Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

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”).  (See Note 13 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stored underground represents purchases that are recorded to inventory and then expensed at weighted average cost when withdrawn and distributed to customers or used in electric generation.  Materials and supplies are recorded 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)	2012		2011
Electricity generating facilities (1)	10 to 100	$	8,253	$	6,488
Electricity distribution facilities	10 to 55		23,767		22,395
Electricity transmission	10 to 70		7,681		6,968
Natural gas distribution facilities	20 to 53		8,257		7,832
Natural gas transportation and storage	5 to 48		4,314		4,099
Construction work in progress			1,894		1,770
Total property, plant, and equipment			54,166		49,552
Accumulated depreciation			(16,643)		(15,898)
Net property, plant, and equipment		$	37,523	$	33,654
(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 3.63% in 2012, 3.67% in 2011, and 3.38% in 2010.

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 $49 million and $107 million during 2012, $40 million and $87 million during 2011, and $50 million and $110 million during 2010, related to debt and equity, respectively.

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 in which 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's ability to recover the revenue requirements that have been authorized by the CPUC in a general rate case (“GRC”) and a gas transmission and storage rate case (“GT&S”) does not depend on the volume of the Utility's sales of electricity and natural gas services. The Utility's recovery of a significant portion of its authorized revenue requirements through rates is independent, or “decoupled,” from the volume of electricity and natural gas sales.  

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 and the differences do not have an impact on net income.  For further discussion, see “Revenue Recognition” 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 $110 million at December 31, 2012 and $112 million at December 31, 2011.  The accumulated amortization was $49 million at December 31, 2012 and $47 million at December 31, 2011.

The Utility's amortization expense related to intangible assets was $2 million in 2012, $3 million in 2011, and $4 million in 2010.  The estimated annual amortization expense for 2013 through 2017 based on the December 31, 2012 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.  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 generation facilities are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceedings (“NDCTP”) conducted by the CPUC.  In December 2012, the Utility submitted its updated decommissioning cost estimate with the CPUC.  The estimated undiscounted cost to decommission the Utility's nuclear power plants increased by $1.4 billion due to higher spent nuclear fuel disposal costs and an increase in the scope of work.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear generation facilities.  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.  The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.  A significant portion of the increase in decommissioning cost estimates is due to the need to develop on-site storage for spent nuclear fuel because the federal government has failed to meet its obligation to develop a permanent repository for the disposal of nuclear waste from nuclear facilities in the United States.  The Utility expects that it will recover its future on-site storage costs from the federal government.  The Utility already has recovered $266 million for spent nuclear fuel costs incurred through 2010. (See “Spent Nuclear Fuel Storage Proceedings” in Note 15 below).  Recovered amounts will be refunded to customers through rates.  In its 2012 NDCTP application, the Utility requested that the CPUC issue a final decision by the end of 2013.

The estimated undiscounted nuclear decommissioning cost for the Utility's nuclear generation facilities was approximately $3.5 billion at December 31, 2012 and $2.3 billion at December 31, 2011, as filed in the 2012 and 2009 NDCTPs, respectively.  In future dollars, the estimated nuclear decommissioning cost is approximately $6.1 billion and $4.4 billion, respectively.  These estimates are based on the 2012 and 2009 decommissioning cost studies, respectively, and are prepared in accordance with CPUC requirements.  The estimated nuclear decommissioning cost in future dollars is discounted for GAAP purposes and recognized as an ARO on the Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued in accordance with GAAP was $2.5 billion at December 31, 2012 and $1.2 billion at December 31, 2011.  

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

(in millions)
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
Revision in estimated cash flows		1,301
Accretion		101
Liabilities settled		(92)
ARO liability at December 31, 2012	$	2,919

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 will be maintained for the foreseeable future, and therefore, the Utility cannot reasonably estimate the settlement date(s) 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(s) cannot be reasonably estimated at this time.

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge to net income when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.  During 2012, the Utility recorded a $353 million charge to net income for capital expenditures incurred in connection with its pipeline safety enhancement plan that were either specifically disallowed or that are forecasted to exceed the CPUC's authorized levels.  (See “CPUC Gas Safety Rulemaking Proceeding” in Note 15 below).  No material disallowance losses were recorded in 2011 and $36 million in disallowance losses were recorded in 2010.

