Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value.

Restricted Cash

Restricted cash consists primarily of the Utility's cash held in escrow pending the resolution of the remaining disputed claims made by electricity suppliers in the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code ("Chapter 11 Settlement Agreement"). (See Note 13 below.) Restricted cash also includes the cash collected from the Utility's electricity customers and remitted to PG&E Energy Recovery Funding LLC ("PERF") for payment of principal, interest, and miscellaneous expenses associated with the energy recovery bonds ("ERBs") issued by PERF. (See Note 5 below.)

Allowance for Doubtful Accounts Receivable

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.

Inventories

Inventories are carried at weighted-average cost. Inventories include natural gas stored underground, and materials and supplies. Natural gas stored underground represents purchases that are injected into inventory and then expensed at weighted average cost when withdrawn and distributed to customers or used in electric generation. Materials and supplies are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.

Property, Plant, and Equipment

Property, plant, and equipment are reported at their original cost. These original costs include labor and materials, construction overhead, and allowance for funds used during construction ("AFUDC"). The Utility's estimated useful lives and balances of its property, plant, and equipment were as follows:


	Estimated Useful	Balance at December 31,
(in millions, except estimated useful lives)	Lives (years)	2011			2010
Electricity generating facilities ⁽¹⁾	20 to 100	$	6,488		$	6,012
Electricity distribution facilities	10 to 55		22,395			20,991
Electricity transmission	25 to 70		6,968			6,505
Natural gas distribution facilities	24 to 53		7,832			7,443
Natural gas transportation and storage	5 to 48		4,099			3,939
Construction work in progress			1,770			1,384

Total property, plant, and equipment			49,552			46,274

Accumulated Depreciation			(15,898	)		(14,826	)

Net property, plant, and equipment		$	33,654		$	31,448

⁽¹⁾ Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.)

Depreciation

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment in a particular class of property. This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment. The Utility's composite depreciation rates were 3.67% in 2011, 3.38% in 2010, and 3.43% in 2009.

The useful lives of the Utility's property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.

AFUDC

AFUDC is a method used to compensate the Utility for the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC of $40 million and $87 million during 2011, $50 million and $110 million during 2010, and $44 million and $95 million during 2009, related to debt and equity, respectively.

Capitalized Software Costs

PG&E Corporation and the Utility capitalize costs incurred during the application development stage of internal use software projects to property, plant, and equipment. PG&E Corporation and the Utility amortize capitalized software costs ratably over the expected lives of the software, ranging from 5 to 15 years and commencing upon operational use. Capitalized software costs totaled $714 million at December 31, 2011 and $580 million at December 31, 2010, net of accumulated amortization of $480 million at December 31, 2011 and $386 million at December 31, 2010. Amortization expense for capitalized software was $138 million in 2011, $94 million in 2010, and $37 million in 2009. Amortization expense is estimated to be approximately $154 million annually for 2012 through 2016.

Regulation and Regulated Operations

As a regulated entity, the Utility's rates are designed to recover the costs of providing service. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods that the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future are recorded as regulatory liabilities.

The Utility records differences between customer billings and the Utility's authorized revenue requirements as a significant portion of recovery is independent, or "decoupled", from the volume of electricity and natural gas sales. The Utility also records differences between incurred costs and customer billings or authorized revenue meant to recover those costs. To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively. For further discussion, see "Revenue Recognition" and Note 3 below.

To the extent that portions of the Utility's operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Intangible Assets

Intangible assets primarily consist of hydroelectric facility licenses with terms ranging from 19 to 53 years. The gross carrying amount of intangible assets was $112 million at December 31, 2011 and 2010. The accumulated amortization was $47 million at December 31, 2011 and $44 million at December 31, 2010.

The Utility's amortization expense related to intangible assets was $3 million in 2011 and $4 million in 2010 and 2009. The estimated annual amortization expense for 2012 through 2016 based on the December 31, 2011 intangible assets balance is $3 million. Intangible assets are recorded to other noncurrent assets – other in the Consolidated Balance Sheets.

Asset Retirement Obligations

PG&E Corporation and the Utility record an ARO at discounted fair value in the period in which the obligation is incurred if the discounted fair value can be reasonably estimated. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period, the ARO is accreted to its present value, and the capitalized cost is depreciated over the useful life of the long-lived asset. PG&E Corporation and the Utility also record an ARO if a legal obligation to perform an asset removal exists and can be reasonably estimated, but performance is conditional upon a future event. The Utility recognizes timing differences between the recognition of costs and the costs recovered through the ratemaking process as regulatory assets or liabilities. (See Note 3 below). The Utility has an ARO primarily for its nuclear generation facilities, certain fossil fuel-fired generation facilities, and gas transmission system assets.

