Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2013

Summary Of Significant Accounting Policies [Abstract]

Cash And Cash Equivalents

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

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.  (See Note 12 below.)  

Allowance For Doubtful Accounts Receivable

Allowance for Doubtful Accounts Receivable

Accounts receivable are primarily composed of trade receivables and unbilled revenue.  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

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground represents gas that is recorded to inventory when purchased and then expensed as the gas is withdrawn for distribution  to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.

      The Utility also purchases greenhouse gas emission allowances that are recorded as inventory. They are carried at weighted average cost and included in Other Noncurrent Assets - Other in the Consolidated Balance Sheets.  The costs of the greenhouse gas emissions are expensed and recoverable through rates.

Property, Plant, And Equipment

Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.) The Utility's total 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)	2013			2012
Electricity generating facilities (1)	20 to 100	$	9,116		$	8,253
Electricity distribution facilities	10 to 55		25,333			23,767
Electricity transmission	10 to 70		8,429			7,681
Natural gas distribution facilities	20 to 53		9,117			8,257
Natural gas transportation and storage	5 to 65		5,265			4,314
Construction work in progress			1,834			1,894
Total property, plant, and equipment			59,094			54,166
Accumulated depreciation			(17,843	)		(16,643	)
Net property, plant, and equipment		$	41,251		$	37,523

 ⁽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 14 below.)

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 balance 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 3.51% in 2013, 3.63% in 2012, and 3.67% in 2011.  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

AFUDC represents the estimated costs 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 related to debt and equity, respectively, of $47 million and $101 million during 2013, $49 million and $107 million during 2012, and $40 million and $87 million during 2011.

Regulation And Regulated Operations

Regulation and Regulated Operations

As a regulated entity, the Utility collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility's costs of service.  The Utility's ability to recover a significant portion of its authorized revenue requirements through rates is independent, or “decoupled,” from the volume of the Utility's electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  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.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between actual customer billings and authorized revenue requirements that are probable of recovery or refund.  These differences do not have an impact on net income.  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, and the differences do not have an impact on net income.  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.  

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.

Asset Retirement Obligations

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.  

For the year ended December 31, 2013, the Utility recorded an increase of $596 million to its ARO. The increase primarily reflects a higher expected cost per unit of transmission pipeline replacements.

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 Proceeding 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 in 2012 due to higher spent nuclear fuel disposal costs and an increase in the scope of work.  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. Recovered amounts will be refunded to customers through rates.

The estimated undiscounted nuclear decommissioning cost for the Utility's nuclear generation facilities was approximately $3.5 billion at December 31, 2013 and 2012, as filed in the 2012 NDCTP.  In future dollars, the estimated nuclear decommissioning cost is approximately $6.1 billion at December 31, 2013 and 2012.  These estimates are based on the 2012 decommissioning cost studies 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, 2013 and 2012.  

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

(in millions)
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
Revision in estimated cash flows		596
Accretion		130
Liabilities settled		(107	)
ARO liability at December 31, 2013	$	3,538

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

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge 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 2013 and 2012, the Utility recorded charges of $196 million and $353 million, respectively, for PSEP capital costs that are expected to exceed the CPUC's authorized levels or that are specifically disallowed.  (See “Natural Gas Matters” in Note 14 below).  No material disallowance losses were recorded in 2011.

Gains And Losses On Debt Extinguishments

Gains and Losses on Debt Extinguishments

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 regulated operations are deferred and amortized over a period consistent with the recovery of costs through regulated rates.  PG&E Corporation and the Utility recorded unamortized loss on debt extinguishments, net of gain, of $157 million, $163 million, and $186 million at December 31, 2013, 2012, and 2011, respectively.  The amortization expense related to this loss was $23 million in both 2013 and 2012, and $18 million in 2011.  

Revenue Recognition

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 revenues in the Utility's GRC and its GT&S rate cases, which generally occur every three years.  In general, 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 are expected to be collected within 24 months.  Generally, the revenue is recognized ratably over the year. 

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 periodic (often annual) TO 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 can be affected by incentive ratemaking mechanisms that adjust rates depending on the extent to which the Utility meets certain performance criteria. 

Income Taxes

Income Taxes

PG&E Corporation and the Utility use the liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period 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 those arising from depreciation expense.  (See Note 8 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 the Utility and domestic subsidiaries in which its ownership is 80% or more.  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

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 by the trust is determined by specific identification.

Variable Interest Entities

Variable Interest Entities

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 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.  To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2013, it assessed 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, analyzed the variability in the VIE's gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE's performance, such as dispatch rights and operating and maintenance activities.  The Utility's financial exposure is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2013, it did not consolidate any of them.

PG&E Corporation affiliates have entered into four tax equity agreements to fund residential and commercial retail solar energy installations with four separate privately held funds that are considered VIEs.  Under these agreements, PG&E Corporation has made cumulative lease payments and investment contributions of $362 million from 2010 to 2013 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.  At December 31, 2013 and 2012, the carrying amount of PG&E Corporation's investment in these agreements was $98 million and $166 million, respectively.  PG&E Corporation has no material remaining commitment to fund these agreements.  PG&E Corporation determined that it does not have control over the companies' significant economic activities, such as the design of the companies, vendor selection, construction, and the ongoing operations of the companies.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs at December 31, 2013, it did not consolidate any of them.