DEI_Document
DEI Document (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Feb. 10, 2015 | Jun. 30, 2014 | |
Entity Information [Line Items] | |||
Entity Registrant Name | PORTLAND GENERAL ELECTRIC CO /OR/ | ||
Entity Central Index Key | 784977 | ||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Amendment Flag | FALSE | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 78,228,827 | ||
Entity Public Float | $2,699,904,749 | ||
Trading Symbol | POR |
Consolidated_Statements_of_Inc
Consolidated Statements of Income (USD $) | 12 Months Ended | ||
In Millions, except Share data in Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues, net | $1,900 | $1,810 | $1,805 |
Operating expenses: | |||
Purchased power and fuel | 713 | 757 | 726 |
Generation, transmission and distribution | 257 | 225 | 211 |
Cascade Crossing transmission project | 0 | 52 | 0 |
Administrative and other | 227 | 219 | 216 |
Depreciation and amortization | 301 | 248 | 248 |
Taxes other than income taxes | 109 | 103 | 102 |
Total operating expenses | 1,607 | 1,604 | 1,503 |
Income from operations | 293 | 206 | 302 |
Interest expense, net | 96 | 101 | 108 |
Other income: | |||
Allowance for equity funds used during construction | 37 | 13 | 6 |
Miscellaneous income, net | 1 | 7 | 4 |
Other income, net | 38 | 20 | 10 |
Income before income taxes | 235 | 125 | 204 |
Income tax expense | 61 | 21 | 64 |
Net income | 174 | 104 | 140 |
Less: net loss attributable to noncontrolling interest | -1 | -1 | -1 |
Net income attributable to Portland General Electric Company | $175 | $105 | $141 |
Weighted-average shares outstanding (in thousands): | |||
Basic | 78,180 | 76,821 | 75,498 |
Diluted | 80,494 | 77,388 | 75,647 |
Earnings per share: | |||
Basic | $2.24 | $1.36 | $1.87 |
Diluted | $2.18 | $1.35 | $1.87 |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Income (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Net income | $174 | $104 | $140 |
Other comprehensive income (loss) - Change in compensation retirement benefits liability and amortization, net of taxes of $2 in 2014 and $(1) in 2013 | -2 | 1 | 0 |
Comprehensive income | 172 | 105 | 140 |
Less: comprehensive loss attributable to the noncontrolling interests | 1 | 1 | 1 |
Comprehensive income attributable to Portland General Electric Company | $173 | $106 | $141 |
Consolidated_Statements_of_Com1
Consolidated Statements of Comprehensive Income Consolidated Statement of Comprehensive Income Parentheticals (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Net Taxes on change in compensation retirement benefits liability and amortization | $2 | ($1) |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $127 | $107 |
Accounts receivable, net | 149 | 146 |
Unbilled revenues | 93 | 104 |
Inventories, at average cost: | ||
Materials and supplies | 42 | 41 |
Fuel | 40 | 24 |
Regulatory assets--current | 133 | 66 |
Other current assets | 115 | 103 |
Total current assets | 699 | 591 |
Electric utility plant: | ||
Generation | 3,742 | 2,968 |
Transmission | 440 | 417 |
Distribution | 3,075 | 2,943 |
General | 426 | 381 |
Intangible | 478 | 386 |
Construction work-in-progress | 417 | 508 |
Total electric utility plant | 8,578 | 7,603 |
Accumulated depreciation and amortization | -2,899 | -2,723 |
Electric utility plant, net | 5,679 | 4,880 |
Regulatory assets--noncurrent | 494 | 464 |
Nuclear decommissioning trust | 90 | 82 |
Non-qualified benefit plan trust | 32 | 35 |
Other noncurrent assets | 48 | 49 |
Total assets | 7,042 | 6,101 |
Current liabilities: | ||
Accounts payable | 156 | 173 |
Liabilities from price risk management activities-current | 106 | 49 |
Current portion of long-term debt | 375 | 0 |
Accrued expenses and other current liabilities | 236 | 171 |
Total current liabilities | 873 | 393 |
Long-term debt, net of current portion | 2,126 | 1,916 |
Regulatory liabilities--noncurrent | 906 | 865 |
Deferred income taxes | 625 | 586 |
Unfunded status of pension and postretirement plans | 237 | 154 |
Liabilities from price risk management activities--noncurrent | 122 | 141 |
Asset retirement obligations | 116 | 100 |
Non-qualified benefit plan liabilities | 105 | 101 |
Other noncurrent liabilities | 21 | 25 |
Total liabilities | 5,131 | 4,281 |
Commitments and Contingencies (see notes) | ||
Portland General Electric Company shareholders’ equity: | ||
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding | 0 | 0 |
Common stock, no par value, 160,000,000 shares authorized; 78,228,339 and 78,085,559 shares issued and outstanding as of December 31, 2014 and 2013, respectively | 918 | 911 |
Accumulated other comprehensive loss | -7 | -5 |
Retained earnings | 1,000 | 913 |
Total Portland General Electric Company shareholders’ equity | 1,911 | 1,819 |
Noncontrolling interests' equity | 0 | 1 |
Total equity | 1,911 | 1,820 |
Total liabilities and equity | $7,042 | $6,101 |
Consolidated_Balance_Sheets_Co
Consolidated Balance Sheets Consolidated Balance Sheet Parentheticals (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Preferred Stock, No Par Value | $0 | $0 |
Preferred Stock, Shares Authorized | 30,000,000 | 30,000,000 |
Preferred Stock, Shares Issued | 0 | 0 |
Preferred Stock, Shares Outstanding | 0 | 0 |
Common Stock, No Par Value | $0 | $0 |
Common Stock, Shares Authorized | 160,000,000 | 160,000,000 |
Common Stock, Shares, Issued | 78,228,339 | 78,085,559 |
Common Stock, Shares, Outstanding | 78,228,339 | 78,085,559 |
Consolidated_Statements_of_Equ
Consolidated Statements of Equity (USD $) | Total | Common Stock Shares | Common Stock Amount | Accumulated Other Comprehensive Loss | Retained Earnings | Noncontrolling Interests' Equity |
In Millions, except Share data, unless otherwise specified | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | |
Balance at Dec. 31, 2011 | $836 | ($6) | $833 | $3 | ||
Balance, shares at Dec. 31, 2011 | 75,362,956 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Shares issued pursuant to equity-based plans | 193,316 | |||||
Proceeds from issuance of shares pursuant to equity-based plans | 1 | |||||
Stock-based compensation | 4 | 0 | 0 | 0 | ||
Dividends declared | 0 | 0 | -81 | 0 | ||
Net income (loss) | 140 | 0 | 0 | 141 | -1 | |
Balance at Dec. 31, 2012 | 841 | -6 | 893 | 2 | ||
Balance, shares at Dec. 31, 2012 | 75,556,272 | |||||
Issuances of common stock, net of issuance costs of $3 | 2,365,000 | |||||
Issuances of common stock, net of issuance costs of $3 | 67 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Shares issued pursuant to equity-based plans | 164,287 | |||||
Proceeds from issuance of shares pursuant to equity-based plans | 1 | |||||
Stock-based compensation | 2 | 0 | 0 | 0 | ||
Dividends declared | 0 | 0 | -85 | 0 | ||
Net income (loss) | 104 | 0 | 0 | 105 | -1 | |
Other comprehensive income (loss) | 0 | 1 | 0 | 0 | ||
Balance at Dec. 31, 2013 | 1,820 | 911 | -5 | 913 | 1 | |
Balance, shares at Dec. 31, 2013 | 78,085,559 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Shares issued pursuant to equity-based plans | 142,780 | |||||
Proceeds from issuance of shares pursuant to equity-based plans | 1 | |||||
Stock-based compensation | 6 | 0 | 0 | 0 | ||
Dividends declared | 0 | 0 | -88 | 0 | ||
Net income (loss) | 174 | 0 | 0 | 175 | -1 | |
Other comprehensive income (loss) | 0 | -2 | 0 | 0 | ||
Balance at Dec. 31, 2014 | $1,911 | $918 | ($7) | $1,000 | $0 | |
Balance, shares at Dec. 31, 2014 | 78,228,339 |
Consolidated_Statements_of_Equ1
Consolidated Statements of Equity Consolidated Statement of Equity Parenthetical (USD $) | 12 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Issuance costs | $3 | ||
Common Stock, Dividends, Per Share, Declared | $1.12 | $1.09 | $1.07 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flows from operating activities: | |||
Net income | $174 | $104 | $140 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation and amortization | 301 | 248 | 248 |
Increase (decrease) in net liabilities from price risk management activities | 45 | -18 | -175 |
Regulatory deferrals—price risk management activities | -45 | 18 | 172 |
Cascade Crossing transmission project | 0 | 52 | 0 |
Deferred income taxes | 39 | 11 | 47 |
Allowance for equity funds used during construction | -37 | -13 | -6 |
Pension and other postretirement benefits | 33 | 37 | 27 |
Regulatory deferral of settled derivative instruments | 10 | 7 | -9 |
Unrealized losses on non-qualified benefit plan trust assets | 7 | 3 | 3 |
Decoupling mechanism deferrals, net of amortization | 6 | -6 | 2 |
Power cost deferrals, net of amortization | 0 | -6 | -4 |
Other non-cash income and expenses, net | 12 | 18 | 17 |
Changes in working capital, net of effects from purchase of 10% interest in Boardman: | |||
Decrease (increase) in receivables and unbilled revenues | 8 | 0 | -4 |
(Increase) decrease in margin deposits | -2 | 37 | 34 |
Income tax refund received | 0 | 0 | 8 |
(Decrease) increase in payables and accrued liabilities | -13 | 14 | 1 |
Other working capital items, net | -12 | 17 | 1 |
Cash received to be returned to customers pursuant to the Residential Exchange Program | 13 | 1 | 0 |
Proceeds received from Trojan spent fuel legal settlement | 6 | 44 | 0 |
Contribution to non-qualified employee benefit trust | -8 | -6 | 0 |
Contribution to voluntary employees’ benefit association trust | -3 | -3 | -2 |
Other, net | -16 | -15 | -6 |
Net cash provided by operating activities | 518 | 544 | 494 |
Cash flows from investing activities: | |||
Capital expenditures | -1,007 | -656 | -303 |
Purchases of nuclear decommissioning trust securities | -19 | -26 | -26 |
Sales of nuclear decommissioning trust securities | 17 | 25 | 23 |
Contribution to nuclear decommissioning fund | -6 | -44 | 0 |
Cash received in connection with purchase of 10% interest in Boardman, net of cash paid | 8 | 0 | 0 |
Proceeds received from insurance recoveries | 3 | 6 | 0 |
Proceeds from sale of properties | 5 | 0 | 10 |
Other, net | 5 | 3 | 2 |
Net cash used in investing activities | -994 | -692 | -294 |
Cash flows from financing activities: | |||
Proceeds from issuance of long-term debt | 585 | 380 | 0 |
Payments on long-term debt | 0 | -100 | -100 |
Proceeds from issuance of common stock, net of issuance costs | 0 | 67 | 0 |
Borrowings on short-term debt | 0 | 35 | 0 |
Payments on short-term debt | 0 | -35 | 0 |
Maturities of commercial paper, net | 0 | -17 | -13 |
Dividends paid | -87 | -84 | -81 |
Debt issuance costs | -2 | -3 | 0 |
Net cash provided by (used in) financing activities | 496 | 243 | -194 |
Increase in cash and cash equivalents | 20 | 95 | 6 |
Cash and cash equivalents, beginning of year | 107 | 12 | 6 |
Cash and cash equivalents, end of year | 127 | 107 | 12 |
Supplemental disclosures of cash flow information: | |||
Cash paid for interest, net of amounts capitalized | 86 | 90 | 97 |
Cash paid for income taxes | 22 | 10 | 13 |
Non-cash investing and financing activities: | |||
Accrued capital additions | 70 | 84 | 19 |
Accrued dividends payable | 23 | 22 | 21 |
Accrued sales tax refund | 23 | 0 | 0 |
Preliminary engineering transferred to Construction work in progress from Other noncurrent assets | $0 | $9 | $0 |
Basis_of_Presentation
Basis of Presentation | 12 Months Ended |
Dec. 31, 2014 | |
Basis of Presentation [Abstract] | |
Basis of Presentation | BASIS OF PRESENTATION |
Nature of Operations | |
Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power marketers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. PGE’s service area includes 52 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. As of December 31, 2014, PGE served 842,273 retail customers with a service area population of approximately 1.8 million, comprising approximately 46% of the state’s population. | |
As of December 31, 2014, PGE had 2,600 employees, with 780 employees covered under two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 743 and 37 employees and expire in February 2016 and August 2017, respectively. | |
PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC) with respect to retail prices, utility services, accounting policies and practices, issuances of securities, and certain other matters. Retail prices are based on the Company’s cost to serve customers, including an opportunity to earn a reasonable rate of return, as determined by the OPUC. The Company is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in matters related to wholesale energy transactions, transmission services, reliability standards, natural gas pipelines, hydroelectric project licensing, accounting policies and practices, short-term debt issuances, and certain other matters. | |
Consolidation Principles | |
The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries and those variable interest entities (VIEs) where PGE has determined it is the primary beneficiary. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. Intercompany balances and transactions have been eliminated. | |
For entities that are determined to meet the definition of a VIE and where the Company has determined it is the primary beneficiary, the VIE is consolidated and a noncontrolling interest is recognized for any third party interests. This has resulted in the Company consolidating entities in which it has less than a 50% equity interest. For further information, see Note 16, Variable Interest Entities. | |
Use of Estimates | |
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of gain or loss contingencies, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates. | |
Customer Billing Matter | |
In May 2013, PGE discovered that it had over-billed an industrial customer during a period of several years as a result of a meter configuration error. An analysis of the data determined that the Company’s revenues were overstated by approximately $3 million in 2012 and in 2011, $2 million in 2010, and $1 million in 2009. PGE believes the customer billing error is not material to any annual reporting period. The Company corrected this matter in the second quarter of 2013 as an out of period adjustment, and recorded, as a reduction to Revenues, net, a refund to the customer in the amount of $9 million. | |
Reclassifications | |
To conform with the 2014 presentation, PGE has reclassified Margin deposits of $9 million with Other current assets in the consolidated balance sheet as of December 31, 2013. In addition, the Company reclassified Renewable adjustment clause deferrals of $1 million to Other non-cash income and expenses, net in the operating activities section of the consolidated statement of cash flows for the year ended December 31, 2012 and separately presented Cash received to be returned to customers pursuant to the Residential Exchange Program of $1 million from Other non-cash income and expenses, net for the year ended December 31, 2013. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | ||
Dec. 31, 2014 | |||
Summary of Significant Accounting Policies [Abstract] | |||
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||
Cash and Cash Equivalents | |||
Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, of which PGE had $120 million and $104 million as of December 31, 2014 and 2013, respectively. | |||
Accounts Receivable | |||
Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 16 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice. | |||
Provisions for uncollectible accounts receivable related to retail sales are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on management’s assessment of the probability of collection, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors. | |||
Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable. There have been no material write-offs of accounts receivable related to wholesale sales in 2014, 2013 and 2012. | |||
Price Risk Management | |||
PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, oil and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statement of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting. | |||
Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers. | |||
In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument. | |||
Electricity sale and purchase transactions that are physically settled are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement. | |||
Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are included with Other current assets in the consolidated balance sheets and were $11 million and $9 million as of December 31, 2014 and 2013, respectively. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet and were $30 million and $29 million as of December 31, 2014 and 2013, respectively. | |||
Inventories | |||
PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance and capital activities and fuel for use in generating plants. Fuel inventories include natural gas, oil, and coal. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market. | |||
Electric Utility Plant | |||
Capitalization Policy | |||
Electric utility plant is capitalized at its original cost, which includes direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at the Company’s generating plants are charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining a FERC license for the Company’s hydroelectric projects are capitalized and amortized over the related license period. | |||
During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. If any costs are expensed, the Company may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted. | |||
During the year ended December 31, 2013, PGE charged $52 million of costs previously included in CWIP related to the Cascade Crossing Transmission Project (Cascade Crossing), which was originally proposed as a 215-mile, 500 kV transmission project between Boardman, Oregon and Salem, Oregon. Based on an updated forecast of demand and future transmission capacity in the region, PGE determined in the second quarter of 2013 that the original projections of transmission capacity limitations contemplated in the Company’s 2009 Integrated Resource Plan, as acknowledged by the OPUC, were not likely to fully materialize. As a result, PGE and Bonneville Power Administration (BPA) worked toward refining the scope of the project and executed a non-binding memorandum of understanding (MOU) in May 2013. In connection with the MOU, the parties explored a new option under which BPA could provide PGE with ownership of approximately 1,500 MW of transmission capacity rights. As a result of the changed conditions reflected in the MOU, PGE also suspended permitting and development of Cascade Crossing and charged the capitalized costs related to Cascade Crossing to expense in the second quarter of 2013. In October 2013, the parties determined that they would not be able to reach an agreement on the financial terms for the proposed ownership of transmission capacity rights and, therefore, agreed to discontinue discussions on this option. The Company has determined that, under current conditions, the best option for meeting its transmission needs is to continue to acquire transmission service offered under BPA’s Open Access Transmission Tariff. PGE has determined that it will not seek recovery of these costs. | |||
PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes and is based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. The average rate used by PGE was 7.4% in 2014, and 7.5% in 2013 and in 2012. AFDC from borrowed funds was $22 million in 2014, $7 million in 2013, and $4 million in 2012 and is reflected as a reduction to Interest expense. AFDC from equity funds was $37 million in 2014, $13 million in 2013, and $6 million in 2012 and is included in Other income, net. | |||
Costs disallowed for recovery in customer prices, if any, are charged to expense at the time such disallowance is probable. | |||
Depreciation and Amortization | |||
Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.6% in 2014, 3.7% in 2013, and 3.8% in 2012. Estimated asset retirement removal costs included in depreciation expense were $57 million in 2014, and $55 million in 2013 and in 2012. | |||
Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of asset retirement obligations (AROs) and asset retirement removal costs. The studies are conducted at a minimum of every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. The most recent depreciation study was completed for 2013, with an order received from the OPUC in September 2014 authorizing new depreciation rates effective January 1, 2015. | |||
Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years): | |||
Generation, excluding thermal: | |||
Hydro | 87 | ||
Wind | 27 | ||
Transmission | 53 | ||
Distribution | 40 | ||
General | 13 | ||
The original cost of depreciable property units, net of any related salvage value, is charged to accumulated depreciation when property is retired and removed from service. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, included in Regulatory liabilities, for assets without AROs. | |||
Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. Accumulated amortization was $191 million and $170 million as of December 31, 2014 and 2013, respectively, with amortization expense of $25 million in 2014, and $22 million in 2013 and in 2012. Future estimated amortization expense as of December 31, 2014 is as follows: $35 million in 2015; $33 million in 2016; $29 million in 2017; $28 million in 2018; and $22 million in 2019. | |||
Marketable Securities | |||
All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading. These securities are classified as noncurrent because they are not available for use in operations. Trading securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the Non-qualified benefit plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking. The cost of securities sold is based on the average cost method. | |||
Regulatory Accounting | |||
Regulatory Assets and Liabilities | |||
As a rate-regulated enterprise, the Company applies regulatory accounting, resulting in regulatory assets or regulatory liabilities. Regulatory assets represent i) probable future revenue associated with certain actual or estimated costs that are expected to be recovered from customers through the ratemaking process, or ii) probable future collections from customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established by or subject to approval by independent third-party regulators; prices are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the consolidated statement of income over the period in which it is included in prices. | |||
Circumstances that could result in the discontinuance of regulatory accounting include i) increased competition that restricts the Company’s ability to establish prices to recover specific costs, and ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. PGE periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate. Based on a current evaluation of the various factors and conditions, management believes that recovery of the Company’s regulatory assets is probable. | |||
For additional information concerning the Company’s regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities. | |||
Power Cost Adjustment Mechanism | |||
PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. NVPC consists of i) the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income; and is net of ii) wholesale sales, which are classified as Revenues, net in the consolidated statements of income. | |||
To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from or refunded to customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. PGE’s authorized ROE was 9.75% for 2014, and 10% for 2013 and for 2012. | |||
Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review. | |||
For 2014, actual NVPC was below baseline NVPC by $7 million, which is within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2014. A final determination regarding the 2014 PCAM results will be made by the OPUC through a public filing and review in 2015. | |||
For 2013, actual NVPC was above baseline NVPC by $11 million, which is within the established deadband range. Accordingly, no estimated collection from customers was recorded as of December 31, 2013. A final determination regarding the 2013 PCAM results was made by the OPUC through a public filing and review in 2014, which confirmed no collection from customers pursuant to the PCAM for 2013. | |||
For 2012, actual NVPC was below baseline NVPC by $17 million, and exceeded the lower deadband threshold of $15 million. However, based on results of the regulated earnings test, no estimated refund to customers was recorded as of December 31, 2012. A final determination regarding the 2012 PCAM results was made by the OPUC through a public filing and review in 2013, which confirmed no refund to customers pursuant to the PCAM for 2012. | |||
Asset Retirement Obligations | |||
Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheet. An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred. | |||
The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. Changes in the ARO resulting from the passage of time (accretion) is based on the original discount rate and recognized as an increase in the carrying amount of the liability and as a charge to accretion expense, which is classified as Depreciation and amortization expense in the Company’s consolidated statements of income. | |||
The difference between the timing of the recognition of the AROs’ depreciation and accretion expenses and the amount included in customers’ prices is recorded as a regulatory asset or liability in the Company’s consolidated balance sheets. PGE had a regulatory liability related to AROs in the amount of $39 million as of December 31, 2014 and 2013. See Note 6, Regulatory Assets and Liabilities. | |||
Contingencies | |||
Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. Legal costs incurred in connection with loss contingencies are expensed as incurred. | |||
A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons. | |||
If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. | |||
Gain contingencies are recognized when realized and are disclosed when material. | |||
Accumulated Other Comprehensive Loss | |||
Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position. | |||
Revenue Recognition | |||
Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC), and state (OPUC) regulation. Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes and totaled $42 million in 2014, $41 million in 2013, and $42 million in 2012. | |||
Retail revenue is billed monthly based on meter readings taken throughout the month. Unbilled revenue represents the revenue earned from the last meter read date through the last day of the month, which has not been billed as of the last day of the month. Unbilled revenue is calculated based on each month’s actual net retail system load, the number of days from the last meter read date through the last day of the month, and current retail customer prices. | |||
As a rate-regulated utility, there are situations in which PGE recognizes revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization. For additional information, see “Regulatory Assets and Liabilities” in this Note 2. | |||
Stock-Based Compensation | |||
The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite vesting period. PGE attributes the value of stock-based compensation to expense on a straight-line basis. | |||
Income Taxes | |||
Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance is established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns. | |||
As a rate-regulated enterprise, changes in deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as net regulatory assets of $86 million and $76 million as of December 31, 2014 and 2013, respectively, and will be included in prices when the temporary differences reverse. | |||
Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheet. | |||
PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income. | |||
Recent Accounting Pronouncement | |||
Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), creates a new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized that consists of: i) identify the contract with the customer; ii) identify the performance obligations in the contract; iii) determine the transaction price; iv) allocate the transaction price to the performance obligations in the contract; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively or as a cumulative-effect adjustment as of the date of adoption, which is January 1, 2017 for the Company, with early adoption prohibited. The impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows of the adoption of ASU 2014-09 is not known at this time. |
Balance_Sheet_Components
Balance Sheet Components | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Balance Sheet Components [Abstract] | ||||||||||||||||
Balance Sheet Components | BALANCE SHEET COMPONENTS | |||||||||||||||
Accounts Receivable, Net | ||||||||||||||||
Accounts receivable is net of an allowance for uncollectible accounts of $6 million as of December 31, 2014 and 2013. The following is the activity in the allowance for uncollectible accounts (in millions): | ||||||||||||||||
Years Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Balance as of beginning of year | $ | 6 | $ | 5 | $ | 6 | ||||||||||
Increase in provision | 6 | 6 | 6 | |||||||||||||
Amounts written off, less recoveries | (6 | ) | (5 | ) | (7 | ) | ||||||||||
Balance as of end of year | $ | 6 | $ | 6 | $ | 5 | ||||||||||
Trust Accounts | ||||||||||||||||
PGE maintains two trust accounts as follows: | ||||||||||||||||
Nuclear decommissioning trust—Reflects assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) at the Trojan nuclear power plant (Trojan), which was closed in 1993. The Nuclear decommissioning trust includes amounts collected from customers less qualified expenditures plus any realized and unrealized gains and losses on the investments held therein. In 2014 and 2013, the Company received $6 million and $44 million, respectively, from the settlement of a legal matter concerning costs associated with the operation of the ISFSI. Those funds were deposited into the Nuclear decommissioning trust. For additional information concerning the legal matter, see Note 7, Asset Retirement Obligations. | ||||||||||||||||
Non-qualified benefit plan trust—Reflects assets held in trust to cover the obligations of PGE’s non-qualified benefit plans and represents contributions made by the Company less qualified expenditures plus any realized and unrealized gains and losses on the investment held therein. | ||||||||||||||||
The trusts are comprised of the following investments as of December 31 (in millions): | ||||||||||||||||
Nuclear | Non-Qualified Benefit | |||||||||||||||
Decommissioning Trust | Plan Trust | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Cash equivalents | $ | 65 | $ | 59 | $ | — | $ | — | ||||||||
Marketable securities, at fair value: | ||||||||||||||||
Equity securities | — | — | 6 | 8 | ||||||||||||
Debt securities | 25 | 23 | — | 1 | ||||||||||||
Insurance contracts, at cash surrender value | — | — | 26 | 26 | ||||||||||||
$ | 90 | $ | 82 | $ | 32 | $ | 35 | |||||||||
For information concerning the fair value measurement of those assets recorded at fair value held in the trusts, see Note 4, Fair Value of Financial Instruments. | ||||||||||||||||
Other Current Assets and Accrued Expenses and Other Current Liabilities | ||||||||||||||||
Other current assets and Accrued expenses and other current liabilities consist of the following (in millions): | ||||||||||||||||
As of December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Other current assets: | ||||||||||||||||
Prepaid expenses | $ | 39 | $ | 38 | ||||||||||||
Current deferred income tax asset | 33 | 42 | ||||||||||||||
Accrued sales tax refund related to Tucannon River Wind Farm | 23 | — | ||||||||||||||
Margin deposits | 11 | 9 | ||||||||||||||
