DEI Document
DEI Document - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 02, 2018 | Jun. 30, 2017 | |
Entity Information [Line Items] | |||
Entity Registrant Name | PORTLAND GENERAL ELECTRIC CO /OR/ | ||
Entity Central Index Key | 784,977 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
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 | 89,114,522 | ||
Entity Public Float | $ 4,048,647,464 | ||
Trading Symbol | POR |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues, net | $ 2,009 | $ 1,923 | $ 1,898 |
Operating expenses: | |||
Purchased power and fuel | 592 | 617 | 661 |
Generation, transmission and distribution | 309 | 286 | 266 |
Administrative and other | 264 | 247 | 241 |
Depreciation and amortization | 345 | 321 | 305 |
Taxes other than income taxes | 123 | 119 | 116 |
Total operating expenses | 1,633 | 1,590 | 1,589 |
Income from operations | 376 | 333 | 309 |
Interest expense, net | 120 | 112 | 114 |
Other income: | |||
Allowance for equity funds used during construction | 12 | 21 | 21 |
Miscellaneous income, net | 5 | 1 | 1 |
Other income, net | 17 | 22 | 22 |
Income before income taxes | 273 | 243 | 217 |
Income tax expense | 86 | 50 | 45 |
Net income | $ 187 | $ 193 | $ 172 |
Weighted-average shares outstanding (in thousands): | |||
Basic | 89,056 | 88,896 | 84,180 |
Diluted | 89,176 | 89,054 | 84,341 |
Earnings per share: | |||
Basic | $ 2.10 | $ 2.17 | $ 2.05 |
Diluted | $ 2.10 | $ 2.16 | $ 2.04 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Net income | $ 187 | $ 193 | $ 172 |
Other comprehensive (loss) income - Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2017, 2016, and 2015 | (1) | 1 | (1) |
Comprehensive income | $ 186 | $ 194 | $ 171 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 39 | $ 6 |
Accounts receivable, net | 168 | 155 |
Unbilled revenues | 106 | 107 |
Inventories, at average cost: | ||
Materials and supplies | 52 | 50 |
Fuel | 26 | 32 |
Regulatory assets--current | 62 | 36 |
Other current assets | 73 | 77 |
Total current assets | 526 | 463 |
Electric utility plant: | ||
Generation | 4,667 | 4,597 |
Transmission | 547 | 521 |
Distribution | 3,543 | 3,343 |
General | 550 | 501 |
Intangible | 607 | 572 |
Construction work-in-progress | 391 | 213 |
Total electric utility plant | 10,305 | 9,747 |
Accumulated depreciation and amortization | (3,564) | (3,313) |
Electric utility plant, net | 6,741 | 6,434 |
Regulatory assets--noncurrent | 438 | 498 |
Nuclear decommissioning trust | 42 | 41 |
Non-qualified benefit plan trust | 37 | 34 |
Other noncurrent assets | 54 | 57 |
Total assets | 7,838 | 7,527 |
Current liabilities: | ||
Accounts payable | 132 | 129 |
Liabilities from price risk management activities-current | 59 | 44 |
Short-term debt | 0 | |
Current portion of long-term debt | 0 | 150 |
Accrued expenses and other current liabilities | 241 | 254 |
Total current liabilities | 432 | 577 |
Long-term debt, net of current portion | 2,426 | 2,200 |
Regulatory liabilities--noncurrent | 1,288 | 958 |
Deferred income taxes | 376 | 669 |
Unfunded status of pension and postretirement plans | 284 | 281 |
Liabilities from price risk management activities--noncurrent | 151 | 125 |
Asset retirement obligations | 167 | 161 |
Non-qualified benefit plan liabilities | 106 | 105 |
Other noncurrent liabilities | 192 | 107 |
Total liabilities | 5,422 | 5,183 |
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; 89,114,265 and 88,946,704 shares issued and outstanding as of December 31, 2017 and 2016, respectively | 1,207 | 1,201 |
Accumulated other comprehensive loss | (8) | (7) |
Retained earnings | 1,217 | 1,150 |
Total equity | 2,416 | 2,344 |
Total liabilities and equity | $ 7,838 | $ 7,527 |
Consolidated Balance Sheets Con
Consolidated Balance Sheets Consolidated Balance Sheet Parentheticals - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
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 | 89,114,265 | 88,946,704 |
Common Stock, Shares, Outstanding | 89,114,265 | 88,946,704 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Millions | Total | Common Stock Shares | Common Stock Amount | Accumulated Other Comprehensive Loss | Retained Earnings |
Balance, shares at Dec. 31, 2014 | 78,228,339 | ||||
Balance at Dec. 31, 2014 | $ 1,911 | $ 918 | $ (7) | $ 1,000 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Issuances of common stock, net of issuance costs | 10,400,000 | ||||
Issuances of common stock, net of issuance costs | 271 | 271 | |||
Shares issued pursuant to equity-based plans | 164,412 | ||||
Proceeds from issuance of shares pursuant to equity-based plans | 1 | 1 | |||
Stock-based compensation | 6 | 6 | 0 | 0 | |
Dividends declared | (102) | 0 | 0 | (102) | |
Net income (loss) | 172 | 0 | 0 | 172 | |
Other comprehensive income (loss) | (1) | 0 | (1) | 0 | |
Balance, shares at Dec. 31, 2015 | 88,792,751 | ||||
Balance at Dec. 31, 2015 | 2,258 | 1,196 | (8) | 1,070 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Shares issued pursuant to equity-based plans | 153,953 | ||||
Proceeds from issuance of shares pursuant to equity-based plans | 1 | 1 | |||
Stock-based compensation | 4 | 4 | 0 | 0 | |
Dividends declared | (113) | 0 | 0 | (113) | |
Net income (loss) | 193 | 0 | 0 | 193 | |
Other comprehensive income (loss) | 1 | 0 | 1 | 0 | |
Balance, shares at Dec. 31, 2016 | 88,946,704 | ||||
Balance at Dec. 31, 2016 | 2,344 | 1,201 | (7) | 1,150 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Shares issued pursuant to equity-based plans | 167,561 | ||||
Proceeds from issuance of shares pursuant to equity-based plans | 2 | 2 | |||
Stock-based compensation | 4 | 4 | 0 | 0 | |
Dividends declared | (120) | 0 | 0 | (120) | |
Net income (loss) | 187 | 0 | 0 | 187 | |
Other comprehensive income (loss) | (1) | 0 | (1) | 0 | |
Balance, shares at Dec. 31, 2017 | 89,114,265 | ||||
Balance at Dec. 31, 2017 | $ 2,416 | $ 1,207 | $ (8) | $ 1,217 |
Consolidated Statements of Equ7
Consolidated Statements of Equity Consolidated Statement of Equity Parenthetical - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Issuance costs | $ 12 | ||
Common Stock, Dividends, Per Share, Declared | $ 1.34 | $ 1.26 | $ 1.18 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities: | |||
Net income | $ 187 | $ 193 | $ 172 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation and amortization | 345 | 321 | 305 |
Deferred income taxes | 70 | 37 | 40 |
Allowance for equity funds used during construction | (12) | (21) | (21) |
Pension and other postretirement benefits | 24 | 28 | 34 |
Unrealized losses on non-qualified benefit plan trust assets | 2 | 5 | 6 |
Decoupling mechanism deferrals, net of amortization | (22) | (6) | 14 |
Other non-cash income and expenses, net | 29 | 7 | 22 |
Changes in working capital: | |||
(Increase) in receivables and unbilled revenues | (3) | (9) | (11) |
(Increase) decrease in margin deposits | (3) | 25 | (22) |
Increase in payables and accrued liabilities | 5 | 15 | 6 |
Other working capital items, net | 1 | (4) | (4) |
Contribution to non-qualified employee benefit trust | (8) | (10) | (9) |
Other, net | (18) | (28) | (12) |
Net cash provided by operating activities | 597 | 553 | 520 |
Cash flows from investing activities: | |||
Capital expenditures | (514) | (584) | (598) |
Purchases of nuclear decommissioning trust securities | (18) | (25) | (19) |
Sales of nuclear decommissioning trust securities | 21 | 27 | 22 |
Distribution from nuclear decommissioning trust | 0 | 0 | 50 |
Sales tax refund received - Tucannon River Wind Farm | 0 | 0 | 23 |
Other, net | (3) | (3) | 0 |
Net cash used in investing activities | (514) | (585) | (522) |
Cash flows from financing activities: | |||
Proceeds from issuance of long-term debt | 225 | 290 | 145 |
Payments on long-term debt | (150) | (133) | (442) |
Proceeds from issuance of common stock, net of issuance costs | 0 | 0 | 271 |
(Maturities) issuances of commercial paper, net | 0 | (6) | 6 |
Dividends paid | (118) | (110) | (97) |
Other | (7) | (7) | (4) |
Net cash (used in) provided by financing activities | (50) | 34 | (121) |
Increase (decrease) in cash and cash equivalents | 33 | 2 | (123) |
Cash and cash equivalents, beginning of year | 6 | 4 | 127 |
Cash and cash equivalents, end of year | 39 | 6 | 4 |
Supplemental disclosures of cash flow information: | |||
Cash paid for interest, net of amounts capitalized | 110 | 104 | 108 |
Cash paid for income taxes | 18 | 16 | 3 |
Non-cash investing and financing activities: | |||
Accrued capital additions | 53 | 50 | 32 |
Accrued dividends payable | 31 | 30 | 28 |
Assets obtained under leasing arrangements | $ 87 | $ 78 | $ 0 |
Basis of Presentation
Basis of Presentation | 12 Months Ended |
Dec. 31, 2017 | |
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 participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its approximately 4,000 square mile, state-approved service area is located entirely within the State of Oregon. PGE’s allocated service area includes 51 incorporated cities, of which Portland and Salem are the largest. As of December 31, 2017 , PGE served approximately 875,000 retail customers with a service area population of approximately 1.9 million , comprising approximately 46% of the population of the state. As of December 31, 2017 , PGE had 2,906 employees, with 785 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 732 and 53 employees and expire March 2020 and August 2022, 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. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. For further information on PGE’s jointly-owned plant, see Note 16, Jointly-Owned Plant. Intercompany balances and transactions have been eliminated. For entities that are determined to meet the definition of a VIE and in which 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. There were no material VIEs in 2017 or 2016. 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. Reclassifications To conform with the 2017 presentation, PGE has reclassified Cash received to be returned to customers pursuant to the Residential Exchange Program, net of amortization of $6 million and $1 million in 2016 and 2015, respectively, and Contribution to voluntary employees’ benefit association trust of $2 million and $4 million in 2016 and 2015, respectively, to Other net within the operating activities section of the Consolidated Statements of Cash Flows. PGE has also reclassified the Regulatory deferral of settled derivative instruments of $2 million in both 2016 and 2015 to Other non-cash income and expense, net within the operating activities section of the Consolidated Statements of Cash Flows. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
