PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY,
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
See accompanying Notes to the Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED BALANCE SHEETS
PACIFIC GAS AND ELECTRIC COMPANY
See accompanying Notes to the Condensed Consolidated Financial Statements.
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
See accompanying Notes to the Condensed Consolidated Financial Statements.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
PG&E Corporation is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). The Utility’s accounts for electric and gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.
This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. Therefore, the Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries, as well as, the accounts of variable interest entities (“VIEs”) for which the Utility is the primary beneficiary. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.
The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflect all adjustments that management believes are necessary for the fair presentation of their financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2009 in both PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets incorporated by reference into their combined 2009 Annual Report on Form 10-K filed on February 19, 2010. PG&E Corporation’s and the Utility’s combined 2009 Annual Report on Form 10-K, together with the information incorporated by reference into such report, is referred to in this quarterly report as the “2009 Annual Report.”
The significant accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report. Any significant changes to those policies or new significant policies are described in Note 2 below.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict. Some of the more critical estimates and assumptions relate to the Utility’s regulatory assets and liabilities, environmental remediation liability, asset retirement obligations (“ARO”), income tax-related assets and liabilities, pension plan and other postretirement plan obligations, and accruals for legal matters. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.
This quarterly report should be read in conjunction with PG&E Corporation’s and the Utility’s audited Consolidated Financial Statements and related notes included in the 2009 Annual Report.
Pension and Other Postretirement Benefits
PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees (referred to collectively as “pension benefits”), contributory postretirement medical plans for eligible employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility use a December 31 measurement date for all plans.
The net periodic benefit costs as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income as a component of Operating and maintenance for the three months ended March 31, 2010 and 2009 were as follows:
There was no material difference between PG&E Corporation’s and the Utility’s consolidated net periodic benefit costs for the three months ended March 31, 2010 and 2009.
On February 16, 2010, the Utility amended its defined benefit medical plans for retirees to provide for additional contributions towards retiree premiums. The plan amendment was accounted for as a plan modification that required re-measurement of the accumulated benefit obligation, plan assets, and periodic benefit costs. The inputs and assumptions used in re-measurement did not change significantly from December 31, 2009 and did not have a material impact on the funded status of the plans. The re-measurement of the accumulated benefit obligation and plan assets resulted in an increase to pension and other postretirement benefits and a decrease to other comprehensive loss of $148 million as of February 16, 2010. The impact to net periodic benefit cost for the three months ended March 31, 2010 was not significant.
Adoption of New Accounting Pronouncements
Consolidations (Topic 810) - Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities
On January 1, 2010, PG&E Corporation and the Utility adopted Accounting Standards Update (“ASU”) No. 2009-17, “Consolidations (Topic 810) - Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (“ASU No. 2009-17”). ASU No. 2009-17 amends the Consolidation Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) regarding when and how to determine, or re-determine, whether an entity is a VIE, which could require consolidation. In addition, ASU No. 2009-17 replaces the Consolidation Topic of the FASB ASC’s quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach. Furthermore, ASU No. 2009-17 requires ongoing assessments of whether an entity is the primary beneficiary of a VIE.
PG&E Corporation and the Utility are required to consolidate any entities which the companies control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on voting equity interests alone. These entities are referred to as VIEs. A VIE is an entity which does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has (1) the obligation to absorb expected losses or receive expected gains that could potentially be significant to the VIE and (2) the power to direct the activities that are most significant to the VIE’s economic performance. The enterprise that has a controlling financial interest is known as the VIE’s primary beneficiary and is the enterprise that will consolidate the VIE.
The Utility’s exposure to VIEs relates primarily to entities with which it has a power purchase agreement. When determining whether a controlling financial interest exists, the Utility must first assess whether it absorbs any of a VIE’s expected losses or receives portions of the expected residual returns as a result of the arrangement. This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders. Power plants typically are exposed to credit risk, production risk, commodity price risk, and any applicable tax incentive risks, among others. The Utility analyzes the variability in the VIE’s gross margin and the impact of the power purchase agreement on the gross margin to determine whether the Utility absorbs variability. Factors that may be considered when assessing the impact to the VIE’s gross margin include the pricing structure of the agreement and the cost of inputs and production, depending on the technology of the power plant.
For each variable interest, the Utility evaluates the activities of the power plant that most directly impact the VIE’s economic performance. The Utility’s assessment of the activities that are economically significant to the VIE’s performance often include decision making rights associated with designing the VIE, operating and maintenance activities, and re-marketing activities of the power plant after the end of its power purchase agreement with the Utility.
