kilowatt-hour for a five-year term under those contracts in lieu of using the SRAC energy price formula. By this order, the CPUC authorized the QF contract energy price amendments without further CPUC concurrence. As part of the agreement we entered into with PG&E pursuant to which PG&E agreed to assume its QF contracts with us in bankruptcy, PG&E agreed with us to amend these contracts to adopt the fixed price component that averages 5.37 cents pursuant to the June 2001 Decision. This election became effective as of July 16, 2001. As a result of the June 2001 Decision and our agreement with PG&E to amend the QF contracts to adopt the fixed price energy component, the energy price component in our QF contracts is now fixed for five years and we are no longer subject to any uncertainty that may have existed with respect to this component of our QF contract pricing as a result of the March 2001 Decision. Further, the March 2001 Decision has no bearing on PG&E's agreement with us to assume the QF contracts in bankruptcy or on the amount of the receivable that was so assumed.
California Long-Term Supply Contracts California has adopted legislation permitting it to issue long-term revenue bonds to provide funding for wholesale purchases of power. The bonds will be repaid with the proceeds of payments by retail customers over time. The California Department of Water Resources ("DWR") sought bids for long-term power supply contracts in a publicly announced auction. Calpine successfully bid in that auction and signed several long-term power supply contracts with DWR.
On February 7, 2001, we announced the signing of a 10-year, $4.6 billion fixed-price contract with DWR to provide electricity to the State of California. We committed to sell up to 1,000 megawatts of electricity, with initial deliveries of 200 megawatts starting October 1, 2001, which increases to 1,000 megawatts by January 1, 2004. The electricity will be sold directly to DWR on a 24 hours-a-day, 7 days-a-week basis. This contract is contingent upon our satisfaction, in our sole discretion, that adequate provisions have been made by DWR to assure us of full payment under the terms of the contract (including, but not limited to, the terms and conditions of any bonds issued by DWR to provide funds for payment of its obligations under the contract).
On February 28, 2001, we announced the signing of two long-term power sales contracts with DWR. Under the terms of the first contract, a 10-year, $5.2 billion fixed-price contract, we committed to sell up to 1,000 megawatts of generation. Initial deliveries began July 1, 2001, with 200 megawatts and increase to 1,000 megawatts by as early as July 2002. Under the terms of the second contract, a 20-year contract totaling up to $3.1 billion, we will supply DWR with up to 495 megawatts of peaking generation, beginning with 90 megawatts as early as August 2001, and increasing up to 495 megawatts as early as August 2002. Each of these contracts is also contingent upon our satisfaction, in our sole discretion, that adequate provisions have been made by DWR to assure us of full payment under the terms of that contract (including, but not limited to, the terms and conditions of any bonds issued by DWR to provide funds for payment of its obligations under that contract).
FERC Investigation into California Wholesale Markets On June 19, 2001, FERC ordered price mitigation in 11 states in the western United States in an attempt to reduce the dependence of the California market on spot markets in favor of longer-term committed energy supplies. The order provides for price mitigation in the spot market throughout the 11 state western region during "reserve deficiency hours," which is when operating reserves in California fall below seven percent. This price will be a single market clearing price based upon the marginal operating cost of the last unit dispatched by the California ISO. In addition, FERC implemented price mitigation in non-reserve deficiency hours, which will be set at 85% of the market clearing price during the last reserve deficiency period. These price mitigation procedures went into effect on June 20, 2001, and will remain in effect until September 30, 2002.
FERC also ordered all sellers and buyers in wholesale power markets administered by the California ISO, as well as representatives of the State of California, to participate in a settlement conference before a FERC administrative judge. The settlement discussions were intended to resolve all issues that remain outstanding to resolve past accounts, including sellers' claims for unpaid invoices, and buyers' claims for refunds of alleged overcharges, for past periods. The settlement discussions began on June 25, 2001, and ended on July 9, 2001. The Chief Administrative Law Judge issued his report and recommendations to FERC on July 12, 2001. On July 25, 2001, FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California. The hearing must be completed within 45 days from the date the California ISO provides certain critical data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. While it is not possible to predict the amount of any refunds until the hearing takes place, based upon the information available at this time, we do not believe that this proceeding will result in a material adverse effect on Calpine's financial condition or results of operations.
Selected Operating Information
Set forth below is certain selected operating information for our power plants and steam fields, for which results are consolidated in our statements of operations. Results vary for the three and six months ended June 30, 2001, respectively, as compared to the same periods in 2000, primarily due to the consolidation of acquisitions, favorable energy pricing, and increased production. Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity revenue includes, besides traditional capacity payments, other revenues such as reliability must run and ancillary service revenues. The information set forth under thermal and other revenue consists of host thermal sales and other revenue.