Assets from price risk management activities | 6 | 13 | ||||||||||||||
Other | 3 | 1 | ||||||||||||||
$ | 115 | $ | 103 | |||||||||||||
Accrued expenses and other current liabilities: | ||||||||||||||||
Regulatory liabilities—current | $ | 60 | $ | 1 | ||||||||||||
Accrued employee compensation and benefits | 51 | 46 | ||||||||||||||
Accrued interest payable | 26 | 23 | ||||||||||||||
Dividends payable | 23 | 22 | ||||||||||||||
Accrued taxes payable | 22 | 21 | ||||||||||||||
Other | 54 | 58 | ||||||||||||||
$ | 236 | $ | 171 | |||||||||||||
Fair_Value_of_FInancial_Instru
Fair Value of FInancial Instruments | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Fair Value of Financial Instruments Note [Abstract] | |||||||||||||||||||||||||
Fair Value of FInancial Instruments | FAIR VALUE OF FINANCIAL INSTRUMENTS | ||||||||||||||||||||||||
PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2014 and 2013, and then classifies these financial assets and liabilities based on a fair value hierarchy. The fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below. | |||||||||||||||||||||||||
Level 1 | Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. | ||||||||||||||||||||||||
Level 2 | Pricing inputs include those that are directly or indirectly observable in the marketplace as of the reporting date. | ||||||||||||||||||||||||
Level 3 | Pricing inputs include significant inputs which are unobservable for the asset or liability. | ||||||||||||||||||||||||
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. | |||||||||||||||||||||||||
PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels during the years ended December 31, 2014 and 2013, except those transfers from Level 3 to Level 2 presented in this note. | |||||||||||||||||||||||||
The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions): | |||||||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
Assets: | |||||||||||||||||||||||||
Nuclear decommissioning trust (1): | |||||||||||||||||||||||||
Money market funds | $ | — | $ | 65 | $ | — | $ | 65 | |||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Domestic government | 7 | 7 | — | 14 | |||||||||||||||||||||
Corporate credit | — | 11 | — | 11 | |||||||||||||||||||||
Non-qualified benefit plan trust (2): | |||||||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Domestic | 4 | 1 | — | 5 | |||||||||||||||||||||
International | 1 | — | — | 1 | |||||||||||||||||||||
Assets from price risk management activities (1) (3): | |||||||||||||||||||||||||
Electricity | — | 4 | 1 | 5 | |||||||||||||||||||||
Natural gas | — | 2 | — | 2 | |||||||||||||||||||||
$ | 12 | $ | 90 | $ | 1 | $ | 103 | ||||||||||||||||||
Liabilities - Liabilities from price risk management | |||||||||||||||||||||||||
activities (1) (3): | |||||||||||||||||||||||||
Electricity | $ | — | $ | 32 | $ | 80 | $ | 112 | |||||||||||||||||
Natural gas | — | 95 | 21 | 116 | |||||||||||||||||||||
$ | — | $ | 127 | $ | 101 | $ | 228 | ||||||||||||||||||
-1 | Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate. | ||||||||||||||||||||||||
-2 | Excludes insurance policies of $26 million, which are recorded at cash surrender value. | ||||||||||||||||||||||||
-3 | For further information, see Note 5, Price Risk Management. | ||||||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
Assets: | |||||||||||||||||||||||||
Nuclear decommissioning trust (1): | |||||||||||||||||||||||||
Money market funds | $ | — | $ | 59 | $ | — | $ | 59 | |||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Domestic government | 6 | 8 | — | 14 | |||||||||||||||||||||
Corporate credit | — | 9 | — | 9 | |||||||||||||||||||||
Non-qualified benefit plan trust (2): | |||||||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Domestic | 4 | 3 | — | 7 | |||||||||||||||||||||
International | 1 | — | — | 1 | |||||||||||||||||||||
Debt securities - domestic government | 1 | — | — | 1 | |||||||||||||||||||||
Assets from price risk management activities (1) (3): | |||||||||||||||||||||||||
Electricity | — | 9 | 1 | 10 | |||||||||||||||||||||
Natural gas | — | 4 | — | 4 | |||||||||||||||||||||
$ | 12 | $ | 92 | $ | 1 | $ | 105 | ||||||||||||||||||
Liabilities - Liabilities from price risk management | |||||||||||||||||||||||||
activities (1) (3): | |||||||||||||||||||||||||
Electricity | $ | — | $ | 10 | $ | 117 | $ | 127 | |||||||||||||||||
Natural gas | — | 40 | 23 | 63 | |||||||||||||||||||||
$ | — | $ | 50 | $ | 140 | $ | 190 | ||||||||||||||||||
-1 | Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate. | ||||||||||||||||||||||||
-2 | Excludes insurance policies of $26 million, which are recorded at cash surrender value. | ||||||||||||||||||||||||
-3 | For further information, see Note 5, Price Risk Management. | ||||||||||||||||||||||||
Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s consolidated balance sheets and invested in securities that are exposed to interest rate, credit and market volatility risks. These assets are classified within Level 1, 2 or 3 based on the following factors: | |||||||||||||||||||||||||
Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. Money market funds are classified as Level 2 in the fair value hierarchy as the securities are traded in active markets of similar securities but are not directly valued using quoted market prices. | |||||||||||||||||||||||||
Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. | |||||||||||||||||||||||||
Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation as applicable. | |||||||||||||||||||||||||
Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE). Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs are directly or indirectly observable in the marketplace. | |||||||||||||||||||||||||
Assets and liabilities from price risk management activities are recorded at fair value in PGE’s consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net power costs for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Price Risk Management. | |||||||||||||||||||||||||
For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures and swaps. | |||||||||||||||||||||||||
Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term commodity forwards, futures and swaps. | |||||||||||||||||||||||||
Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below: | |||||||||||||||||||||||||
Significant | Price per Unit | ||||||||||||||||||||||||
Fair Value | Valuation | Unobservable | Weighted | ||||||||||||||||||||||
Commodity Contracts | Assets | Liabilities | Technique | Input | Low | High | Average | ||||||||||||||||||
(in millions) | |||||||||||||||||||||||||
As of December 31, 2014: | |||||||||||||||||||||||||
Electricity physical forward | $ | — | $ | 77 | Discounted cash flow | Electricity forward price (per MWh) | $ | 11.97 | $ | 122.72 | $ | 37.43 | |||||||||||||
Natural gas financial swaps | — | 21 | Discounted cash flow | Natural gas forward price (per Dth) | 2.88 | 4.86 | 3.41 | ||||||||||||||||||
Electricity financial futures | 1 | 3 | Discounted cash flow | Electricity forward price (per MWh) | 11.97 | 39.26 | 27.88 | ||||||||||||||||||
$ | 1 | $ | 101 | ||||||||||||||||||||||
As of December 31, 2013: | |||||||||||||||||||||||||
Electricity physical forward | $ | — | $ | 103 | Discounted cash flow | Electricity forward price (per MWh) | $ | 9.63 | $ | 77.95 | $ | 40.18 | |||||||||||||
Natural gas financial swaps | — | 23 | Discounted cash flow | Natural gas forward price (per Dth) | 3.16 | 4.49 | 3.71 | ||||||||||||||||||
Electricity financial futures | 1 | 14 | Discounted cash flow | Electricity forward price (per MWh) | 9.63 | 46.07 | 33.01 | ||||||||||||||||||
$ | 1 | $ | 140 | ||||||||||||||||||||||
The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter term contracts, the Company uses internally-developed price curves that employ the mid-point of the market’s bid-ask spread derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These internally-developed price curves are validated against nonbinding broker quotes, market data from a regulated exchange and benchmark price assessments from a pricing vendor. For certain longer term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such circumstances, the Company uses internally-developed price curves, which utilize observable data and regression techniques to derive future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a monthly basis by the Company. This process includes analytical review of changes in commodity prices as well as procedures to analyze and identify the reasons for the changes over specific reporting periods. | |||||||||||||||||||||||||
The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and the Company’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows: | |||||||||||||||||||||||||
Significant Unobservable Input | Position | Change to Input | Impact on Fair Value Measurement | ||||||||||||||||||||||
Market price | Buy | Increase (decrease) | Gain (loss) | ||||||||||||||||||||||
Market price | Sell | Increase (decrease) | Loss (gain) | ||||||||||||||||||||||
Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions): | |||||||||||||||||||||||||
Years Ended December 31, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
Net liabilities from price risk management activities as of beginning of year | $ | 139 | $ | 16 | |||||||||||||||||||||
Net realized and unrealized losses * | 15 | 134 | |||||||||||||||||||||||
Settlements | (4 | ) | (1 | ) | |||||||||||||||||||||
Net transfers out of Level 3 to Level 2 | (50 | ) | (10 | ) | |||||||||||||||||||||
Net liabilities from price risk management activities as of end of year | $ | 100 | $ | 139 | |||||||||||||||||||||
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting | $ | 12 | $ | 133 | |||||||||||||||||||||
* Includes realized losses, net of $3 million in 2014 and $1 million in 2013. | |||||||||||||||||||||||||
Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2014 and 2013, there were no significant transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements. | |||||||||||||||||||||||||
Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. The fair value of PGE’s unsecured term bank loans is classified as Level 3 fair value measurement and is estimated based on the terms of the loans and the Company’s creditworthiness. These significant unobservable inputs to the Level 3 fair value measurement include the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximates their carrying value. | |||||||||||||||||||||||||
As of December 31, 2014, the carrying amount of PGE’s long-term debt was $2,501 million and its estimated aggregate fair value was $2,901 million, consisting of $2,596 million and $305 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy. As of December 31, 2013, the carrying amount of PGE’s long-term debt was $1,916 million and its estimated aggregate fair value was $2,074 million, all classified as Level 2 in the fair value hierarchy. | |||||||||||||||||||||||||
For fair value information concerning the Company’s pension plan assets, see Note 10, Employee Benefits. |
Price_Risk_Management_Notes
Price Risk Management (Notes) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Price Risk Management [Abstract] | ||||||||||||||||||||||||||||
Price Risk Management | PRICE RISK MANAGEMENT | |||||||||||||||||||||||||||
PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generating resources combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existing long-term wholesale contracts. Such activities include fuel and power purchases and sales resulting from economic dispatch decisions for its own generation. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, where adverse changes in prices and/or rates may affect the Company’s financial position, performance, or cash flow. | ||||||||||||||||||||||||||||
PGE utilizes derivative instruments in its wholesale electric utility activities to manage its exposure to commodity price risk and foreign exchange rate risk in order to manage volatility in net power costs for its retail customers. These derivative instruments may include forward, futures, swap, and option contracts for electricity, natural gas, oil and foreign currency, which are recorded at fair value on the consolidated balance sheet, with changes in fair value recorded in the statement of income. In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. PGE does not engage in trading activities for non-retail purposes. | ||||||||||||||||||||||||||||
PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions): | ||||||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||
Current assets: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | $ | 4 | $ | 9 | ||||||||||||||||||||||||
Natural gas | 2 | 4 | ||||||||||||||||||||||||||
Total current derivative assets | 6 | (1) | 13 | (1) | ||||||||||||||||||||||||
Noncurrent assets: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | 1 | 1 | ||||||||||||||||||||||||||
Total noncurrent derivative assets | 1 | (2) | 1 | (2) | ||||||||||||||||||||||||
Total derivative assets not designated as hedging instruments | $ | 7 | $ | 14 | ||||||||||||||||||||||||
Total derivative assets | $ | 7 | $ | 14 | ||||||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | $ | 54 | $ | 20 | ||||||||||||||||||||||||
Natural gas | 52 | 29 | ||||||||||||||||||||||||||
Total current derivative liabilities | 106 | 49 | ||||||||||||||||||||||||||
Noncurrent liabilities: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | 58 | 107 | ||||||||||||||||||||||||||
Natural gas | 64 | 34 | ||||||||||||||||||||||||||
Total noncurrent derivative liabilities | 122 | 141 | ||||||||||||||||||||||||||
Total derivative liabilities not designated as hedging instruments | $ | 228 | $ | 190 | ||||||||||||||||||||||||
Total derivative liabilities | $ | 228 | $ | 190 | ||||||||||||||||||||||||
-1 | Included in Other current assets on the consolidated balance sheets. | |||||||||||||||||||||||||||
-2 | Included in Other noncurrent assets on the consolidated balance sheet. | |||||||||||||||||||||||||||
PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions): | ||||||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | 16 | MWh | 14 | MWh | ||||||||||||||||||||||||
Natural gas | 127 | Dth | 106 | Dth | ||||||||||||||||||||||||
Foreign currency exchange | $ | 7 | Canadian | $ | 7 | Canadian | ||||||||||||||||||||||
PGE has elected to report gross on the consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit, which are excluded from the offsetting table below. | ||||||||||||||||||||||||||||
Information related to price risk management liabilities subject to master netting agreements is as follows (in millions): | ||||||||||||||||||||||||||||
Gross | Gross | Net | Gross Amounts Not Offset in | |||||||||||||||||||||||||
Amounts | Amounts | Amounts | Consolidated Balance Sheets | |||||||||||||||||||||||||
Recognized | Offset | Presented | Derivatives | Cash Collateral(1) | Net Amount | |||||||||||||||||||||||
As of December 31, 2014: | ||||||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity(2) | $ | 55 | $ | — | $ | 55 | $ | (55 | ) | $ | — | $ | — | |||||||||||||||
Natural gas(2) | 17 | — | 17 | (17 | ) | — | — | |||||||||||||||||||||
$ | 72 | $ | — | $ | 72 | $ | (72 | ) | $ | — | $ | — | ||||||||||||||||
As of December 31, 2013: | ||||||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity(2) | $ | 91 | $ | — | $ | 91 | $ | (91 | ) | $ | — | $ | — | |||||||||||||||
Natural gas(2) | 1 | — | 1 | (1 | ) | — | — | |||||||||||||||||||||
$ | 92 | $ | — | $ | 92 | $ | (92 | ) | $ | — | $ | — | ||||||||||||||||
-1 | As of December 31, 2014 and 2013, the Company had collateral posted of $11 million and $7 million, respectively, which consists entirely of letters of credit. | |||||||||||||||||||||||||||
-2 | Included in Liabilities from price risk management activities—current and Liabilities from price risk management activities—noncurrent. | |||||||||||||||||||||||||||
Net realized and unrealized losses on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the consolidated statements of income and were as follows (in millions): | ||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | $ | 13 | $ | 78 | $ | 56 | ||||||||||||||||||||||
Natural Gas | 72 | 28 | 19 | |||||||||||||||||||||||||
Foreign currency exchange | — | 1 | — | |||||||||||||||||||||||||
Net unrealized losses and certain net realized losses presented in the table above are offset within the statement of income by the effects of regulatory accounting. Of the net loss recognized in net income for the years ended December 31, 2014, 2013, and 2012, $83 million, $120 million, and $42 million, respectively, have been offset. | ||||||||||||||||||||||||||||
Assuming no changes in market prices and interest rates, the following table presents the year in which the net unrealized loss recorded as of December 31, 2014 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions): | ||||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | $ | 50 | $ | 19 | $ | 6 | $ | 5 | $ | 5 | $ | 22 | $ | 107 | ||||||||||||||
Natural gas | 49 | 44 | 18 | 3 | — | — | 114 | |||||||||||||||||||||
Net unrealized loss | $ | 99 | $ | 63 | $ | 24 | $ | 8 | $ | 5 | $ | 22 | $ | 221 | ||||||||||||||
PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and Standard & Poor’s Ratings Services (S&P). Should Moody’s and/or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties and some other counterparties will have the right to terminate their agreements with the Company. | ||||||||||||||||||||||||||||
The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of December 31, 2014 was $216 million, for which the Company had posted $29 million in collateral, consisting primarily of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at December 31, 2014, the cash requirement to either post as collateral or settle the instruments immediately would have been $213 million. As of December 31, 2014, PGE had posted an additional $11 million in cash collateral for derivative instruments with no credit-risk-related contingent features, which is classified as Margin deposits on the Company’s consolidated balance sheet. | ||||||||||||||||||||||||||||
Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows: | ||||||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||
Assets from price risk management activities: | ||||||||||||||||||||||||||||
Counterparty A | 63 | % | 53 | % | ||||||||||||||||||||||||
Counterparty B | 14 | 6 | ||||||||||||||||||||||||||
77 | % | 59 | % | |||||||||||||||||||||||||
Liabilities from price risk management activities: | ||||||||||||||||||||||||||||
Counterparty C | 22 | % | 43 | % | ||||||||||||||||||||||||
Counterparty D | 12 | 11 | ||||||||||||||||||||||||||
34 | % | 54 | % | |||||||||||||||||||||||||
For additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities, see Note 4, Fair Value of Financial Instruments. |
Regulatory_Assets_and_Liabilit
Regulatory Assets and Liabilities | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | ||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Text Block] | REGULATORY ASSETS AND LIABILITIES | |||||||||||||||||
The majority of PGE’s regulatory assets and liabilities are reflected in customer prices and are amortized over the period in which they are reflected in customer prices. Items not currently reflected in prices are pending before the regulatory body as discussed below. | ||||||||||||||||||
Regulatory assets and liabilities consist of the following (dollars in millions): | ||||||||||||||||||
Weighted Average Remaining | As of December 31, | |||||||||||||||||
Life (1) | 2014 | 2013 | ||||||||||||||||
Current | Noncurrent | Current | Noncurrent | |||||||||||||||
Regulatory assets: | ||||||||||||||||||
Price risk management (2) | 3 years | $ | 100 | $ | 121 | $ | 36 | $ | 140 | |||||||||
Pension and other postretirement plans (2) | (3) | — | 247 | — | 194 | |||||||||||||
Deferred income taxes (2) | (4) | — | 86 | — | 76 | |||||||||||||
Debt issuance costs (2) | 8 years | — | 15 | — | 17 | |||||||||||||
Deferred capital projects | 1 year | 19 | — | 16 | 18 | |||||||||||||
Other (5) | Various | 14 | 25 | 14 | 19 | |||||||||||||
Total regulatory assets | $ | 133 | $ | 494 | $ | 66 | $ | 464 | ||||||||||
Regulatory liabilities: | ||||||||||||||||||
Asset retirement removal costs (6) | (4) | $ | — | $ | 804 | $ | — | $ | 747 | |||||||||
Trojan decommissioning activities | 2 years | 23 | 34 | — | 49 | |||||||||||||
Asset retirement obligations (6) | (4) | — | 39 | — | 39 | |||||||||||||
Other | Various | 37 | 29 | 1 | 30 | |||||||||||||
Total regulatory liabilities | $ | 60 | (7) | $ | 906 | $ | 1 | (7) | $ | 865 | ||||||||
-1 | As of December 31, 2014. | |||||||||||||||||
-2 | Does not include a return on investment. | |||||||||||||||||
-3 | Recovery expected over the average service life of employees. For additional information, see Note 2, Summary of Significant Accounting Policies. | |||||||||||||||||
-4 | Recovery expected over the estimated lives of the assets. | |||||||||||||||||
-5 | Of the total other unamortized regulatory asset balances, a return is recorded on $33 million and $16 million as of December 31, 2014 and 2013, respectively. | |||||||||||||||||
-6 | Included in rate base for ratemaking purposes. | |||||||||||||||||
-7 | Included in Accrued expenses and other current liabilities on the consolidated balance sheets. | |||||||||||||||||
As of December 31, 2014, PGE had regulatory assets of $63 million earning a return on investment at the following rates: i) $33 million earning a return by inclusion in rate base; ii) $19 million at PGE’s cost of debt of 5.54%; iii) $9 million at the approved rate for deferred accounts under amortization, ranging from 1.47% to 1.77%, depending on the year of approval; and iv) $2 million at PGE’s cost of capital of 7.65%. | ||||||||||||||||||
Price risk management represents the difference between the net unrealized losses recognized on derivative instruments related to price risk management activities and their realization and subsequent recovery in customer prices. For further information regarding assets and liabilities from price risk management activities, see Note 5, Price Risk Management. | ||||||||||||||||||
Pension and other postretirement plans represents unrecognized components of the benefit plans’ funded status, which are recoverable in customer prices when recognized in net periodic benefit cost. For further information, see Note 10, Employee Benefits. | ||||||||||||||||||
Deferred income taxes represents income tax benefits resulting from property-related timing differences that previously flowed to customers and will be included in customer prices when the temporary differences reverse. For further information, see Note 11, Income Taxes. | ||||||||||||||||||
Debt issuance costs represents unrecognized debt issuance costs related to debt instruments retired prior to the stipulated maturity date. | ||||||||||||||||||
Deferred capital projects represents costs related to four capital projects that were deferred for future accounting treatment pursuant to the Company’s 2011 GRC. The recovery of these project costs in customer prices began January 1, 2014. | ||||||||||||||||||
Asset retirement removal costs represent the costs that do not qualify as AROs and are a component of depreciation expense allowed in customer prices. Such costs are recorded as a regulatory liability as they are collected in prices, and are reduced by actual removal costs incurred. | ||||||||||||||||||
Trojan decommissioning activities represents proceeds received for the settlement of a legal matter concerning the reimbursement from the United States Department of Energy of certain monitoring costs incurred related to spent nuclear fuel at Trojan. The proceeds will be returned to customers over a three-year period beginning January 1, 2015 and offset amounts previously collected from customers in relation to Trojan decommissioning activities. To conform with the 2014 presentation, PGE reclassified tax credits to be returned to customers related to the operation of the ISFSI in the amount of $8 million from Other to Trojan decommissioning activities in the noncurrent regulatory liabilities section as of December 31, 2013 in the preceding table. | ||||||||||||||||||
Asset retirement obligations represent the difference in the timing of recognition of i) the amounts recognized for depreciation expense of the asset retirement costs and accretion of the ARO, and ii) the amount recovered in customer prices. |
Asset_Retirement_Obilgations
Asset Retirement Obilgations | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Asset Retirement Obligation [Abstract] | ||||||||||||
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS | |||||||||||
AROs consist of the following (in millions): | ||||||||||||
As of December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Trojan decommissioning activities | $ | 41 | $ | 41 | ||||||||
Utility plant | 64 | 49 | ||||||||||
Non-utility property | 11 | 10 | ||||||||||
Asset retirement obligations | $ | 116 | $ | 100 | ||||||||
Trojan decommissioning activities represents the present value of future decommissioning costs for the plant, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the ISFSI, an interim dry storage facility that is licensed by the Nuclear Regulatory Commission. The ISFSI is to house the spent nuclear fuel at the former plant site until an off-site storage facility is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a United States Department of Energy (USDOE) facility is complete, which is not expected prior to 2033. | ||||||||||||
In 2004, the co-owners of Trojan (PGE, Eugene Water & Electric Board, and PacifiCorp, collectively referred to as Plaintiffs) filed a complaint against the USDOE for failure to accept spent nuclear fuel by January 31, 1998. PGE had contracted with the USDOE for the permanent disposal of spent nuclear fuel in order to allow the final decommissioning of Trojan. The Plaintiffs paid for permanent disposal services during the period of plant operation and have met all other conditions precedent. The Plaintiffs were seeking approximately $112 million in damages incurred through 2009. | ||||||||||||
A trial before the U.S. Court of Federal Claims concluded in 2012, with the U.S. Court of Federal Claims issuing a judgment awarding certain damages to the Plaintiffs. In 2013, the Plaintiffs received $70 million for the settlement of this matter. The settlement agreement also provided for a process to submit claims for allowable costs for the period 2010 through 2013, and was subsequently extended to cover 2014 through 2016. In 2014, the Plaintiffs received $9 million for costs related to 2010 through 2013. The Company will seek recovery of any costs for subsequent periods in future extensions of the agreement. | ||||||||||||
PGE has received proceeds of $50 million related to its share in this legal matter, with $44 million received in 2013 and $6 million received in 2014. Such funds were deposited into the Nuclear decommissioning trust and recorded as a regulatory liability to offset amounts previously collected in relation to Trojan decommissioning activities. In December 2014, the OPUC issued an order on the Company’s 2015 GRC, authorizing the return of the $50 million of proceeds received related to this legal matter to customers over a three-year period beginning January 1, 2015. | ||||||||||||
The ARO related to Trojan decommissioning activities is not impacted by the outcome of this legal matter because the proceeds received in connection with the settlement of this legal matter are for past Trojan decommissioning costs and this ARO reflects future Trojan decommissioning costs. | ||||||||||||
Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites, distribution and transmission assets where disposal is governed by environmental regulation. During 2014, the Company incurred AROs totaling $8 million related to the three new generating resources: Port Westward Unit 2 (PW2), Tucannon River Wind Farm (Tucannon River), and Carty Generating Station (Carty). | ||||||||||||
In December 2014 and 2013, PGE increased its ARO related to Boardman by $7 million and $4 million, respectively, in connection with the acquisition of additional interests in Boardman, with corresponding increases in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. For additional information regarding the Company’s acquisition of additional interests in Boardman, see Note 17, Jointly-owned Plant. | ||||||||||||
Non-utility property primarily represents AROs which have been recognized for portions of unregulated properties leased to third parties. | ||||||||||||
The following is a summary of the changes in the Company’s AROs (in millions): | ||||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Balance as of beginning of year | $ | 100 | $ | 94 | $ | 87 | ||||||
Liabilities incurred | 15 | 4 | — | |||||||||
Liabilities settled | (3 | ) | (4 | ) | (3 | ) | ||||||
Accretion expense | 6 | 6 | 6 | |||||||||
Revisions in estimated cash flows | (2 | ) | — | 4 | ||||||||
Balance as of end of year | $ | 116 | $ | 100 | $ | 94 | ||||||
Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability. Recovery of Trojan decommissioning costs is included in PGE’s retail prices, approximately $4 million annually, with an equal amount recorded in Depreciation and amortization expense. | ||||||||||||
PGE maintains a separate trust account, Nuclear decommissioning trust in the consolidated balance sheet, for funds collected from customers through prices to cover the cost of Trojan decommissioning activities. See “Trust Accounts” in Note 3, Balance Sheet Components, for additional information on the Nuclear decommissioning trust. | ||||||||||||
The Oak Grove hydro facility and transmission and distribution plant located on public right-of-ways and on certain easements meet the requirements of a legal obligation and will require removal when the plant is no longer in service. An ARO liability is not currently measurable as management believes that these assets will be used in utility operations for the foreseeable future. Removal costs are charged to accumulated asset retirement removal costs, which is included in Regulatory liabilities on PGE’s consolidated balance sheets. |
Revolving_Credit_Facilities
Revolving Credit Facilities | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Line of Credit Facility [Abstract] | ||||||||||||
Revolving Credit Facilities | CREDIT FACILITIES | |||||||||||
PGE has credit facilities with an aggregate capacity of $700 million as follows: | ||||||||||||
• | A $400 million revolving credit facility, which is scheduled to terminate in November 2018; and | |||||||||||
• | A $300 million revolving credit facility, which is scheduled to terminate in December 2017. | |||||||||||
Pursuant to the terms of the agreements, both revolving credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings, and also permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. Both revolving credit facilities contain two, one-year extensions subject to approval by the banks, require annual fees based on PGE’s unsecured credit ratings, and contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65.0% of total capitalization. As of December 31, 2014, PGE was in compliance with this covenant with a 56.7% debt to total capital ratio. | ||||||||||||
PGE classifies any borrowings under the revolving credit facilities and outstanding commercial paper as Short-term debt in the consolidated balance sheets. As of December 31, 2014, PGE had no borrowings or commercial paper outstanding, $20 million of letters of credit issued, and an aggregate available capacity of $680 million under the revolving credit facilities. | ||||||||||||