As of March 31, 2010, the Utility held a variable interest in VIEs as a result of power purchase agreements with entities that are single power plant owners of power plants. Each of these entities were designed to generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, hydroelectric, and other technologies. Under each of the power purchase agreements that represent a variable interest, the Utility is obligated to purchase electricity or capacity, or both, from the VIEs. The Utility does not provide any other financial or other support to these VIEs and the Utility’s financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 11 below for further discussion.) As of March 31, 2010, the Utility was not the primary beneficiary of any power plant VIEs.
The Utility continues to consolidate PG&E Energy Recovery Funding LLC (“PERF”) at March 31, 2010, as the Utility held a controlling financial interest and is the primary beneficiary. The Utility was the primary beneficiary as it was involved in the design of PERF and has exposure to losses and returns through its equity investment. The Utility consolidated PERF’s assets of $1.2 billion and liabilities of $1.1 billion (see Note 4 below for further discussion). The assets of PERF are only available to settle the liabilities of PERF.
The adoption of ASU 2009-17 did not have an impact on the Condensed Consolidated Financial Statements.
Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements
On January 1, 2010, PG&E Corporation and the Utility adopted ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements” (“ASU No. 2010-06”). ASU No. 2010-06 requires disclosures regarding (1) significant transfers into and out of Levels 1 and 2 of the fair value hierarchy and (2) fair value measurement inputs and valuation techniques. Furthermore, ASU No. 2010-06 requires presentation of disaggregated activity within the reconciliation for fair value measurements using significant unobservable inputs (Level 3), beginning in the first quarter of 2011. The adoption of ASU No. 2010-06 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.
Subsequent Events (Topic 855) - Amendments to Certain Recognition and Disclosure Requirements
On March 31, 2010, PG&E Corporation and the Utility adopted ASU No. 2010-09, “Subsequent Events (Topic 855) - Amendments to Certain Recognition and Disclosure Requirements” (“ASU No. 2010-09”). ASU No. 2010-09 does not significantly change the prior accounting for subsequent events but eliminates the requirement to disclose the date through which an SEC filer has evaluated subsequent events and the basis for that date. The adoption of ASU No. 2010-09 did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.
Current Regulatory Assets
At March 31, 2010 and December 31, 2009, the Utility had current regulatory assets of $568 million and $427 million, respectively, consisting primarily of the current portion of price risk management regulatory assets. Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms of one year or less. (See Note 7 below for further discussion.) Current regulatory assets are included in Prepaid expenses and other in the Condensed Consolidated Balance Sheets.
Long-Term Regulatory Assets
Long-term regulatory assets are composed of the following:
The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP, which also includes amounts that otherwise would be fully recorded to Accumulated other comprehensive loss in the Condensed Consolidated Balance Sheets. (See Note 13 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.)
The regulatory assets for deferred income taxes represent deferred income tax benefits previously passed through to customers offset by deferred income tax liabilities. The CPUC requires the Utility to pass through certain tax benefits to customers, ignoring the effect of deferred taxes on rates. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income taxes related to regulatory assets over periods ranging from 1 to 45 years.
The regulatory asset for energy recovery bonds (“ERBs”) represents the refinancing of the regulatory asset provided for in the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11 Settlement Agreement”). (See Note 4 below.) The regulatory asset is amortized over the life of the bonds consistent with the period over which the related billed revenues and bond-related expenses are recognized. The Utility expects to fully recover this asset by the end of 2012 when the ERBs mature.
In connection with the Chapter 11 Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. The weighted average remaining life of the assets is 15 years.
Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms in excess of one year. (See Note 7 below.)
The regulatory assets for environmental compliance costs represent the portion of estimated environmental remediation expense that the Utility expects to recover in future rates as actual remediation costs are incurred. The Utility expects to recover these costs over the next 30 years. (See Note 11 below.)
The regulatory assets for unamortized loss, net of gain, on reacquired debt represent costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the remaining original amortization period of the reacquired debt over the next 17 years, and these costs will be fully recovered by 2026.