Three Months Ended June 30, Six Months Ended June 30,
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2001 2000 2001 2000
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Electricity and steam ("E & S") revenues:
Energy (1) ............................... $ 354,366 $ 199,950 $ 806,552 $ 325,329
Capacity ................................. $ 147,064 $ 89,318 $ 245,323 $ 144,802
Thermal and other ........................ $ 32,157 $ 20,738 $ 74,205 $ 34,696
Megawatt hours produced ..................... 7,877,505 4,678,000 15,116,704 9,059,189
Average energy price per megawatt hour ...... $ 44.98 $ 42.74 $ 53.36 $ 35.91
(1) Includes spread on sales of purchased power.
Megawatt hours produced at the power plants increased 68% and 67% for the three and six months ended June 30, 2001, as compared to the same periods in 2000. This was primarily due to the addition of power plants that were either acquired or commenced commercial operation subsequent to June 30, 2000.
Results of Operations
Three Months Ended June 30, 2001, Compared to Three Months Ended June 30, 2000
Revenue Total revenue increased to $1,612.9 million for the three months ended June 30, 2001, compared to $417.2 million for the same period in 2000.
Electric generation and marketing revenue increased 268% to $1,257.3 million in 2001 compared to $341.6 million in 2000. Approximately $192.9 million of the $915.7 million variance was due to electricity and steam sales, which increased due to our growing portfolio and favorable energy pricing. Our revenue for the period ended June 30, 2001, includes the consolidated results of fourteen additional facilities that we acquired or completed construction on subsequent to June 30, 2000. Our power marketing revenue (sales of purchased power) grew by $654.2 million due to increased price hedging and optimization activity during the three months ended June 30, 2001. We also recognized $68.4 million in mark-to-market gains on power derivatives.
Oil and gas production and marketing revenue increased to $343.0 million in 2001 compared to $69.7 million in 2000. The majority of the increase is due to marketing activities relating to purchased gas sold to third parties in hedging, balancing and related transactions. Additionally, approximately $54.4 million of the variance relates to increased production and commodity prices from sales to third parties from our reserves in Canada and in the United States.
Income from unconsolidated investments in power projects decreased to $1.6 million in 2001 compared to $4.8 million during 2000. The variance is primarily due to the contractual reduction in distributions from the Sumas Power Plant of approximately $2.6 million.
Other revenue increased to $10.9 million in 2001 compared to $1.1 million in 2000. This increase is due primarily to $4.8 million recognized in 2001 from our custom turbine parts manufacturing subsidiary, Power Systems Mfg., LLC, which was acquired in December 2000, and $2.8 million in interest income on loans to power projects.
Cost of revenue Cost of revenue increased to $1,308.6 million in 2001 compared to $270.5 million in 2000. Approximately $623.7 million of the $1,038.1 million increase relates to the cost of power purchased by our energy services organization. Similarly, oil and gas production and marketing expense grew by $220.5 million, largely due to $218.3 million of expense for the cost of gas purchased by the energy services organization, compared to $7.5 million in the second quarter of 2000. Fuel expense increased 120%, from $104.0 million in 2000 to $228.4 million in 2001, due to a 68% increase in megawatt hours generated and increased fuel price. Depreciation expense increased by 42%, from $50.7 million in the second quarter of 2000 to $72.1 million in the second quarter of 2001, due to fourteen additional power facilities in consolidated operations at June 30, 2001, as compared to the same period in 2000, and due to $14.4 million in higher depreciation and depletion in our oil and gas operating subsidiaries. Operating lease expense increased by $16.8 million due to leases entered into or acquired in connection with our Pasadena, Tiverton, Rumford, and KIAC facilities, all of which were either entered into during or after the second quarter of 2000.
General and administrative expense General and administrative expense increased 173% to $50.5 million for the three months ended June 30, 2001, as compared to $18.5 million for the same period in 2000. The increase was attributable to continued growth in personnel and associated overhead costs necessary to support the overall growth in our operations and due to recent acquisitions, including power facilities and natural gas operations.
Nonrecurring merger costs We incurred approximately $35.6 million in the three months ended June 30, 2001, in connection with the merger with Encal Energy Limited on April 19, 2001. The transaction was accounted for under the pooling-of-interests method and, accordingly, all transaction costs have been expensed as incurred and all periods presented have been restated to reflect the transaction.
Interest expense Interest expense increased 138% to $43.3 million for the three months ended June 30, 2001, from $18.2 million for the same period in 2000. Interest expense increased primarily due to the issuances of $1.15 billion of Senior Notes Due 2011 in February 2001 and of $1.5 billion of Energy Finance Senior Notes Due 2008 in April 2001. The associated incremental interest expense was partially offset by interest capitalized in connection with our growing construction portfolio.
Distributions on trust preferred securities Distributions on trust preferred securities increased 69% to $15.4 million for the three months ended June 30, 2001, compared to $9.1 million for the corresponding months in 2000. The increase is attributable to the issuance of additional trust preferred securities in August 2000.