In addition, PGE has two one-year $30 million letter of credit facilities, under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit are subject to the approval of the issuing institution. As of December 31, 2014, $56 million of letters of credit had been issued under these facilities. | ||||||||||||
The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the credit facilities. | ||||||||||||
Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt up to $900 million through February 6, 2016. The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested. | ||||||||||||
Short-term borrowings under these credit facilities and related interest rates were as follows (dollars in millions): | ||||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Average daily amount of short-term debt outstanding | $ | — | $ | 9 | $ | 4 | ||||||
Weighted daily average interest rate * | — | % | 0.4 | % | 0.4 | % | ||||||
Maximum amount outstanding during the year | $ | — | $ | 54 | $ | 44 | ||||||
* | Excludes the effect of commitment fees, facility fees and other financing fees. |
Longterm_Debt
Long-term Debt | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Long-term Debt Disclosure [Abstract] | ||||||||
Long-term Debt | LONG-TERM DEBT | |||||||
Long-term debt consists of the following (in millions): | ||||||||
As of December 31, | ||||||||
2014 | 2013 | |||||||
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.42% in 2014 and 5.62% in 2013, due at various dates through 2048 | $ | 2,075 | $ | 1,795 | ||||
Unsecured term bank loans, rates range from 0.86% to 0.93%, due October 2015 | 305 | — | ||||||
Pollution Control Revenue Bonds, 5% rate, due 2033 | 142 | 148 | ||||||
Pollution Control Revenue Bonds owned by PGE | (21 | ) | (27 | ) | ||||
Total long-term debt | 2,501 | 1,916 | ||||||
Less: current portion of long-term debt | (375 | ) | — | |||||
Long-term debt, net of current portion | $ | 2,126 | $ | 1,916 | ||||
First Mortgage Bonds—During 2014, PGE issued a total of $280 million of FMBs, consisting of the following: | ||||||||
• | In November, issued $80 million of 3.51% Series FMBs due 2024; | |||||||
• | In October, issued $100 million of 4.44% Series FMBs due 2046; and | |||||||
• | In August, issued $100 million of 4.39% Series FMBs due 2045. | |||||||
The Indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. | ||||||||
In January 2015, the Company issued $75 million of 3.55% Series FMBs due 2030. | ||||||||
Unsecured term bank loans—During 2014, PGE obtained four term loans pursuant to a credit agreement in an aggregate principal amount of $305 million. The term loan interest rates are set at the beginning of the interest period for periods ranging from one- to six-months, as selected by PGE and are based on the London Interbank Offered Rate (LIBOR) plus 70 basis points, with no other fees. The credit agreement expires October 30, 2015, at which time any amounts outstanding under the term loans become due and payable. Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults and other customary defaults. Interest is payable monthly on the unsecured term bank loans. | ||||||||
Pollution Control Revenue Bonds—In January 2014, PGE retired $6 million of Pollution Control Revenue Bonds (PCBs). The Company has the option to remarket through 2033 the $21 million of PCBs held by PGE as of December 31, 2014. At the time of any remarketing, the Company can choose a new interest rate period that could be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of remarketing. The PCBs could be backed by FMBs or a bank letter of credit depending on market conditions. Interest is payable semi-annually on PCBs. | ||||||||
As of December 31, 2014, the future minimum principal payments on long-term debt are as follows (in millions): | ||||||||
Years ending December 31: | ||||||||
2015 | $ | 375 | ||||||
2016 | 67 | |||||||
2017 | 58 | |||||||
2018 | 75 | |||||||
2019 | 300 | |||||||
Thereafter | 1,626 | |||||||
$ | 2,501 | |||||||
Employee_Benefits
Employee Benefits | 12 Months Ended | |||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||
Employee Benefits [Abstract] | ||||||||||||||||||||||||||||||||||||
Employee Benefits | EMPLOYEE BENEFITS | |||||||||||||||||||||||||||||||||||
Pension and Other Postretirement Plans | ||||||||||||||||||||||||||||||||||||
Defined Benefit Pension Plan—PGE sponsors a non-contributory defined benefit pension plan. The plan has been closed to most new employees since January 31, 2009 and to all new employees since January 1, 2012. No changes were made to the benefits provided to existing participants when the plan was closed to new employees. | ||||||||||||||||||||||||||||||||||||
The assets of the pension plan are held in a trust and are comprised of equity and debt instruments, all of which are recorded at fair value. Pension plan calculations include several assumptions which are reviewed annually and are updated as appropriate, with the measurement date of December 31. | ||||||||||||||||||||||||||||||||||||
PGE made no contributions to the pension plan in 2014, 2013, and 2012. No contributions to the pension plan are expected in 2015. | ||||||||||||||||||||||||||||||||||||
In 2014, the Company offered certain eligible participants of the pension plan the option to select a lump sum distribution. As a result of this offering, PGE made lump sum distributions totaling $16 million on July 1, 2014. | ||||||||||||||||||||||||||||||||||||
Other Postretirement Benefits—PGE has non-contributory postretirement health and life insurance plans, as well as Health Reimbursement Accounts (HRAs) for its employees (collectively “Other Postretirement Benefits” in the following tables). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE’s obligation pursuant to the postretirement health plan by establishing a maximum benefit per employee with employees paying the additional cost. | ||||||||||||||||||||||||||||||||||||
The assets of these plans are held in voluntary employees’ beneficiary association trusts and are comprised of money market funds, common stocks, common and collective trust funds, partnerships/joint ventures, and registered investment companies, all of which are recorded at fair value. Postretirement health and life insurance benefit plan calculations include several assumptions which are reviewed annually with PGE’s consulting actuaries and trust investment consultants and updated as appropriate, with measurement dates of December 31. | ||||||||||||||||||||||||||||||||||||
Contributions to the HRAs provide for claims by retirees for qualified medical costs. For bargaining employees, the participants’ accounts are credited with 58% of the value of the employee’s accumulated sick time as of April 30, 2004, a stated amount per compensable hour worked, plus 100% of their earned time off accumulated at the time of retirement. For active non-bargaining employees, the Company grants a fixed dollar amount that will become available for qualified medical expenses upon their retirement. | ||||||||||||||||||||||||||||||||||||
Non-Qualified Benefit Plans—The non-qualified benefit plans (NQBP) in the following tables include obligations for a Supplemental Executive Retirement Plan, and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also include pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in a non-qualified benefit plan trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. These trust assets are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bond, and equity mutual funds, are classified as trading and recorded at fair value. The measurement date for the non-qualified benefit plans is December 31. | ||||||||||||||||||||||||||||||||||||
Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. PGE holds investments in a non-qualified benefit plan trust which are intended to be a funding source for these plans. | ||||||||||||||||||||||||||||||||||||
Trust assets and plan liabilities related to the NQBP included in PGE’s consolidated balance sheets are as follows as of December 31 (in millions): | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||
NQBP | Other NQBP | Total | NQBP | Other NQBP | Total | |||||||||||||||||||||||||||||||
Non-qualified benefit plan trust | $ | 15 | $ | 17 | $ | 32 | $ | 16 | $ | 19 | $ | 35 | ||||||||||||||||||||||||
Non-qualified benefit plan liabilities * | 25 | 80 | 105 | 22 | 79 | 101 | ||||||||||||||||||||||||||||||
* | For the NQBP, excludes the current portion of $2 million in 2014 and in 2013, which is classified in Other current liabilities in the consolidated balance sheets. | |||||||||||||||||||||||||||||||||||
See “Trust Accounts” in Note 3, Balance Sheet Components, for information on the Non-qualified benefit plan trust. | ||||||||||||||||||||||||||||||||||||
Investment Policy and Asset Allocation—The Board of Directors of PGE appoints an Investment Committee, which is comprised of officers of the Company. In addition, the Board also establishes the Company’s asset allocation. The Investment Committee is then responsible for implementation and oversight of the asset allocation. The Company’s investment policy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities and other alternative investments. The commitments to each class are controlled by an asset deployment and cash management strategy that takes profits from asset classes whose allocations have shifted above their target ranges to fund benefit payments and investments in asset classes whose allocations have shifted below their target ranges. | ||||||||||||||||||||||||||||||||||||
The asset allocations for the plans, and the target allocation, are as follows: | ||||||||||||||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||
Actual | Target * | Actual | Target * | |||||||||||||||||||||||||||||||||
Defined Benefit Pension Plan: | ||||||||||||||||||||||||||||||||||||
Equity securities | 66 | % | 67 | % | 67 | % | 67 | % | ||||||||||||||||||||||||||||
Debt securities | 34 | 33 | 33 | 33 | ||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||||||||||||||||||||
Other Postretirement Benefit Plans: | ||||||||||||||||||||||||||||||||||||
Equity securities | 66 | % | 67 | % | 58 | % | 58 | % | ||||||||||||||||||||||||||||
Debt securities | 34 | 33 | 42 | 42 | ||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||||||||||||||||||||
Non-Qualified Benefits Plans: | ||||||||||||||||||||||||||||||||||||
Equity securities | 19 | % | 13 | % | 24 | % | 16 | % | ||||||||||||||||||||||||||||
Debt securities | 1 | 7 | 1 | 9 | ||||||||||||||||||||||||||||||||
Insurance contracts | 80 | 80 | 75 | 75 | ||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||||||||||||||||||||
* | The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the Non-Qualified Benefit Plans, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and Non-Qualified Benefit Plans, reported percentages are affected by the fair market values of the investments within the pools. | |||||||||||||||||||||||||||||||||||
The Company’s overall investment strategy is to meet the goals and objectives of the individual plans through a wide diversification of asset types, fund strategies, and fund managers. Equity securities primarily include investments across the capitalization ranges and style biases, both domestically and internationally. Fixed income securities include, but are not limited to, corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other types of investments include investments in hedge funds and private equity funds that follow several different strategies. | ||||||||||||||||||||||||||||||||||||
The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions): | ||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||
As of December 31, 2014: | ||||||||||||||||||||||||||||||||||||
Defined Benefit Pension Plan assets: | ||||||||||||||||||||||||||||||||||||
Money market funds | $ | — | $ | 6 | $ | — | $ | 6 | ||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | $ | 42 | $ | 146 | $ | — | $ | 188 | ||||||||||||||||||||||||||||
International | — | 171 | — | 171 | ||||||||||||||||||||||||||||||||
Debt securities: | ||||||||||||||||||||||||||||||||||||
Domestic government and corporate credit | — | 197 | — | 197 | ||||||||||||||||||||||||||||||||
Private equity funds | — | — | 29 | 29 | ||||||||||||||||||||||||||||||||
$ | 42 | $ | 520 | $ | 29 | $ | 591 | |||||||||||||||||||||||||||||
Other Postretirement Benefit Plans assets: | ||||||||||||||||||||||||||||||||||||
Money market funds | $ | — | $ | 6 | $ | — | $ | 6 | ||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | 10 | 1 | — | 11 | ||||||||||||||||||||||||||||||||
International | 10 | — | — | 10 | ||||||||||||||||||||||||||||||||
Debt securities—Domestic government | 5 | — | — | 5 | ||||||||||||||||||||||||||||||||
$ | 25 | $ | 7 | $ | — | $ | 32 | |||||||||||||||||||||||||||||
As of December 31, 2013: | ||||||||||||||||||||||||||||||||||||
Defined Benefit Pension Plan assets: | ||||||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | $ | 166 | $ | 19 | $ | — | $ | 185 | ||||||||||||||||||||||||||||
International | 185 | — | — | 185 | ||||||||||||||||||||||||||||||||
Debt securities: | ||||||||||||||||||||||||||||||||||||
Domestic government and corporate credit | — | 181 | — | 181 | ||||||||||||||||||||||||||||||||
Corporate credit | 14 | — | — | 14 | ||||||||||||||||||||||||||||||||
Private equity funds | — | — | 31 | 31 | ||||||||||||||||||||||||||||||||
$ | 365 | $ | 200 | $ | 31 | $ | 596 | |||||||||||||||||||||||||||||
Other Postretirement Benefit Plans assets: | ||||||||||||||||||||||||||||||||||||
Money market funds | $ | — | $ | 10 | $ | — | $ | 10 | ||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | 8 | 2 | — | 10 | ||||||||||||||||||||||||||||||||
International | 9 | — | — | 9 | ||||||||||||||||||||||||||||||||
Debt securities—Domestic government | 3 | — | — | 3 | ||||||||||||||||||||||||||||||||
$ | 20 | $ | 12 | $ | — | $ | 32 | |||||||||||||||||||||||||||||
An overview of the identification of Level 1, 2, and 3 financial instruments is provided in Note 4, Fair Value of Financial Instruments. The following methods are used in valuation of each asset class of investments held in the pension and other postretirement benefit plan trusts. | ||||||||||||||||||||||||||||||||||||
Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short term treasury bills, federal agency securities, certificates of deposit, and commercial paper. Money market funds held in the trusts are classified as Level 2 instruments as they are traded in an active market of similar securities but are not directly valued using quoted prices. | ||||||||||||||||||||||||||||||||||||
Equity securities—Equity mutual fund and common stock securities are classified as Level 1 securities as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 securities due to pricing inputs that are not directly or indirectly observable in the marketplace. | ||||||||||||||||||||||||||||||||||||
Debt securities—PGE invests in highly-liquid United States treasury and corporate credit mutual fund securities to support the investment objectives of the trusts. These securities are classified as Level 1 instruments due to the highly observable nature of pricing in an active market. | ||||||||||||||||||||||||||||||||||||
Fair values for Level 2 debt securities, including municipal debt and corporate credit securities, mortgage-backed securities and asset-backed securities are determined by evaluating pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation if applicable. | ||||||||||||||||||||||||||||||||||||
Private equity funds—PGE invests in a combination of primary and secondary fund-of-funds which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, venture capital, buyout and special situations. Private equity investments are classified as Level 3 securities due to fund valuation methodologies that utilize discounted cash flow, market comparable and limited secondary market pricing to develop estimates of fund valuation. PGE valuation of individual fund performance compares stated fund performance against published benchmarks. | ||||||||||||||||||||||||||||||||||||
Changes in the fair value of assets held by the pension plan classified as Level 3 in the fair value hierarchy, which consists of Private equity funds, were as follows (in millions): | ||||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||
Level 3 balance as of beginning of year | $ | 31 | $ | 32 | ||||||||||||||||||||||||||||||||
Unrealized gains, net | 2 | 4 | ||||||||||||||||||||||||||||||||||
Realized gains (losses), net | 3 | (2 | ) | |||||||||||||||||||||||||||||||||
Sales, net | (7 | ) | (3 | ) | ||||||||||||||||||||||||||||||||
Level 3 balance as of end of year | $ | 29 | $ | 31 | ||||||||||||||||||||||||||||||||
The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and non-qualified benefit plans as of and for the years ended December 31, 2014 and 2013. Information related to the Other NQBP is not included in the following tables (dollars in millions): | ||||||||||||||||||||||||||||||||||||
Defined Benefit Pension Plan | Other Postretirement | Non-Qualified | ||||||||||||||||||||||||||||||||||
Benefits | Benefit Plans | |||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||
Benefit obligation: | ||||||||||||||||||||||||||||||||||||
As of January 1 | $ | 705 | $ | 728 | $ | 77 | $ | 84 | $ | 24 | $ | 27 | ||||||||||||||||||||||||
Service cost | 15 | 17 | 2 | 2 | — | — | ||||||||||||||||||||||||||||||
Interest cost | 34 | 30 | 4 | 3 | 1 | 1 | ||||||||||||||||||||||||||||||
Participants’ contributions | — | — | 1 | 2 | — | — | ||||||||||||||||||||||||||||||
Actuarial (gain) loss | 72 | (38 | ) | 4 | (9 | ) | 5 | (2 | ) | |||||||||||||||||||||||||||
Contractual termination benefits | — | — | 1 | 1 | — | — | ||||||||||||||||||||||||||||||
Benefit payments | (48 | ) | (32 | ) | (6 | ) | (6 | ) | (3 | ) | (2 | ) | ||||||||||||||||||||||||
Administrative expenses | (1 | ) | — | — | — | — | — | |||||||||||||||||||||||||||||
As of December 31 | $ | 777 | $ | 705 | $ | 83 | $ | 77 | $ | 27 | $ | 24 | ||||||||||||||||||||||||
Fair value of plan assets: | ||||||||||||||||||||||||||||||||||||
As of January 1 | $ | 596 | $ | 537 | $ | 32 | $ | 28 | $ | 16 | $ | 15 | ||||||||||||||||||||||||
Actual return on plan assets | 44 | 91 | 1 | 5 | 1 | 3 | ||||||||||||||||||||||||||||||
Company contributions | — | — | 4 | 3 | 1 | — | ||||||||||||||||||||||||||||||
Participants’ contributions | — | — | 1 | 2 | — | — | ||||||||||||||||||||||||||||||
Benefit payments | (48 | ) | (32 | ) | (6 | ) | (6 | ) | (3 | ) | (2 | ) | ||||||||||||||||||||||||
Administrative expenses | (1 | ) | — | — | — | — | — | |||||||||||||||||||||||||||||
As of December 31 | $ | 591 | $ | 596 | $ | 32 | $ | 32 | $ | 15 | $ | 16 | ||||||||||||||||||||||||
Unfunded position as of December 31 | $ | (186 | ) | $ | (109 | ) | $ | (51 | ) | $ | (45 | ) | $ | (12 | ) | $ | (8 | ) | ||||||||||||||||||
Accumulated benefit plan obligation as of December 31 | $ | 691 | $ | 631 | N/A | N/A | $ | 27 | $ | 24 | ||||||||||||||||||||||||||
Classification in consolidated balance sheet: | ||||||||||||||||||||||||||||||||||||
Noncurrent asset | $ | — | $ | — | $ | — | $ | — | $ | 15 | $ | 16 | ||||||||||||||||||||||||
Current liability | — | — | — | — | (2 | ) | (2 | ) | ||||||||||||||||||||||||||||
Noncurrent liability | (186 | ) | (109 | ) | (51 | ) | (45 | ) | (25 | ) | (22 | ) | ||||||||||||||||||||||||
Net liability | $ | (186 | ) | $ | (109 | ) | $ | (51 | ) | $ | (45 | ) | $ | (12 | ) | $ | (8 | ) | ||||||||||||||||||
Amounts included in comprehensive income: | ||||||||||||||||||||||||||||||||||||
Net actuarial (gain) loss | $ | 67 | $ | (89 | ) | $ | 5 | $ | (11 | ) | $ | 5 | $ | (1 | ) | |||||||||||||||||||||
Amortization of net actuarial loss | (17 | ) | (24 | ) | (1 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||||||||||||||||||
Amortization of prior service cost | — | — | (1 | ) | (1 | ) | — | — | ||||||||||||||||||||||||||||
$ | 50 | $ | (113 | ) | $ | 3 | $ | (13 | ) | $ | 4 | $ | (2 | ) | ||||||||||||||||||||||
Amounts included in AOCL*: | ||||||||||||||||||||||||||||||||||||
Net actuarial loss | $ | 236 | $ | 186 | $ | 10 | $ | 6 | $ | 13 | $ | 9 | ||||||||||||||||||||||||
Prior service cost | — | — | 1 | 2 | — | — | ||||||||||||||||||||||||||||||
$ | 236 | $ | 186 | $ | 11 | $ | 8 | $ | 13 | $ | 9 | |||||||||||||||||||||||||
Defined Benefit Pension Plan | Other Postretirement | Non-Qualified | ||||||||||||||||||||||||||||||||||
Benefits | Benefit Plans | |||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||
Assumptions used: | ||||||||||||||||||||||||||||||||||||
Discount rate for benefit obligation | 4.02 | % | 4.84 | % | 3.07 | % | - | 3.46 | % | - | 4.02 | % | 4.84 | % | ||||||||||||||||||||||
4.1 | % | 4.96 | % | |||||||||||||||||||||||||||||||||
Discount rate for benefit cost | 4.84 | % | 4.24 | % | 3.46 | % | - | 2.77 | % | - | 4.84 | % | 4.24 | % | ||||||||||||||||||||||
4.96 | % | 4.13 | % | |||||||||||||||||||||||||||||||||
Weighted average rate of compensation increase for benefit obligation | 3.65 | % | 3.65 | % | 4.58 | % | 4.58 | % | N/A | N/A | ||||||||||||||||||||||||||
Weighted average rate of compensation increase for benefit cost | 3.65 | % | 3.65 | % | 4.58 | % | 4.58 | % | N/A | N/A | ||||||||||||||||||||||||||
Long-term rate of return on plan assets for benefit obligation | 7.5 | % | 7.5 | % | 6.37 | % | 6.46 | % | N/A | N/A | ||||||||||||||||||||||||||
Long-term rate of return on plan assets for benefit cost | 7.5 | % | 8.25 | % | 6.46 | % | 5.89 | % | N/A | N/A | ||||||||||||||||||||||||||
* | Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are transferred to Regulatory assets due to the future recoverability from retail customers. Accordingly, as of the balance sheet date, such amounts are included in Regulatory assets. | |||||||||||||||||||||||||||||||||||
Net periodic benefit cost consists of the following for the years ended December 31 (in millions): | ||||||||||||||||||||||||||||||||||||
Defined Benefit | Other Postretirement | Non-Qualified | ||||||||||||||||||||||||||||||||||
Pension Plan | Benefits | Benefit Plans | ||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||||||
Service cost | $ | 15 | $ | 17 | $ | 14 | $ | 2 | $ | 2 | $ | 2 | $ | — | $ | — | $ | — | ||||||||||||||||||
Interest cost on benefit obligation | 34 | 30 | 31 | 4 | 3 | 3 | 1 | 1 | 1 | |||||||||||||||||||||||||||
Expected return on plan assets | (39 | ) | (40 | ) | (41 | ) | (2 | ) | (1 | ) | (1 | ) | — | — | — | |||||||||||||||||||||
Amortization of prior service cost | — | — | — | 1 | 1 | 1 | — | — | — | |||||||||||||||||||||||||||
Amortization of net actuarial loss | 17 | 24 | 17 | 1 | 1 | 1 | 1 | 1 | 1 | |||||||||||||||||||||||||||
Net periodic benefit cost | $ | 27 | $ | 31 | $ | 21 | $ | 6 | $ | 6 | $ | 6 | $ | 2 | $ | 2 | $ | 2 | ||||||||||||||||||
PGE estimates that $23 million will be amortized from AOCL into net periodic benefit cost in 2015, consisting of a net actuarial loss of $20 million for pension benefits, $1 million for non-qualified benefits and $1 million for other postretirement benefits, and prior service cost of $1 million for other postretirement benefits. Amounts related to the pension and other postretirement benefits are offset with the amortization of the corresponding regulatory asset. | ||||||||||||||||||||||||||||||||||||
The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions): | ||||||||||||||||||||||||||||||||||||
Payments Due | ||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | 2020 - 2024 | |||||||||||||||||||||||||||||||
Defined benefit pension plan | $ | 35 | $ | 37 | $ | 38 | $ | 40 | $ | 41 | $ | 221 | ||||||||||||||||||||||||
Other postretirement benefits | 5 | 5 | 5 | 5 | 5 | 26 | ||||||||||||||||||||||||||||||
Non-qualified benefit plans | 2 | 2 | 2 | 2 | 3 | 9 | ||||||||||||||||||||||||||||||
Total | $ | 42 | $ | 44 | $ | 45 | $ | 47 | $ | 49 | $ | 256 | ||||||||||||||||||||||||
All of the plans develop expected long-term rates of return for the major asset classes using long-term historical returns, with adjustments based on current levels and forecasts of inflation, interest rates, and economic growth. Also included are incremental rates of return provided by investment managers whose returns are expected to be greater than the markets in which they invest. | ||||||||||||||||||||||||||||||||||||
For measurement purposes, the assumed health care cost trend rates, which can affect amounts reported for the health care plans, were as follows: | ||||||||||||||||||||||||||||||||||||
• | For 2014, 7% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019; | |||||||||||||||||||||||||||||||||||
• | For 2013, 7.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2014, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019; and | |||||||||||||||||||||||||||||||||||
• | For 2012, 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2013, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019. | |||||||||||||||||||||||||||||||||||
A one percentage point increase or decrease in the above health care cost assumption would have no material impact on total service or interest cost, or on the postretirement benefit obligation. | ||||||||||||||||||||||||||||||||||||
401(k) Retirement Savings Plan | ||||||||||||||||||||||||||||||||||||
PGE sponsors a 401(k) Plan that covers substantially all employees. For eligible employees who are covered by PGE’s defined benefit pension plan, the Company matches employee contributions up to 6% of the employee’s base pay. For eligible employees who are not covered by PGE’s defined benefit pension plan, the Company contributes 5% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan, and also matches employee contributions up to 5% of the employee’s base pay. | ||||||||||||||||||||||||||||||||||||
For the majority of bargaining employees who are subject to the International Brotherhood of Electrical Workers Local 125 agreements the Company contributes an additional 1% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan. | ||||||||||||||||||||||||||||||||||||
All contributions are invested in accordance with employees’ elections, limited to investment options available under the 401(k) Plan. PGE made contributions to employee accounts of $16 million in 2014, 2013 and 2012. |
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Income Taxes Note [Abstract] | ||||||||||||
Income Taxes | INCOME TAXES | |||||||||||
Income tax expense consists of the following (in millions): | ||||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Current: | ||||||||||||
Federal | $ | 20 | $ | 10 | $ | 16 | ||||||
State and local | 2 | — | 1 | |||||||||
22 | 10 | 17 | ||||||||||
Deferred: | ||||||||||||
Federal | 26 | 4 | 30 | |||||||||
State and local | 13 | 7 | 17 | |||||||||
39 | 11 | 47 | ||||||||||
Income tax expense | $ | 61 | $ | 21 | $ | 64 | ||||||
The significant differences between the U.S. federal statutory rate and PGE’s effective tax rate for financial reporting purposes are as follows: | ||||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory tax rate | 35 | % | 35 | % | 35 | % | ||||||
Federal tax credits | (11.4 | ) | (21.8 | ) | (11.8 | ) | ||||||
State and local taxes, net of federal tax benefit | 3.9 | 3.4 | 3.5 | |||||||||
Flow through depreciation and cost basis differences | (2.3 | ) | 2.8 | 2.4 | ||||||||
Adjustment to deferred taxes for change in blended composite state tax rate | — | — | 2.6 | |||||||||
Other | 0.8 | (2.6 | ) | (0.6 | ) | |||||||
Effective tax rate | 26 | % | 16.8 | % | 31.1 | % | ||||||
Deferred income tax assets and liabilities consist of the following (in millions): | ||||||||||||
As of December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Deferred income tax assets: | ||||||||||||
Employee benefits | $ | 161 | $ | 122 | ||||||||
Price risk management | 88 | 71 | ||||||||||
Regulatory liabilities | 48 | 33 | ||||||||||
Tax credits | 13 | 51 | ||||||||||
Other | 1 | — | ||||||||||
Total deferred income tax assets | 311 | 277 | ||||||||||
Deferred income tax liabilities: | ||||||||||||
Depreciation and amortization | 693 | 646 | ||||||||||
Regulatory assets | 210 | 175 | ||||||||||
Total deferred income tax liabilities | 903 | 821 | ||||||||||
Deferred income tax liability, net | $ | (592 | ) | $ | (544 | ) | ||||||
Classification of net deferred income taxes: | ||||||||||||
Current deferred income tax asset * | $ | 33 | $ | 42 | ||||||||
Noncurrent deferred income tax liability | (625 | ) | (586 | ) | ||||||||
$ | (592 | ) | $ | (544 | ) | |||||||
* Included in Other current assets in the consolidated balance sheets. | ||||||||||||
To conform with the 2014 presentation, the Company reclassified $17 million to Regulatory liabilities from Other in the 2013 deferred income tax assets section of the preceding table. | ||||||||||||
As of December 31, 2014, PGE has federal and state tax credit carryforwards of $10 million and $3 million, respectively, which will expire at various dates from 2021 through 2036. | ||||||||||||
PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 2014 and 2013 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 2014 and 2013, PGE had no unrecognized tax benefits. | ||||||||||||
PGE and its subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns in certain jurisdictions, including Oregon, California, Montana, and certain local jurisdictions. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2010 and all issues were resolved related to those years. The Company does not believe that any open tax years for federal or state income taxes could result in any adjustments that would be significant to the consolidated financial statements. | ||||||||||||
Further guidance was issued during 2014 that clarified final regulations issued on September 13, 2013, regarding the deduction and capitalization of expenditures related to tangible property. The final regulations under Internal Revenue Code Sections 162, 167 and 263(a) apply to amounts paid to acquire, produce, or improve tangible property, as well as dispositions of such property and have been adopted by PGE as of the January 1, 2014 effective date. The adoption of these regulations, including the consideration of subsequent guidance, did not have a material impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows. | ||||||||||||
House of Representatives Bill 5771—The Tax Increase Prevention Act of 2014 was signed into law on December 19, 2014. PGE has examined the new law and while the Company intends to take advantage of some of the provisions, no provision will materially impact its consolidated financial position. |
Stock_Purchase_Plan
Stock Purchase Plan | 12 Months Ended |
Dec. 31, 2014 | |
Employee Stock Purchase Plan Note [Abstract] | |
Stock Purchase Plan [Text Block] | EQUITY-BASED PLANS |
Equity Forward Sale Agreement | |
PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 11,100,000 shares of its common stock in June 2013. In connection with such public offering, the underwriters exercised their over-allotment option in full and PGE issued 1,665,000 shares of its common stock for net proceeds of $47 million. Pursuant to the terms of the EFSA, a forward counterparty borrowed 11,100,000 shares of PGE’s common stock from third parties in the open market and sold the shares to a group of underwriters for $29.50 per share, less an underwriting discount equal to $0.96 per share. The underwriters then sold the shares in a public offering. PGE receives proceeds from the sale of common stock when the EFSA is physically settled (described below), and at that time PGE issues new shares of common stock and records the proceeds in equity. Through December 31, 2014, the Company has issued 700,000 shares of its common stock pursuant to the EFSA for net proceeds of $20 million. | |