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 $30 million as of December 31, 2017 and $1 million as of December 31, 2016 included within Cash and cash equivalents in the consolidated balance sheets. 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 2017 , 2016 , or 2015 . 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, 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, the Company recognizes a realized gain or loss on the derivative instrument. Physically settled electricity and natural gas sale and purchase transactions are recorded in Revenues, net and Purchased power and fuel expense, respectively, upon settlement, 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 within Other current assets in the consolidated balance sheets and were $11 million and $8 million as of December 31, 2017 and 2016 , respectively. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet and were $31 million and $17 million as of December 31, 2017 and 2016 , 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, as well as fuel, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that it is recorded at the lower of average cost or net realizable value. Electric Utility Plant Capitalization Policy Electric utility plant is capitalized at 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 PGE’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 FERC licenses 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, PGE may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted. Costs disallowed for recovery in customer prices, if any, are charged to expense at the time such disallowance becomes probable. PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes, 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 7.3% in 2017, 2016 , and 2015 . AFDC from borrowed funds was $6 million in 2017 , $11 million in 2016 , and $13 million in 2015 and is reflected as a reduction to Interest expense. AFDC from equity funds, included in Other income, net, was $12 million in 2017 , and $21 million in 2016 and 2015. 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 2017 , 3.5% in 2016 and 3.6% in 2015 . A component of depreciation expense includes estimated asset retirement removal costs allowed in customer prices. 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 2015, with an order received from the OPUC in September 2017 authorizing new depreciation rates effective January 1, 2018. This study was incorporated into the Company’s 2018 general rate case filed with the OPUC in 2017. 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 PGE’s other classes of plant in service over their estimated average service lives, which are as follows (in years): Generation, excluding thermal: Hydro 95 Wind 30 Transmission 57 Distribution 45 General 12 When property is retired and removed from service, the original cost of the depreciable property units, net of any related salvage value, is charged to accumulated depreciation. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, if applicable, and included in Regulatory liabilities. 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 $296 million and $257 million as of December 31, 2017 and 2016 , respectively, with amortization expense of $46 million in 2017 , and $44 million in 2016 and $38 million in 2015 . Future estimated amortization expense as of December 31, 2017 is as follows: $49 million in 2018 ; $48 million in 2019 ; $43 million in 2020 ; $35 million in 2021 ; and $28 million in 2022 . 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 treatment. The cost of securities sold is based on the average cost method. Regulatory Accounting Regulatory Assets and Liabilities As a rate-regulated enterprise, PGE applies regulatory accounting, which results in the creation of regulatory assets and 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 PGE’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. The Company 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 PGE’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 net variable power costs (NVPC) forecast each year and included in customer prices (baseline NVPC) and actual NVPC. NVPC consists of 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 wholesale sales, which are classified as Revenues, net in the consolidated statements of income. The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC. 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 the given 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 9.6% for 2017 , 9.6% for 2016 , and 9.68% for 2015 . Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in PGE’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. The PCAM has resulted in no collection from, or refund to, customers since 2011. 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 the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and market-risk premiums are not available. The present value of estimated future decommissioning 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 included in Depreciation and amortization expense in the Company’s consolidated statements of income. For additional information concerning the Company’s AROs, see Note 7, Asset Retirement Obligations. The difference between the timing of the recognition of ARO 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 $52 million as of December 31, 2017 and $49 million as of December 31, 2016 . For additional information concerning the Company’s regulatory liability related to AROs, 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. Legal costs incurred in connection with loss contingencies are expensed as incurred. 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 determined, 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. 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. 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 $43 million in 2017 , 2016 and 2015 . Retail revenue is billed monthly based on meter readings taken throughout the month. Unbilled revenue represents the revenue earned from the time of the last meter read date through the last day of the month, a period that has not been billed as of the last day of the month. Unbilled revenue is calculated based on actual net retail system load each month, 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, PGE, in certain situations, 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. For additional information concerning the Company’s Stock-Based Compensation, see Note 13, Stock-Based Compensation Expense. 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 would be established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns. Because PGE is a rate-regulated enterprise, changes in certain deferred tax assets and liabilities are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. Such amounts were recognized as net regulatory liabilities of $277 million and net regulatory assets of $86 million as of December 31, 2017 , and 2016 , 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 Pronouncements 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; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively (full retrospective method) or as a cumulative-effect adjustment as of the effective date (modified retrospective method), which is January 1, 2018 for calendar year-end public entities. The Company plans to elect the modified retrospective method for implementation. PGE does not anticipate any material changes to its revenue recognition policy for tariff-based revenues, which comprises a majority of PGE’s retail, wholesale, and other revenues, as performance obligations are expected to be satisfied in a similar recognition pattern. PGE continues to finalize its evaluation of certain matters of presentation such as alternative revenue programs (including decoupling) and enhanced required disclosures. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases . Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Accounting for lessors is substantially unchanged from current accounting principles. Lessees will be required to classify leases as either finance leases or operating leases. Initial balance sheet measurement is similar for both types of leases; however, expense recognition and amortization of right-of-use assets will differ. Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability (as calculated using the effective interest method) and amortization expense of the right-of-use asset. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The provisions of this pronouncement are effective for calendar year-end, public entities on January 1, 2019. As issued, ASU 2016-02 requires transition under a modified retrospective basis as of the beginning of the earliest comparative period presented, however the Company is monitoring the FASB’s decisions regarding potential transition practical expedients that would allow companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. Early adoption is permitted, but the Company does not plan to early adopt. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 , which amends ASU 2016-02 to provide entities an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 842. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. PGE plans to elect this practical expedient. The Company is monitoring utility industry implementation issues that may change existing and future lease classification in areas such as purchase power agreements, pipeline laterals, utility pole attachments, and other utility industry-related arrangements. In conjunction with monitoring industry issues that may impact lease classification, the Company is in the process of evaluating whether it will elect to adopt certain other, optional practical expedients included within the standard. Decisions surrounding the election of practical expedients may impact the Company’s lease population that is ultimately recorded. As a result, PGE has not yet quantified the estimated financial statement impact, but overall, the Company does expect an increase in the recognition of right-of-use assets and lease liabilities on the Company’s consolidated balance sheet. In March 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). Pursuant to this ASU, only the service cost component of net periodic pension and postretirement benefit costs will be eligible for capitalization and should be applied on a prospective basis upon implementation. Also, the non-service components are required to be presented in the income statement separately from the service cost component and outside the subtotal of income from operations and should be applied on a retrospective basis upon implementation. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2018. The Company does not plan to early adopt. For ratemaking purposes, the Company will continue to be allowed to recover this portion of the non-service costs as a component of rate base, however such amounts will be recorded as Regulatory assets on the Company’s condensed consolidated balance sheets, instead of Utility plant, and amortized in a systematic and rational manner and reflected as expense in a line item outside the subtotal of income from operations on the condensed consolidated statements of income and other comprehensive income. PGE estimates the portion of the non-service components of net periodic pension and postretirement benefit costs that is eligible for deferral for ratemaking purposes, to be $3 million for the twelve month period ending December 31, 2018, and is deemed to have an immaterial impact on the Company’s consolidated financial position and consolidated results of operations. |
Balance Sheet Components
Balance Sheet Components | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 and December 31, 2016 . The following is the activity in the allowance for uncollectible accounts (in millions): Years Ended December 31, 2017 2016 2015 Balance as of beginning of year $ 6 $ 6 $ 6 Increase in provision 6 5 6 Amounts written off, less recoveries (6 ) (5 ) (6 ) Balance as of end of year $ 6 $ 6 $ 6 Trust Accounts 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. In anticipation of the refund of the settlement amount to customers over a three-year period that began in 2015, those funds were withdrawn from the Nuclear decommissioning trust during 2015. 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 Decommissioning Trust Non-Qualified Benefit Plan Trust 2017 2016 2017 2016 Cash equivalents $ 25 $ 21 $ 1 $ 1 Marketable securities, at fair value: Equity securities — — 7 6 Debt securities 17 20 1 1 Insurance contracts, at cash surrender value — — 28 26 $ 42 $ 41 $ 37 $ 34 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, 2017 2016 Other current assets: Prepaid expenses $ 50 $ 48 Margin deposits 11 8 Assets from price risk management activities 6 18 Other 6 3 $ 73 $ 77 Accrued expenses and other current liabilities: Regulatory liabilities—current $ 31 $ 51 Accrued employee compensation and benefits 60 52 Accrued dividends payable 31 30 Accrued interest payable 27 25 Accrued taxes payable 31 25 Other 61 71 $ 241 $ 254 |
Fair Value of FInancial Instrum
Fair Value of FInancial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 and 2016 , and then classifies these financial assets and liabilities based on a fair value hierarchy that is used to prioritize the inputs to the valuation techniques used to measure fair value. The three 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 measurement date. Level 2 Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement 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. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements. 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, 2017 and 2016 , except those 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, 2017 Level 1 Level 2 Level 3 Other (2) Total Assets: Nuclear decommissioning trust: (1) Debt securities: Domestic government $ 4 $ 7 $ — $ — $ 11 Corporate credit — 6 — — 6 Money market funds measured at NAV (2) — — — 25 25 Non-qualified benefit plan trust: (3) Money market funds 1 — — — 1 Equity securities—domestic 7 — — — 7 Debt securities—domestic government 1 — — — 1 Investments measured at NAV: (2) Collective trust—domestic equity — — — — — Assets from price risk management activities: (1) (4) Electricity — 3 — — 3 Natural gas — 3 — — 3 $ 13 $ 19 $ — $ 25 $ 57 Liabilities - Liabilities from price risk management activities: (1) (4) Electricity $ — $ 5 $ 130 $ — $ 135 Natural gas — 66 9 — 75 $ — $ 71 $ 139 $ — $ 210 (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) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $28 million , which are recorded at cash surrender value. (4) For further information, see Note 5, Price Risk Management. As of December 31, 2016 Level 1 Level 2 Level 3 Other (2) Total Assets: Nuclear decommissioning trust: (1) Debt securities: Domestic government $ 2 $ 10 $ — $ — $ 12 Corporate credit — 8 — — 8 Money market funds measured at NAV (2) — — — 21 21 Non-qualified benefit plan trust: (3) Money market funds 1 — — — 1 Equity securities—domestic 4 — — — 4 Debt securities—domestic government 1 — — — 1 Investments measured at NAV: (2) Collective trust—domestic equity — — — 2 2 Assets from price risk management activities: (1) (4) Electricity — 6 1 — 7 Natural gas — 15 1 — 16 $ 8 $ 39 $ 2 $ 23 $ 72 Liabilities - Liabilities from price risk management activities: (1) (4) Electricity $ — $ 6 $ 112 $ — $ 118 Natural gas — 42 9 — 51 $ — $ 48 $ 121 $ — $ 169 (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) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $26 million , which are recorded at cash surrender value. (4) For further information, see Note 5, Price Risk Management. Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) 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: 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 measurement 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 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 measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE). 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. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice. The NQBP trust is invested in exchange traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy. Common and collective trust funds —PGE invests in common and collective trust funds that invests in equity securities. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value as a practical expedient. The funds allow for daily liquidity with appropriate notice. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient. All collective trusts for the NQBP were liquidated during 2017. 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 NVPC 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, 2017: Electricity physical forward $ — $ 130 Discounted cash flow Electricity forward price (per MWh) $ 7.79 $ 41.23 $ 30.95 Natural gas financial swaps — 9 Discounted cash flow Natural gas forward price (per Dth) 1.26 2.92 1.90 Electricity financial futures — — Discounted cash flow Electricity forward price (per MWh) 7.79 29.74 21.74 $ — $ 139 As of December 31, 2016: Electricity physical forward $ — $ 112 Discounted cash flow Electricity forward price (per MWh) $ 14.25 $ 54.73 $ 38.18 Natural gas financial swaps 1 9 Discounted cash flow Natural gas forward price (per Dth) 1.85 4.92 2.64 Electricity financial futures 1 — Discounted cash flow Electricity forward price (per MWh) 8.57 33.60 25.10 $ 2 $ 121 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, PGE employs the mid-point of the bid-ask spread of the market and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data from multiple sources. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed price curves, which derive longer term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a quarterly basis by the Company. 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, 2017 2016 Net liabilities from price risk management activities as of beginning of year $ 119 $ 119 Net realized and unrealized losses * 35 11 Net transfers in to Level 3 from Level 2 — (1 ) Net transfers out of Level 3 to Level 2 (15 ) (10 ) Net liabilities from price risk management activities as of end of year $ 139 $ 119 Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting $ 41 $ 11 * Includes $6 million in net realized losses in 2017 and none in 2016 . 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 year ended December 31, 2017 , there were no transfers into Level 3 from Level 2, as reflected in the table above. During 2016 , there was $1 million transferred into Level 3. 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 First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds (PCBs) 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 was classified as Level 3 fair value measurement and was estimated based on the terms of the loans and the Company’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value. As of December 31, 2017 , the carrying amount of PGE’s long-term debt was $2,426 million , net of $10 million of unamortized debt expense, and its estimated aggregate fair value was $2,829 million , all of which is classified as Level 2 in the fair value hierarchy. As of December 31, 2016 , the carrying amount of PGE’s long-term debt was $2,350 million , net of $11 million of unamortized debt expense, with an estimated aggregate fair value of $2,693 million , consisting of $2,543 million and $150 million classified as Level 2 and Level 3, respectively, 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, 2017 | |