Interest income Interest income increased to $20.5 million for the three months ended June 30, 2001, compared to $5.6 million for the same period in 2000. This increase is due to the significantly higher cash balances that we have maintained, primarily from senior notes issuances and the issuance of our convertible securities in April 2001.
Other income Other income increased to $3.3 million in 2001 from $(0.2) million in 2000 primarily due to foreign currency gains relating to Encal debt that was repaid during the quarter.
Provision for income taxes The effective income tax rate was approximately 39.1% and 41.1% for the three months ended June 30, 2001 and 2000, respectively. The decrease in rates was due to the lower contribution of Canadian operations (which are subject to higher statutory tax rates) due partially to the recognition of nonrecurring merger costs.
Extraordinary charge, net The $1.3 million charge relating to write off of unamortized deferred financing costs was a result of the repayment of $105 million 9 1/4% Senior Notes Due 2004.
Six Months Ended June 30, 2001, Compared to Six Months Ended June 30, 2000
Revenue Total revenue increased to $2,952.6 million for the six months ended June 30, 2001, compared to $702.4 million for the same period in 2000.
Electric generation and marketing revenue increased to $2,307.4 million in 2001 compared to $547.7 million in 2000. Approximately $594.3 million of the $1,759.7 million variance was due to electricity and steam sales, which increased due to our growing portfolio and favorable energy pricing. Our revenue for the period ended June 30, 2001, includes the consolidated results of fourteen additional facilities that we acquired or completed construction on subsequent to June 30, 2000. Our power marketing activities contributed an additional $1,095.7 million due to increased price hedging and optimization activity during the six months ended June 30, 2001. We also recognized $69.7 million in mark-to-market gains on power derivatives.
Oil and gas production and marketing revenue increased to $628.9 million in 2001 compared to $136.6 million in 2000. Approximately $339.5 million of the increase is due to marketing activities relating to purchased gas sold to third parties in hedging, balancing and related transactions. Additionally, approximately $152.7 million of the variance relates to increased production and commodity prices in sales to third parties from reserves acquired in Canada and in the United States.
Income from unconsolidated investments in power projects decreased to $2.2 million in 2001 compared to $14.6 million during 2000. The variance is primarily due to the contractual reduction in distributions from the Sumas Power Plant of approximately $9.7 million.
Other revenue increased to $14.2 million in 2001 compared to $3.4 million in 2000. This increase is due primarily to $6.4 million recognized in 2001 from our custom turbine parts manufacturing subsidiary, Power Systems Mfg., LLC, and a $2.8 million increase in interest income on loans to power projects.
Cost of revenue Cost of revenue increased to $2,372.8 million in 2001 compared to $484.6 million in 2000. Approximately $1,068.7 million of the $1,888.2 million increase relates to the cost of power purchased by our energy services organization. Similarly, oil and gas production and marketing expense grew by $343.0 million, largely due to a $321.7 million increase in expense for the cost of gas purchased and resold by the energy services organization. Fuel expense increased 173%, from $177.7 million in 2000 to $485.4 million in 2001, due to a 67% increase in megawatt hours generated and a significant increase in fuel price. Depreciation expense increased by 51%, from $95.8 million in the first six months of 2000 to $144.2 million in the first six months of 2001, due to additional power facilities in operation in 2001 and due to $30.2 million in higher depreciation and depletion in our oil and gas operating subsidiaries. Operating lease expense increased by $34.3 million due to leases entered into or acquired in connection with our Pasadena, Tiverton, Rumford, and KIAC facilities during and subsequent to the period ended June 30, 2000.
General and administrative expense General and administrative expense increased 202% to $86.6 million for the six months ended June 30, 2001, as compared to $28.7 million for the same period in 2000. The increase was attributable to continued growth in personnel and associated overhead costs necessary to support the overall growth in our operations and due to recent acquisitions, including power facilities and natural gas operations.
Nonrecurring merger costs We incurred approximately $41.6 million in the six months ended June 30, 2001, in connection with the merger with Encal Energy Limited on April 19, 2001. The transaction was accounted for under the pooling-of-interests method and, accordingly, all transaction costs have been expensed as incurred and all periods presented have been restated to reflect the transaction.
Interest expense Interest expense increased 58% to $63.3 million for the six months ended June 30, 2001, from $40.0 million for the same period in 2000. Interest expense increased primarily due to the issuances of $1.15 billion of Senior Notes Due 2011 in February 2001 and of $1.5 billion of Energy Finance Senior Notes Due 2008 in April 2000. The associated incremental interest expense was partially offset by interest capitalized in connection with our growing construction portfolio.