Under the terms of the EFSA, PGE may elect to settle the equity forward transactions by means of: i) physical; ii) cash; or iii) net share settlement, in whole or in part, at any time on or prior to June 11, 2015, except in specified circumstances or events that would require physical settlement. To the extent that the transactions are physically settled, PGE would be required to issue and deliver shares of PGE common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $29.50 per share at the time the EFSA was entered into, and the amount of cash to be received by PGE upon physical settlement of the EFSA is subject to certain adjustments in accordance with the terms of the EFSA. | |
The EFSA had no initial fair value since it was entered into at the then market price of the common stock. Accordingly, PGE concluded that the EFSA was an equity instrument which does not qualify as a derivative because the EFSA was indexed to the Company’s stock. PGE anticipates settling the EFSA through physical settlement on or before June 11, 2015. | |
As of December 31, 2014, the Company could have physically settled the EFSA by delivering 10,400,000 shares to the forward counterparty in exchange for cash of $275 million. In addition, at December 31, 2014, the Company could have elected to make a cash settlement by paying approximately $119 million, or a net share settlement by delivering approximately 3,135,000 shares of common stock. To the extent that PGE makes a cash or net share settlement, the Company would receive no additional proceeds from the public offering. | |
Prior to settlement, the potentially issuable shares pursuant to the EFSA will be reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period). | |
Employee Stock Purchase Plan | |
PGE has an employee stock purchase plan (ESPP), under which a total of 625,000 shares of the Company’s common stock may be issued. The ESPP permits all eligible employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000 in common stock (based on fair value on the purchase date) or 1,500 shares, whichever is less. There are two six-month offering periods each year, January 1 through June 30 and July 1 through December 31, during which eligible employees may purchase shares of PGE common stock at a price equal to 95% of the fair value of the stock on the purchase date, the last day of the offering period. As of December 31, 2014, there were 427,021 shares available for future issuance pursuant to the ESPP. | |
Dividend Reinvestment and Direct Stock Purchase Plan | |
PGE has a Dividend Reinvestment and Direct Stock Purchase Plan (DRIP), under which a total of 2,500,000 shares of the Company’s common stock may be issued. Under the DRIP, investors may elect to buy shares of the Company’s common stock or elect to reinvest cash dividends in additional shares of the Company’s common stock. As of December 31, 2014, there were 2,481,110 shares available for future issuance pursuant to the DRIP. |
Stockbased_Compensation_Expens
Stock-based Compensation Expense | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Text Block] | STOCK-BASED COMPENSATION EXPENSE | |||||||||
Pursuant to the Portland General Electric Company 2006 Stock Incentive Plan (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units (RSUs) with time-based vesting conditions (time-based RSUs) and performance-based vesting conditions (performance-based RSUs) to non-employee directors, officers and certain key employees. Service requirements generally must be met for RSUs to vest. For each grant, the number of RSUs is determined by dividing the specified award amount for each grantee by the closing stock price on the date of grant. RSU activity is summarized in the following table: | ||||||||||
Units | Weighted Average | |||||||||
Grant Date | ||||||||||
Fair Value | ||||||||||
Outstanding as of December 31, 2011 | 491,404 | $ | 18.54 | |||||||
Granted | 186,495 | 24.72 | ||||||||
Forfeited | (22,947 | ) | 18.95 | |||||||
Vested | (214,390 | ) | 15.67 | |||||||
Outstanding as of December 31, 2012 | 440,562 | 22.54 | ||||||||
Granted | 183,071 | 29.25 | ||||||||
Forfeited | (7,007 | ) | 27.15 | |||||||
Vested | (185,536 | ) | 20.2 | |||||||
Outstanding as of December 31, 2013 | 431,090 | 26.31 | ||||||||
Granted | 203,410 | 31.49 | ||||||||
Forfeited | (12,278 | ) | 29.9 | |||||||
Vested | (158,329 | ) | 24.95 | |||||||
Outstanding as of December 31, 2014 | 463,893 | 28.96 | ||||||||
A total of 4,687,500 shares of common stock were registered for future issuance under the Plan, of which 3,554,884 shares remain available for future issuance as of December 31, 2014. | ||||||||||
Outstanding RSUs provide for the payment of one Dividend Equivalent Right (DER) for each stock unit. DERs represent an amount equal to dividends paid to shareholders on a share of PGE’s common stock and vest on the same schedule as the RSUs. The DERs are settled in cash (for grants to non-employee directors) or shares of PGE common stock valued either at the closing stock price on the vesting date (for performance-based RSUs) or dividend payment date (for all other grants). The cash from the settlement of the DERs for non-employee directors may be deferred under the terms of the Portland General Electric Company 2006 Outside Directors’ Deferred Compensation Plan. | ||||||||||
Time-based RSUs vest in either equal installments over a one-year period on the last day of each calendar quarter, over a three-year period on each anniversary of the grant date, or at the end of a three-year period following the grant date. The fair value of time-based RSUs is measured based on the closing price of PGE common stock on the date of grant and charged to compensation expense on a straight-line basis over the requisite service period for the entire award. The total value of time-based RSUs vested was less than $1 million for the years ended December 31, 2014, 2013, and 2012. | ||||||||||
Performance-based RSUs vest if performance goals are met at the end of a three-year performance period. For grants prior to March 5, 2013, such goals include return on equity relative to allowed return on equity, and regulated asset base growth. Grants on and after March 5, 2013 are based on three equally-weighted metrics: return on equity relative to allowed return on equity; regulated asset growth; and a relative total shareholder return (TSR) of PGE’s common stock as compared to the Edison Electric Institute Regulated Index (EEI Index) during the performance period. Vesting of performance-based RSUs is calculated by multiplying the number of units granted by a performance percentage determined by the Compensation and Human Resources Committee of PGE’s Board of Directors. The performance percentage is calculated based on the extent to which the performance goals are met. In accordance with the Plan, however, the committee may disregard or offset the effect of extraordinary, unusual or non-recurring items in determining results relative to these goals. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant. | ||||||||||
For the return on equity and regulated asset base growth portions of the performance-based RSUs, fair value is measured based on the closing price of PGE common stock on the date of grant. For the TSR portion of the performance-based RSUs, fair value is determined using a Monte Carlo simulation model utilizing actual information for the common shares of PGE and its peer group for the period from the beginning of the performance period to the grant date and estimated future stock volatility over the remaining performance period. The fair value of stock-based compensation related to the TSR component of performance-based RSUs was determined using the Monte Carlo model and the following weighted average assumptions: | ||||||||||
2014 | 2013 | |||||||||
Risk-free interest rate | 0.6 | % | 0.3 | % | ||||||
Expected dividend yield | — | % | — | % | ||||||
Expected term (in years) | 3 | 3 | ||||||||
Volatility | 12.40% | - | 23.00% | 12.10% | - | 25.10% | ||||
The fair value of performance-based RSUs is charged to compensation expense on a straight-line basis over the requisite service period for the entire award based on the number of shares expected to vest. Stock-based compensation expense was calculated assuming the attainment of performance goals that would allow the weighted average vesting of 134.2%, 117.5%, and 112.0% of awarded performance-based RSUs for 2014, 2013, and 2012, respectively, with an estimated 5% forfeiture rate. | ||||||||||
The total value of performance-based RSUs vested was $3 million for the years ended December 31, 2014, 2013, and 2012. | ||||||||||
Stock-based compensation was $6 million for the year ended December 31, 2014, and $4 million in 2013 and in 2012, which is included in Administrative and other expense in the consolidated statements of income. Such amounts differ from those reported in the consolidated statements of equity for Stock-based compensation due primarily to the impact from the income tax payments made on behalf of employees. The Company withholds a portion of the vested shares for the payment of income taxes on behalf of the employees. The net impact to equity from the income tax payments, partially offset by the issuance of DERs, resulted in a charge to equity of $1 million in 2014, $2 million in 2013, and $1 million in 2012, which is not included in Administrative and other expenses in the consolidated statements of income. | ||||||||||
As of December 31, 2014, unrecognized stock-based compensation expense was $6 million, of which approximately $4 million and $2 million is expected to be expensed in 2015 and 2016, respectively. No stock-based compensation costs have been capitalized and the Plan had no material impact on cash flows for the years ended December 31, 2014, 2013, or 2012. |
Earnings_Per_Share
Earnings Per Share | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Earnings Per Share [Abstract] | |||||||||
Earnings Per Share | EARNINGS PER SHARE | ||||||||
Basic earnings per share is computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share is computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; ii) unvested time-based and performance-based restricted stock units, along with associated dividend equivalent rights; and iii) shares issuable pursuant to the EFSA. See Note 12, Equity-based Plans, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria has been met. | |||||||||
Net income attributable to PGE common shareholders is the same for both the basic and diluted earnings per share computation. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands): | |||||||||
Years Ended December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
Weighted average common shares outstanding—basic | 78,180 | 76,821 | 75,498 | ||||||
Dilutive effect of potential common shares | 2,314 | 567 | 149 | ||||||
Weighted average common shares outstanding—diluted | 80,494 | 77,388 | 75,647 | ||||||
Commitments_and_Guarantees
Commitments and Guarantees | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ||||||||||||||||||||||||||||
Commitments and Guarantees [Text Block] | COMMITMENTS AND GUARANTEES | |||||||||||||||||||||||||||
Commitments | ||||||||||||||||||||||||||||
As of December 31, 2014, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions): | ||||||||||||||||||||||||||||
Payments Due | ||||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||||||||
Capital and other purchase commitments | $ | 242 | $ | 21 | $ | 2 | $ | 2 | $ | 2 | $ | 74 | $ | 343 | ||||||||||||||
Purchased power and fuel: | ||||||||||||||||||||||||||||
Electricity purchases | 179 | 167 | 140 | 143 | 143 | 833 | 1,605 | |||||||||||||||||||||
Capacity contracts | 27 | 26 | 6 | 6 | 5 | 20 | 90 | |||||||||||||||||||||
Public utility districts | 8 | 7 | 5 | 4 | 2 | 23 | 49 | |||||||||||||||||||||
Natural gas | 56 | 37 | 40 | 40 | 36 | 244 | 453 | |||||||||||||||||||||
Coal and transportation | 23 | 14 | 11 | 5 | 5 | — | 58 | |||||||||||||||||||||
Operating leases | 10 | 11 | 12 | 11 | 8 | 192 | 244 | |||||||||||||||||||||
Total | $ | 545 | $ | 283 | $ | 216 | $ | 211 | $ | 201 | $ | 1,386 | $ | 2,842 | ||||||||||||||
Capital and other purchase commitments—Certain commitments have been made for capital and other purchases for 2015 and beyond. Such commitments include those related to hydro licenses, upgrades to generating, distribution and transmission facilities, information systems, and system maintenance work. A large component of these commitments for 2015 are costs associated with the construction of Carty. Termination of these agreements could result in cancellation charges. | ||||||||||||||||||||||||||||
Electricity purchases and Capacity contracts—PGE has power purchase contracts with counterparties, which expire at varying dates through 2049, and power capacity contracts through 2019. In addition to the power purchase contracts with counterparties presented in the table, PGE has power sale contracts with counterparties of approximately $43 million that settle as follows: $14 million in 2015; $11 million in 2016 and 2017; and $7 million in 2018. | ||||||||||||||||||||||||||||
Public utility districts—PGE has long-term power purchase agreements with certain public utility districts in the state of Washington and with the City of Portland, Oregon. Under the agreements, the Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether or not they are operable. The future minimum payments for the public utility districts in the preceding table reflect the principal payment only and do not include interest, operation, or maintenance expenses. Selected information regarding these projects is summarized as follows (dollars in millions): | ||||||||||||||||||||||||||||
Revenue Bonds as of December 31, 2014 | PGE’s Share as of December 31, 2014 | Contract | PGE Cost, | |||||||||||||||||||||||||
Expiration | including Debt Service | |||||||||||||||||||||||||||
Output | Capacity | 2014 | 2013 | 2012 | ||||||||||||||||||||||||
(in MW) | ||||||||||||||||||||||||||||
Priest Rapids and Wanapum | $ | 1,102 | 8.6 | % | 163 | 2052 | $ | 14 | $ | 14 | $ | 14 | ||||||||||||||||
Wells | 215 | 19.4 | 150 | 2018 | 10 | 10 | 10 | |||||||||||||||||||||
Portland Hydro | 4 | 100 | 36 | 2017 | 4 | 4 | 4 | |||||||||||||||||||||
The agreements for Priest Rapids and Wanapum and Wells provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro rata share of the output and operating and debt service costs of the defaulting purchaser. For Wells, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchaser’s percentage. For Priest Rapids and Wanapum, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax exempt status of any outstanding debt. | ||||||||||||||||||||||||||||
Natural gas—PGE has agreements for the purchase and transportation of natural gas from domestic and Canadian sources for its natural gas-fired generating facilities. The Company also has a natural gas storage agreement for the purpose of fueling the Company’s natural gas-fired generating plants (Port Westward Unit 1 (PW1), PW2 and Beaver). | ||||||||||||||||||||||||||||
Coal and transportation—PGE has coal and related rail transportation agreements with take-or-pay provisions related to Boardman, which expire at various dates through 2020. | ||||||||||||||||||||||||||||
Operating leases—PGE has various operating leases associated with its headquarters and certain of its production, transmission, and support facilities. The majority of the future minimum operating lease payments presented in the table consist of i) the corporate headquarters lease, which expires in 2018, but includes renewal period options through 2043, and ii) the Port of St. Helens land lease, where PW1, PW2 and Beaver are located, which expires in 2096. Rent expense was $11 million in 2014, $9 million in 2013, and $10 million in 2012. | ||||||||||||||||||||||||||||
The future minimum operating lease payments presented is net of sublease income of: $3 million in 2015; $2 million in 2016; and $1 million in 2017, 2018 and 2019. Sublease income was $3 million in 2014, 2013 and 2012. | ||||||||||||||||||||||||||||
Guarantees | ||||||||||||||||||||||||||||
PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of December 31, 2014, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the consolidated balance sheets with respect to these indemnities. |
Variable_Interest_Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2014 | |
Variable interest Entities [Abstract] | |
VariableInterestEntities [Text Block] | VARIABLE INTEREST ENTITIES |
PGE has determined that as of December 31, 2014 it is the primary beneficiary of two VIEs (three as of December 31, 2013), and, therefore, consolidates the VIEs within the Company’s consolidated financial statements. Such arrangements were formed for the sole purpose of designing, developing, constructing, owning, maintaining, operating and financing photovoltaic solar power facilities located on real property owned by third parties, and selling the energy generated by the facilities. The Company is the Managing Member and a financial institution is the Investor Member in each of the Limited Liability Companies (LLCs), holding equity interests of less than 1% and more than 99%, respectively, in each entity. PGE has determined that its interests in these VIEs contain the obligation to absorb the variability of the entities that could potentially be significant to the VIEs, and the Company has the power to direct the activities that most significantly affect the entities’ economic performance. | |
Determining whether PGE is the primary beneficiary of a VIE is complex, subjective and requires the use of judgments and assumptions. Significant judgments and assumptions made by PGE in determining it is the primary beneficiary of these LLCs include the following: i) PGE has the experience to own and operate electric generating facilities and is authorized to operate the LLCs pursuant to the operating agreements, and, therefore, PGE has control over the most significant activities of the LLCs; ii) PGE expects to own 100% of the LLCs shortly after five years have elapsed from when the facility was placed in service, at which time the facilities will have approximately 75% of their estimated useful life remaining; and iii) based on projections prepared in accordance with the operating agreements, PGE expects to absorb a majority of any expected losses of the LLCs. | |
Included in PGE’s consolidated balance sheets as of December 31, 2014 and 2013 are LLC net assets of $4 million and $5 million, respectively, primarily comprised of Electric utility plant, and includes Cash and cash equivalents of $1 million as of December 31, 2013. These assets can only be used to settle the obligations of the consolidated VIEs and their creditors have no recourse to the general credit of PGE. | |
In January 2015, PGE acquired the equity interest held by the Investor Member of one of the LLCs pursuant to the terms of the operating agreement. The transaction did not have a significant impact to the Company’s consolidated financial position, consolidated results of operations or consolidated cash flows. |
Jointlyowned_Plant
Jointly-owned Plant | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Jointly-owned Plant [Abstract] | |||||||||||||||||||
Jointly-owned Plant [Text Block] | JOINTLY-OWNED PLANT | ||||||||||||||||||
PGE has interests in three jointly-owned generating facilities. Under the joint operating agreements, each participating owner is responsible for financing its share of construction, operating and leasing costs. PGE’s proportionate share of direct operating and maintenance expenses of the facilities is included in the corresponding operating and maintenance expense categories in the consolidated statements of income. | |||||||||||||||||||
In 1985, PGE sold a 15% undivided interest in Boardman and a 10.714% undivided interest in the Company’s share of the Pacific Northwest Intertie transmission line (jointly, the Facility Assets) to an unrelated third party (Purchaser). Under terms of the original 1985 agreements, on December 31, 2013, PGE acquired the Facility Assets from the Purchaser in exchange for $1 from the Purchaser. PGE assumed responsibility for the ARO related to that 15% interest in Boardman in the amount of $7 million. The acquisition of the 15% interest in Boardman increased the Company’s ownership share from 65% to 80% on December 31, 2013. Such transaction is non-cash and is excluded from investing activities in the consolidated statement of cash flows for the year ended December 31, 2013. | |||||||||||||||||||
On December 31, 2014, PGE acquired an additional 10% interest in Boardman from another co-owner, whereby the Company received net cash of $8 million from the co-owner to assume the net liabilities associated with the ownership of this 10% interest. In connection with this transaction, PGE recorded Electric utility plant of $7 million, inventory of $4 million, an ARO of $7 million, a regulatory liability of $6 million to be returned to customers in 2015 and 2016, a regulatory liability of $4 million related to future additional decommissioning and environmental costs, and deferred revenue of $2 million. The acquisition of the 10% interest in Boardman increased the Company’s ownership share from 80% to 90%. | |||||||||||||||||||
As of December 31, 2014, PGE had the following investments in jointly-owned plant (dollars in millions): | |||||||||||||||||||
PGE | In-service Date | Plant | Accumulated | Construction | |||||||||||||||
Share | In-service | Depreciation* | Work In | ||||||||||||||||
Progress | |||||||||||||||||||
Boardman | 90 | % | 1980 | $ | 510 | $ | 350 | $ | — | ||||||||||
Colstrip | 20 | 1986 | 520 | 334 | 2 | ||||||||||||||
Pelton/Round Butte | 66.67 | 1958 | / | 1964 | 237 | 55 | 8 | ||||||||||||
Total | $ | 1,267 | $ | 739 | $ | 10 | |||||||||||||
* | Excludes AROs and accumulated asset retirement removal costs. |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
Contingencies [Abstract] | |
Contingencies [Text Block] | CONTINGENCIES |
PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted. | |
Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. | |
A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or ii) discloses that an estimate cannot be made and the reasons. | |
If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. | |
The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) there are significant facts in dispute; vi) there are a large number of parties (including where it is uncertain how liability, if any, will be shared among multiple defendants); or vii) there is a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact. | |
Trojan Investment Recovery | |
Regulatory Proceedings. In 1993, PGE closed Trojan and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan. | |
Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 1998, the Oregon Court of Appeals upheld the OPUC’s order authorizing PGE’s recovery of the Trojan investment, but held that the OPUC did not have the authority to allow the Company to recover a return on the Trojan investment and remanded the case to the OPUC for reconsideration. | |
In 2000, PGE entered into agreements to settle the litigation related to recovery of, and return on, its investment in Trojan. The settlement, which was approved by the OPUC, allowed PGE to remove from its balance sheet the remaining investment in Trojan as of September 30, 2000, along with several largely offsetting regulatory liabilities. After offsetting the investment in Trojan with these liabilities, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE’s investment in Trojan was no longer included in prices charged to customers, either through a return of or a return on that investment. The Utility Reform Project (URP) did not participate in the settlement and filed a complaint with the OPUC challenging the settlement agreements. In 2002, the OPUC issued an order (2002 Order) denying all of the URP’s challenges. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration. | |
The OPUC then issued an order in 2008 (2008 Order) that required PGE to provide refunds, including interest from September 30, 2000, to customers who received service from the Company during the period from October 1, 2000 to September 30, 2001. The Company recorded a charge of $33.1 million in 2008 related to the refund and accrued additional interest expense on the liability until refunds to customers were completed in the first quarter of 2010. The URP and the plaintiffs in the class actions described below separately appealed the 2008 Order to the Oregon Court of Appeals. | |
On February 6, 2013, the Oregon Court of Appeals issued an opinion that upheld the 2008 Order. On May 31, 2013, the Court of Appeals denied the appellants’ request for reconsideration of the decision. On October 18, 2013, the Oregon Supreme Court granted plaintiffs’ petition seeking review of the February 6, 2013 Oregon Court of Appeals decision. | |
On October 2, 2014, the Oregon Supreme Court, in a unanimous decision, affirmed the February 6, 2013 Oregon Court of Appeals decision that upheld the OPUC’s 2008 Order. On January 15, 2015, the Oregon Supreme Court denied the plaintiffs petition seeking reconsideration of the October 2, 2014 decision. | |
Class Actions. In two separate legal proceedings, lawsuits were filed in Marion County Circuit Court against PGE in 2003 on behalf of two classes of electric service customers. The class action lawsuits seek damages totaling $260 million, plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan. | |
In 2006, the Oregon Supreme Court issued a ruling ordering the abatement of the class action proceedings until the OPUC responded to the 2002 Order (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy can be offered to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment that the Company collected in prices. | |
The Oregon Supreme Court further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The Oregon Supreme Court added that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The Oregon Supreme Court also ruled that the plaintiffs retain the right to return to the Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. The Marion County Circuit Court subsequently abated the class actions in response to the ruling of the Oregon Supreme Court. | |
The October 2, 2014 Oregon Supreme Court decision described above expressly noted that the plaintiffs in the class action must address any request to lift the abatement with the Marion County Circuit Court. PGE is evaluating how to proceed with respect to the class actions. | |
PGE believes that the October 2, 2014 Oregon Supreme Court decision has reduced the risk of a loss to the Company in excess of the amounts previously recorded and discussed above. However, because the class actions remain pending, management believes that it is still reasonably possible that such a loss to the Company could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss, or to estimate a range of potential loss. | |
Pacific Northwest Refund Proceeding | |
In 2001, the FERC called for a hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001 (Pacific Northwest Refund proceeding). During that period, PGE both sold and purchased electricity in the Pacific Northwest. Upon appeal of the decision to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit), the Ninth Circuit remanded the case to the FERC to, among other things, address market manipulation evidence in detail and account for the evidence in any future orders regarding the award or denial of refunds in the proceedings. | |
In response to the Ninth Circuit remand, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. The orders held that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest. The FERC also expanded the scope of the hearing to allow parties to pursue refunds for transactions between January 1, 2000 and December 24, 2000 under Section 309 of the Federal Power Act by showing violations of a filed tariff or rate schedule of a statutory requirement. The FERC directed the presiding judge, if necessary, to determine a refund methodology and to calculate refunds, but held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Refund claimants have filed petitions for appeal of these procedural orders with the Ninth Circuit. | |
Pursuant to a FERC-ordered settlement process, the Company received notice of two claims and reached agreements to settle both claims for an immaterial amount. The FERC approved both settlements during 2012. | |
Additionally, the settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, et seq., approved by the FERC in May 2007, resolved all claims between PGE and the California parties named in the settlement, including the California Energy Resource Scheduling division of the California Department of Water Resources (CERS), as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 20, 2001, but did not settle potential claims from other market participants relating to transactions in the Pacific Northwest. | |
The above-referenced settlements resulted in a release of the Company as a named respondent in the first phase of the remand proceedings, which are limited to initial and direct claims for refunds, but there remains a possibility that additional claims related to this matter could be asserted against the Company in a subsequent phase of the proceeding if refunds are ordered against some or all of the current respondents. | |
During the first phase of the remand hearing, now completed, two sets of refund proponents, the City of Seattle, Washington (Seattle) and various California parties on behalf of CERS, presented cases alleging that multiple respondents had engaged in unlawful activities and caused severe financial harm that justified the imposition of refunds. After conclusion of the hearing, the presiding Administrative Law Judge issued an Initial Decision on March 28, 2014 finding: i) that Seattle did not carry its Mobile-Sierra burden with respect to its refund claims against any of its respondent sellers; and ii) that the California representatives of CERS did not carry their Mobile-Sierra burden with respect to one of the two CERS’ respondents, but that CERS had produced evidence that the remaining CERS respondent had engaged in unlawful activity in the implementation of multiple transactions and bad faith in the formation of as many as 119 contracts. The Administrative Law Judge scheduled a second phase of the hearing to commence after a final FERC decision on the Initial Decision. The Administrative Law Judge determined that in the second phase the remaining respondent will have an opportunity to produce additional evidence as to why its transactions should be considered legitimate and why refunds should not be ordered. The findings in the Initial Decision are subject to further FERC action. If the FERC requires one or more respondents to make refunds, it is possible that such respondent(s) will attempt to recover similar refunds from their suppliers, including the Company. | |
Management believes that this matter could result in a loss to the Company in future proceedings. However, management cannot predict whether the FERC will order refunds from any of the current respondents, which contracts would be subject to refunds, the basis on which refunds would be ordered, or how such refunds, if any, would be calculated. Further, management cannot predict whether any current respondents, if ordered to make refunds, will pursue additional refund claims against their suppliers, and, if so, what the basis or amounts of such potential refund claims against the Company would be. Due to these uncertainties, sufficient information is currently not available to determine PGE’s liability, if any, or to estimate a range of reasonably possible loss. | |
EPA Investigation of Portland Harbor | |
A 1997 investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) as a federal Superfund site and listed 69 Potentially Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river. In January 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over one hundred. | |