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 generation 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 purchases and sales of both power and fuel resulting from economic dispatch decisions for Company-owned generating resources. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flow. PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk in order to manage volatility in net variable power costs for its retail customers. Such derivative instruments may include forward, futures, swap, and option contracts, which are recorded at fair value on the consolidated balance sheet, for electricity, natural gas, oil, and foreign currency, with changes in fair value recorded in the consolidated statements of income. In accordance with ratemaking and cost recovery processes authorized by the OPUC, the Company 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. The Company 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, 2017 2016 Current assets: Commodity contracts: Electricity $ 3 $ 6 Natural gas 3 12 Total current derivative assets 6 (1) 18 (1) Noncurrent assets: Commodity contracts: Electricity — 1 Natural gas — 4 Total noncurrent derivative assets — (2) 5 (2) Total derivative assets not designated as hedging instruments $ 6 $ 23 Total derivative assets $ 6 $ 23 Current liabilities: Commodity contracts: Electricity $ 13 $ 12 Natural gas 46 32 Total current derivative liabilities 59 44 Noncurrent liabilities: Commodity contracts: Electricity 122 106 Natural gas 29 19 Total noncurrent derivative liabilities 151 125 Total derivative liabilities not designated as hedging instruments $ 210 $ 169 Total derivative liabilities $ 210 $ 169 (1) Included in Other current assets on the consolidated balance sheets. (2) Included in Other noncurrent assets on the consolidated balance sheets. 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, 2017 2016 Commodity contracts: Electricity 7 MWh 8 MWh Natural gas 114 Dth 107 Dth Foreign currency exchange $ 21 Canadian $ 22 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, such agreements provide for the net settlement of all related contractual obligations with a given 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. As of December 31, 2017 and 2016 , gross amounts included as Price risk management liabilities subject to master netting agreements were $136 million and $115 million , respectively, for which PGE posted collateral of $11 million for 2017 and 2016, which consisted entirely of letters of credit. As of December 31, 2017 , of the gross amounts included, $130 million was for electricity and $6 million was for natural gas compared to $112 million for electricity and $3 million for natural gas recognized as of December 31, 2016 . Net realized and unrealized losses (gains) 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, 2017 2016 2015 Commodity contracts: Electricity $ 41 $ 34 $ 72 Natural Gas 85 (56 ) 103 Foreign currency exchange (1 ) — 1 Net unrealized and certain net realized losses (gains) presented in the table above are offset within the consolidated statements of income by the effects of regulatory accounting. Net losses of $82 million , net gains of $13 million , and net losses of $160 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, have been offset in Net income. 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, 2017 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions): 2018 2019 2020 2021 2022 Thereafter Total Commodity contracts: Electricity $ 10 $ 8 $ 8 $ 8 $ 7 $ 91 $ 132 Natural gas 43 20 7 2 — — 72 Net unrealized loss $ 53 $ 28 $ 15 $ 10 $ 7 $ 91 $ 204 PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (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. Certain other counterparties would 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, 2017 was $205 million , for which the Company had posted $31 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at December 31, 2017 , the cash requirement to either post as collateral or settle the instruments immediately would have been $202 million . As of December 31, 2017 , PGE had no posted cash collateral for derivative instruments with no credit-risk-related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets 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, 2017 2016 Assets from price risk management activities: Counterparty A 39 % 22 % Counterparty B 12 17 Counterparty C 3 12 54 % 51 % Liabilities from price risk management activities: Counterparty D 62 % 66 % 62 % 66 % 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 Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
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 Life (1) As of December 31, 2017 2016 Current Noncurrent Current Noncurrent Regulatory assets: Price risk management (2) 6 years $ 53 $ 151 $ 26 $ 120 Pension and other postretirement plans (2) (3) — 218 — 235 Deferred income taxes (6) (4) — — — 86 Debt issuance costs (2) 6 years — 19 — 22 Other (5) Various 9 50 10 35 Total regulatory assets $ 62 $ 438 $ 36 $ 498 Regulatory liabilities: Asset retirement removal costs (6) (4) $ — $ 933 $ — $ 887 Deferred income taxes (6) (4) — 277 — — Trojan decommissioning activities 5 years 3 — 18 — Asset retirement obligations (6) (4) — 52 — 49 Other Various 28 26 33 22 Total regulatory liabilities $ 31 (7) $ 1,288 $ 51 (7) $ 958 (1) As of December 31, 2017 . (2) Does not include a return on investment. (3) Recovery expected over the average service life of employees. (4) Recovery or refund expected over the estimated lives of the net balance. (5) Of the total other unamortized regulatory asset balances, a return is recorded on $51 million and $44 million as of December 31, 2017 and 2016 , 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, 2017 , PGE had regulatory assets of $51 million earning a return on investment at the following rates: i) $14 million earning a return by inclusion in rate base; ii) $25 million at the approved rate for deferred accounts under amortization, ranging from 1.47% to 2.38% , depending on the year of approval; iii) $10 million at PGE’s 2017 cost of capital of 7.51% , and iv) $2 million at a rate of the 5-year Treasury rate plus 100 basis points, which currently equates to 2.87% . 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 primarily from property-related timing differences that previously flowed to customers and will be included in customer prices when the temporary differences reverse. In 2017, the net regulatory liability was increased by $357 million as the Company deferred the impact of re-measuring accumulated deferred income taxes pursuant to the enactment of the Tax Cuts and Jobs Act (the TCJA) on December 22, 2017. PGE has proposed to defer and refund the net benefits of the change in tax law under a deferral application filed with the OPUC on December 29, 2017. Substantially all of the amounts deferred under the proposed deferral application are subject to tax normalization rules that require that the impact to the results of operations of amortizing the excess deferred income tax balance cannot occur more rapidly than would have occurred before the change in tax law. The Company plans to use the average rate assumption method to account for the refund to customers. 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. Asset retirement removal costs represents 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 (USDOE) of certain monitoring costs incurred related to spent nuclear fuel at Trojan, as well as ongoing costs and collections associated with decommissioning activities. Asset retirement obligations represents 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, 2017 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS AROs consist of the following (in millions): As of December 31, 2017 2016 Trojan decommissioning activities $ 45 $ 44 Utility plant 109 105 Non-utility property 13 12 Asset retirement obligations $ 167 $ 161 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 USDOE facility is complete, which is not expected prior to 2034. 