Detailed studies of the cost to decommission the Utility's nuclear power plants are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceedings conducted by the CPUC. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.

For GAAP purposes, the Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimated costs of decommissioning its nuclear power facilities and records this as an adjustment to the ARO liability on its Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $1.2 billion at December 31, 2011 and 2010. For regulatory purposes, the estimated undiscounted nuclear decommissioning cost for the Utility's nuclear power plants was approximately $2.3 billion at December 31, 2011 and 2010 (or approximately $4.4 billion in future dollars). These estimates are based on the 2009 decommissioning cost studies, prepared in accordance with CPUC requirements.

A reconciliation of the changes in the ARO liability is as follows:


(in millions)
ARO liability at December 31, 2009	$	1,593
Revision in estimated cash flows		(23	)
Accretion		93
Liabilities settled		(77	)

ARO liability at December 31, 2010		1,586

Revision in estimated cash flows		10
Accretion		100
Liabilities settled		(87	)

ARO liability at December 31, 2011	$	1,609

The Utility has identified the following AROs for which a reasonable estimate of fair value could not be made. As a result, the Utility has not recorded a liability related to these AROs:

•

Restoration of land to its pre-use condition under the terms of certain land rights agreements. Land rights, communications equipment leases, and substation facilities will be maintained for the foreseeable future, and therefore, the Utility cannot reasonably estimate the settlement date or range of settlement dates for the obligations associated with these assets;

•

Removal and proper disposal of lead-based paint contained in some Utility facilities. The Utility does not have information available that specifies which facilities contain lead-based paint and, therefore, cannot reasonably estimate the settlement date(s) associated with the obligations; and

•

Removal of certain communications equipment from leased property, and retirement activities associated with substation and certain hydroelectric facilities. The Utility will maintain and continue to operate its hydroelectric facilities until the operation of a facility becomes uneconomical. The operation of the majority of the Utility's hydroelectric facilities is currently, and for the foreseeable future, expected to be economically beneficial. Therefore, the settlement date cannot be determined at this time.

Impairment of Long-Lived Assets

PG&E Corporation and the Utility evaluate the carrying amounts of long-lived assets for impairment, based on projections of undiscounted future cash flows, whenever events occur or circumstances change that may affect the recoverability or the estimated life of long-lived assets. If this evaluation indicates that such cash flows are not expected to fully recover the assets, the assets are written down to their estimated fair value. No significant impairments were recorded in 2011, 2010, or 2009.

Gains and Losses on Debt Extinguishments

Gains and losses on debt extinguishments associated with regulated operations are deferred and amortized over the remaining original amortization period of the debt reacquired, consistent with recovery of costs through regulated rates. PG&E Corporation and the Utility recorded unamortized loss on debt extinguishments, net of gain, of $186 million and $204 million at December 31, 2011 and 2010, respectively. The amortization expense related to this loss was $18 million in 2011, $23 million in 2010, and $25 million in 2009. Deferred gains and losses on debt extinguishments are recorded to current assets – regulatory assets and other noncurrent assets – regulatory assets in the Consolidated Balance Sheets.

Gains and losses on debt extinguishments associated with unregulated operations are fully recognized at the time such debt is reacquired and are reported as a component of interest expense.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss reports a measure for accumulated changes in equity of an enterprise that result from transactions and other economic events, other than transactions with shareholders. The following table sets forth the after-tax changes in each component of PG&E Corporation's accumulated other comprehensive loss:


(in millions)	2011			2010			2009
Balance at beginning of year	$	(202	)	$	(160	)	$	(221	)

Period change in pension benefits and other benefits (Note 12):
Unrecognized prior service cost ⁽¹⁾		36			(29	)		(1	)
Unrecognized net gain (loss) ⁽²⁾		(655	)		(110	)		363
Unrecognized net transition obligation ⁽³⁾		15			15			15
Transfer to regulatory account ^{(4) (5)}		593			82			(316	)

Balance at end of year	$	(213	)	$	(202	)	$	(160	)

⁽¹⁾Net of income tax benefit (expense) of $(24) million, $20 million, and $1 million for December 31, 2011, 2010, and 2009, respectively.

⁽²⁾Net of income tax benefit (expense) of $452 million, $73 million, and $(216) million for December 31, 2011, 2010, and 2009, respectively.