The Portland Harbor site is currently undergoing a remedial investigation (RI) and feasibility study (FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE. | |
In March 2012, the LWG submitted a draft FS to the EPA for review and approval. The draft FS, along with the RI, provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision, which the EPA is not expected to issue before 2017. | |
The draft FS evaluates several alternative clean-up approaches. These approaches would take from two to 28 years with costs ranging from $169 million to $1.8 billion, depending on the selected remedial action levels and the choice of remedy. The draft FS does not address responsibility for the costs of clean-up, allocate such costs among PRPs, or define precise boundaries for the clean-up. Responsibility for funding and implementing the EPA’s selected clean-up will be determined after the issuance of the Record of Decision. | |
Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties discussed above, sufficient information is currently not available to determine PGE’s liability for the cost of any required investigation or remediation of the Portland Harbor site or to estimate a range of potential loss. | |
DEQ Investigation of Downtown Reach | |
The Oregon Department of Environmental Quality (DEQ) has executed a memorandum of understanding with the EPA to administer and enforce clean-up activities for portions of the Willamette River that are upriver from the Portland Harbor Superfund site (the Downtown Reach). In January 2010, the DEQ issued an order requiring PGE to perform an investigation of certain portions of the Downtown Reach. PGE completed this investigation in December 2011 and entered into a consent order with the DEQ in July 2012 to conduct a feasibility study of alternatives for remedial action for the portions of the Downtown Reach that were included within the scope of PGE’s investigation. The draft feasibility study report, which describes possible remediation alternatives that range in estimated cost from $3 million to $8 million, was submitted to the DEQ in February 2014. Following the DEQ’s evaluation of the draft feasibility study, PGE submitted a final feasibility study to the DEQ in September 2014. The estimated costs in the final feasibility study did not differ significantly from those in the draft feasibility study. Using the Company’s best estimate of the probable cost for the remediation effort from the set of alternatives provided in the feasibility study report, PGE has a $3 million reserve for this matter as of December 31, 2014. | |
Based on the available evidence of previous rate recovery of incurred environmental remediation costs for PGE, as well as for other utilities operating within the same jurisdiction, the Company has concluded that the estimated cost of $3 million to remediate the Downtown Reach is probable of recovery. As a result, the Company also has a regulatory asset of $3 million for future recovery in prices as of December 31, 2014. The Company included recovery of the regulatory asset in its 2015 GRC filed with the OPUC. The final order issued by the OPUC in the 2015 GRC includes revenues to offset the amortization of the regulatory asset over a two year period beginning January 1, 2015. | |
Alleged Violation of Environmental Regulations at Colstrip | |
On July 30, 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (CSES) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other CSES co-owners, including PPL Montana, LLC, the operator of CSES. PGE has a 20% ownership interest in Units 3 and 4 of CSES. The Notice alleges certain violations of the CAA, including New Source Review, Title V, and opacity requirements, and states that the Sierra Club and MEIC will: i) request a United States District Court to impose injunctive relief and civil penalties; ii) require a beneficial environmental project in the areas affected by the alleged air pollution; and iii) seek reimbursement of Sierra Club’s and MEIC’s costs of litigation and attorney’s fees. | |
The Sierra Club and MEIC asserted that the CSES owners violated the Title V air quality operating permit during portions of 2008 and 2009 and that the owners have violated the CAA by failing to timely submit a complete air quality operating permit application to the Montana Department of Environmental Quality (MDEQ). The Sierra Club and MEIC also asserted violations of opacity provisions of the CAA. | |
On March 6, 2013, the Sierra Club and MEIC sued the CSES co-owners, including PGE, for these and additional alleged violations of various environmental related regulations. The plaintiffs are seeking relief that includes an injunction preventing the co-owners from operating CSES except in accordance with the CAA, the Montana State Implementation Plan, and the plant’s federally enforceable air quality permits. In addition, plaintiffs are seeking civil penalties against the co-owners including $32,500 per day for each violation occurring through January 12, 2009, and $37,500 per day for each violation occurring thereafter. | |
On May 3, 2013, the defendants filed a motion to dismiss 36 of 39 claims alleged in the complaint. In September 2013, the plaintiffs filed a motion for partial summary judgment regarding the appropriate method of calculating emissions increases. Also in September 2013, the plaintiffs filed an amended complaint that withdrew Title V and opacity claims, added claims associated with two 2011 projects, and expanded the scope of certain claims to encompass approximately 40 additional projects. In July 2014, the court denied the defendants’ motion to dismiss and the plaintiffs’ motion for partial summary judgment. | |
On August 27, 2014, the plaintiffs filed a second amended complaint to which the defendants’ response was filed on September 26, 2014. The second amended complaint continues to seek injunctive relief, declaratory relief, and civil penalties for alleged violations of the federal Clean Air Act. The plaintiffs state in the second amended complaint that it was filed, in part, to comply with the court’s ruling on the defendants’ motion to dismiss and plaintiffs’ motion for partial summary judgment. Discovery in this matter is ongoing with trial now scheduled for November 2015. | |
Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome or determine whether it would have a material impact on the Company. | |
Oregon Tax Court Ruling | |
On September 17, 2012, the Oregon Tax Court issued a ruling contrary to an Oregon Department of Revenue (DOR) interpretation and a current Oregon administrative rule, regarding the treatment of wholesale electricity sales. The underlying issue is whether electricity should be treated as tangible or intangible property for state income tax apportionment purposes. The DOR has appealed the ruling of the Oregon Tax Court to the Oregon Supreme Court. It is uncertain whether the ruling will be upheld. Oral argument occurred in May 2014 and the parties now await a Court decision. | |
If the ruling is upheld, PGE estimates that its income tax liability could increase by as much as $7 million due to an increase in the tax rate at which deferred tax liabilities would be recognized in future years. During the third quarter of 2013, the Company entered into a closing agreement with the DOR, under which the DOR agreed to the tax apportionment methodology utilized on the tax returns relating to open tax years 2008 through 2012. | |
Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome. | |
Other Matters | |
PGE is subject to other regulatory, environmental, and legal proceedings, investigations, and claims that arise from time to time in the ordinary course of business, which may result in judgments against the Company. Although management currently believes that resolution of such matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future. |
Basis_of_Presentation_Basis_of
Basis of Presentation Basis of Presentation (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
Basis of Presentation [Abstract] | |
Consolidation, Policy [Policy Text Block] | The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries and those variable interest entities (VIEs) where PGE has determined it is the primary beneficiary. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. Intercompany balances and transactions have been eliminated. |
For entities that are determined to meet the definition of a VIE and where the Company has determined it is the primary beneficiary, the VIE is consolidated and a noncontrolling interest is recognized for any third party interests. This has resulted in the Company consolidating entities in which it has less than a 50% equity interest. For further information, see Note 16, Variable Interest Entities. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
Summary of Significant Accounting Policies [Abstract] | |
Cash and Cash Equivalents, Policy [Policy Text Block] | Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, |
Trade and Other Accounts Receivable, Policy [Policy Text Block] | Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 16 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice. |
Provisions for uncollectible accounts receivable related to retail sales are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on management’s assessment of the probability of collection, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors. | |
Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable. | |
Derivatives, Policy [Policy Text Block] | PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, oil and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statement of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting. |
Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers. | |
In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument. | |
Electricity sale and purchase transactions that are physically settled are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement. | |
Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. | |
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block] | Cash deposits provided as collateral are included with Other current assets in the consolidated balance sheets |
Off-Balance-Sheet Credit Exposure, Policy [Policy Text Block] | Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet |
Inventory, Policy [Policy Text Block] | PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance and capital activities and fuel for use in generating plants. Fuel inventories include natural gas, oil, and coal. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market. |
Property, Plant and Equipment, Policy [Policy Text Block] | Electric utility plant is capitalized at its original cost, which includes direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at the Company’s generating plants are charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining a FERC license for the Company’s hydroelectric projects are capitalized and amortized over the related license period. |
During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. | |
Allowance for Funds Used During Construction, Policy [Policy Text Block] | PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes and is based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. |
Regulatory Depreciation and Amortization, Policy [Policy Text Block] | Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. |
Depreciation Lives [Policy Text Block] | Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, |
Plant Retirement and Abandonment, Policy [Policy Text Block] | The original cost of depreciable property units, net of any related salvage value, is charged to accumulated depreciation when property is retired and removed from service. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, included in Regulatory liabilities, for assets without AROs. |
Goodwill and Intangible Assets, Intangible Assets, Policy [Policy Text Block] | Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. |
Marketable Securities, Policy [Policy Text Block] | All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading. These securities are classified as noncurrent because they are not available for use in operations. Trading securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the Non-qualified benefit plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking. The cost of securities sold is based on the average cost method. |
Public Utilities, Policy [Policy Text Block] | the Company applies regulatory accounting, resulting in regulatory assets or regulatory liabilities. Regulatory assets represent i) probable future revenue associated with certain actual or estimated costs that are expected to be recovered from customers through the ratemaking process, or ii) probable future collections from customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established by or subject to approval by independent third-party regulators; prices are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the consolidated statement of income over the period in which it is included in prices. |
Circumstances that could result in the discontinuance of regulatory accounting include i) increased competition that restricts the Company’s ability to establish prices to recover specific costs, and ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. PGE periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate. | |
Power Cost [Policy Text Block] | PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. NVPC consists of i) the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income; and is net of ii) wholesale sales, which are classified as Revenues, net in the consolidated statements of income. |
To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from or refunded to customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. PGE’s authorized ROE was 9.75% for 2014, and 10% for 2013 and for 2012. | |
Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review. | |
Asset Retirement Obligations, Policy [Policy Text Block] | An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred. |
The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. | |
Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability. | |
Commitments and Contingencies, Policy [Policy Text Block] | Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. Legal costs incurred in connection with loss contingencies are expensed as incurred. |
A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons. | |
If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. | |
Gain contingencies are recognized when realized and are disclosed when material. | |
Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted. | |
Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. | |
A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or ii) discloses that an estimate cannot be made and the reasons. | |
If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. | |
The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) there are significant facts in dispute; vi) there are a large number of parties (including where it is uncertain how liability, if any, will be shared among multiple defendants); or vii) there is a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact. | |
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block] | Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position. |
The assets of the pension plan are held in a trust and are comprised of equity and debt instruments, all of which are recorded at fair value. Pension plan calculations include several assumptions which are reviewed annually and are updated as appropriate, with the measurement date of December 31. | |
Revenue Recognition, Policy [Policy Text Block] | Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC), and state (OPUC) regulation. |
Franchise Tax [Policy Text Block] | Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes |
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block] | Retail revenue is billed monthly based on meter readings taken throughout the month. Unbilled revenue represents the revenue earned from the last meter read date through the last day of the month, which has not been billed as of the last day of the month. Unbilled revenue is calculated based on each month’s actual net retail system load, the number of days from the last meter read date through the last day of the month, and current retail customer prices. |
As a rate-regulated utility, there are situations in which PGE recognizes revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization. | |
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block] | The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite vesting period. PGE attributes the value of stock-based compensation to expense on a straight-line basis. |
Income Tax, Policy [Policy Text Block] | Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance is established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns. |
As a rate-regulated enterprise, changes in deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. | |
Income Tax Uncertainties, Policy [Policy Text Block] | Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheet. |
Interest and Penalties Related to Income Taxes [Policy Text Block] | PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income. |
Recovered_Sheet1
Fair Value of Financial Instruments (Policies) | 12 Months Ended | |
Dec. 31, 2014 | ||
Fair Value of Financial Instruments [Abstract] | ||
Fair Value of Financial Instruments, Policy [Policy Text Block] | PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2014 and 2013, and then classifies these financial assets and liabilities based on a fair value hierarchy. The fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below. | |
Level 1 | Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. | |
Level 2 | Pricing inputs include those that are directly or indirectly observable in the marketplace as of the reporting date. | |
Level 3 | Pricing inputs include significant inputs which are unobservable for the asset or liability. | |
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. | ||
PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. | ||
Allocation of Financial Asset to Hierarchy Levels [Policy Text Block] | Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s consolidated balance sheets and invested in securities that are exposed to interest rate, credit and market volatility risks. These assets are classified within Level 1, 2 or 3 based on the following factors: | |
Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. Money market funds are classified as Level 2 in the fair value hierarchy as the securities are traded in active markets of similar securities but are not directly valued using quoted market prices. | ||
Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. | ||
Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation as applicable. | ||
Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE). Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs are directly or indirectly observable in the marketplace. | ||
Assets and liabilities from price risk management activities are recorded at fair value in PGE’s consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net power costs for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Price Risk Management. | ||
For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures and swaps. | ||
Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term commodity forwards, futures and swaps. | ||
Transfers in and out of Level 3 [Policy Text Block] | Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2014 and 2013, there were no significant transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements. | |
Debt, Policy [Policy Text Block] | Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. |
Price_Risk_Management_Policies
Price Risk Management (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
Price Risk Management [Abstract] | |
Gross Reporting of Positive and Negative Exposures Related to Derivative Instruments [Policy Text Block] | PGE has elected to report gross on the consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit |
Asset_Retirement_Obligations_P
Asset Retirement Obligations (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations, Policy [Policy Text Block] | An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred. |
The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. | |
Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability. |
Employee_Benefits_Policies
Employee Benefits (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
Employee Benefits [Abstract] | |
pension and other postretirement benefits valuation methodology [Policy Text Block] | The following methods are used in valuation of each asset class of investments held in the pension and other postretirement benefit plan trusts. |
Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short term treasury bills, federal agency securities, certificates of deposit, and commercial paper. Money market funds held in the trusts are classified as Level 2 instruments as they are traded in an active market of similar securities but are not directly valued using quoted prices. | |
Equity securities—Equity mutual fund and common stock securities are classified as Level 1 securities as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 securities due to pricing inputs that are not directly or indirectly observable in the marketplace. | |
Debt securities—PGE invests in highly-liquid United States treasury and corporate credit mutual fund securities to support the investment objectives of the trusts. These securities are classified as Level 1 instruments due to the highly observable nature of pricing in an active market. | |
Fair values for Level 2 debt securities, including municipal debt and corporate credit securities, mortgage-backed securities and asset-backed securities are determined by evaluating pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation if applicable. | |
Private equity funds—PGE invests in a combination of primary and secondary fund-of-funds which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, venture capital, buyout and special situations. Private equity investments are classified as Level 3 securities due to fund valuation methodologies that utilize discounted cash flow, market comparable and limited secondary market pricing to develop estimates of fund valuation. PGE valuation of individual fund performance compares stated fund performance against published benchmarks. | |
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block] | Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position. |
The assets of the pension plan are held in a trust and are comprised of equity and debt instruments, all of which are recorded at fair value. Pension plan calculations include several assumptions which are reviewed annually and are updated as appropriate, with the measurement date of December 31. | |
Pension and Other Postretirement Plans, Nonpension Benefits, Policy [Policy Text Block] | The assets of these plans are held in voluntary employees’ beneficiary association trusts and are comprised of money market funds, common stocks, common and collective trust funds, partnerships/joint ventures, and registered investment companies, all of which are recorded at fair value. Postretirement health and life insurance benefit plan calculations include several assumptions which are reviewed annually with PGE’s consulting actuaries and trust investment consultants and updated as appropriate, with measurement dates of December 31. |
Non-qualified benefit [Policy Text Block] | Non-Qualified Benefit Plans—The non-qualified benefit plans (NQBP) in the following tables include obligations for a Supplemental Executive Retirement Plan, and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also include pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in a non-qualified benefit plan trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. These trust assets are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bond, and equity mutual funds, are classified as trading and recorded at fair value. The measurement date for the non-qualified benefit plans is December 31. |
Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. PGE holds investments in a non-qualified benefit plan trust which are intended to be a funding source for these plans. |
Commitments_and_Guarantees_Pol
Commitments and Guarantees (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | |
Minimum Guarantees, Policy [Policy Text Block] | PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. |
Contingencies_Policies
Contingencies (Policies) | 12 Months Ended |
Dec. 31, 2014 | |
Contingencies [Abstract] | |
Commitments and Contingencies, Policy [Policy Text Block] | Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. Legal costs incurred in connection with loss contingencies are expensed as incurred. |
A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons. | |
If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. | |
Gain contingencies are recognized when realized and are disclosed when material. | |
Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted. | |
Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. | |
A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or ii) discloses that an estimate cannot be made and the reasons. | |
If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. | |
The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) there are significant facts in dispute; vi) there are a large number of parties (including where it is uncertain how liability, if any, will be shared among multiple defendants); or vii) there is a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | ||
Dec. 31, 2014 | |||
Summary of Significant Accounting Policies [Abstract] | |||
Estimated average service lives [Table Text Block] | Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years): | ||
Generation, excluding thermal: | |||
Hydro | 87 | ||
Wind | 27 | ||
Transmission | 53 | ||
Distribution | 40 | ||
General | 13 | ||
Balance_Sheet_Components_Table
Balance Sheet Components (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Balance Sheet Components [Abstract] | ||||||||||||||||
Schedule of Valuation and Qualifying Accounts Disclosure [Text Block] | The following is the activity in the allowance for uncollectible accounts (in millions): | |||||||||||||||
Years Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Balance as of beginning of year | $ | 6 | $ | 5 | $ | 6 | ||||||||||
Increase in provision | 6 | 6 | 6 | |||||||||||||
Amounts written off, less recoveries | (6 | ) | (5 | ) | (7 | ) | ||||||||||
Balance as of end of year | $ | 6 | $ | 6 | $ | 5 | ||||||||||
Investments held in trust [Table Text Block] | The trusts are comprised of the following investments as of December 31 (in millions): | |||||||||||||||
Nuclear | Non-Qualified Benefit | |||||||||||||||
Decommissioning Trust | Plan Trust | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Cash equivalents | $ | 65 | $ | 59 | $ | — | $ | — | ||||||||
Marketable securities, at fair value: | ||||||||||||||||
Equity securities | — | — | 6 | 8 | ||||||||||||
Debt securities | 25 | 23 | — | 1 | ||||||||||||
Insurance contracts, at cash surrender value | — | — | 26 | 26 | ||||||||||||
$ | 90 | $ | 82 | $ | 32 | $ | 35 | |||||||||
Schedule of Other Assets and Other Liabilities [Table Text Block] | Other current assets and Accrued expenses and other current liabilities consist of the following (in millions): | |||||||||||||||
As of December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Other current assets: | ||||||||||||||||
Prepaid expenses | $ | 39 | $ | 38 | ||||||||||||
Current deferred income tax asset | 33 | 42 | ||||||||||||||
Accrued sales tax refund related to Tucannon River Wind Farm | 23 | — | ||||||||||||||
Margin deposits | 11 | 9 | ||||||||||||||
Assets from price risk management activities | 6 | 13 | ||||||||||||||
Other | 3 | 1 | ||||||||||||||
$ | 115 | $ | 103 | |||||||||||||
Accrued expenses and other current liabilities: | ||||||||||||||||
Regulatory liabilities—current | $ | 60 | $ | 1 | ||||||||||||
Accrued employee compensation and benefits | 51 | 46 | ||||||||||||||
Accrued interest payable | 26 | 23 | ||||||||||||||
Dividends payable | 23 | 22 | ||||||||||||||
Accrued taxes payable | 22 | 21 | ||||||||||||||
Other | 54 | 58 | ||||||||||||||
$ | 236 | $ | 171 | |||||||||||||
Fair_Value_of_Financial_Instru1
Fair Value of Financial Instruments (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Fair Value of Financial Instruments [Abstract] | |||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions): | ||||||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
Assets: | |||||||||||||||||||||||||
Nuclear decommissioning trust (1): | |||||||||||||||||||||||||
Money market funds | $ | — | $ | 65 | $ | — | $ | 65 | |||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Domestic government | 7 | 7 | — | 14 | |||||||||||||||||||||
Corporate credit | — | 11 | — | 11 | |||||||||||||||||||||
Non-qualified benefit plan trust (2): | |||||||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Domestic | 4 | 1 | — | 5 | |||||||||||||||||||||
International | 1 | — | — | 1 | |||||||||||||||||||||
Assets from price risk management activities (1) (3): | |||||||||||||||||||||||||
Electricity | — | 4 | 1 | 5 | |||||||||||||||||||||
Natural gas | — | 2 | — | 2 | |||||||||||||||||||||
$ | 12 | $ | 90 | $ | 1 | $ | 103 | ||||||||||||||||||
Liabilities - Liabilities from price risk management | |||||||||||||||||||||||||
activities (1) (3): | |||||||||||||||||||||||||
Electricity | $ | — | $ | 32 | $ | 80 | $ | 112 | |||||||||||||||||
Natural gas | — | 95 | 21 | 116 | |||||||||||||||||||||
$ | — | $ | 127 | $ | 101 | $ | 228 | ||||||||||||||||||
-1 | Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate. | ||||||||||||||||||||||||
-2 | Excludes insurance policies of $26 million, which are recorded at cash surrender value. | ||||||||||||||||||||||||
-3 | For further information, see Note 5, Price Risk Management. | ||||||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
Assets: | |||||||||||||||||||||||||
Nuclear decommissioning trust (1): | |||||||||||||||||||||||||
Money market funds | $ | — | $ | 59 | $ | — | $ | 59 | |||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Domestic government | 6 | 8 | — | 14 | |||||||||||||||||||||
Corporate credit | — | 9 | — | 9 | |||||||||||||||||||||
Non-qualified benefit plan trust (2): | |||||||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Domestic | 4 | 3 | — | 7 | |||||||||||||||||||||
International | 1 | — | — | 1 | |||||||||||||||||||||
Debt securities - domestic government | 1 | — | — | 1 | |||||||||||||||||||||
Assets from price risk management activities (1) (3): | |||||||||||||||||||||||||
Electricity | — | 9 | 1 | 10 | |||||||||||||||||||||
Natural gas | — | 4 | — | 4 | |||||||||||||||||||||
$ | 12 | $ | 92 | $ | 1 | $ | 105 | ||||||||||||||||||
Liabilities - Liabilities from price risk management | |||||||||||||||||||||||||
activities (1) (3): | |||||||||||||||||||||||||
Electricity | $ | — | $ | 10 | $ | 117 | $ | 127 | |||||||||||||||||
Natural gas | — | 40 | 23 | 63 | |||||||||||||||||||||
$ | — | $ | 50 | $ | 140 | $ | 190 | ||||||||||||||||||
-1 | Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate. | ||||||||||||||||||||||||
-2 | Excludes insurance policies of $26 million, which are recorded at cash surrender value. | ||||||||||||||||||||||||
-3 | For further information, see Note 5, Price Risk Management. | ||||||||||||||||||||||||
The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions): | |||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