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, which holds a 67.5% ownership interest in Trojan, 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 sought reimbursement for damages incurred through 2009. A trial before the U.S. Court of Federal Claims concluded in 2012, with the Court issuing a judgment awarding certain damages to the Plaintiffs. The settlement agreement also provides for a process to submit claims for allowable costs for the periods subsequent to 2009, including an extension to cover costs through 2019. Pursuant to this process, the USDOE has reimbursed the Plaintiffs $85 million for costs incurred through 2016 resulting from USDOE delays in accepting spent nuclear fuel. PGE has received proceeds of $53 million related to its share in this legal matter. The settlement amounts received were 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 $50 million of the proceeds received related to this legal matter to customers over a three-year period beginning January 1, 2015. PGE will return the remaining $3 million to customers in 2018. The ARO related to Trojan decommissioning activities was not impacted by the outcome of this legal matter because the proceeds received in connection with the settlement of this legal matter were 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, the disposal of which is governed by environmental regulation. During 2017, the Company recorded an overall increase in AROs, including Trojan, of $6 million , with the change comprised of an increase to revisions in estimated cash flows and incurred liabilities of $2 million , accretion of $7 million , and a reduction of $3 million due to settled liabilities. In 2015, the Company recorded an increase to the Colstrip ARO in the amount of $17 million , as Colstrip utilizes wet scrubbers and a number of settlement ponds that will require upgrading or closure to meet new EPA regulatory requirements. PGE plans to seek recovery in customer prices of the incremental costs associated with the final EPA rules. 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, 2017 2016 2015 Balance as of beginning of year $ 161 $ 151 $ 116 Liabilities incurred 2 1 2 Liabilities settled (3 ) (3 ) (4 ) Accretion expense 7 7 7 Revisions in estimated cash flows — 5 30 Balance as of end of year $ 167 $ 161 $ 151 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. |
Credit Facilities
Credit Facilities | 12 Months Ended |
Dec. 31, 2017 | |
Line of Credit Facility [Abstract] | |
Credit Facilities | CREDIT FACILITIES As of December 31, 2017 , PGE had a $500 million revolving credit facility scheduled to expire in November 2021 . Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, as backup for commercial paper borrowings, and to 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. The revolving credit facility requires annual fees based on PGE’s unsecured credit ratings, and contains 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, 2017 , PGE was in compliance with this covenant with a 51.8% debt to total capital ratio. 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 revolving credit facility. PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt in the consolidated balance sheets. PGE had no borrowings outstanding and there was no commercial paper or letters of credit issued under the revolving credit facility as of December 31, 2017 . As a result, as of December 31, 2017 , the aggregate unused available credit capacity under the revolving credit facility was $500 million . In addition, PGE has four letter of credit facilities that provide capacity up to a total of $220 million under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, $67 million of letters of credit was outstanding, as of December 31, 2017 . Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount up to $900 million through February 6, 2020 . Short-term borrowings under these credit facilities and related interest rates are reflected in the following table (dollars in millions). The Company had no short-term borrowings during 2017. Years Ended December 31, 2017 2016 2015 Average daily amount of short-term debt outstanding $ — $ 1 $ — Weighted daily average interest rate * — % 0.7 % 0.6 % Maximum amount outstanding during the year $ — $ 23 $ 11 * Excludes the effect of commitment fees, facility fees and other financing fees. |
Long-term Debt
Long-term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Debt Disclosure [Abstract] | |
Long-term Debt | LONG-TERM DEBT Long-term debt consists of the following (in millions): As of December 31, 2017 2016 First Mortgage Bonds , rates range from 2.51% to 9.31%, with a weighted average rate of 5.03% in 2017 and 4.86% in 2016, due at various dates through 2048 $ 2,315 $ 2,090 Unsecured term bank loans , variable rates of approximately 1.87% at 11/27/2017 and 1.37% at 12/31/2016 — 150 Pollution Control Revenue Bonds , 5% rate, due 2033 142 142 Pollution Control Revenue Bonds owned by PGE (21 ) (21 ) Total long-term debt 2,436 2,361 Less: Unamortized debt expense (10 ) (11 ) Less: Current portion of long-term debt — (150 ) Long-term debt, net of current portion $ 2,426 $ 2,200 First Mortgage Bonds and Unsecured term bank loans —During 2017 , PGE issued a total of $225 million of FMBs and repaid long-term debt, in an aggregate amount of $150 million . In 2017 , the Company issued a total of $225 million at an interest rate of 3.98% . PGE drew $75 million in August with a maturity of 2048 and drew the remaining $150 million in November with a maturity of 2047 . 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 2017 , PGE repaid an unsecured credit agreement under which it had borrowed $150 million from certain financial institutions. PGE repaid the loan in three separate payments as follows: • $50 million on August 21, 2017; • $25 million on October 30, 2017; and • $75 million on November 27, 2017. The term loan interest rates were set at the beginning of the interest period for periods of 1-month, 3-months, or 6-months, as selected by PGE and are based on the London Interbank Offered Rate (LIBOR) plus 63 basis points. The final rate was 1.87% as of November 27, 2017, with no other fees. Pollution Control Revenue Bonds —The Company has the option to remarket through 2033 the $21 million of Pollution Control Revenue Bonds (PCBs) held by PGE as of December 31, 2017 . 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, 2017 , the future minimum principal payments on long-term debt are as follows (in millions): Years ending December 31: 2018 $ — 2019 300 2020 — 2021 160 2022 — Thereafter 1,976 $ 2,436 |
Employee Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2017 | |
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, which 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 that are reviewed annually and updated as appropriate, with the measurement date of December 31. PGE contributed $2 million to the pension plan in 2017 , and made no contributions in 2016 or 2015 . PGE expects to contribute $21 million to the pension plan in 2018 . Other Postretirement Benefits— PGE has non-contributory postretirement health and life insurance plans, as well as health reimbursement arrangements (HRAs) for its employees (collectively, “Other Postretirement Benefits” in the following tables). Participants 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 responsible for 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 that are reviewed annually by PGE and updated as appropriate, with measurement dates of December 31. Non-Qualified Benefit Plan —The 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 includes pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in the NQBP trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. The assets of such trust 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 NQBP is December 31. Other NQBP —In addition to the NQBP 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 NQBP trust that 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): 2017 2016 NQBP Other NQBP Total NQBP Other NQBP Total Non-qualified benefit plan trust $ 17 $ 20 $ 37 $ 16 $ 18 $ 34 Non-qualified benefit plan liabilities * 25 81 106 25 80 105 * For the NQBP, excludes the current portion of $2 million in 2017 and 2016 , respectively, which are classified in Other current liabilities in the consolidated balance sheets. See “ Trust Accounts ” in Note 3, Balance Sheet Components, for information on the NQBP trust. Investment Policy and Asset Allocation —The Board of Directors of PGE appoints an Investment Committee, which is comprised of certain members of management from the Company, and establishes the Company’s asset allocation. The Investment Committee is then responsible for implementation of the asset allocation and oversight of the benefit plan investments. 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. Asset classes are regularly rebalanced to ensure asset allocations remain within prescribed parameters. The asset allocations for the plans, and the target allocation, are as follows: As of December 31, 2017 2016 Actual Target * Actual Target * Defined Benefit Pension Plan: Equity securities 68 % 67 % 68 % 67 % Debt securities 32 33 32 33 Total 100 % 100 % 100 % 100 % Other Postretirement Benefit Plans: Equity securities 63 % 62 % 60 % 62 % Debt securities 37 38 40 38 Total 100 % 100 % 100 % 100 % Non-Qualified Benefits Plans: Equity securities 18 % 12 % 15 % 11 % Debt securities 6 12 7 11 Insurance contracts 76 76 78 78 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 NQBP, 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 NQBP, 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. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements. 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 Other * Total As of December 31, 2017: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 83 $ — $ — $ — $ 83 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 528 528 Private equity funds — — — 13 13 $ 83 $ — $ — $ 546 $ 629 Other Postretirement Benefit Plans assets: Money market funds $ 3 $ — $ — $ — $ 3 Equity securities: Domestic — 3 — — 3 International 10 — — — 10 Debt securities—Domestic government — 5 — — 5 Investments measured at NAV: Money market funds — — — 4 4 Collective trust funds — — — 8 8 $ 13 $ 8 $ — $ 12 $ 33 As of December 31, 2016: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 52 $ — $ — $ — $ 52 Investments measured at NAV: Money market funds — — — 6 6 Collective trust funds — — — 483 483 Private equity funds — — — 18 18 $ 52 $ — $ — $ 507 $ 559 Other Postretirement Benefit Plans assets: Money market funds $ 4 $ — $ — $ — $ 4 Equity securities: Domestic — 3 — — 3 International 8 — — — 8 Debt securities—Domestic government — 4 — — 4 Investments measured at NAV: Money market funds — — — 4 4 Collective trust funds $ — $ — $ — $ 7 $ 7 $ 12 $ 7 $ — $ 11 $ 30 * Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. 