Distributions on trust preferred securities Distributions on trust preferred securities increased 90% to $30.6 million for the first six months in 2001 compared to $16.1 million for the corresponding months in 2000. The increase is attributable to the issuance of additional trust preferred securities in August 2000, as well as a full period of distributions on the January 2000 offering and the subsequent exercise of the purchasers' option to purchase additional securities.
Interest income Interest income increased to $39.9 million for the six months ended June 30, 2001, compared to $13.2 million for the same period in 2000. This increase is due primarily to the significantly higher cash balances that we have maintained as a result of our senior notes and convertible securities offerings during the second quarter of 2001.
Other income Other income increased to $9.0 million in 2001 from $0.4 million in 2000 primarily due to a gain on the sale of our interests in the Elwood development project and the Bayonne facility and related contingent income recognized as earned thereafter.
Provision for income taxes The effective income tax rate was approximately 41.1% and 41.2% for the six months ended June 30, 2001 and 2000, respectively.
Extraordinary charge, net The $1.3 million charge was a result of writing off unamortized deferred financing costs related to the repayment of $105 million 9 1/4% Senior Notes Due 2004.
Cumulative effect of a change in accounting principle The $1.0 million of additional income, net of tax, is due to the adoption of Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," amended by SFAS No. 137 and SFAS No. 138 ("SFAS No. 133").
Liquidity and Capital Resources
To date, we have obtained cash from our operations; borrowings under our credit facilities and other working capital lines; sales of debt, equity, trust preferred securities and convertible debentures; and proceeds from project financing. We utilized this cash to fund our operations, service debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures and meet our other cash and liquidity needs.
Outlook
Our strategy is to continue our rapid growth by capitalizing on the significant opportunities in the power industry, primarily through our active development and acquisition programs. In pursuing our proven growth strategy, we utilize our extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach uses our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations, risk management and power marketing, which we believe provides us with a competitive advantage. The key elements of our strategy are as follows:
Development of new and expansion of existing power plants We are actively pursuing the development of new and expansion of both baseload and peaking capacity at our existing highly efficient, low-cost, gas-fired power plants that replace old and inefficient generating facilities and meet the demand for new generation. Our strategy is to develop power plants in strategic geographic locations that enable us to leverage existing power generation assets and operate the power plants as integrated electric generation systems. This allows us to achieve significant operating synergies and efficiencies in fuel procurement, power marketing and operation and maintenance.
At August 13, 2001, we had 27 projects under construction, representing an additional 14,932 megawatts of net capacity. Included in these 27 projects are 4 project expansions, representing 735 megawatts of net capacity. We have also announced plans to develop 29 additional power generation projects, representing a net capacity of 16,618 megawatts. Included in these 29 development projects are 5 expansion projects representing 592 megawatts.
Acquisition of power plants Our strategy is to acquire power generating facilities that meet our stringent acquisition criteria and provide significant potential for revenue, cash flow and earnings growth, and that provide the opportunity to enhance the operating efficiencies of the plants. We have significantly expanded and diversified our project portfolio through numerous acquisitions of power generation facilities.
Enhance the performance and efficiency of existing power projects We continually seek to maximize the power generation potential of our operating assets and minimize our operation and maintenance expense and fuel cost. This will become even more significant as our portfolio of power generation facilities expands to 81 power plants with a net capacity of 24,558 megawatts, after completion of our projects currently under construction. We focus on operating our plants as an integrated system of power generation, which enables us to minimize costs and maximize operating efficiencies. We believe that achieving and maintaining a low cost of production will be increasingly important to compete effectively in the power generation industry.
Risk Factors
CPUC Proceedings Regarding QF Contract Pricing Our QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility "avoided cost" to be used to set energy payments for certain QF contracts, including those for all of our QF plants in California which sell power to PG&E. Section 390 of the California Public Utility Code provides QFs the option to elect to receive energy payments based on the PX market clearing price. In mid-2000, our QF facilities elected this option and were paid based upon the PX Price from summer 2000 until January 19, 2001, when the PX ceased operating a day ahead market. Since that time, the CPUC has ordered that the price to be paid for energy deliveries by QFs electing the PX Price shall be based on a natural gas cost-based "transition formula." The CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC has issued a proposed decision to the effect that the PX price was the appropriate price for energy payments under the California Public Utility Code. However, a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. We believe that the PX Price was the appropriate price for energy payments but there can be no assurance that this will be the outcome of the CPUC proceedings.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March 2001 Decision") proposing to change, on a prospective basis, the composition of the short run avoided cost ("SRAC") energy price formula, which is reset monthly, used by the California utilities in QF contracts. Prior to the March 2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50% Malin border gas indices. In the March 2001 Decision, the CPUC changed this formulation to eliminate the prices at Topock from the SRAC formula. The March 2001 Decision is subject to challenges at the CPUC and the Federal Energy Regulatory Commission.
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