As of December 31, 2014: | |||||||||||||||||||||||||
Defined Benefit Pension Plan assets: | |||||||||||||||||||||||||
Money market funds | $ | — | $ | 6 | $ | — | $ | 6 | |||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Domestic | $ | 42 | $ | 146 | $ | — | $ | 188 | |||||||||||||||||
International | — | 171 | — | 171 | |||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Domestic government and corporate credit | — | 197 | — | 197 | |||||||||||||||||||||
Private equity funds | — | — | 29 | 29 | |||||||||||||||||||||
$ | 42 | $ | 520 | $ | 29 | $ | 591 | ||||||||||||||||||
Other Postretirement Benefit Plans assets: | |||||||||||||||||||||||||
Money market funds | $ | — | $ | 6 | $ | — | $ | 6 | |||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Domestic | 10 | 1 | — | 11 | |||||||||||||||||||||
International | 10 | — | — | 10 | |||||||||||||||||||||
Debt securities—Domestic government | 5 | — | — | 5 | |||||||||||||||||||||
$ | 25 | $ | 7 | $ | — | $ | 32 | ||||||||||||||||||
As of December 31, 2013: | |||||||||||||||||||||||||
Defined Benefit Pension Plan assets: | |||||||||||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Domestic | $ | 166 | $ | 19 | $ | — | $ | 185 | |||||||||||||||||
International | 185 | — | — | 185 | |||||||||||||||||||||
Debt securities: | |||||||||||||||||||||||||
Domestic government and corporate credit | — | 181 | — | 181 | |||||||||||||||||||||
Corporate credit | 14 | — | — | 14 | |||||||||||||||||||||
Private equity funds | — | — | 31 | 31 | |||||||||||||||||||||
$ | 365 | $ | 200 | $ | 31 | $ | 596 | ||||||||||||||||||
Other Postretirement Benefit Plans assets: | |||||||||||||||||||||||||
Money market funds | $ | — | $ | 10 | $ | — | $ | 10 | |||||||||||||||||
Equity securities: | |||||||||||||||||||||||||
Domestic | 8 | 2 | — | 10 | |||||||||||||||||||||
International | 9 | — | — | 9 | |||||||||||||||||||||
Debt securities—Domestic government | 3 | — | — | 3 | |||||||||||||||||||||
$ | 20 | $ | 12 | $ | — | $ | 32 | ||||||||||||||||||
Fair Value, Option, Quantitative Disclosures [Table Text Block] | Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below: | ||||||||||||||||||||||||
Significant | Price per Unit | ||||||||||||||||||||||||
Fair Value | Valuation | Unobservable | Weighted | ||||||||||||||||||||||
Commodity Contracts | Assets | Liabilities | Technique | Input | Low | High | Average | ||||||||||||||||||
(in millions) | |||||||||||||||||||||||||
As of December 31, 2014: | |||||||||||||||||||||||||
Electricity physical forward | $ | — | $ | 77 | Discounted cash flow | Electricity forward price (per MWh) | $ | 11.97 | $ | 122.72 | $ | 37.43 | |||||||||||||
Natural gas financial swaps | — | 21 | Discounted cash flow | Natural gas forward price (per Dth) | 2.88 | 4.86 | 3.41 | ||||||||||||||||||
Electricity financial futures | 1 | 3 | Discounted cash flow | Electricity forward price (per MWh) | 11.97 | 39.26 | 27.88 | ||||||||||||||||||
$ | 1 | $ | 101 | ||||||||||||||||||||||
As of December 31, 2013: | |||||||||||||||||||||||||
Electricity physical forward | $ | — | $ | 103 | Discounted cash flow | Electricity forward price (per MWh) | $ | 9.63 | $ | 77.95 | $ | 40.18 | |||||||||||||
Natural gas financial swaps | — | 23 | Discounted cash flow | Natural gas forward price (per Dth) | 3.16 | 4.49 | 3.71 | ||||||||||||||||||
Electricity financial futures | 1 | 14 | Discounted cash flow | Electricity forward price (per MWh) | 9.63 | 46.07 | 33.01 | ||||||||||||||||||
$ | 1 | $ | 140 | ||||||||||||||||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions): | ||||||||||||||||||||||||
Years Ended December 31, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
Net liabilities from price risk management activities as of beginning of year | $ | 139 | $ | 16 | |||||||||||||||||||||
Net realized and unrealized losses * | 15 | 134 | |||||||||||||||||||||||
Settlements | (4 | ) | (1 | ) | |||||||||||||||||||||
Net transfers out of Level 3 to Level 2 | (50 | ) | (10 | ) | |||||||||||||||||||||
Net liabilities from price risk management activities as of end of year | $ | 100 | $ | 139 | |||||||||||||||||||||
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting | $ | 12 | $ | 133 | |||||||||||||||||||||
* Includes realized losses, net of $3 million in 2014 and $1 million in 2013. | |||||||||||||||||||||||||
Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2014 and 2013, there were no significant transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements. |
Price_Risk_Management_Tables
Price Risk Management (Tables) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Price Risk Management [Abstract] | ||||||||||||||||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions): | |||||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||
Current assets: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | $ | 4 | $ | 9 | ||||||||||||||||||||||||
Natural gas | 2 | 4 | ||||||||||||||||||||||||||
Total current derivative assets | 6 | (1) | 13 | (1) | ||||||||||||||||||||||||
Noncurrent assets: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | 1 | 1 | ||||||||||||||||||||||||||
Total noncurrent derivative assets | 1 | (2) | 1 | (2) | ||||||||||||||||||||||||
Total derivative assets not designated as hedging instruments | $ | 7 | $ | 14 | ||||||||||||||||||||||||
Total derivative assets | $ | 7 | $ | 14 | ||||||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | $ | 54 | $ | 20 | ||||||||||||||||||||||||
Natural gas | 52 | 29 | ||||||||||||||||||||||||||
Total current derivative liabilities | 106 | 49 | ||||||||||||||||||||||||||
Noncurrent liabilities: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | 58 | 107 | ||||||||||||||||||||||||||
Natural gas | 64 | 34 | ||||||||||||||||||||||||||
Total noncurrent derivative liabilities | 122 | 141 | ||||||||||||||||||||||||||
Total derivative liabilities not designated as hedging instruments | $ | 228 | $ | 190 | ||||||||||||||||||||||||
Total derivative liabilities | $ | 228 | $ | 190 | ||||||||||||||||||||||||
-1 | Included in Other current assets on the consolidated balance sheets. | |||||||||||||||||||||||||||
-2 | Included in Other noncurrent assets on the consolidated balance sheet. | |||||||||||||||||||||||||||
Schedule of Derivative Instruments [Table Text Block] | PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions): | |||||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | 16 | MWh | 14 | MWh | ||||||||||||||||||||||||
Natural gas | 127 | Dth | 106 | Dth | ||||||||||||||||||||||||
Foreign currency exchange | $ | 7 | Canadian | $ | 7 | Canadian | ||||||||||||||||||||||
Price risk management assets and liabilties subject to master netting agreements [Table Text Block] | price risk management liabilities subject to master netting agreements is as follows (in millions): | |||||||||||||||||||||||||||
Gross | Gross | Net | Gross Amounts Not Offset in | |||||||||||||||||||||||||
Amounts | Amounts | Amounts | Consolidated Balance Sheets | |||||||||||||||||||||||||
Recognized | Offset | Presented | Derivatives | Cash Collateral(1) | Net Amount | |||||||||||||||||||||||
As of December 31, 2014: | ||||||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity(2) | $ | 55 | $ | — | $ | 55 | $ | (55 | ) | $ | — | $ | — | |||||||||||||||
Natural gas(2) | 17 | — | 17 | (17 | ) | — | — | |||||||||||||||||||||
$ | 72 | $ | — | $ | 72 | $ | (72 | ) | $ | — | $ | — | ||||||||||||||||
As of December 31, 2013: | ||||||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity(2) | $ | 91 | $ | — | $ | 91 | $ | (91 | ) | $ | — | $ | — | |||||||||||||||
Natural gas(2) | 1 | — | 1 | (1 | ) | — | — | |||||||||||||||||||||
$ | 92 | $ | — | $ | 92 | $ | (92 | ) | $ | — | $ | — | ||||||||||||||||
-1 | As of December 31, 2014 and 2013, the Company had collateral posted of $11 million and $7 million, respectively, which consists entirely of letters of credit. | |||||||||||||||||||||||||||
-2 | Included in Liabilities from price risk management activities—current and Liabilities from price risk management activities—noncurrent. | |||||||||||||||||||||||||||
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Net realized and unrealized losses on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the consolidated statements of income and were as follows (in millions): | |||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | $ | 13 | $ | 78 | $ | 56 | ||||||||||||||||||||||
Natural Gas | 72 | 28 | 19 | |||||||||||||||||||||||||
Foreign currency exchange | — | 1 | — | |||||||||||||||||||||||||
Net unrealized losses and certain net realized losses presented in the table above are offset within the statement of income by the effects of regulatory accounting. Of the net loss recognized in net income for the years ended December 31, 2014, 2013, and 2012, $83 million, $120 million, and $42 million, respectively, have been offset. | ||||||||||||||||||||||||||||
Schedule of Price Risk Derivatives [Table Text Block] | Assuming no changes in market prices and interest rates, the following table presents the year in which the net unrealized loss recorded as of December 31, 2014 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions): | |||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||||||||
Commodity contracts: | ||||||||||||||||||||||||||||
Electricity | $ | 50 | $ | 19 | $ | 6 | $ | 5 | $ | 5 | $ | 22 | $ | 107 | ||||||||||||||
Natural gas | 49 | 44 | 18 | 3 | — | — | 114 | |||||||||||||||||||||
Net unrealized loss | $ | 99 | $ | 63 | $ | 24 | $ | 8 | $ | 5 | $ | 22 | $ | 221 | ||||||||||||||
Schedule of Concentration of Risk, by Counterparty [Table Text Block] | Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows: | |||||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||
Assets from price risk management activities: | ||||||||||||||||||||||||||||
Counterparty A | 63 | % | 53 | % | ||||||||||||||||||||||||
Counterparty B | 14 | 6 | ||||||||||||||||||||||||||
77 | % | 59 | % | |||||||||||||||||||||||||
Liabilities from price risk management activities: | ||||||||||||||||||||||||||||
Counterparty C | 22 | % | 43 | % | ||||||||||||||||||||||||
Counterparty D | 12 | 11 | ||||||||||||||||||||||||||
34 | % | 54 | % |
Regulatory_Assets_and_Liabilit1
Regulatory Assets and Liabilities (Tables) | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Schedule of Regulatory Assets and Liabilities [Table Text Block] | Regulatory assets and liabilities consist of the following (dollars in millions): | |||||||||||||||||
Weighted Average Remaining | As of December 31, | |||||||||||||||||
Life (1) | 2014 | 2013 | ||||||||||||||||
Current | Noncurrent | Current | Noncurrent | |||||||||||||||
Regulatory assets: | ||||||||||||||||||
Price risk management (2) | 3 years | $ | 100 | $ | 121 | $ | 36 | $ | 140 | |||||||||
Pension and other postretirement plans (2) | (3) | — | 247 | — | 194 | |||||||||||||
Deferred income taxes (2) | (4) | — | 86 | — | 76 | |||||||||||||
Debt issuance costs (2) | 8 years | — | 15 | — | 17 | |||||||||||||
Deferred capital projects | 1 year | 19 | — | 16 | 18 | |||||||||||||
Other (5) | Various | 14 | 25 | 14 | 19 | |||||||||||||
Total regulatory assets | $ | 133 | $ | 494 | $ | 66 | $ | 464 | ||||||||||
Regulatory liabilities: | ||||||||||||||||||
Asset retirement removal costs (6) | (4) | $ | — | $ | 804 | $ | — | $ | 747 | |||||||||
Trojan decommissioning activities | 2 years | 23 | 34 | — | 49 | |||||||||||||
Asset retirement obligations (6) | (4) | — | 39 | — | 39 | |||||||||||||
Other | Various | 37 | 29 | 1 | 30 | |||||||||||||
Total regulatory liabilities | $ | 60 | (7) | $ | 906 | $ | 1 | (7) | $ | 865 | ||||||||
-1 | As of December 31, 2014. | |||||||||||||||||
-2 | Does not include a return on investment. | |||||||||||||||||
-3 | Recovery expected over the average service life of employees. For additional information, see Note 2, Summary of Significant Accounting Policies. | |||||||||||||||||
-4 | Recovery expected over the estimated lives of the assets. | |||||||||||||||||
-5 | Of the total other unamortized regulatory asset balances, a return is recorded on $33 million and $16 million as of December 31, 2014 and 2013, respectively. | |||||||||||||||||
-6 | Included in rate base for ratemaking purposes. | |||||||||||||||||
-7 | Included in Accrued expenses and other current liabilities on the consolidated balance sheets. |
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||
Schedule of Asset Retirement Obligations [Table Text Block] | AROs consist of the following (in millions): | |||||||||||
As of December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Trojan decommissioning activities | $ | 41 | $ | 41 | ||||||||
Utility plant | 64 | 49 | ||||||||||
Non-utility property | 11 | 10 | ||||||||||
Asset retirement obligations | $ | 116 | $ | 100 | ||||||||
Schedule of Change in Asset Retirement Obligation [Table Text Block] | The following is a summary of the changes in the Company’s AROs (in millions): | |||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Balance as of beginning of year | $ | 100 | $ | 94 | $ | 87 | ||||||
Liabilities incurred | 15 | 4 | — | |||||||||
Liabilities settled | (3 | ) | (4 | ) | (3 | ) | ||||||
Accretion expense | 6 | 6 | 6 | |||||||||
Revisions in estimated cash flows | (2 | ) | — | 4 | ||||||||
Balance as of end of year | $ | 116 | $ | 100 | $ | 94 | ||||||
Revolving_Credit_Facilities_Ta
Revolving Credit Facilities (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Line of Credit Facility [Abstract] | ||||||||||||
Schedule of Short-term Debt [Table Text Block] | Short-term borrowings under these credit facilities and related interest rates were as follows (dollars in millions): | |||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Average daily amount of short-term debt outstanding | $ | — | $ | 9 | $ | 4 | ||||||
Weighted daily average interest rate * | — | % | 0.4 | % | 0.4 | % | ||||||
Maximum amount outstanding during the year | $ | — | $ | 54 | $ | 44 | ||||||
* | Excludes the effect of commitment fees, facility fees and other financing fees. |
Long_term_debt_Tables
Long term debt (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Long-term Debt, Unclassified [Abstract] | ||||||||
Schedule of Long-term Debt Instruments [Table Text Block] | Long-term debt consists of the following (in millions): | |||||||
As of December 31, | ||||||||
2014 | 2013 | |||||||
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.42% in 2014 and 5.62% in 2013, due at various dates through 2048 | $ | 2,075 | $ | 1,795 | ||||
Unsecured term bank loans, rates range from 0.86% to 0.93%, due October 2015 | 305 | — | ||||||
Pollution Control Revenue Bonds, 5% rate, due 2033 | 142 | 148 | ||||||
Pollution Control Revenue Bonds owned by PGE | (21 | ) | (27 | ) | ||||
Total long-term debt | 2,501 | 1,916 | ||||||
Less: current portion of long-term debt | (375 | ) | — | |||||
Long-term debt, net of current portion | $ | 2,126 | $ | 1,916 | ||||
Schedule of Maturities of Long-term Debt [Table Text Block] | As of December 31, 2014, the future minimum principal payments on long-term debt are as follows (in millions): | |||||||
Years ending December 31: | ||||||||
2015 | $ | 375 | ||||||
2016 | 67 | |||||||
2017 | 58 | |||||||
2018 | 75 | |||||||
2019 | 300 | |||||||
Thereafter | 1,626 | |||||||
$ | 2,501 | |||||||
Employee_Benefits_Tables
Employee Benefits (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||
Employee Benefits [Abstract] | ||||||||||||||||||||||||||||||||||||
Assets and Liabilities associated with Non Qualified Benefit Plans [Table Text Block] | Trust assets and plan liabilities related to the NQBP included in PGE’s consolidated balance sheets are as follows as of December 31 (in millions): | |||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||
NQBP | Other NQBP | Total | NQBP | Other NQBP | Total | |||||||||||||||||||||||||||||||
Non-qualified benefit plan trust | $ | 15 | $ | 17 | $ | 32 | $ | 16 | $ | 19 | $ | 35 | ||||||||||||||||||||||||
Non-qualified benefit plan liabilities * | 25 | 80 | 105 | 22 | 79 | 101 | ||||||||||||||||||||||||||||||
* | For the NQBP, excludes the current portion of $2 million in 2014 and in 2013, which is classified in Other current liabilities in the consolidated balance sheets. | |||||||||||||||||||||||||||||||||||
Schedule of Allocation of Plan Assets [Table Text Block] | The asset allocations for the plans, and the target allocation, are as follows: | |||||||||||||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||
Actual | Target * | Actual | Target * | |||||||||||||||||||||||||||||||||
Defined Benefit Pension Plan: | ||||||||||||||||||||||||||||||||||||
Equity securities | 66 | % | 67 | % | 67 | % | 67 | % | ||||||||||||||||||||||||||||
Debt securities | 34 | 33 | 33 | 33 | ||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||||||||||||||||||||
Other Postretirement Benefit Plans: | ||||||||||||||||||||||||||||||||||||
Equity securities | 66 | % | 67 | % | 58 | % | 58 | % | ||||||||||||||||||||||||||||
Debt securities | 34 | 33 | 42 | 42 | ||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||||||||||||||||||||
Non-Qualified Benefits Plans: | ||||||||||||||||||||||||||||||||||||
Equity securities | 19 | % | 13 | % | 24 | % | 16 | % | ||||||||||||||||||||||||||||
Debt securities | 1 | 7 | 1 | 9 | ||||||||||||||||||||||||||||||||
Insurance contracts | 80 | 80 | 75 | 75 | ||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||||||||||||||||||||
* | The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the Non-Qualified Benefit Plans, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and Non-Qualified Benefit Plans, reported percentages are affected by the fair market values of the investments within the pools. | |||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions): | |||||||||||||||||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust (1): | ||||||||||||||||||||||||||||||||||||
Money market funds | $ | — | $ | 65 | $ | — | $ | 65 | ||||||||||||||||||||||||||||
Debt securities: | ||||||||||||||||||||||||||||||||||||
Domestic government | 7 | 7 | — | 14 | ||||||||||||||||||||||||||||||||
Corporate credit | — | 11 | — | 11 | ||||||||||||||||||||||||||||||||
Non-qualified benefit plan trust (2): | ||||||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | 4 | 1 | — | 5 | ||||||||||||||||||||||||||||||||
International | 1 | — | — | 1 | ||||||||||||||||||||||||||||||||
Assets from price risk management activities (1) (3): | ||||||||||||||||||||||||||||||||||||
Electricity | — | 4 | 1 | 5 | ||||||||||||||||||||||||||||||||
Natural gas | — | 2 | — | 2 | ||||||||||||||||||||||||||||||||
$ | 12 | $ | 90 | $ | 1 | $ | 103 | |||||||||||||||||||||||||||||
Liabilities - Liabilities from price risk management | ||||||||||||||||||||||||||||||||||||
activities (1) (3): | ||||||||||||||||||||||||||||||||||||
Electricity | $ | — | $ | 32 | $ | 80 | $ | 112 | ||||||||||||||||||||||||||||
Natural gas | — | 95 | 21 | 116 | ||||||||||||||||||||||||||||||||
$ | — | $ | 127 | $ | 101 | $ | 228 | |||||||||||||||||||||||||||||
-1 | Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate. | |||||||||||||||||||||||||||||||||||
-2 | Excludes insurance policies of $26 million, which are recorded at cash surrender value. | |||||||||||||||||||||||||||||||||||
-3 | For further information, see Note 5, Price Risk Management. | |||||||||||||||||||||||||||||||||||
As of December 31, 2013 | ||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust (1): | ||||||||||||||||||||||||||||||||||||
Money market funds | $ | — | $ | 59 | $ | — | $ | 59 | ||||||||||||||||||||||||||||
Debt securities: | ||||||||||||||||||||||||||||||||||||
Domestic government | 6 | 8 | — | 14 | ||||||||||||||||||||||||||||||||
Corporate credit | — | 9 | — | 9 | ||||||||||||||||||||||||||||||||
Non-qualified benefit plan trust (2): | ||||||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | 4 | 3 | — | 7 | ||||||||||||||||||||||||||||||||
International | 1 | — | — | 1 | ||||||||||||||||||||||||||||||||
Debt securities - domestic government | 1 | — | — | 1 | ||||||||||||||||||||||||||||||||
Assets from price risk management activities (1) (3): | ||||||||||||||||||||||||||||||||||||
Electricity | — | 9 | 1 | 10 | ||||||||||||||||||||||||||||||||
Natural gas | — | 4 | — | 4 | ||||||||||||||||||||||||||||||||
$ | 12 | $ | 92 | $ | 1 | $ | 105 | |||||||||||||||||||||||||||||
Liabilities - Liabilities from price risk management | ||||||||||||||||||||||||||||||||||||
activities (1) (3): | ||||||||||||||||||||||||||||||||||||
Electricity | $ | — | $ | 10 | $ | 117 | $ | 127 | ||||||||||||||||||||||||||||
Natural gas | — | 40 | 23 | 63 | ||||||||||||||||||||||||||||||||
$ | — | $ | 50 | $ | 140 | $ | 190 | |||||||||||||||||||||||||||||
-1 | Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate. | |||||||||||||||||||||||||||||||||||
-2 | Excludes insurance policies of $26 million, which are recorded at cash surrender value. | |||||||||||||||||||||||||||||||||||
-3 | For further information, see Note 5, Price Risk Management. | |||||||||||||||||||||||||||||||||||
The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions): | ||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||
As of December 31, 2014: | ||||||||||||||||||||||||||||||||||||
Defined Benefit Pension Plan assets: | ||||||||||||||||||||||||||||||||||||
Money market funds | $ | — | $ | 6 | $ | — | $ | 6 | ||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | $ | 42 | $ | 146 | $ | — | $ | 188 | ||||||||||||||||||||||||||||
International | — | 171 | — | 171 | ||||||||||||||||||||||||||||||||
Debt securities: | ||||||||||||||||||||||||||||||||||||
Domestic government and corporate credit | — | 197 | — | 197 | ||||||||||||||||||||||||||||||||
Private equity funds | — | — | 29 | 29 | ||||||||||||||||||||||||||||||||
$ | 42 | $ | 520 | $ | 29 | $ | 591 | |||||||||||||||||||||||||||||
Other Postretirement Benefit Plans assets: | ||||||||||||||||||||||||||||||||||||
Money market funds | $ | — | $ | 6 | $ | — | $ | 6 | ||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | 10 | 1 | — | 11 | ||||||||||||||||||||||||||||||||
International | 10 | — | — | 10 | ||||||||||||||||||||||||||||||||
Debt securities—Domestic government | 5 | — | — | 5 | ||||||||||||||||||||||||||||||||
$ | 25 | $ | 7 | $ | — | $ | 32 | |||||||||||||||||||||||||||||
As of December 31, 2013: | ||||||||||||||||||||||||||||||||||||
Defined Benefit Pension Plan assets: | ||||||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | $ | 166 | $ | 19 | $ | — | $ | 185 | ||||||||||||||||||||||||||||
International | 185 | — | — | 185 | ||||||||||||||||||||||||||||||||
Debt securities: | ||||||||||||||||||||||||||||||||||||
Domestic government and corporate credit | — | 181 | — | 181 | ||||||||||||||||||||||||||||||||
Corporate credit | 14 | — | — | 14 | ||||||||||||||||||||||||||||||||
Private equity funds | — | — | 31 | 31 | ||||||||||||||||||||||||||||||||
$ | 365 | $ | 200 | $ | 31 | $ | 596 | |||||||||||||||||||||||||||||
Other Postretirement Benefit Plans assets: | ||||||||||||||||||||||||||||||||||||
Money market funds | $ | — | $ | 10 | $ | — | $ | 10 | ||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||||||
Domestic | 8 | 2 | — | 10 | ||||||||||||||||||||||||||||||||
International | 9 | — | — | 9 | ||||||||||||||||||||||||||||||||
Debt securities—Domestic government | 3 | — | — | 3 | ||||||||||||||||||||||||||||||||
$ | 20 | $ | 12 | $ | — | $ | 32 | |||||||||||||||||||||||||||||
Schedule of Changes in Fair Value of Plan Assets [Table Text Block] | Changes in the fair value of assets held by the pension plan classified as Level 3 in the fair value hierarchy, which consists of Private equity funds, were as follows (in millions): | |||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||
Level 3 balance as of beginning of year | $ | 31 | $ | 32 | ||||||||||||||||||||||||||||||||
Unrealized gains, net | 2 | 4 | ||||||||||||||||||||||||||||||||||
Realized gains (losses), net | 3 | (2 | ) | |||||||||||||||||||||||||||||||||
Sales, net | (7 | ) | (3 | ) | ||||||||||||||||||||||||||||||||
Level 3 balance as of end of year | $ | 29 | $ | 31 | ||||||||||||||||||||||||||||||||
Schedule of Defined Benefit Plans Disclosures [Table Text Block] | The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and non-qualified benefit plans as of and for the years ended December 31, 2014 and 2013. Information related to the Other NQBP is not included in the following tables (dollars in millions): | |||||||||||||||||||||||||||||||||||
Defined Benefit Pension Plan | Other Postretirement | Non-Qualified | ||||||||||||||||||||||||||||||||||
Benefits | Benefit Plans | |||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||
Benefit obligation: | ||||||||||||||||||||||||||||||||||||
As of January 1 | $ | 705 | $ | 728 | $ | 77 | $ | 84 | $ | 24 | $ | 27 | ||||||||||||||||||||||||
Service cost | 15 | 17 | 2 | 2 | — | — | ||||||||||||||||||||||||||||||
Interest cost | 34 | 30 | 4 | 3 | 1 | 1 | ||||||||||||||||||||||||||||||
Participants’ contributions | — | — | 1 | 2 | — | — | ||||||||||||||||||||||||||||||
Actuarial (gain) loss | 72 | (38 | ) | 4 | (9 | ) | 5 | (2 | ) | |||||||||||||||||||||||||||
Contractual termination benefits | — | — | 1 | 1 | — | — | ||||||||||||||||||||||||||||||
Benefit payments | (48 | ) | (32 | ) | (6 | ) | (6 | ) | (3 | ) | (2 | ) | ||||||||||||||||||||||||
Administrative expenses | (1 | ) | — | — | — | — | — | |||||||||||||||||||||||||||||
As of December 31 | $ | 777 | $ | 705 | $ | 83 | $ | 77 | $ | 27 | $ | 24 | ||||||||||||||||||||||||
Fair value of plan assets: | ||||||||||||||||||||||||||||||||||||
As of January 1 | $ | 596 | $ | 537 | $ | 32 | $ | 28 | $ | 16 | $ | 15 | ||||||||||||||||||||||||
Actual return on plan assets | 44 | 91 | 1 | 5 | 1 | 3 | ||||||||||||||||||||||||||||||
Company contributions | — | — | 4 | 3 | 1 | — | ||||||||||||||||||||||||||||||
Participants’ contributions | — | — | 1 | 2 | — | — | ||||||||||||||||||||||||||||||
Benefit payments | (48 | ) | (32 | ) | (6 | ) | (6 | ) | (3 | ) | (2 | ) | ||||||||||||||||||||||||
Administrative expenses | (1 | ) | — | — | — | — | — | |||||||||||||||||||||||||||||
As of December 31 | $ | 591 | $ | 596 | $ | 32 | $ | 32 | $ | 15 | $ | 16 | ||||||||||||||||||||||||
Unfunded position as of December 31 | $ | (186 | ) | $ | (109 | ) | $ | (51 | ) | $ | (45 | ) | $ | (12 | ) | $ | (8 | ) | ||||||||||||||||||
Accumulated benefit plan obligation as of December 31 | $ | 691 | $ | 631 | N/A | N/A | $ | 27 | $ | 24 | ||||||||||||||||||||||||||
Classification in consolidated balance sheet: | ||||||||||||||||||||||||||||||||||||
Noncurrent asset | $ | — | $ | — | $ | — | $ | — | $ | 15 | $ | 16 | ||||||||||||||||||||||||
Current liability | — | — | — | — | (2 | ) | (2 | ) | ||||||||||||||||||||||||||||
Noncurrent liability | (186 | ) | (109 | ) | (51 | ) | (45 | ) | (25 | ) | (22 | ) | ||||||||||||||||||||||||
Net liability | $ | (186 | ) | $ | (109 | ) | $ | (51 | ) | $ | (45 | ) | $ | (12 | ) | $ | (8 | ) | ||||||||||||||||||
Amounts included in comprehensive income: | ||||||||||||||||||||||||||||||||||||
Net actuarial (gain) loss | $ | 67 | $ | (89 | ) | $ | 5 | $ | (11 | ) | $ | 5 | $ | (1 | ) | |||||||||||||||||||||
Amortization of net actuarial loss | (17 | ) | (24 | ) | (1 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||||||||||||||||||
Amortization of prior service cost | — | — | (1 | ) | (1 | ) | — | — | ||||||||||||||||||||||||||||
$ | 50 | $ | (113 | ) | $ | 3 | $ | (13 | ) | $ | 4 | $ | (2 | ) | ||||||||||||||||||||||
Amounts included in AOCL*: | ||||||||||||||||||||||||||||||||||||
Net actuarial loss | $ | 236 | $ | 186 | $ | 10 | $ | 6 | $ | 13 | $ | 9 | ||||||||||||||||||||||||
Prior service cost | — | — | 1 | 2 | — | — | ||||||||||||||||||||||||||||||
$ | 236 | $ | 186 | $ | 11 | $ | 8 | $ | 13 | $ | 9 | |||||||||||||||||||||||||
Defined Benefit Pension Plan | Other Postretirement | Non-Qualified | ||||||||||||||||||||||||||||||||||
Benefits | Benefit Plans | |||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||
Assumptions used: | ||||||||||||||||||||||||||||||||||||
Discount rate for benefit obligation | 4.02 | % | 4.84 | % | 3.07 | % | - | 3.46 | % | - | 4.02 | % | 4.84 | % | ||||||||||||||||||||||
4.1 | % | 4.96 | % | |||||||||||||||||||||||||||||||||
Discount rate for benefit cost | 4.84 | % | 4.24 | % | 3.46 | % | - | 2.77 | % | - | 4.84 | % | 4.24 | % | ||||||||||||||||||||||
4.96 | % | 4.13 | % | |||||||||||||||||||||||||||||||||
Weighted average rate of compensation increase for benefit obligation | 3.65 | % | 3.65 | % | 4.58 | % | 4.58 | % | N/A | N/A | ||||||||||||||||||||||||||
Weighted average rate of compensation increase for benefit cost | 3.65 | % | 3.65 | % | 4.58 | % | 4.58 | % | N/A | N/A | ||||||||||||||||||||||||||
Long-term rate of return on plan assets for benefit obligation | 7.5 | % | 7.5 | % | 6.37 | % | 6.46 | % | N/A | N/A | ||||||||||||||||||||||||||
Long-term rate of return on plan assets for benefit cost | 7.5 | % | 8.25 | % | 6.46 | % | 5.89 | % | N/A | N/A | ||||||||||||||||||||||||||
* | Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are transferred to Regulatory assets due to the future recoverability from retail customers. Accordingly, as of the balance sheet date, such amounts are included in Regulatory assets. | |||||||||||||||||||||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | Net periodic benefit cost consists of the following for the years ended December 31 (in millions): | |||||||||||||||||||||||||||||||||||
Defined Benefit | Other Postretirement | Non-Qualified | ||||||||||||||||||||||||||||||||||
Pension Plan | Benefits | Benefit Plans | ||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||||||
Service cost | $ | 15 | $ | 17 | $ | 14 | $ | 2 | $ | 2 | $ | 2 | $ | — | $ | — | $ | — | ||||||||||||||||||
Interest cost on benefit obligation | 34 | 30 | 31 | 4 | 3 | 3 | 1 | 1 | 1 | |||||||||||||||||||||||||||
Expected return on plan assets | (39 | ) | (40 | ) | (41 | ) | (2 | ) | (1 | ) | (1 | ) | — | — | — | |||||||||||||||||||||
Amortization of prior service cost | — | — | — | 1 | 1 | 1 | — | — | — | |||||||||||||||||||||||||||
Amortization of net actuarial loss | 17 | 24 | 17 | 1 | 1 | 1 | 1 | 1 | 1 | |||||||||||||||||||||||||||
Net periodic benefit cost | $ | 27 | $ | 31 | $ | 21 | $ | 6 | $ | 6 | $ | 6 | $ | 2 | $ | 2 | $ | 2 | ||||||||||||||||||
Schedule of Expected Benefit Payments [Table Text Block] | The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions): | |||||||||||||||||||||||||||||||||||
Payments Due | ||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | 2020 - 2024 | |||||||||||||||||||||||||||||||
Defined benefit pension plan | $ | 35 | $ | 37 | $ | 38 | $ | 40 | $ | 41 | $ | 221 | ||||||||||||||||||||||||
Other postretirement benefits | 5 | 5 | 5 | 5 | 5 | 26 | ||||||||||||||||||||||||||||||
Non-qualified benefit plans | 2 | 2 | 2 | 2 | 3 | 9 | ||||||||||||||||||||||||||||||
Total | $ | 42 | $ | 44 | $ | 45 | $ | 47 | $ | 49 | $ | 256 | ||||||||||||||||||||||||
Income_Taxes_Income_Taxes_Tabl
Income Taxes Income Taxes (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Income Taxes [Abstract] | ||||||||||||
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | Income tax expense consists of the following (in millions): | |||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Current: | ||||||||||||
Federal | $ | 20 | $ | 10 | $ | 16 | ||||||
State and local | 2 | — | 1 | |||||||||
22 | 10 | 17 | ||||||||||
Deferred: | ||||||||||||
Federal | 26 | 4 | 30 | |||||||||
State and local | 13 | 7 | 17 | |||||||||
39 | 11 | 47 | ||||||||||
Income tax expense | $ | 61 | $ | 21 | $ | 64 | ||||||
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The significant differences between the U.S. federal statutory rate and PGE’s effective tax rate for financial reporting purposes are as follows: | |||||||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory tax rate | 35 | % | 35 | % | 35 | % | ||||||