At March 31, 2010 and December 31, 2009, “Other” consisted of regulatory assets relating to ARO expenses recorded in accordance with GAAP that are probable of future recovery through the ratemaking process, and removal costs associated with the replacement of the steam generators in the Utility’s two nuclear generating units at the Diablo Canyon Power Plant (“Diablo Canyon”), as approved by the CPUC for future recovery. “Other” also consisted of costs that the Utility incurred in terminating a 30-year power purchase agreement, which are being amortized and collected in rates through September 2014, as well as costs incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004.
In general, the Utility does not earn a return on regulatory assets in which the related costs do not accrue interest. Accordingly, the Utility earns a return only on the Utility’s retained generation regulatory assets; unamortized loss, net of gain, on reacquired debt; and regulatory assets associated with the plan of reorganization.
Current Regulatory Liabilities
At March 31, 2010 and December 31, 2009, the Utility had current regulatory liabilities of $138 million and $163 million, respectively, primarily consisting of the current portion of electric transmission wheeling revenue refunds and amounts that the Utility expects to refund to customers for over-collected electric transmission rates and the current portion of price risk management regulatory liabilities. Price risk management regulatory liabilities represent the deferral of unrealized gains related to price risk management derivative instruments with terms of one year or less. Current regulatory liabilities are included in Current Liabilities – Other in the Condensed Consolidated Balance Sheets.
Long-Term Regulatory Liabilities
Long-term regulatory liabilities are composed of the following:
The regulatory liability for the Utility’s cost of removal obligations represents differences between amounts collected in rates for asset removal costs and the asset removal costs recorded in accordance with GAAP.
The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs that are expected to be incurred in the future. For example, these regulatory liabilities include revenues collected from customers to pay for costs that the Utility expects to incur in the future under the California Solar Initiative to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties.
The regulatory liability for recoveries in excess of ARO represents differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the ARO expenses recorded in accordance with GAAP. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The regulatory liability for recoveries in excess of ARO also represents the deferral of realized and unrealized gains and losses on those nuclear decommissioning trust assets.
“Other” at March 31, 2010 and December 31, 2009 included the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year, the gain associated with the Utility’s acquisition of the permits and other assets related to the Gateway Generating Station as part of a settlement that the Utility entered with Mirant Corporation, as well as insurance recoveries for hazardous substance remediation.
Regulatory Balancing Accounts
The Utility uses regulatory balancing accounts to accumulate differences between actual billed and unbilled revenues and the Utility’s authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs and authorized revenue meant to recover those costs. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being refunded to customers are recorded as regulatory balancing account liabilities.
The Utility’s current regulatory balancing accounts represent the amounts expected to be received from or refunded to the Utility’s customers through authorized rate adjustments within the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next 12 months are included in Other Noncurrent Assets – Regulatory assets and Noncurrent Liabilities – Regulatory liabilities in the Condensed Consolidated Balance Sheets.
Current Regulatory Balancing Accounts, net
The utility generation balancing account is used to record and recover the authorized revenue requirements associated with Utility-owned electric generation, including capital and related non-fuel operating and maintenance expenses. The distribution revenue adjustment mechanism balancing account is used to record and recover the authorized electric distribution revenue requirements and certain other electric distribution-related authorized costs. The Utility’s recovery of these revenue requirements is independent, or “decoupled,” from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales. During periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales and lower rates. During the warmer months of summer, there is generally an over-collection due to higher rates and electric usage that cause an increase in generation revenues.
The public purpose programs balancing accounts primarily track the recovery of the authorized public purpose program revenue requirements, the actual costs of such programs, and incentive awards earned by the Utility for implementing customer energy efficiency programs. The public purpose programs primarily consist of the energy efficiency programs; low-income energy efficiency programs; research, development, and demonstration programs; and renewable energy programs.
The Utility is generally authorized to recover 100% of its prudently incurred electric fuel and energy procurement costs. The Utility tracks energy procurement costs in balancing accounts and files annual forecasts of energy procurement costs that it expects to incur during the following year. The Utility’s electric rates are set to recover such expected costs.
The gas fixed cost balancing account is used to track the recovery of CPUC-authorized gas distribution revenue requirements and certain other gas distribution-related costs. The under-collected or over-collected position of this account is dependent on seasonality and volatility in gas volumes.
The ERB balancing accounts record certain benefits and costs associated with ERBs that are provided to, or received from, customers. In addition, these accounts ensure that customers receive the benefits of the net amount of energy supplier refunds, claim offsets, and other credits received by the Utility after the second series of ERBs was issued.