⁽³⁾Net of income tax benefit (expense) of $(11) million for December 31, 2011, 2010, and 2009.

⁽⁴⁾Net of income tax benefit (expense) of $(408) million, $(57) million, and $218 million for December 31, 2011, 2010, and 2009, respectively.

⁽⁵⁾Amounts transferred to the pension regulatory asset are probable of recovery from customers in future rates.

There was no material difference between PG&E Corporation's and the Utility's accumulated other comprehensive income (loss) for the periods presented above.

Revenue Recognition

The Utility recognizes revenues after the CPUC or the FERC has authorized rate recovery, amounts are objectively determinable and probable of recovery, and amounts will be collected within 24 months. (See Note 3 below.) The Utility recognizes revenues as the electricity and natural gas services are delivered, and include amounts for services rendered but not yet billed at the end of the period.

The CPUC authorizes most of the Utility's revenue requirements in its general rate case ("GRC"), which generally occurs every three years. The Utility's ability to recover revenue requirements authorized by the CPUC in the GRC is independent, or "decoupled", from the volume of the Utility's sales of electricity and natural gas services. Generally, the revenue recognition criteria are met ratably over the year.

The CPUC also has authorized the Utility to collect additional revenue requirements to recover certain capital expenditures and costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; to fund public purpose, demand response, and customer energy efficiency programs. Generally, the revenue recognition criteria for pass through costs billed to customers are met at the time the costs are incurred.

The Utility's revenues and earnings also are affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets certain performance criteria.

The FERC authorizes the Utility's revenue requirements in annual transmission owner rate cases. The Utility's ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility's electricity sales, and revenue is recognized only for amounts billed and unbilled.

The Utility records differences between actual customer billings and the Utility's authorized revenue requirement, as well as differences between incurred costs and customer billings or authorized revenue meant to recover those costs. To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively.

In determining whether revenue transactions should be presented net of the related expenses, the Utility considers various factors, including whether the Utility takes title to the product being delivered, has latitude in establishing price for the product, and is subject to the customer credit risk.

Income Taxes

PG&E Corporation and the Utility use the liability method of accounting for income taxes. Income tax provision (benefit) includes current and deferred income taxes resulting from operations during the year. Investment tax credits are deferred and amortized to income over time. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period. (See Note 9 below.)

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. The difference between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.

PG&E Corporation files a consolidated U.S. federal income tax return that includes domestic subsidiaries in which its ownership is 80% or more. In addition, PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.

Nuclear Decommissioning Trusts

The Utility's nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.

The Utility classifies its investments held in the nuclear decommissioning trusts as "available-for-sale." As the Utility's nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility's earnings or accumulated other comprehensive income. The cost of debt and equity securities sold is determined by specific identification.

Accounting for Derivatives and Hedging Activities

Derivative instruments are recorded in PG&E Corporation's and the Utility's Consolidated Balance Sheets at fair value, unless they qualify for the normal purchase and sales exception. Changes in the fair value of derivative instruments are recorded in earnings or, to the extent that they are probable of future recovery through regulated rates, are deferred and recorded in regulatory accounts.

The normal purchase and sales exception to derivative accounting requires, among other things, physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business. Transactions for which the Utility elects the normal purchase and sales exception are not reflected in the Consolidated Balance Sheets at fair value. They are accounted for under the accrual method of accounting. Therefore, expenses are recognized as incurred.

PG&E Corporation and the Utility offset the cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement where the right of offset and the intention to offset exist. (See Note 10 below.)

Fair Value Measurements

PG&E Corporation and the Utility determine the fair value of certain assets and liabilities based on assumptions that market participants would use in pricing the assets or liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or the "exit price." PG&E Corporation and the Utility utilize a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value and give precedence to observable inputs in determining fair value. An instrument's level within the hierarchy is based on the lowest level of any significant input to the fair value measurement. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). (See Note 11 below.)

Variable Interest Entities

PG&E Corporation and the Utility evaluate whether any entities are a variable interest entity ("VIE") that could require consolidation. PG&E Corporation and the Utility use a qualitative approach to determine who has a controlling financial interest in a VIE and perform 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 that they 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 ownership or voting interests alone. These entities are referred to as VIEs. A VIE is an entity that 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 the obligation to absorb expected losses or receive expected gains that could potentially be significant to a VIE and the power to direct the activities that are most significant to a VIE's economic performance. An enterprise that has a controlling financial interest is known as the VIE's primary beneficiary and is required to consolidate the VIE.