Federal tax credits | (11.4 | ) | (21.8 | ) | (11.8 | ) | ||||||
State and local taxes, net of federal tax benefit | 3.9 | 3.4 | 3.5 | |||||||||
Flow through depreciation and cost basis differences | (2.3 | ) | 2.8 | 2.4 | ||||||||
Adjustment to deferred taxes for change in blended composite state tax rate | — | — | 2.6 | |||||||||
Other | 0.8 | (2.6 | ) | (0.6 | ) | |||||||
Effective tax rate | 26 | % | 16.8 | % | 31.1 | % | ||||||
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | Deferred income tax assets and liabilities consist of the following (in millions): | |||||||||||
As of December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Deferred income tax assets: | ||||||||||||
Employee benefits | $ | 161 | $ | 122 | ||||||||
Price risk management | 88 | 71 | ||||||||||
Regulatory liabilities | 48 | 33 | ||||||||||
Tax credits | 13 | 51 | ||||||||||
Other | 1 | — | ||||||||||
Total deferred income tax assets | 311 | 277 | ||||||||||
Deferred income tax liabilities: | ||||||||||||
Depreciation and amortization | 693 | 646 | ||||||||||
Regulatory assets | 210 | 175 | ||||||||||
Total deferred income tax liabilities | 903 | 821 | ||||||||||
Deferred income tax liability, net | $ | (592 | ) | $ | (544 | ) | ||||||
Classification of net deferred income taxes: | ||||||||||||
Current deferred income tax asset * | $ | 33 | $ | 42 | ||||||||
Noncurrent deferred income tax liability | (625 | ) | (586 | ) | ||||||||
$ | (592 | ) | $ | (544 | ) | |||||||
* Included in Other current assets in the consolidated balance sheets. |
Stockbased_Compensation_Expens1
Stock-based Compensation Expense Restricted and Performance Stock Unit activity (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract] | ||||||||||
Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block] | RSU activity is summarized in the following table: | |||||||||
Units | Weighted Average | |||||||||
Grant Date | ||||||||||
Fair Value | ||||||||||
Outstanding as of December 31, 2011 | 491,404 | $ | 18.54 | |||||||
Granted | 186,495 | 24.72 | ||||||||
Forfeited | (22,947 | ) | 18.95 | |||||||
Vested | (214,390 | ) | 15.67 | |||||||
Outstanding as of December 31, 2012 | 440,562 | 22.54 | ||||||||
Granted | 183,071 | 29.25 | ||||||||
Forfeited | (7,007 | ) | 27.15 | |||||||
Vested | (185,536 | ) | 20.2 | |||||||
Outstanding as of December 31, 2013 | 431,090 | 26.31 | ||||||||
Granted | 203,410 | 31.49 | ||||||||
Forfeited | (12,278 | ) | 29.9 | |||||||
Vested | (158,329 | ) | 24.95 | |||||||
Outstanding as of December 31, 2014 | 463,893 | 28.96 | ||||||||
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block] | The fair value of stock-based compensation related to the TSR component of performance-based RSUs was determined using the Monte Carlo model and the following weighted average assumptions: | |||||||||
2014 | 2013 | |||||||||
Risk-free interest rate | 0.6 | % | 0.3 | % | ||||||
Expected dividend yield | — | % | — | % | ||||||
Expected term (in years) | 3 | 3 | ||||||||
Volatility | 12.40% | - | 23.00% | 12.10% | - | 25.10% |
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Earnings Per Share [Abstract] | |||||||||
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands): | ||||||||
Years Ended December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
Weighted average common shares outstanding—basic | 78,180 | 76,821 | 75,498 | ||||||
Dilutive effect of potential common shares | 2,314 | 567 | 149 | ||||||
Weighted average common shares outstanding—diluted | 80,494 | 77,388 | 75,647 | ||||||
Commitments_and_Guarantees_Tab
Commitments and Guarantees (Tables) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Long-term Purchase Commitment [Line Items] | ||||||||||||||||||||||||||||
Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block] | As of December 31, 2014, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions): | |||||||||||||||||||||||||||
Payments Due | ||||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||||||||
Capital and other purchase commitments | $ | 242 | $ | 21 | $ | 2 | $ | 2 | $ | 2 | $ | 74 | $ | 343 | ||||||||||||||
Purchased power and fuel: | ||||||||||||||||||||||||||||
Electricity purchases | 179 | 167 | 140 | 143 | 143 | 833 | 1,605 | |||||||||||||||||||||
Capacity contracts | 27 | 26 | 6 | 6 | 5 | 20 | 90 | |||||||||||||||||||||
Public utility districts | 8 | 7 | 5 | 4 | 2 | 23 | 49 | |||||||||||||||||||||
Natural gas | 56 | 37 | 40 | 40 | 36 | 244 | 453 | |||||||||||||||||||||
Coal and transportation | 23 | 14 | 11 | 5 | 5 | — | 58 | |||||||||||||||||||||
Operating leases | 10 | 11 | 12 | 11 | 8 | 192 | 244 | |||||||||||||||||||||
Total | $ | 545 | $ | 283 | $ | 216 | $ | 211 | $ | 201 | $ | 1,386 | $ | 2,842 | ||||||||||||||
Schedule of Long-term Contracts for Purchase of Electric Power [Table Text Block] | PGE has long-term power purchase agreements with certain public utility districts in the state of Washington and with the City of Portland, Oregon. Under the agreements, the Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether or not they are operable. The future minimum payments for the public utility districts in the preceding table reflect the principal payment only and do not include interest, operation, or maintenance expenses. Selected information regarding these projects is summarized as follows (dollars in millions): | |||||||||||||||||||||||||||
Revenue Bonds as of December 31, 2014 | PGE’s Share as of December 31, 2014 | Contract | PGE Cost, | |||||||||||||||||||||||||
Expiration | including Debt Service | |||||||||||||||||||||||||||
Output | Capacity | 2014 | 2013 | 2012 | ||||||||||||||||||||||||
(in MW) | ||||||||||||||||||||||||||||
Priest Rapids and Wanapum | $ | 1,102 | 8.6 | % | 163 | 2052 | $ | 14 | $ | 14 | $ | 14 | ||||||||||||||||
Wells | 215 | 19.4 | 150 | 2018 | 10 | 10 | 10 | |||||||||||||||||||||
Portland Hydro | 4 | 100 | 36 | 2017 | 4 | 4 | 4 | |||||||||||||||||||||
Jointlyowned_Plant_Tables
Jointly-owned Plant (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Jointly-owned Plant [Abstract] | |||||||||||||||||||
Schedule of Jointly Owned Utility Plants [Table Text Block] | As of December 31, 2014, PGE had the following investments in jointly-owned plant (dollars in millions): | ||||||||||||||||||
PGE | In-service Date | Plant | Accumulated | Construction | |||||||||||||||
Share | In-service | Depreciation* | Work In | ||||||||||||||||
Progress | |||||||||||||||||||
Boardman | 90 | % | 1980 | $ | 510 | $ | 350 | $ | — | ||||||||||
Colstrip | 20 | 1986 | 520 | 334 | 2 | ||||||||||||||
Pelton/Round Butte | 66.67 | 1958 | / | 1964 | 237 | 55 | 8 | ||||||||||||
Total | $ | 1,267 | $ | 739 | $ | 10 | |||||||||||||
* | Excludes AROs and accumulated asset retirement removal costs. |
Basis_of_Presentation_Details
Basis of Presentation (Details) (USD $) | 12 Months Ended | |||||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2009 |
sqmi | ||||||
Basis of Presentation [Abstract] | ||||||
Incorporated Cities | 52 | |||||
Service Area Sq Miles | 4,000 | |||||
Number of Retail Customers | 842,273 | |||||
Service area population | 1,800,000 | |||||
Percent of State's Population | 46.00% | |||||
Entity Number of Employees | 2,600 | |||||
Number of Union Employees | 780 | |||||
Number of Union Employees Subject to Agreement A | 743 | |||||
Number of Union Employees Subject to Agreement B | 37 | |||||
revenue overstatment | $9 | $3 | $3 | $2 | $1 | |
Margin Deposit Assets | 11 | 9 | ||||
Renewable adjustment clause deferrals | 1 | |||||
Cash Received from BPA | $13 | $1 | $0 |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies Estimated average service lives (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Production, excluding thermal: | |
Hydro | 87 |
Wind | 27 |
Transmission | 53 |
Distribution | 40 |
General | 13 |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Property, Plant and Equipment [Line Items] | |||
Other Investments | $120 | $104 | |
Business days after the invoice date | 16 | ||
Days after the due date | 45 | ||
Wholesale accounts receivable written off | 0 | 0 | 0 |
Margin deposit | 11 | 9 | |
Letters of Credit Outstanding, Amount | 30 | 29 | |
Expenses related to Cascade Crossing | 0 | 52 | 0 |
Public Utilities, Allowance for Funds Used During Construction, Rate | 7.40% | 7.50% | 7.50% |
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest | 22 | 7 | 4 |
Allowance for equity funds used during construction | 37 | 13 | 6 |
Depreciation expense rate | 3.60% | 3.70% | 3.80% |
Asset Retirement Removal Costs Included in Depreciation Expense | 57 | 55 | 55 |
Finite-Lived Intangible Assets, Accumulated Amortization | 191 | 170 | |
Amortization of Intangible Assets | 25 | 22 | 22 |
Future Amortization Expense, Year One | 35 | ||
Future Amortization Expense, Year Two | 33 | ||
Future Amortization Expense, Year Three | 29 | ||
Future Amortization Expense, Year Four | 28 | ||
Future Amortization Expense, Year Five | 22 | ||
Power Cost Deadband - Lower Threshold | 15 | ||
Power Cost Deadband - Upper Threshold | 30 | ||
Public Utilities, Approved Return on Equity, Percentage | 9.75% | 10.00% | 10.00% |
Net Variable Power Cost Underrun | -7 | -17 | |
Net variable power cost overrun | 11 | ||
Estimated Refund Under Power Cost Adjustment Mechanism | 0 | 0 | 0 |
Actual Refund Under Power Cost Adjustment Mechanism | 0 | 0 | |
Franchise taxes | 42 | 41 | 42 |
Deferred Tax Assets, Regulatory Assets and Liabilities | 48 | 33 | |
Noncurrent Regulatory Assets [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Deferred Tax Assets, Regulatory Assets and Liabilities | 86 | 76 | |
Noncurrent Regulatory Liabilities [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Asset Retirement Obligations, Noncurrent | $39 | $39 |
Balance_Sheet_Components_Allow
Balance Sheet Components Allowance for Uncollectible accounts activity (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Balance as of beginning of year | $6 | $5 | $6 |
Increase in provision | 6 | 6 | 6 |
Amounts written off, less recoveries | -6 | -5 | -7 |
Balance as of end of year | $6 | $6 | $5 |
Balance_Sheet_Components_Inves
Balance Sheet Components Investments Held in Trust (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Marketable securities, at fair value: | ||
Decommissioning Fund Investments, Fair Value | $90 | $82 |
Non-qualified benefit plan trust | 32 | 35 |
Nuclear Decommissioning [Member] | ||
Cash equivalents | 65 | 59 |
Marketable securities, at fair value: | ||
Equity securities | 0 | 0 |
Debt securities | 25 | 23 |
Insurance contracts, at cash surrender value | 0 | 0 |
Decommissioning Fund Investments, Fair Value | 90 | 82 |
Non Qualified Benefit Plans [Member] | ||
Cash equivalents | 0 | 0 |
Marketable securities, at fair value: | ||
Equity securities | 6 | 8 |
Debt securities | 0 | 1 |
Insurance contracts, at cash surrender value | 26 | 26 |
Non-qualified benefit plan trust | $32 | $35 |
Balance_Sheet_Components_Sched
Balance Sheet Components Schedule of Other Asssets and Other Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | |||
Other current assets: | |||
Prepaid Expense, Current | $39 | $38 | |
Current deferred income tax asset | 33 | 42 | |
accrued sales tax refund | 23 | 0 | 0 |
Margin Deposit Assets | 11 | 9 | |
Assets from price risk management activities | 6 | 13 | |
Other | 3 | 1 | |
Other Assets, Current | 115 | 103 | |
Accrued expenses and other current liabilities: | |||
Regulatory Liability, Current | 60 | 1 | |
Accrued employee compensation and benefits | 51 | 46 | |
Accrued interest payable | 26 | 23 | |
Dividends payable | 23 | 22 | |
Taxes Payable, Current | 22 | 21 | |
Other | 54 | 58 | |
Other Liabilities, Current | $236 | $171 |
Balance_Sheet_Components_Detai
Balance Sheet Components (Details) (USD $) | 9 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Sep. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Allowance for Doubtful Accounts Receivable, Current | $6 | $6 | $5 | $6 | |
Proceeds from Legal Settlements | $50 | $6 | $44 | $0 |
Recovered_Sheet2
Fair Value of FInancial Instruments Schedule of Fair Value (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money market funds | $65 | $59 |
Domestic government, Debt securities | 14 | 14 |
Corporate debt securities held in decommissioning trust assets | 11 | 9 |
Domestic Equity Securities | 5 | 7 |
International Equity Securities | 1 | 1 |
Debt securities - domestic government | 1 | |
Electricity | 5 | 10 |
Natural gas | 2 | 4 |
Financial Instruments, Owned, at Fair Value | 103 | 105 |
Liabilities from price risk management activities: [Abstract] | ||
Electricity | 112 | 127 |
Natural gas | 116 | 63 |
Liabilities, Fair Value Disclosure | 228 | 190 |
Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money market funds | 0 | 0 |
Domestic government, Debt securities | 7 | 6 |
Corporate debt securities held in decommissioning trust assets | 0 | 0 |
Domestic Equity Securities | 4 | 4 |
International Equity Securities | 1 | 1 |
Debt securities - domestic government | 1 | |
Electricity | 0 | 0 |
Natural gas | 0 | 0 |
Financial Instruments, Owned, at Fair Value | 12 | 12 |
Liabilities from price risk management activities: [Abstract] | ||
Electricity | 0 | 0 |
Natural gas | 0 | 0 |
Liabilities, Fair Value Disclosure | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money market funds | 65 | 59 |
Domestic government, Debt securities | 7 | 8 |
Corporate debt securities held in decommissioning trust assets | 11 | 9 |
Domestic Equity Securities | 1 | 3 |
International Equity Securities | 0 | 0 |
Debt securities - domestic government | 0 | |
Electricity | 4 | 9 |
Natural gas | 2 | 4 |
Financial Instruments, Owned, at Fair Value | 90 | 92 |
Liabilities from price risk management activities: [Abstract] | ||
Electricity | 32 | 10 |
Natural gas | 95 | 40 |
Liabilities, Fair Value Disclosure | 127 | 50 |
Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money market funds | 0 | 0 |
Domestic government, Debt securities | 0 | 0 |
Corporate debt securities held in decommissioning trust assets | 0 | 0 |
Domestic Equity Securities | 0 | 0 |
International Equity Securities | 0 | 0 |
Debt securities - domestic government | 0 | |
Electricity | 1 | 1 |
Natural gas | 0 | 0 |
Financial Instruments, Owned, at Fair Value | 1 | 1 |
Liabilities from price risk management activities: [Abstract] | ||
Electricity | 80 | 117 |
Natural gas | 21 | 23 |
Liabilities, Fair Value Disclosure | 101 | 140 |
Non Qualified Benefit Plans [Member] | ||
Liabilities from price risk management activities: [Abstract] | ||
Insurance contracts, at cash surrender value | $26 | $26 |
Fair_Value_of_FInancial_Instru2
Fair Value of FInancial Instruments Fair Value Options Quantitative Disclosure (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Minimum [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | $11.97 | $9.63 |
Natural gas financial swaps | 2.88 | 3.16 |
Fnancial swaps - electricity | 11.97 | 9.63 |
Maximum [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | 122.72 | 77.95 |
Natural gas financial swaps | 4.86 | 4.49 |
Fnancial swaps - electricity | 39.26 | 46.07 |
Weighted Average [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | 37.43 | 40.18 |
Natural gas financial swaps | 3.41 | 3.71 |
Fnancial swaps - electricity | 27.88 | 33.01 |
Assets [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | 0 | 0 |
Natural gas financial swaps | 0 | 0 |
Fnancial swaps - electricity | 1,000,000 | 1,000,000 |
Total commodity contracts | 1,000,000 | 1,000,000 |
Liabilities [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | 77,000,000 | 103,000,000 |
Natural gas financial swaps | 21,000,000 | 23,000,000 |
Fnancial swaps - electricity | 3,000,000 | 14,000,000 |
Total commodity contracts | $101,000,000 | $140,000,000 |
Fair_Value_of_FInancial_Instru3
Fair Value of FInancial Instruments Fair Value Unobservable Input Reconciliation (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Net realized and unrealized losses | $15 | $134 | |
Settlements | -4 | -1 | |
Net transfers out of Level 3 to Level 2 | -50 | -10 | |
Net liabilities from price risk management activities as of end of year | 100 | 139 | 16 |
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting | 12 | 133 | |
Net realized losses | $3 | $1 |
Recovered_Sheet3
Fair Value of Financial Instruments (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Net realized losses | $3,000,000 | $1,000,000 |
Long-term Debt, Fair Value | 2,901,000,000 | 2,074,000,000 |
Long-term Debt | 2,501,000,000 | 1,916,000,000 |
Defined Benefit Plan, Transfers Between Measurement Levels | 0 | 0 |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3 | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | 2,596,000,000 | |
Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | $305,000,000 |
Fair_values_of_price_risk_mana
Fair values of price risk management assets and liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Current Assets, Commodity Contracts: | ||
Electricity | $4 | $9 |
Natural Gas | 2 | 4 |
Total current derivative assets | 6 | 13 |
Noncurrent Assets, Commodity Contracts: [Abstract] | ||
Commodity Contract Asset, Noncurrent, Electricity | 1 | 1 |
Derivative Asset, Noncurrent | 1 | 1 |
Total derivative assets not designated as hedging instruments | 7 | 14 |
Total derivative assets | 7 | 14 |
Current Liabilities, Commodity Contracts: [Abstract] | ||
Electricity | 54 | 20 |
Natural Gas | 52 | 29 |
Total current derivative liabilities | 106 | 49 |
Noncurrent Liabilities, Commodity Contracts: [Abstract] | ||
Electricity | 58 | 107 |
Natural Gas | 64 | 34 |
Total noncurrent derivative liabilities | 122 | 141 |
Total derivative liabilities not designated as hedging instruments | 228 | 190 |
Total derivative liabilities | $228 | $190 |
Net_volumes_related_to_price_r
Net volumes related to price risk management activities (Details) (CAD) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | MMBTU | MWh |
MWh | MMBTU | |
Commodity contracts: [Abstract] | ||
Electricity | 16,000,000 | 14,000,000 |
Natural gas | 127,000,000 | 106,000,000 |
Foreign currency exchange | 7 | 7 |
Price_Risk_Management_Price_ri
Price Risk Management Price risk management assets and liabilities subject to master netting agreements (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Electricity [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | ($55) | ($91) |
Electricity [Member] | Gross amounts offset [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 0 |
Electricity [Member] | net amount presented [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -55 | -91 |
Electricity [Member] | Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -55 | -91 |
Electricity [Member] | Securities Pledged as Collateral [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 0 |
Electricity [Member] | Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 0 |
Natural Gas [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -17 | -1 |
Natural Gas [Member] | Gross amounts offset [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 0 |
Natural Gas [Member] | net amount presented [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -17 | -1 |
Natural Gas [Member] | Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -17 | -1 |
Natural Gas [Member] | Securities Pledged as Collateral [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 0 |
Natural Gas [Member] | Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 0 |
Liabilities, Total [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -72 | -92 |
Liabilities, Total [Member] | Gross amounts offset [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 0 |
Liabilities, Total [Member] | net amount presented [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -72 | -92 |
Liabilities, Total [Member] | Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -72 | -92 |
Liabilities, Total [Member] | Securities Pledged as Collateral [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 0 |
Liabilities, Total [Member] | Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $0 | $0 |
Net_realized_and_unrealized_ga
Net realized and unrealized gains and losses on derivative transactions (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Commodity contracts: [Abstract] | |||
Electricity | $13 | $78 | $56 |
Natural Gas | 72 | 28 | 19 |
Realized And Unrealized Losses Net Commodity Contracts, Foreign Currency | $0 | $1 | $0 |
Future_year_net_unrealized_gai
Future year net unrealized gain/loss recorded at balance sheet date expected to become realized (Details) (USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Commodity contracts: | |
Other Commitment, Due in Next Twelve Months | $14 |
Other Commitment, Due in Second Year | 11 |
Other Commitment, Due in Third Year | 11 |
Other Commitment, Due in Fourth Year | 7 |
Total | 43 |
Electricity [Member] | |
Commodity contracts: | |
Other Commitment, Due in Next Twelve Months | 50 |
Other Commitment, Due in Second Year | 19 |
Other Commitment, Due in Third Year | 6 |
Other Commitment, Due in Fourth Year | 5 |
Other Commitment, Due in Fifth Year | 5 |
Other Commitment, Due after Fifth Year | 22 |
Total | 107 |
Natural Gas [Member] | |
Commodity contracts: | |
Other Commitment, Due in Next Twelve Months | 49 |
Other Commitment, Due in Second Year | 44 |
Other Commitment, Due in Third Year | 18 |
Other Commitment, Due in Fourth Year | 3 |
Other Commitment, Due in Fifth Year | 0 |
Other Commitment, Due after Fifth Year | 0 |
Total | 114 |
Unrealized Gain Loss On Derivatives [Member] | |
Commodity contracts: | |
Other Commitment, Due in Next Twelve Months | 99 |
Other Commitment, Due in Second Year | 63 |
Other Commitment, Due in Third Year | 24 |
Other Commitment, Due in Fourth Year | 8 |
Other Commitment, Due in Fifth Year | 5 |
Other Commitment, Due after Fifth Year | 22 |
Total | $221 |
Counterparties_representing_10
Counterparties representing 10% or more (Details) | Dec. 31, 2014 | Dec. 31, 2013 |
Assets from price risk management activities: | ||
Counterparty A | 63.00% | 53.00% |
Counterparty B | 14.00% | 6.00% |
Concentration of Risk, Derivative Instruments, Assets | 77.00% | 59.00% |
Liabilities from price risk management activities: [Abstract] | ||
Counterparty C | 22.00% | 43.00% |
Counterparty D | 12.00% | 11.00% |
Concentration of Risk, Derivative Instruments, Liabilities | 34.00% | 54.00% |
Price_Risk_Management_Details
Price Risk Management (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative [Line Items] | |||
Derivative, Collateral, Master Netting Arrangements, Letters of Credit | $11 | $7 | |
Net gain or loss recognized in the statement of income offset by regulatory accounting | 83 | 120 | 42 |
Derivative, Net Liability Position, Aggregate Fair Value | 216 | ||
Collateral Already Posted, Aggregate Fair Value | 29 | ||
Collateral Aggregate Fair Value | 213 | ||
Margin Deposit Assets | $11 | $9 |
Regulatory_Assets_and_Liabilit2
Regulatory Assets and Liabilities Schedule of Regulatory Assets and Liabilities (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Regulatory Assets [Line Items] | ||
Remaining Recovery Period of Regulatory Assets, Price Risk Management | 3 years | |
Remaining Recovery Period of Regulatory Asset, Debt Reacquisition Costs | 8Â years | |
Price risk management | $6 | $13 |
Deferred income taxes | 48 | 33 |
remaining recovery period of regulatory assets, deferred capital projects | 1 year | |
Remaining refund period of regulatory liability, Trojan decommissioning activities | 2Â years | |
Current Regulatory Liabilities [Member] | ||
Regulatory Assets [Line Items] | ||
Asset retirement removal costs | 0 | 0 |
Proceeds from Legal Settlements | 23 | 0 |
Asset retirement obligations | 0 | 0 |
Other | 37 | 1 |
Total regulatory liabilities | 60 | 1 |
Noncurrent Regulatory Liabilities [Member] | ||
Regulatory Assets [Line Items] | ||
Asset retirement removal costs | 804 | 747 |
Proceeds from Legal Settlements | 34 | 49 |
Asset retirement obligations | 39 | 39 |
Other | 29 | 30 |
Total regulatory liabilities | 906 | 865 |
Regulatory Assets, Current [Member] | ||
Regulatory Assets [Line Items] | ||
Price risk management | 100 | 36 |
Pension and other postretirement plans | 0 | 0 |
Deferred income taxes | 0 | 0 |
Debt reacquisition costs | 0 | 0 |
Deferred capital project | 19 | 16 |
Other | 14 | 14 |
Total regulatory assets | 133 | 66 |
Noncurrent Regulatory Assets [Member] | ||
Regulatory Assets [Line Items] | ||
Price risk management | 121 | 140 |
Pension and other postretirement plans | 247 | 194 |
Deferred income taxes | 86 | 76 |
Debt reacquisition costs | 15 | 17 |
Deferred capital project | 0 | 18 |
Other | 25 | 19 |
Total regulatory assets | $494 | $464 |
Regulatory_Assets_and_Liabilit3
Regulatory Assets and Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Regulatory Assets and Liabilities Disclosure [Abstract] | ||
Regulatory Assets Earning a Return, Other Category | $33 | $16 |
Regulatory Assets Earning a Return | 63 | |
Regulatory Assets Earning a Rate of Return at the Cost of Debt | 19 | |
Authorized Cost of Debt | 5.54% | |
Regulatory Assets Earning a Rate of Return at the Cost of Capital | 2 | |
Authorized Cost of Capital | 7.65% | |
Regulatory Assets Earning a Rate of Return by Inclusion in Rate Base | 33 | |
Regulatory Assets Earning a Rate of Return at the Approved Rate | 9 | |
Approved Rate for Deferred Account Under Amortization, Low End of Range | 1.47% | |
Approved Rate for Deferred Accounts under Amortization, High End of Range | 1.77% | |
Trojan ISFSI pollution control tax credits | $8 |
Schedule_of_Asset_Retirement_O
Schedule of Asset Retirement Obligations (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Millions, unless otherwise specified | ||||
Asset Retirement Obligation Disclosure [Abstract] | ||||
Trojan decommissioning activities | $41 | $41 | ||
Utility plant | 64 | 49 | ||
Non-utility property | 11 | 10 | ||
Asset Retirement Obligation | $116 | $100 | $94 | $87 |
Schedule_of_Change_in_Asset_Re
Schedule of Change in Asset Retirement Obligations (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation Disclosure [Abstract] | |||||
Asset Retirement Obligation | $100 | $94 | $87 | ||
Asset Retirement Obligation, Liabilities Incurred | 7 | 8 | 15 | 4 | 0 |
Asset Retirement Obligation, Liabilities Settled | -3 | -4 | -3 | ||
Asset Retirement Obligation, Accretion Expense | 6 | 6 | 6 | ||
Asset Retirement Obligation, Revision of Estimate | 2 | 0 | 4 | ||
Asset Retirement Obligation | $116 | $116 | $116 | $100 | $94 |
Asset_Retirement_Obligations_D
Asset Retirement Obligations (Details) (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation Disclosure [Abstract] | |||||||
Damages sought in USDOE claim | $112 | ||||||
Asset Retirement Obligation Rate Recovery related to Trojan Plant | 4 | ||||||
Loss Contingency, Damages Awarded, Value | 70 | 9 | |||||
Proceeds from Legal Settlements | 50 | 6 | 44 | 0 | |||
Asset Retirement Obligation, Liabilities Incurred | $7 | $8 | $15 | $4 | $0 |
Revolving_Credit_Facilities_Sc
Revolving Credit Facilities Schedule of Short term debt (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Short-term Debt [Line Items] | |||
Average daily amount of short-term debt outstanding | $0 | $9 | $4 |
Weighted daily average interest rate | 0.00% | 0.40% | 0.40% |
Maximum amount outstanding during the year | $0 | $54 | $44 |
Revolving_Credit_Facilities_De
Revolving Credit Facilities (Details) (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Line of Credit Facility [Abstract] | |
Line of Credit Facility, Maximum Borrowing Capacity | $700,000,000 |
Credit Facilities - $400 million revolver | 400,000,000 |
Credit Facilities - $300 million revolver | 300,000,000 |
Line of Credit Facitlity, Covenant Terms, One Month Term | one |
Line of Credit Facitlity, Covenant Terms, Two Month Term | two |
Line of Credit Facitlity, Covenant Terms, Three Month Term | three |
Line of Credit Facitlity, Covenant Terms, Six Month Term | six |
Debt Instrument, Covenant Description | 0.65 |
Ratio of Indebtedness to Net Capital | 0.567 |
Commercial Paper, Maximum Term | 270 |
FERC Authorized Short-term Debt, effective through February 6, 2014 | 900,000,000 |
Short-term Debt | 0 |
Line of Credit Facility, Amount Outstanding | 20,000,000 |
Line of Credit Facility, Remaining Borrowing Capacity | 680,000,000 |
letter of credit facility | 30,000,000 |
Letters of Credit Outstanding, Amount | $56,000,000 |
Longterm_Debt_Schedule_of_Long
Long-term Debt Schedule of Long Term Debt Instruments (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Debt Instrument [Line Items] | ||
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.42% in 2014 and 5.62% in 2013, due at various dates through 2048 | $2,075 | $1,795 |
Unsecured Debt, Current | 305 | 0 |
Pollution Control Revenue Bonds, 5% rate, due 2033 | 142 | 148 |
Pollution Control Revenue Bonds owned by PGE | -21 | -27 |
Total long-term debt | 2,501 | 1,916 |
Less: current portion of long-term debt | -375 | 0 |
Long-term debt, net of current portion | $2,126 | $1,916 |
Longterm_Debt_Schedule_of_Matu
Long-term Debt Schedule of Maturities of Long term debt (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Long-term Debt, Unclassified [Abstract] | ||
2015 | $375 | |
2016 | 67 | |
2017 | 58 | |
2018 | 75 | |
2019 | 300 | |
Thereafter | 1,626 | |
Total long-term debt | $2,501 | $1,916 |
Long_term_debt_Details
Long term debt (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | ||||
In Millions, unless otherwise specified | Nov. 30, 2014 | Dec. 31, 2014 | Sep. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 31, 2015 |
Debt Instrument [Line Items] | ||||||||
Proceeds from Issuance of First Mortgage Bond | $280 | |||||||
Long-term Pollution Control Bond | 21 | 21 | ||||||
Pollution Control Bonds Retired | -6 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.51% | 4.44% | 4.39% | 4.44% | ||||
Proceeds from Issuance of Long-term Debt | 80 | 100 | 100 | 585 | 380 | 0 | ||
Unsecured Debt, Current | 305 | 305 | 0 | |||||
Debt Instrument, Description of Variable Rate Basis | 70 | |||||||
First mortgage Bonds - minimum rate | 3.46% | 3.46% | 3.46% | |||||
First Mortgage Bonds - maximum rate | 9.31% | 9.31% | 9.31% | |||||
Debt, Weighted Average Interest Rate | 5.42% | 5.42% | 5.62% | |||||
Unsecured term bank loan rate - minimum | 0.86% | 0.86% | ||||||
Unsecured term bank loan rate - maximum | 0.93% | 0.93% | ||||||
Pollution Control Revenue Bonds owned by PGE | 21 | 21 | 27 | |||||
Long-term Pollution Control Bond, Rate | 5.00% | 5.00% | 5.00% | |||||
Subsequent Event [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.55% | |||||||
Proceeds from Issuance of Long-term Debt | $75 |
Employee_Benefits_Assets_and_L
Employee Benefits Assets and Liabilities associated with Non-qualified benefit plans (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-qualified benefit plan trust | $32 | $35 |
Non-qualified benefit plan liabilities | 105 | 101 |
Other Postretirement Benefit Plans [Domain] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-qualified benefit plan trust | 0 | 0 |
Defined Benefit Pension Plan [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-qualified benefit plan trust | 17 | 19 |
Non-qualified benefit plan liabilities | 80 | 79 |
Non Qualified Benefit Plans [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-qualified benefit plan trust | 15 | 16 |
Non-qualified benefit plan liabilities | 25 | 22 |
Total Non-qualified benefit plan trust assets [Domain] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-qualified benefit plan trust | 32 | |
Non-qualified benefit plan liabilities | $105 | $101 |
Employee_Benefits_Schedule_of_
Employee Benefits Schedule of Allocation of Plan Assets (Details) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Pension Plan [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 100.00% | 100.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% |