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 $163 million and $186 million at December 31, 2012 and 2011, respectively.  The amortization expense related to this loss was $23 million in 2012, $18 million in 2011, and $23 million in 2010.  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.

Revenue Recognition

The Utility recognizes revenues as electricity and natural gas services are delivered, and includes 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 GRC and its GT&S, which generally occur every three years.  The Utility's ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility's sales of electricity and natural gas services.  The Utility recognizes revenues once they have been authorized for rate recovery, amounts are objectively determinable and probable of recovery, and amounts will be collected within 24 months.  Generally, the revenue recognition criteria are met ratably over the year.  (See Note 3 below.)

The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and 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 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's revenues and net income also are affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets certain performance criteria.  

Income Taxes

PG&E Corporation and the Utility use the liability method of accounting for income taxes.  Income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period actual tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as depreciation, and are reported within the PG&E Corporation and Utility's balance sheets.  (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.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.  

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

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 generation facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility 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.”  Since 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 through rates.  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

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 which qualify for the normal purchase and sales exception are not reflected in the Consolidated Balance Sheets at fair value, but are accounted for under the accrual method of accounting.  Therefore, expenses are recognized as incurred.

PG&E Corporation and the Utility offset 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 are required to consolidate the financial results of any entities that they control.  In most cases, control can be determined based on majority ownership or voting interests.  However, there are certain entities known as variable interest entities (“VIEs”) for which control is difficult to discern based on ownership or voting interests alone.  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 in a VIE if it has the obligation to absorb expected losses or the right to receive expected gains that could potentially be significant to the VIE and if it has any decision-making rights associated with the activities that are most significant to the VIE's economic performance, including the power to design the VIE.  An enterprise that has a controlling financial interest in a VIE is known as the VIE's primary beneficiary and is required to consolidate the VIE.

In determining whether consolidation of a particular entity is required, PG&E Corporation and the Utility first evaluate whether the entity is a VIE.  If the entity is a VIE, PG&E Corporation and the Utility use a qualitative approach to determine if either is the primary beneficiary of the VIE.

Some of the counterparties to the Utility's power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility subject to the terms of a power purchase agreement.  In determining whether the Utility is the primary beneficiary of any of these VIEs, it assesses whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns under the terms of the power purchase agreement.  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 the power purchase agreement on the gross margin.  Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE.  The Utility does 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 any decision-making rights associated with the design of any VIEs, nor does the Utility have the power to direct the activities that are most significant to the economic performance of any VIEs such as dispatch rights, operating and maintenance activities, or re-marketing activities of the power plant after the termination of any VIE's power purchase agreement with the Utility.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2012, it did not consolidate any of them.

The Utility continued to consolidate the financial results of PG&E Energy Recovery Funding LLC (“PERF”), a VIE, at December 31, 2012, since the Utility is the primary beneficiary of PERF.  PERF was formed in 2005 as a wholly owned subsidiary of the Utility to issue energy recovery bonds (“ERBs”) in connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility's proceeding under Chapter 11 (“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.  PERF is expected to be dissolved in 2013.  (See Note 5 below.)  While PERF is a wholly owned consolidated 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 of PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.

At December 31, 2012, PG&E Corporation affiliates had entered into four tax equity agreements to fund residential and commercial retail solar energy installations with two privately held companies that are considered VIEs.  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.  At December 31, 2012, PG&E Corporation had made total payments of $361 million under these agreements and received $228 million in benefits and customer payments.  In determining whether  PG&E Corporation is the primary beneficiary of any of these VIEs, PG&E Corporation assesses which of the variable interest holders has control over these companies' significant economic activities, such as the design of the companies, vendor selection, construction, customer selection, and re-marketing activities after the termination of customer leases. PG&E Corporation determined that these companies control these activities, while its financial exposure from these agreements is generally limited to its lease payments and investment contributions to these companies.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs at December 31, 2012, it did not consolidate any of them.