At March 31, 2010 and December 31, 2009, “Other” included the California Department of Water Resources (“DWR”) power charge collection balancing account, which ensures amounts collected from customers for DWR-delivered power are remitted to the DWR; balancing accounts that track recovery of the authorized revenue requirements and costs related to the SmartMeterTM advanced metering project; and the transition access charge balancing account, which is used to pass through transmission high voltage access charges and credits.
On April 1, 2010, the Utility issued $250 million principal amount of 5.8% Senior Notes due March 1, 2037.
Pollution Control Bonds
On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution control bonds series 2010E due on November 1, 2026 and loaned the proceeds to the Utility. The proceeds were used to refund the corresponding related series of pollution control bonds issued in 2005 which were repurchased by the Utility in 2008. The series 2010E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to mandatory tender on April 2, 2012 at a price of 100% of the principal amount plus accrued interest. Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode.
Credit Facility and Short-Term Borrowings
At March 31, 2010, the Utility had $265 million of letters of credit outstanding under the Utility’s $1.94 billion revolving credit facility.
The revolving credit facility also provides liquidity support for commercial paper offerings. At March 31, 2010, the Utility had $751 million of commercial paper outstanding at an average yield of 0.31%.
Energy Recovery Bonds
In 2005, PERF, a wholly owned consolidated subsidiary of the Utility, issued two separate series of ERBs in the aggregate amount of $2.7 billion. The proceeds of the ERBs were used by PERF to purchase from the Utility the right, known as “recovery property,” to be paid a specified amount from a dedicated rate component to be collected from the Utility’s electricity customers. The total amount of ERB principal outstanding was $1.1 billion at March 31, 2010.
While PERF is a wholly owned subsidiary of the Utility, it is legally separate from the Utility. The assets, including the recovery property, of PERF are not available to creditors of the Utility or PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.
PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 2010 were as follows:
For the three months ended March 31, 2010, PG&E Corporation contributed equity of $20 million to the Utility in order to maintain the 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.
Comprehensive income consists of net income and accumulated other comprehensive income, which includes certain changes in equity that are excluded from net income. Specifically, cumulative adjustments for employee benefit plans, net of tax, are included in accumulated other comprehensive income.
During the three months ended March 31, 2010, PG&E Corporation paid common stock dividends totaling $157 million. On February 17, 2010, the Board of Directors of PG&E Corporation declared a dividend of $0.455 per share, totaling $169 million, which was paid on April 15, 2010 to shareholders of record on March 31, 2010.
During the three months ended March 31, 2010, the Utility paid common stock dividends totaling $179 million to PG&E Corporation.
During the three months ended March 31, 2010, the Utility paid dividends totaling $4 million to holders of its outstanding series of preferred stock. On February 17, 2010, the Board of Directors of the Utility declared a dividend totaling $3 million on its outstanding series of preferred stock, payable on May 15, 2010, to shareholders of record on April 30, 2010.
Earnings per common share (“EPS”) is calculated utilizing the “two-class” method, dividing the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average number of common shares outstanding during the period. In applying the two-class method, undistributed earnings are allocated to both common shares and participating securities. PG&E Corporation’s 9.50% Convertible Subordinated Notes are entitled to receive pass-through dividends and meet the criteria of participating securities. All of the participating securities participate in dividends on a 1:1 basis with shares of common stock.
The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating basic EPS:
In calculating diluted EPS, PG&E Corporation applies the “if-converted” method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS for three months ended March 31, 2010:
The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS for the three months ended March 31, 2009:
Securities that were antidilutive and excluded from the calculation of diluted shares outstanding were insignificant for the periods presented above.
Use of Derivative Instruments
The Utility faces market risk primarily related to electricity and natural gas commodity prices. All of the Utility’s risk management activities involving derivatives occur to reduce the volatility of commodity costs on behalf of its customers. The CPUC and the FERC allow the Utility to charge customer rates designed to recover the Utility’s reasonable costs of providing services, including the cost to obtain and deliver electricity and natural gas. As these costs are passed through to customers in rates, the Utility’s earnings are not exposed to the commodity price risk inherent in the purchase and sale of electricity and natural gas.
The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price risk, including:
These instruments are not held for speculative purposes and are subject to certain regulatory requirements.
Commodity-Related Price Risk
Commodity-related price risk management activities that meet the definition of a derivative are recorded at fair value on the Condensed Consolidated Balance Sheets. As long as the ratemaking mechanisms discussed above remain in place and the Utility’s risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from customers, in rates, all costs related to commodity-related price risk-related derivative instruments. Therefore, all unrealized gains and losses associated with the fair value of these derivative instruments are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses on derivative instruments related to price risk for commodities are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from customers.