Defined Benefit Pension Plan [Member] | Equity [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 67.00% | 67.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 66.00% | 67.00% |
Defined Benefit Pension Plan [Member] | Debt Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 33.00% | 33.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 34.00% | 33.00% |
Other Postretirement Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 100.00% | 100.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% |
Other Postretirement Benefit Plans [Member] | Equity [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 67.00% | 58.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 66.00% | 58.00% |
Other Postretirement Benefit Plans [Member] | Debt Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 33.00% | 42.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 34.00% | 42.00% |
Non Qualified Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 100.00% | 100.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% |
Non Qualified Benefit Plans [Member] | Equity [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 13.00% | 16.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 19.00% | 24.00% |
Non Qualified Benefit Plans [Member] | Debt Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 7.00% | 9.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 1.00% | 1.00% |
Non Qualified Benefit Plans [Member] | Other Contract [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Target Plan Asset Allocations | 80.00% | 75.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 80.00% | 75.00% |
Employee_Benefits_Schedule_of_1
Employee Benefits Schedule of Fair Value, Assets (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | |||
Defined Benefit Pension Plan assets: | |||
Money market funds | $6 | ||
Equity securities: | |||
Domestic | 188 | 185 | |
International equity securities - defined benefit pension plan assets | 171 | 185 | |
Debt securities: | |||
Domestic government and corporate credit | 197 | 181 | |
Corporate credit | 14 | ||
Private equity funds | 29 | 31 | |
Defined Benefit Plan, Fair Value of Plan Assets | 591 | 596 | |
Other Postretirement Benefit Plans assets: [Abstract] | |||
Money market funds | 6 | 10 | |
Domestic equity securities - Other postretirement benefit plan assets at fair value | 11 | 10 | |
International equity securities - other post retirement assets at fair value | 10 | 9 | |
Debt securities—Domestic government | 5 | 3 | |
Other post retirement benefit plan assets total | 32 | 32 | |
Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Pension Plan assets: | |||
Money market funds | 0 | ||
Equity securities: | |||
Domestic | 42 | 166 | |
International equity securities - defined benefit pension plan assets | 0 | 185 | |
Debt securities: | |||
Domestic government and corporate credit | 0 | 0 | |
Corporate credit | 14 | ||
Private equity funds | 0 | 0 | |
Defined Benefit Plan, Fair Value of Plan Assets | 42 | 365 | |
Other Postretirement Benefit Plans assets: [Abstract] | |||
Money market funds | 0 | 0 | |
Domestic equity securities - Other postretirement benefit plan assets at fair value | 10 | 8 | |
International equity securities - other post retirement assets at fair value | 10 | 9 | |
Debt securities—Domestic government | 5 | 3 | |
Other post retirement benefit plan assets total | 25 | 20 | |
Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Pension Plan assets: | |||
Money market funds | 6 | ||
Equity securities: | |||
Domestic | 146 | 19 | |
International equity securities - defined benefit pension plan assets | 171 | 0 | |
Debt securities: | |||
Domestic government and corporate credit | 197 | 181 | |
Corporate credit | 0 | ||
Private equity funds | 0 | 0 | |
Defined Benefit Plan, Fair Value of Plan Assets | 520 | 200 | |
Other Postretirement Benefit Plans assets: [Abstract] | |||
Money market funds | 6 | 10 | |
Domestic equity securities - Other postretirement benefit plan assets at fair value | 1 | 2 | |
International equity securities - other post retirement assets at fair value | 0 | 0 | |
Debt securities—Domestic government | 0 | 0 | |
Other post retirement benefit plan assets total | 7 | 12 | |
Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Pension Plan assets: | |||
Money market funds | 0 | ||
Equity securities: | |||
Domestic | 0 | 0 | |
International equity securities - defined benefit pension plan assets | 0 | 0 | |
Debt securities: | |||
Domestic government and corporate credit | 0 | 0 | |
Corporate credit | 0 | ||
Private equity funds | 29 | 31 | |
Defined Benefit Plan, Fair Value of Plan Assets | 29 | 31 | 32 |
Other Postretirement Benefit Plans assets: [Abstract] | |||
Money market funds | 0 | 0 | |
Domestic equity securities - Other postretirement benefit plan assets at fair value | 0 | 0 | |
International equity securities - other post retirement assets at fair value | 0 | 0 | |
Debt securities—Domestic government | 0 | 0 | |
Other post retirement benefit plan assets total | $0 | $0 |
Employee_Benefits_Schedule_of_2
Employee Benefits Schedule of Changes in Fair Value of Plan Assets (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Fair Value of Plan Assets | $591 | $596 |
Unrealized gain on assets | 2 | 4 |
Available-for-sale Securities, Gross Realized Gain (Loss) | 3 | -2 |
Purchases and sales, net | ($7) | ($3) |
Employee_Benefits_Schedule_of_3
Employee Benefits Schedule of Defined Benefit Plan Disclosures (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 |
Defined Benefit Plan Disclosure [Line Items] | ||||
Benefit payments | ($16) | |||
As of January 1 | 596 | 591 | ||
Noncurrent asset | -32 | -35 | ||
Noncurrent liability | -237 | -154 | ||
Pension Plans, Defined Benefit [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
As of January 1 | 777 | 705 | 728 | |
Service cost | 15 | 17 | 14 | |
Interest cost on benefit obligation | 34 | 30 | 31 | |
Participants’ contributions | 0 | 0 | ||
Actuarial loss (gain) | 72 | -38 | ||
Defined Benefit Plan, Special Termination Benefits | 0 | 0 | ||
Benefit payments | -48 | -32 | ||
Defined Benefit Plan, Administration Expenses | -1 | 0 | ||
As of January 1 | 596 | 537 | 591 | |
Unfunded position as of December 31 | 186 | 109 | ||
Net actuarial loss (gain) included in comprehensive income | 67 | -89 | ||
Defined Benefit Plan, Amortization of Gains (Losses) | -17 | -24 | -17 | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0 | 0 | 0 | |
Total Amounts included in comprehensive income | 50 | -113 | ||
Defined Benefit Plan, Accumulated Benefit Obligation | 691 | 631 | ||
Actual return on plan assets | 44 | 91 | ||
Company contributions | 0 | 0 | ||
Noncurrent asset | 0 | 0 | ||
Current liability | 0 | 0 | ||
Noncurrent liability | -186 | -109 | ||
Net actuarial loss | 236 | 186 | ||
Prior service cost | 0 | 0 | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 236 | 186 | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate | 4.02% | 4.84% | ||
Discount rate used to calculate benefit obligation | 4.84% | 4.24% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Rate of Compensation Increase | 3.65% | 3.65% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.65% | 3.65% | ||
Long-term rate of return on plan assets | 7.50% | 7.50% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 7.50% | 8.25% | ||
Other Postretirement Benefit Plans [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
As of January 1 | 83 | 77 | 84 | |
Service cost | 2 | 2 | 2 | |
Interest cost on benefit obligation | 4 | 3 | 3 | |
Participants’ contributions | 1 | 2 | ||
Actuarial loss (gain) | 4 | -9 | ||
Defined Benefit Plan, Special Termination Benefits | 1 | 1 | ||
Benefit payments | -6 | -6 | ||
Defined Benefit Plan, Administration Expenses | 0 | 0 | ||
As of January 1 | 32 | 28 | 32 | |
Unfunded position as of December 31 | 51 | 45 | ||
Net actuarial loss (gain) included in comprehensive income | 5 | -11 | ||
Defined Benefit Plan, Amortization of Gains (Losses) | -1 | -1 | -1 | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | -1 | -1 | -1 | |
Total Amounts included in comprehensive income | 3 | -13 | ||
Actual return on plan assets | 1 | 5 | ||
Company contributions | 4 | 3 | ||
Noncurrent asset | 0 | 0 | ||
Current liability | 0 | 0 | ||
Noncurrent liability | -51 | -45 | ||
Net actuarial loss | 10 | 6 | ||
Prior service cost | 1 | 2 | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 11 | 8 | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate | 3.07% | 3.46% | ||
Defined Benefit Plan Discount rate - upper range | 4.10% | 4.96% | ||
Discount rate used to calculate benefit obligation | 3.46% | 2.77% | ||
Defined Benefit Plan Cost Discount rate - upper range | 4.96% | 4.13% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Rate of Compensation Increase | 4.58% | 4.58% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 4.58% | 4.58% | ||
Long-term rate of return on plan assets | 6.37% | 6.46% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.46% | 5.89% | ||
Non Qualified Benefit Plans [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
As of January 1 | 27 | 24 | 27 | |
Service cost | 0 | 0 | 0 | |
Interest cost on benefit obligation | 1 | 1 | 1 | |
Participants’ contributions | 0 | 0 | ||
Actuarial loss (gain) | 5 | -2 | ||
Defined Benefit Plan, Special Termination Benefits | 0 | 0 | ||
Benefit payments | -3 | -2 | ||
Defined Benefit Plan, Administration Expenses | 0 | 0 | ||
As of January 1 | 16 | 15 | 15 | |
Unfunded position as of December 31 | 12 | 8 | ||
Net actuarial loss (gain) included in comprehensive income | 5 | -1 | ||
Defined Benefit Plan, Amortization of Gains (Losses) | -1 | -1 | -1 | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0 | 0 | 0 | |
Total Amounts included in comprehensive income | 4 | -2 | ||
Defined Benefit Plan, Accumulated Benefit Obligation | 27 | 24 | ||
Actual return on plan assets | 1 | 3 | ||
Company contributions | 1 | 0 | ||
Noncurrent asset | -15 | -16 | ||
Current liability | -2 | -2 | ||
Noncurrent liability | -25 | -22 | ||
Net actuarial loss | 13 | 9 | ||
Prior service cost | 0 | 0 | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | $13 | $9 | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate | 4.02% | 4.84% | ||
Discount rate used to calculate benefit obligation | 4.84% | 4.24% |
Employee_Benefits_Schedule_of_4
Employee Benefits Schedule of Net Benefit Costs (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Other Postretirement Benefit Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | $2 | $2 | $2 |
Interest cost on benefit obligation | 4 | 3 | 3 |
Expected return on plan assets | -2 | -1 | -1 |
Amortization of prior service cost | 1 | 1 | 1 |
Amortization of net actuarial loss | 1 | 1 | 1 |
Net periodic benefit cost | 6 | 6 | 6 |
Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 15 | 17 | 14 |
Interest cost on benefit obligation | 34 | 30 | 31 |
Expected return on plan assets | -39 | -40 | -41 |
Amortization of prior service cost | 0 | 0 | 0 |
Amortization of net actuarial loss | 17 | 24 | 17 |
Net periodic benefit cost | 27 | 31 | 21 |
Non Qualified Benefit Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 0 | 0 | 0 |
Interest cost on benefit obligation | 1 | 1 | 1 |
Expected return on plan assets | 0 | 0 | 0 |
Amortization of prior service cost | 0 | 0 | 0 |
Amortization of net actuarial loss | 1 | 1 | 1 |
Net periodic benefit cost | $2 | $2 | $2 |
Employee_Benefits_Schedule_of_5
Employee Benefits Schedule of Expected Benefit Payments (Details) (USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | $42 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 44 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 45 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 47 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 49 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 256 |
Pension Plans, Defined Benefit [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | 35 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 37 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 38 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 40 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 41 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 221 |
Other Postretirement Benefit Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | 5 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 5 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 5 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 5 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 5 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 26 |
Non Qualified Benefit Plans [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | 2 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 2 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 2 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 2 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 3 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | $9 |
Employee_Benefits_Details
Employee Benefits (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Employee Benefits [Abstract] | |||
Pension Contributions | $0 | $0 | $0 |
Defined Benefit Plan, Benefits Paid | 16 | ||
Contribution to health reimbursement account - sick time | 58.00% | ||
Contribution to health reimbursement account - earned time off | 100.00% | ||
OtherPostretirementDefinedBenefitPlanLiabilityCurrent | 2 | 2 | |
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year | 23 | ||
Net actuarial loss portion of amortization from AOCL for pension benefits | 20 | ||
Net Actuarial Loss Portion of Amortization from AOCL for Non-qualified benefits | 1 | ||
Net actuarial loss portion of amortiztion of AOCL for other postretirement benefits | 1 | ||
Prior service cost portion of amortization of AOCL for other postretirement benefits | 1 | ||
Defined benefit plan, current annual rate of health care cost increase | 7.00% | 7.50% | 8.00% |
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 0.50% | 0.50% | 0.50% |
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.00% | 5.00% | 5.00% |
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components | 0 | ||
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation | 0 | ||
Company match pre 2009 hire | 6.00% | ||
Company match post 2008 hire | 5.00% | ||
Company contribution percentage to 401k for post 2008 hires | 5.00% | ||
Company contribution percent to 401k for bargaining employees | 1.00% | ||
401k Plan Company contributions | $16 | $16 | $16 |
Income_Taxes_Schedule_of_Compo
Income Taxes Schedule of Components of Income Tax Expense (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Current: | |||
Federal | $20 | $10 | $16 |
State and local | 2 | 0 | 1 |
Current Income Tax Expense (Benefit) | 22 | 10 | 17 |
Deferred: | |||
Federal | 26 | 4 | 30 |
State and local | 13 | 7 | 17 |
deferred income tax expense | 39 | 11 | 47 |
Income tax expense | $61 | $21 | $64 |
Income_Taxes_Schedule_of_Effec
Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Income Taxes [Abstract] | |||
Federal statutory tax rate | 35.00% | 35.00% | 35.00% |
Federal tax credits | -11.40% | -21.80% | -11.80% |
State and local taxes, net of federal tax benefit | 3.90% | 3.40% | 3.50% |
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance | 0.00% | 0.00% | 2.60% |
Flow through depreciation and cost basis differences | -2.30% | 2.80% | 2.40% |
Other | 0.80% | -2.60% | -0.60% |
Effective tax rate | 26.00% | 16.80% | 31.10% |
Income_Taxes_Schedule_of_Defer
Income Taxes Schedule of Deferred tax Assets and Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Deferred income tax assets: | ||
Price risk management | $88 | $71 |
Employee benefits | 161 | 122 |
Deferred Tax Assets, tax credits, net of valuation allowance | 13 | 51 |
Deferred income taxes | 48 | 33 |
Deferred Tax Assets, Tax Deferred Expense, Other | 1 | 0 |
Total deferred income tax assets | 311 | 277 |
Deferred income tax liabilities: | ||
Depreciation and amortization | 693 | 646 |
Regulatory assets | 210 | 175 |
Total deferred income tax liabilities | 903 | 821 |
Deferred income tax liability, net | -592 | -544 |
Classification of net deferred income taxes: | ||
Current deferred income tax asset | 33 | 42 |
Noncurrent deferred income tax liability | ($625) | ($586) |
Income_Taxes_Income_taxes_Deta
Income Taxes Income taxes (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Operating Loss Carryforwards [Line Items] | ||
Deferred Tax Assets, Other | $17 | |
Tax Credit Carryforward, Federal | 10 | |
Tax Credit Carryforward, State | 3 | |
Deferred Tax Assets, Valuation Allowance | 0 | 0 |
Unrecognized Tax Benefits | $0 | $0 |
Stock_Purchase_Plan_Stock_Purc
Stock Purchase Plan Stock Purchase Plan (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2014 | Sep. 30, 2013 | Jun. 30, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
stock offering | 11,100,000 | |||||
Proceeds from Issuance of Common Stock | $20,000,000 | $47,000,000 | $0 | $67,000,000 | $0 | |
Share Price | $29.50 | |||||
Common Stock, Discount on Shares | 0.96 | |||||
Equity Forward Sale Agreement, Settlement Threshold | 10,400,000 | |||||
equity forward sale agreement future settlement amount | 275,000,000 | |||||
Option Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value | 119,000,000 | 119,000,000 | ||||
Net share settlement | 3,135,000 | 3,135,000 | ||||
employee stock purchase plan shares authorized | 625,000 | 625,000 | ||||
Employee Stock Purchase Plan, Base Pay Threshold | 10.00% | |||||
Employee Stock Purchase Plan, Purchased Stock Value Limitation | $25,000 | |||||
Employee Stock Purchase Plan, Share Purchase Limitation | 1,500 | |||||
Employee Stock Purchase Plan, Purchase Price | 95.00% | |||||
Employee Stock Purchase Plan, Number of Available Shares | 427,021 | 427,021 | ||||
Dividend Reinvestment and Direct Stock Purchase Plan Shares | 2,500,000 | |||||
Dividend Reinvestment and Direct Stock Purchase Plan, Number of Available Shares | 2,481,110 | 2,481,110 | ||||
Common Stock [Member] | ||||||
Stock Issued During Period, Shares, New Issues | 700,000 | 1,665,000 | 2,365,000 |
Stockbased_Compensation_Expens2
Stock-based Compensation Expense Restricted and Performance Stock Unit Activity (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract] | |||
Outstanding, Units | 431,090 | 440,562 | 491,404 |
Outstanding, Weighted Average Grant Date Fair Value | $26.31 | $22.54 | $18.54 |
Granted, Units | 203,410 | 183,071 | 186,495 |
Granted, Weighted Average Grant Date Fair Value | $31.49 | $29.25 | $24.72 |
Forfeited, Units | -12,278 | -7,007 | -22,947 |
Forfeited, Weighted Average Grant Date Fair Value | $29.90 | $27.15 | $18.95 |
Vested, Units | -158,329 | -185,536 | -214,390 |
Vested, Weighted Average Grant Date Fair Value | $24.95 | $20.20 | $15.67 |
Outstanding, Units | 463,893 | 431,090 | 440,562 |
Outstanding, Weighted Average Grant Date Fair Value | $28.96 | $26.31 | $22.54 |
Stockbased_Compensation_Expens3
Stock-based Compensation Expense Schedule Of Share Based Payment Award Stock Options Valuation Assumptions (Details) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate | 0.60% | 0.30% |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | 3 | 3 |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum | 12.40% | 12.10% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum | 23.00% | 25.10% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | 0.00% | 0.00% |
Stockbased_Compensation_Expens4
Stock-based Compensation Expense (Details) (USD $) | 12 Months Ended | ||||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2016 | Dec. 31, 2015 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based Compensation | $6 | $4 | $4 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 4,687,500 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 3,554,884 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid | 1 | 0 | 0 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value | 3 | 0 | 0 | ||
Adjustments Related to Tax Withholding for Share-based Compensation | 1 | 2 | 1 | ||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | 6 | ||||
Stock-based Compensation, Attainment of Performance Goals That Allows Vesting | 134.20% | 117.50% | 112.00% | ||
Stock-based Compensation, Forfeiture Rate | 5.00% | ||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount | 0 | 0 | 0 | ||
stock based compensation impact on cash flows | 0 | 0 | 0 | ||
Performance based stock award percentage - minimum | 0.00% | ||||
Performance based stock award percentage - maximum | 150.00% | ||||
Subsequent Event [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based Compensation | $2 | $4 |
Earnings_Per_Share_Schedule_of
Earnings Per Share Schedule of Earnings per Share, Basic and Diluted (Details) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||
Weighted Average Number of Shares Outstanding, Basic | 78,180 | 76,821 | 75,498 |
Weighted Average Number Diluted Shares Outstanding Adjustment | 2,314 | 567 | 149 |
Weighted Average Number of Shares Outstanding, Diluted | 80,494 | 77,388 | 75,647 |
Commitments_and_Guarantees_Unr
Commitments and Guarantees Unrecorded Unconditional Purchase Obligations (Details) (USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Capital Additions [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | $343 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 242 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 21 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 2 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 2 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 2 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 74 |
Long-term Contract for Purchase of Electric Power [Domain] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 1,605 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 179 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 167 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 140 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 143 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 143 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 833 |
Electric Transmission [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 90 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 27 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 26 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 6 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 6 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 5 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 20 |
Public Utility Districts [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 49 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 8 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 7 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 5 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 4 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 2 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 23 |
Natural gas [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 453 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 56 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 37 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 40 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 40 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 36 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 244 |
Coal and transportationSupply Agreements [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 58 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 23 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 14 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 11 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 5 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 5 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 0 |
Operatomg leases [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 244 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 10 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 11 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 12 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 11 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 8 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 192 |
Commitments [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 2,842 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 545 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 283 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 216 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 211 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 201 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | $1,386 |
Commitments_and_Guarantees_Sch
Commitments and Guarantees Schdule of Long term contracts for purchase of electric power (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
MW | |||
Priest Rapids and Wanapum [Member] | |||
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Revenue Bonds issued by the Public Utility Districts | $1,102 | ||
PGE Share of Output | 8.60% | ||
PGE Share of Capacity | 163 | ||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | 31-Dec-52 | ||
commitment costs | 14 | 14 | 14 |
Wells [Member] | |||
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Revenue Bonds issued by the Public Utility Districts | 215 | ||
PGE Share of Output | 19.40% | ||
PGE Share of Capacity | 150 | ||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | 31-Dec-18 | ||
commitment costs | 10 | 10 | 10 |
Portland Hydro [Member] | |||
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Revenue Bonds issued by the Public Utility Districts | 4 | ||
PGE Share of Output | 100.00% | ||
PGE Share of Capacity | 36 | ||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | 31-Dec-17 | ||
commitment costs | $4 | $4 | $4 |
Commitments_and_Guarantees_Det
Commitments and Guarantees (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Other Commitment | $43 | ||
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost | 14 | ||
Other Commitment, Due in Second Year | 11 | ||
Other Commitment, Due in Third Year | 11 | ||
Other Commitment, Due in Fourth Year | 7 | ||
Operating Leases, Future Minimum Payments, Due in Three Years | 1 | ||
percentage of output | 25.00% | ||
Operating Leases, Rent Expense | 11 | 9 | 10 |
Operating Leases, Future Minimum Payments Receivable, Current | 3 | ||
Operating Leases, Future Minimum Payments Receivable, in Two Years | 2 | ||
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Five Years | 1 | ||
Operating Leases, Rent Expense, Sublease Rentals | 3 | 3 | 3 |
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Three Years | $1 |
Variable_Interest_Entities_Det
Variable Interest Entities (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Variable interest Entities [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net | $4 | $5 |
Variable Interest Entity, Consolidated, Carrying Amount, Cash and Cash Equivalents | $1 | |
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 1.00% | |
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest | 99.00% | |
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions | 100.00% | |
Estimated Remaining Useful Life of Facility Acquired | 75.00% |
Jointlyowned_Plant_Schedule_of
Jointly-owned Plant Schedule of Jointly-owned plant (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 |
Jointly Owned Utility Plant Interests [Line Items] | |||
Jointly Owned Utility Plant, Proportionate Ownership Share of Boardman | 90.00% | 80.00% | 65.00% |
Jointly Owned Plant, Boardman Plant In Service Year | 1980 | ||
Jointly Owned Utility Plant, Gross Ownership Amount of Boardman Plant In Service | $510 | ||
Jointly Owned Utility Plant, Ownership Amount of Boardman Plant Accumulated Depreciation | 350 | ||
Jointly Owned Utility Plant Ownership Amount of Construction Work In Progress Boardman | 0 | ||
Jointly Owned Utility Plant, Proportionate Ownership Share of Colstrip | 20.00% | ||
Jointly Owned Plant, Colstrip Plant In Service Year | 1986 | ||
Jointly Owned Utility Plant, Gross Ownership Amount of Colstrip Plant In Service | 520 | ||
Jointly Owned Utility Plant, Ownership Amount of Colstrip Plant Accumulated Depreciation | 334 | ||
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Colstrip | 2 | ||
Jointly Owned Utility Plant, Proportionate Ownership Share of Pelton/Round Butte | 66.67% | ||
Jointly Owned Plant, Pelton Plant in Service Year | 1958 | ||
Jointly Owned Plant, Round Butte in Service Year | 1964 | ||
Jointly Owned Utility Plant, Gross Ownership Amount of Pelton/Round Butte Plant In Service | 237 | ||
Jointly Owned Utility Plant, Ownership Amount of Pelton/Round Butte Plant Accumulated Depreciation | 55 | ||
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Pelton/Round Butte | 8 | ||
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service | 1,267 | ||
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | 739 | ||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | $10 |
Jointlyowned_Plant_Jointly_Own
Jointly-owned Plant Jointly Owned Plant (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 1985 | |
Property, Plant and Equipment [Line Items] | |||||||
Jointly Owned Utility Plant, Proportionate Ownership Share of Boardman transferred | 10.00% | 10.00% | 10.00% | 15.00% | 15.00% | ||
Property, Plant and Equipment, Additions | $7,000,000 | $7,000,000 | $7,000,000 | ||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory | 4,000,000 | 4,000,000 | 4,000,000 | ||||
Asset Retirement Obligation, Liabilities Incurred | 7,000,000 | 8,000,000 | 15,000,000 | 4,000,000 | 0 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities | 6,000,000 | 6,000,000 | 6,000,000 | ||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities | 4,000,000 | 4,000,000 | 4,000,000 | ||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities | 2,000,000 | 2,000,000 | 2,000,000 | ||||
Asset Retirement Obligation Increase related to Boardman plant | 7,000,000 | ||||||
Interest in Pacific Northwest Intertie | 10.71% | ||||||
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds | $8,000,000 | $8,000,000 | $8,000,000 | $1 | |||
Jointly Owned Utility Plant, Proportionate Ownership Share of Boardman | 90.00% | 90.00% | 90.00% | 80.00% | 65.00% |
Contingencies_Details
Contingencies (Details) (USD $) | 12 Months Ended | |||||||
Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 1997 | Dec. 31, 2013 | Jun. 30, 2013 | Sep. 30, 2008 | Sep. 30, 2000 | Dec. 31, 1993 | |
claims | claims | claims | ||||||
Loss Contingencies [Line Items] | ||||||||
Investment in Trojan | 87.00% | |||||||
Regulatory asset related to Trojan | $5,000,000 | |||||||
Refund to customers for Trojan Investment including interest | 33,100,000 | |||||||
Class action damages sought | 260,000,000 | |||||||
Loss Contingency, Claims Settled, Number | 2 | |||||||
contracts | 119 | |||||||
Site Contingency, Names of Other Potentially Responsible Parties | 100 | 69 | ||||||
Low estimate of range of cost of Portland Harbor cleanup in total | 169,000,000 | |||||||
Upper estimated range of total cost of Portland harbor cleanup | 1,800,000,000 | |||||||
Loss Contingency, Range of Possible Loss, Minimum | 3,000,000 | |||||||
Loss Contingency, Range of Possible Loss, Maximum | 8,000,000 | |||||||
Loss Contingency, Estimate of Possible Loss | 3,000,000 | |||||||
regulatory asset for recovery of loss contingencies | 3,000,000 | |||||||
Jointly Owned Utility Plant, Proportionate Ownership Share of Colstrip | 20.00% | |||||||
Potential Income Tax Liability related to State Tax Court Ruling | 7,000,000 | |||||||
Civil Penalty Claim - Per day per violation through January 12, 2009 | 32,500 | |||||||
Civil Penalty Claim - Per day per violation after January 12, 2009 | $37,500 | |||||||
Claims moved to dismiss | 36 | |||||||
Loss Contingency, Pending Claims, Number | 39 | |||||||
projects added to plaintiff's suit | 2 | |||||||
projects encompassed by suit | 40 |