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 discussion provides information regarding the methods used in valuation of the various asset class 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, or certificates of deposit. Some of the money market funds held in the trusts are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market. The remaining money market funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy. 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 separately managed accounts are classified as Level 2 securities due to pricing inputs that are directly or indirectly observable in the marketplace. Collective trust funds— Domestic and international mutual fund assets included in commingled trusts or separately managed accounts are valued at NAV as a practical expedient and not included in the fair value hierarchy. Debt securities, including municipal debt and corporate credit securities, mortgage-backed securities, and asset-backed securities included in commingled trusts are valued at NAV as a practical expedient and not included in the fair value hierarchy. 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, partnerships, joint ventures, venture capital, buyout, and special situations. Private equity investments are valued at NAV as a practical expedient. The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and NQBP as of and for the years ended December 31, 2017 and 2016 . Information related to the Other NQBP is not included in the following tables (dollars in millions): Defined Benefit Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2017 2016 2017 2016 2017 2016 Benefit obligation: As of January 1 $ 797 $ 758 $ 73 $ 81 $ 27 $ 27 Service cost 17 16 2 2 — — Interest cost 33 33 3 4 1 1 Participants’ contributions — — 2 2 — — Actuarial loss (gain) 60 26 3 (11 ) 1 1 Contractual termination benefits — — 1 — — — Benefit payments (36 ) (34 ) (6 ) (5 ) (2 ) (2 ) Administrative expenses (2 ) (2 ) — — — — As of December 31 $ 869 $ 797 $ 78 $ 73 $ 27 $ 27 Fair value of plan assets: As of January 1 $ 559 $ 550 $ 30 $ 30 $ 16 $ 15 Actual return on plan assets 106 45 4 1 1 1 Company contributions 2 — 3 2 2 2 Participants’ contributions — — 2 2 — — Benefit payments (36 ) (34 ) (6 ) (5 ) (2 ) (2 ) Administrative expenses (2 ) (2 ) — — — — As of December 31 $ 629 $ 559 $ 33 $ 30 $ 17 $ 16 Unfunded position as of December 31 $ (240 ) $ (238 ) $ (45 ) $ (43 ) $ (10 ) $ (11 ) Accumulated benefit plan obligation as of December 31 $ 778 $ 714 N/A N/A $ 27 $ 27 Classification in consolidated balance sheet: Noncurrent asset $ — $ — $ — $ — $ 17 $ 16 Current liability — — — — (2 ) (2 ) Noncurrent liability (240 ) (238 ) (45 ) (43 ) (25 ) (25 ) Net liability $ (240 ) $ (238 ) $ (45 ) $ (43 ) $ (10 ) $ (11 ) Amounts included in comprehensive income: Net actuarial loss (gain) $ (4 ) $ 21 $ — $ (10 ) $ 1 $ 1 Amortization of net actuarial loss (13 ) (14 ) — — (1 ) (1 ) Amortization of prior service cost — — — (1 ) — — $ (17 ) $ 7 $ — $ (11 ) $ — $ — Amounts included in AOCL*: Net actuarial loss (gain) $ 218 $ 236 $ (1 ) $ (2 ) $ 13 $ 13 Prior service cost — — — 1 — — $ 218 $ 236 $ (1 ) $ (1 ) $ 13 $ 13 Defined Benefit Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2017 2016 2017 2016 2017 2016 Assumptions used: Discount rate for benefit obligation 3.65 % 4.17 % 3.42 % - 3.75 % - 3.65 % 4.17 % 3.70 % 4.23 % Discount rate for benefit cost 4.17 % 4.36 % 3.75 % - 3.90 % - 4.17 % 4.36 % 4.23 % 4.45 % Weighted average rate of compensation increase for benefit obligation 4.58 % 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 7.50 % 7.50 % 6.26 % 6.26 % N/A N/A Long-term rate of return on plan assets for benefit cost 7.50 % 7.50 % 6.26 % 6.29 % 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 Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2017 2016 2015 2017 2016 2015 2017 2016 2015 Service cost $ 17 $ 16 $ 18 $ 2 $ 2 $ 2 $ — $ — $ — Interest cost on benefit obligation 33 33 31 3 4 3 1 1 1 Expected return on plan assets (42 ) (40 ) (40 ) (2 ) (2 ) (2 ) — — — Amortization of prior service cost — — — — 1 1 — — — Amortization of net actuarial loss 13 14 20 — — 1 1 1 1 Net periodic benefit cost $ 21 $ 23 $ 29 $ 3 $ 5 $ 5 $ 2 $ 2 $ 2 PGE estimates that $18 million will be amortized from AOCL into net periodic benefit cost in 2018 , consisting of a net actuarial loss of $17 million for pension benefits and $1 million for non-qualified 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 2018 2019 2020 2021 2022 2023 - 2026 Defined benefit pension plan $ 39 $ 41 $ 42 $ 43 $ 44 $ 234 Other postretirement benefits 5 5 5 4 5 22 Non-qualified benefit plans 2 3 2 2 2 10 Total $ 46 $ 49 $ 49 $ 49 $ 51 $ 266 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 2017 , 6.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018 , decreasing to 6.0% in 2019, then decreasing 0.25% per year thereafter, reaching 5.0% in 2023; • For 2016 , 7% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017 , decreasing to 6.5% in 2018, then decreasing 0.25% per year thereafter, reaching 5.0% in 2023; and • For 2015 , 6.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016 , decreasing to 6.0% in 2017, then decreasing 0.25% per year thereafter, reaching 5.0% in 2021. 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 $21 million in 2017 , $19 million in 2016 , and $17 million in 2015 . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Taxes Note [Abstract] | |
Income Taxes | INCOME TAXES On December 22, 2017, the TCJA was enacted and signed into law by the President of the United States with substantially all of the provisions of the TCJA having an effective date of January 1, 2018. Among other provisions, the reduction of the federal corporate tax rate from 35% to 21%, which required the Company to remeasure its existing deferred income tax balances as of December 31, 2017, had the most impact on PGE’s financial condition. As a result of the Company’s remeasurement, net deferred tax liabilities on the Company’s consolidated balance sheets were reduced by $340 million . Of the remeasurement amount, $357 million has been deferred as a regulatory liability and is expected to be refunded to customers over time. These deferred tax items relate primarily to Electric utility plant and other rate base items subject to tax normalization rules that require the benefits to be passed on to customers through future prices over the remaining useful life of the underlying assets for which the deferred income taxes relate. The Company plans to use the average rate assumption method to account for the refund to customers. A portion of the remeasurement is not subject to tax normalization rules and will be amortized over time. The remaining and offsetting remeasurement amount of $17 million represents a reduction to net deferred tax assets related to other business items, primarily comprised of deferred tax assets related to the Company’s NQBPs. The Company has recorded a $17 million charge to the results of operations, reflected as an increase in Income tax expense in the Company’s consolidated statements of income for the period ended December 31, 2017. Based on the Company’s interpretations of the TCJA as of December 31, 2017, PGE believes it has substantially completed its analysis of the tax effects of the TCJA and has reflected such effects in the remeasurement amounts recorded. However, PGE has not yet finalized its federal tax returns for 2017 and also expects regulatory bodies, such as the U.S. Department of the Treasury, Internal Revenue Service, and OPUC to issue additional guidance or orders in 2018 that may result in changes to the Company’s previously finalized analysis of the TCJA. Such changes could result in material changes to the ultimate impact of the TCJA on PGE’s financial condition, results of operations, and cash flows. Income tax expense consists of the following (in millions): Years Ended December 31, 2017 2016 2015 Current: Federal $ 4 $ 10 $ 4 State and local 12 3 1 16 13 5 Deferred: Federal 61 23 26 State and local 9 14 14 70 37 40 Income tax expense $ 86 $ 50 $ 45 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, 2017 2016 2015 Federal statutory tax rate 35.0 % 35.0 % 35.0 % Federal tax credits (1) (14.0 ) (18.2 ) (19.0 ) Change in federal tax law (2) 6.1 — — State and local taxes, net of federal tax benefit 5.0 4.8 4.2 Flow through depreciation and cost basis differences 1.5 0.2 — Other (2.1 ) (1.2 ) 0.5 Effective tax rate 31.5 % 20.6 % 20.7 % (1) Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in service dates. PGE’s PTC generation ends at various dates between 2017 and 2024. (2) Includes a $17 million increase to Income tax expense related to the remeasurement of deferred income taxes as a result of the enacted tax rate change under the TCJA. Deferred income tax assets and liabilities consist of the following (in millions): As of December 31, 2017 2016 Deferred income tax assets: Employee benefits $ 128 $ 181 Price risk management 56 59 Regulatory liabilities 14 29 Tax credits 50 56 Other 4 5 Total deferred income tax assets 252 330 Deferred income tax liabilities: Depreciation and amortization 496 829 Regulatory assets 132 170 Other — — Total deferred income tax liabilities 628 999 Deferred income tax liability, net $ (376 ) $ (669 ) As of December 31, 2017 , PGE has federal credit carryforwards of $50 million , consisting of PTCs, which will expire at various dates through 2037 . PGE has analyzed the provisions of the TCJA and its effects on the Company’s deferred income tax assets, and PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 2017 and 2016 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 2017 and 2016 , PGE had no unrecognized tax benefits. PGE and its subsidiaries file a consolidated federal income tax return. The Company also files income tax returns in the states of Oregon, California, and Montana, and in 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. |