The Utility elects the normal purchase and sale exception for qualifying commodity-related derivative instruments. Derivative instruments that require physical delivery, are probable of physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered are eligible for the normal purchase and sale exception. The fair value of instruments that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.
The following is a discussion of the Utility’s use of derivative instruments intended to mitigate commodity-related price risk for its customers.
The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under DWR contracts, and its own electricity generation facilities. The amount of electricity the Utility needs to meet the demands of customers and that is not satisfied from the Utility’s own generation facilities, existing purchase contracts, or DWR contracts allocated to the Utility’s customers is subject to change for a number of reasons, including:
The Utility enters into third-party power purchase agreements to ensure sufficient electricity to meet customer needs. The Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivative instruments. The Utility elects to use the normal purchase and sale exception for eligible derivative instruments.
A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce the cash flow variability associated with fluctuating electricity prices, the Utility has entered into financial swap contracts to effectively fix the price of future purchases under some of those power purchase agreements. These financial swaps are considered derivative instruments.
Electric Transmission Congestion Revenue Rights
The California Independent System Operator (“CAISO”)-controlled electricity transmission grid used by the Utility to transmit power is subject to transmission constraints. As a result, the Utility is subject to financial risk associated with the cost of transmission congestion. The CAISO implemented its new day-ahead wholesale electricity market as part of its Market Redesign and Technology Update on April 1, 2009. The CAISO created congestion revenue rights (“CRRs”) to allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the new day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants). CRRs are considered derivative instruments.
Natural Gas Procurement (Electric Portfolio)
The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through the Utility-owned natural gas generating facilities, tolling agreements, and natural gas-indexed electricity procurement contracts. In order to reduce the future cash flow variability associated with fluctuating natural gas prices, the Utility purchases financial instruments such as futures, swaps, and options. These financial instruments are considered derivative instruments.
Natural Gas Procurement (Small Commercial and Residential Customers)
The Utility enters into physical natural gas commodity contracts to fulfill the needs of its small commercial and residential, or “core,” customers. (The Utility does not procure natural gas for industrial and large commercial, or “non-core,” customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot markets to balance such seasonal supply and demand.
At March 31, 2010, PG&E Corporation had $247 million of Convertible Subordinated Notes outstanding that will mature on June 30, 2010. The holders of the Convertible Subordinated Notes are entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion prices. The dividend participation rights associated with the Convertible Subordinated Notes are embedded derivative instruments and, therefore, must be bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements. Changes in fair value of the dividend participation rights are recognized in PG&E Corporation’s Condensed Consolidated Statements of Income as non-operating expense or income (in Other (expense) income, net).
Volume of Derivative Activity
At March 31, 2010, the volume of PG&E Corporation’s and the Utility’s outstanding derivative contracts was as follows:
Presentation of Derivative Instruments in the Financial Statements
In PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets, derivative instruments are presented on a net basis by counterparty where the right of offset exists. The net balances include outstanding cash collateral associated with derivative positions.
At March 31, 2010, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:
At December 31, 2009, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:
Expenses related to the dividend participation rights are not recoverable in customers’ rates. Therefore, changes in the fair value of these instruments are recorded in PG&E Corporation’s Condensed Consolidated Statements of Income.
Gains and losses recorded on PG&E Corporation’s and the Utility’s derivative instruments were as follows:
Cash inflows and outflows associated with the settlement of all derivative instruments are recognized in operating cash flows on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Cash Flows.
The majority of the Utility’s commodity risk-related derivative instruments contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.
At March 31, 2010, the additional cash collateral the Utility would be required to post if its credit-risk-related contingent features were triggered was as follows:
PG&E Corporation and the Utility measure their cash equivalents, trust assets, dividend participation rights, and price risk management instruments at fair value. Fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability. A three-tier fair value hierarchy is established as a basis for considering such assumptions and for inputs used in the valuation methodologies in measuring fair value:
Level 1—Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2—Include other inputs that are directly or indirectly observable in the marketplace.
Level 3—Unobservable inputs which are supported by little or no market activities.
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. (See Note 12 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report for further discussion of fair value measurements.)
Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (money market investments, rabbi trusts, and dividend participation rights are held by PG&E Corporation and not the Utility):