(continued)
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.
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.
Financial Market Risks
Short-term investments As of June 30, 2001, we had short-term investments of $740.8 million. These short-term investments consist of highly liquid investments with maturities less than three months. We have the ability to hold these investments to maturity, and as a result, we would not expect the value of these investments to be affected to any significant degree by the effect of a sudden change in market interest rates.
Interest rate swaps From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations. We do not use interest rate swap agreements for speculative or trading purposes. The following table summarizes the fair market value of our existing interest rate swap agreements as of June 30, 2001 (dollars in thousands):
Notional Weighted
Principal Average Fair
Maturity Date Amount Interest Rate Market Value
------------- --------- ------------- ------------
2001................... $ 71,000 7.4% $ (72)
2007................... 38,150 8.0 (3,907)
2007................... 38,150 8.0 (3,889)
2007................... 29,757 7.9 (3,146)
2007................... 29,757 7.9 (3,131)
2009................... 15,000 6.9 (709)
2011................... 55,742 6.9 (2,611)
2012................... 120,078 6.5 (3,273)
2014................... 72,334 6.7 (2,815)
2015................... 22,500 7.0 (1,278)
2018................... 17,500 7.0 (1,055)
--------- ---- ---------
Total......... $ 509,968 7.1% $ (25,886)
========= ==== =========
Energy price fluctuations We enter into derivative commodity instruments to
reduce our exposure to the impact of price fluctuations, primarily electricity
and natural gas prices. All transactions are subject to our risk management
policy which prohibits positions that exceed production capacity and fuel
requirements. Derivative commodity instruments are accounted for under the
requirements of SFAS No. 133.
The fair value of outstanding derivative commodity instruments and the change in fair value that would be expected from a ten percent adverse price change are shown in the table below (in thousands):
Change in Fair
Value From
10% Adverse
Fair Value Price Change
---------- ------------
At June 30, 2001
Electricity................. $ 595,850 $ (204,773)
Natural gas................. (294,840) (105,763)
---------- ----------
Total................... $ 301,010 $ (310,536)
=========== ==========
Derivative commodity instruments included in the table are those included in
Note 3 to the Consolidated Condensed Financial Statements. The fair value of
derivative commodity instruments included in the table is based on present value
adjusted quoted market prices of comparable contracts. During the six months
ended June 30, 2001, significant electricity price volatility occurred in the
western United States. The fair value of derivative commodity instruments
includes the effect of increased power prices versus our forward sales
commitments. Derivative commodity instruments offset physical positions exposed
to the cash market. None of the offsetting physical positions are included in
the above table.
Price changes were calculated by assuming an across-the-board ten percent adverse price change regardless of term or historical relationship between the contract price of an instrument and the underlying commodity price. In the event of an actual ten percent change in prompt month prices, the fair value of Calpine's derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.
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Received by Edgar Online Aug 14, 2001 |