Equity-Based Plans
Equity-Based Plans | 12 Months Ended |
Dec. 31, 2017 | |
Equity Based Plans [Abstract] | |
Stock Purchase Plan [Text Block] | EQUITY-BASED PLANS 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. Two, six-month offering periods occur annually, January 1 through June 30 and July 1 through December 31, during which eligible employees may contribute toward the purchase of shares of PGE common stock. Purchases occur the last day of the offering period, at a price equal to 95% of the fair value of the stock on the purchase date. As of December 31, 2017 , there were 339,542 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, 2017 , there were 2,470,052 shares available for future issuance pursuant to the DRIP. 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 2013, the Company issued 700,000 shares of its common stock pursuant to the EFSA for net proceeds of $20 million . During the second quarter 2015, PGE physically settled in full the EFSA by issuing 10,400,000 shares of common PGE common stock in exchange for cash of $271 million . Prior to settlement, the potentially issuable shares pursuant to the EFSA were 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 were 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 have been purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period). |
Stock-based Compensation Expens
Stock-based Compensation Expense | 12 Months Ended |
Dec. 31, 2017 | |
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, or 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, 2014 463,893 $ 28.96 Granted 181,797 34.77 Forfeited (14,988 ) 34.10 Vested (187,709 ) 25.82 Outstanding as of December 31, 2015 442,993 32.84 Granted 193,734 35.89 Forfeited (3,044 ) 28.62 Vested (174,891 ) 31.47 Outstanding as of December 31, 2016 458,792 34.68 Granted 202,145 41.96 Forfeited (64,840 ) 39.57 Vested (196,721 ) 31.78 Outstanding as of December 31, 2017 399,376 37.98 A total of 4,687,500 shares of common stock were registered for issuance under the Plan, of which 3,229,476 shares remain available for future issuance as of December 31, 2017 . 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, 2017 , 2016 , and 2015 . Performance-based RSUs vest if performance goals are met at the end of a three-year performance period. Grants are based on three equally-weighted metrics: i) return on equity relative to allowed return on equity; ii) regulated asset base growth (applicable only for those grants made prior to 2017); and iii) a relative total shareholder return (TSR) of PGE’s common stock as compared to an index of peer companies 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 (Committee). 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: 2017 2016 Risk-free interest rate 1.5 % 0.9 % Expected dividend yield — % — % Expected term (in years) 3.0 3.0 Volatility 15.6 % - 22.9 % 14.5 % - 25.9 % 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 107.0% , 120.8% , and 118.2% of awarded performance-based RSUs for the respective 2017 , 2016 , and 2015 grants, with an estimated 5% forfeiture rate. The total value of performance-based RSUs vested was $6 million for the year ended December 31, 2017 , $5 million for 2016 , and $4 million for 2015 . Stock-based compensation, included in Administrative and other expense in the consolidated statements of income, was $7 million for the year ended December 31, 2017 , and $6 million for 2016 , and 2015 . 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. Not included in Administrative and other expenses in the consolidated statements of income, is the net impact from these income tax payments, partially offset by the issuance of DERs, resulting in a charge to equity of $3 million in 2017 , and $2 million in 2016 and 2015 . As of December 31, 2017 , unrecognized stock-based compensation expense was $7 million , of which approximately $5 million and $2 million is expected to be expensed in 2018 and 2019 , 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, 2017 , 2016 , or 2015 . |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | EARNINGS PER SHARE Basic earnings per share are computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share are 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) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights; and iii) shares issuable pursuant to the EFSA. During the second quarter of 2015, PGE physically settled in full the EFSA, with the issuance of 10,400,000 shares of common stock. Prior to settlement, the potentially issuable shares pursuant to the EFSA were reflected in PGE’s diluted earnings per share calculations using the treasury stock method. See Note 12, Equity-based Plans, for additional information on the EFSA and its impact on earnings per share. 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, 2017 2016 2015 Weighted average common shares outstanding—basic 89,056 88,896 84,180 Dilutive effect of potential common shares 120 158 161 Weighted average common shares outstanding—diluted 89,176 89,054 84,341 |
Commitments and Guarantees
Commitments and Guarantees | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Guarantees [Text Block] | COMMITMENTS AND GUARANTEES Purchase Commitments As of December 31, 2017 , PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions): Payments Due 2018 2019 2020 2021 2022 Thereafter Total Capital and other purchase commitments $ 191 $ 2 $ 10 $ 2 $ 2 $ 58 $ 265 Purchased power and fuel: Electricity purchases 156 156 201 200 187 1,733 2,633 Capacity contracts 6 5 4 4 4 8 31 Public utility districts 9 17 16 16 15 85 158 Natural gas 51 35 28 25 24 140 303 Coal and transportation 15 5 — — — — 20 Total $ 428 $ 220 $ 259 $ 247 $ 232 $ 2,024 $ 3,410 Capital and other purchase commitments— Certain commitments have been made for 2018 and beyond that include those related to hydro licenses, upgrades to generation, distribution, and transmission facilities, information systems, and system maintenance work. Termination of these agreements could result in cancellation charges. Electricity purchases and Capacity contracts— PGE has power purchase agreements with counterparties, which expire at varying dates through 2044, and power capacity contracts through 2024. Public utility districts —PGE has long-term power purchase agreements with certain public utility districts including, Grant County PUD for the Priest Rapids and Wanapum projects, and Douglas County PUD for the Wells project, in the state of Washington. 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. In addition, although PGE’s current agreement with Douglas County ends on August 31, 2018, a new contract becomes effective on September 1, 2018 that does not require contributions to Douglas County debt obligation or other costs, including the operation and maintenance costs of the projects. The new contract requires monthly payments for capacity that will not vary with annual project generation provided to PGE. The Company has estimated the capacity payments, which are subject to annual adjustments based on Douglas loads, and included the estimated amounts in the table above. The future minimum payments for the public utility districts in the preceding table reflect the principal and capacity payments 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, 2017 PGE’s Share as of December 31, 2017 Contract Expiration PGE Cost, including Debt Service Output Capacity 2017 2016 2015 (in MW) Priest Rapids and Wanapum $ 1,269 8.6 % 163 2052 $ 16 $ 16 $ 18 Wells 160 19.4 150 2018 11 10 10 Portland Hydro — — — 2017 1 1 2 The agreements for Priest Rapids, 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 through August 2018, after which PGE would be responsible for a pro-rata portion of the defaulting purchaser’s share with no limitation, regardless of the reason for any default. 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 of the public utility district’s outstanding debt for the portion of the project that benefits tax exempt purchasers. Natural gas— PGE has contracts 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 Port Westward Unit 1 (PW1), PW2, and Beaver natural gas-fired generating plants. Coal and transportation —PGE has coal and related rail transportation agreements with take-or-pay provisions related to Boardman that expire at various dates through 2020. Lease Obligations As of December 31, 2017 , PGE’s estimated future minimum lease payments pursuant to capital, build-to-suit, and operating leases for the following five years and thereafter are as follows (in millions): Future Minimum Lease Payments Capital Leases Build-to-Suit Operating Leases 2018 $ 7 $ — $ 9 2019 6 15 8 2020 6 15 6 2021 6 14 6 2022 5 14 8 Thereafter 72 260 165 Total minimum lease payments $ 102 $ 318 $ 202 Less imputed interest 51 Present value of net minimum lease payments $ 51 Less current portion 2 Non-current portion $ 49 Capital Leases —PGE has entered into agreements to purchase natural gas transportation capacity to serve Carty via a 24-mile natural gas pipeline, Carty Lateral, that was constructed to serve the Carty facility. The Company has entered into a 30-year agreement to purchase the entire capacity of Carty Lateral, which is approximately 175,000 decatherms per day. At the end of the initial contract term, the Company has the