Some of the counterparties to the Utility's power purchase agreements are considered VIEs. In determining whether the Utility has a controlling financial interest in a VIE, the Utility assesses whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns, as a result of power purchase agreements. This assessment includes an evaluation of how the risks and rewards associated with the power plant's activities are absorbed by variable interest holders as well as an analysis of the variability in the VIE's gross margin and the impact of power purchase agreements on the gross margin. For each variable interest, the Utility assesses whether it has the power to direct the activities of the power plant that most directly impact the VIE's economic performance.

The Utility held a variable interest in several entities that own power plants that generate electricity for sale to the Utility under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, and hydroelectric. Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE. The Utility did not provide any 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 15 below.) The Utility does not have the power to direct the activities that are most significant to these VIE's economic performance. This assessment considers any decision-making rights associated with designing the VIE, dispatch rights, operating and maintenance activities, and re-marketing activities of the power plant after the end of the power purchase agreement with the Utility. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at December 31, 2011, the Utility was not the primary beneficiary of, and did not consolidate, any of these VIEs.

The Utility continued to consolidate PERF at December 31, 2011, as the Utility is the primary beneficiary of PERF. In 2005, PERF was formed as a wholly owned subsidiary of the Utility to issue ERBs in connection with the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Chapter 11 Settlement Agreement. The Utility has a controlling financial interest in PERF since the Utility is exposed to PERF's losses and returns through the Utility's 100% equity investment in PERF and the Utility was involved in the design of PERF, which was an activity that was significant to PERF's economic performance. The assets of PERF were $485 million at December 31, 2011 and primarily consisted of assets related to ERBs, which are included in other current assets – regulatory assets in the Consolidated Balance Sheets. The liabilities of PERF were $423 million at December 31, 2011 and consisted of ERBs, which are included in current liabilities in the Consolidated Balance Sheets. (See Note 5 below.) The assets of PERF are only available to settle the liabilities of PERF.

As of December 31, 2011, PG&E Corporation's affiliates had entered into four tax equity agreements with two privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies. The majority of these amounts are recorded in other noncurrent assets – other in PG&E Corporation's Consolidated Balance Sheets. As of December 31, 2011, PG&E Corporation had made total payments of $359 million under these tax equity agreements and received $136 million in benefits and customer payments. PG&E Corporation holds a variable interest in these companies as a result of these agreements. PG&E Corporation was not the primary beneficiary of and did not consolidate any of these companies at December 31, 2011. In making this determination, PG&E Corporation evaluated which party has control over these companies' significant economic activities such as designing the companies, vendor selection, construction, customer selection, and re-marketing activities at the end of customer leases, and determined that these activities are under the control of these companies. PG&E Corporation's financial exposure from these arrangements is generally limited to its lease payments and investment contributions to these companies.

Accounting Standards Issued But Not Yet Adopted

Amendments to Fair Value Measurement Requirements

In May 2011, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that will clarify certain fair value measurement requirements. In addition, the accounting standards update will permit an entity to measure the fair value of a portfolio of financial instruments based on the portfolio's net position, provided that the portfolio has met certain criteria. Furthermore, the accounting standards update will refine when an entity should, and should not, apply certain premiums and discounts to a fair value measurement. The accounting standards update will be effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2012. The adoption of the accounting standards update will be reflected in footnote disclosures only and will not have an impact on PG&E Corporation's or the Utility's Consolidated Financial Statements.

Presentation of Comprehensive Income

In June 2011, the FASB issued an accounting standards update that will require an entity to present either (1) a statement of comprehensive income or loss or (2) a statement of other comprehensive income or loss. A statement of comprehensive income or loss would be comprised of a statement of income or loss with other comprehensive income and losses, total other comprehensive income or loss, and total comprehensive income or loss appended. A statement of other comprehensive income or loss would immediately follow a statement of income or loss and would be comprised of other comprehensive income and losses, total other comprehensive income or loss, and total comprehensive income or loss. Furthermore, the accounting standards update will prohibit an entity from presenting other comprehensive income and losses in a statement of equity.

In December 2011, the FASB issued an accounting standards update to defer the requirement for an entity to present reclassifications between other comprehensive income or loss and net income or loss. This supersedes the requirement that was originally included in the June 2011 accounting standard update.

The accounting standards updates will be effective retrospectively for PG&E Corporation and the Utility beginning on January 1, 2012. The adoption of the accounting standards updates will impact financial statement presentation with the addition of new statements of comprehensive income or loss.

Pacific Gas And Electric Company [Member]