option to renew the agreement in continuous three-year increments with at least 24-months prior written notice. As of December 31, 2017 , a capital lease asset of $57 million was reflected within Electric utility plant and accumulated amortization of such assets of $6 million was reflected within Accumulated depreciation and amortization in the table above. The present value of the future minimum lease payments due under the agreement included $2 million within Accrued expenses and other current liabilities and $49 million in Other noncurrent liabilities on the consolidated balance sheets. For ratemaking purposes capital leases are treated as operating leases; therefore, in accordance with the accounting rules for regulated operations, the amortization of the leased asset is based on the rental payments recovered from customers. Also for ratemaking purposes, such rental payments were capitalized to the Carty project prior to its in service date of July 29, 2016 and, as a result, amortization of the leased asset of $2 million and interest expense of $3 million was capitalized to CWIP. Beginning August 1, 2016, amortization of the leased asset of $1 million and interest expense of $2 million has been recorded to Purchased power and fuel expense in the consolidated statements of income through December 31, 2016 . For the year ended December 31, 2017 , amortization of the leased asset of $3 million and interest expense of $4 million has been recorded to Purchased power and fuel expense in the consolidated statements of income. Build-to-suit —PGE has entered into a 30-year lease agreement with a local natural gas company, NW Natural, to expand their current natural gas storage facilities, including the development of an underground storage reservoir and construction of a new compressor station and 13-mile pipeline, which will be designed to provide no-notice storage and transportation services to PGE’s PW1, PW2, and Beaver natural gas-fired generating plants. Pursuant to the agreement, on September 30, 2016, PGE issued NW Natural a Notice To Proceed with construction of the expansion project, which the gas company estimates will be completed during the winter of 2018-2019, at a cost of approximately $132 million . Due to the level of PGE’s involvement during the construction period, the Company is deemed to be the owner of the assets for accounting purposes during the construction period. As a result, PGE has recorded $108 million to CWIP and a corresponding liability for the same amount to Other noncurrent liabilities in the consolidated balance sheets as of December 31, 2017 . In 2016 , PGE recorded $21 million to CWIP and a corresponding liability for the same amount to Other noncurrent liabilities in the consolidated balance sheets as of December 31, 2016 . Upon completion of the facility, PGE will assess whether the assets and liabilities qualify as a successful sale-leaseback transaction in which the asset and liability are removed and accounted for as either a capital or operating lease. The table above reflects PGE’s estimated future minimum lease payments pursuant to the agreement based on estimated costs and assumes three 10-year renewable options are exercised. Operating leases —PGE has various operating leases associated with its headquarters and certain of its production, transmission, and support facilities that expire in various years, including the Port of St. Helens land lease, which expires in 2096 and covers the location of PW1, PW2, and Beaver. Rent expense was $9 million in 2017 , and $10 million in 2016 and 2015 . The future minimum operating lease payments presented is net of sublease income of $4 million in each of 2018 , 2019 , 2020 , and 2021 ; and $2 million in 2022 . Sublease income was $4 million in 2017 and 2016 , and $3 million in 2015 . 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, 2017 , 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. |
Jointly-owned Plant
Jointly-owned Plant | 12 Months Ended |
Dec. 31, 2017 | |
Jointly-owned Plant [Abstract] | |
Jointly-owned Plant [Text Block] | JOINTLY-OWNED PLANT As of December 31, 2017 , PGE had the following investments in jointly-owned plant (dollars in millions): PGE Share In-service Date Plant In-service Accumulated Depreciation* Construction Work In Progress Boardman 90.00 % 1980 $ 515 $ 426 $ — Colstrip 20.00 1986 546 351 5 Pelton/Round Butte 66.67 1958 / 1964 251 68 7 Total $ 1,312 $ 845 $ 12 * Excludes AROs and accumulated asset retirement removal costs. Under the respective joint operating agreements for the three generating facilities, 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. |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
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 circumstances in which 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. Carty In 2013, PGE entered into a turnkey engineering, procurement, and construction agreement (Construction Agreement) with Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership (collectively, the “Contractor”), affiliates of Abengoa S.A. - for the construction of the Carty natural gas-fired generating plant (Carty) located in Eastern Oregon. Liberty Mutual Insurance Company and Zurich American Insurance Company (together, the “Sureties”) provided a performance bond of $145.6 million (Performance Bond) in connection with the Construction Agreement. In December 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. Following termination of the Construction Agreement, PGE brought on new contractors and construction resumed. Carty was placed into service on July 29, 2016 and the Company began collecting its revenue requirement in customer prices on August 1, 2016, as authorized by the OPUC, based on the approved capital cost of $514 million . Actual costs for the construction of Carty exceeded the approved amount and, as of December 31, 2017 , PGE has capitalized $637 million to Electric utility plant. As the final construction cost exceeded the amount authorized by the OPUC, higher interest and depreciation expense than allowed in the Company’s revenue requirement has resulted. These incremental expenses are recognized in the Company’s current results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP. As actual project costs for Carty have exceeded $514 million , the Company has incurred a higher cost of service than what is reflected in the current authorized revenue requirement amount, primarily due to higher depreciation, interest expense and legal expenses. Such incremental expenses were $14 million and $3 million for the year ended December 31, 2017 and 2016, respectively. Any amounts approved by the OPUC for recovery under the deferral filing would be recognized in earnings in the period of such approval. Actual costs do not reflect any offsetting amounts that may be received from the Sureties, pursuant to the Performance Bond. The amounts recorded also exclude $8 million of liens and claims filed for goods and services provided under contracts with the former Contractor that remain in dispute. The Company believes these liens and claims are invalid and is contesting the liens and claims in the courts. The incremental costs resulted from various matters relating to the resumption of construction activities following the termination of the Construction Agreement, including, among other things, completing the remaining construction work, correcting deficiencies and defects in work performed by the former Contractor, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, and procuring additional materials. Other items contributing to the increase include costs relating to the removal of certain liens filed on the property for goods and services provided under contracts with the former Contractor, and costs to repair equipment damage that resulted from poor storage and maintenance on the part of the former Contractor. In July 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the incremental capital costs for Carty starting from its in service date to the date that such amounts are approved in a subsequent regulatory proceeding. The Company has requested that the OPUC delay its review of this deferral request until all legal actions with respect to this matter, including PGE’s actions against the Sureties, have been resolved. Any amounts approved by the OPUC for recovery under the deferral filing would be recognized in earnings in the period of such approval, however there is no assurance that such recovery would be granted by the OPUC. The Company believes that costs incurred to date and capitalized in Electric utility plant, net, in the condensed consolidated balance sheet, were prudently incurred. There have been no settlement discussions with regulators related to such costs. The Company is involved in several litigation proceedings concerning the termination of the Construction Agreement and the payment obligations of the Sureties. PGE is seeking recovery of incremental construction costs and other damages pursuant to breach of contract claims against the Contractor and claims against the Sureties pursuant to the Performance Bond. The Sureties have denied liability in whole under the Performance Bond. Various actions relating to this matter have been filed in the U.S. District Court for the District of Oregon (U.S. District Court), in the Ninth Circuit Court of Appeals (Ninth Circuit), and in an arbitration proceeding, including the following: • A breach of contract claim dated March 23, 2016, Portland General Electric Company v. Liberty Mutual Insurance Company and Zurich American Insurance Company, U.S. District Court of the District of Oregon, brought by PGE against the Sureties in U.S. District Court asserting that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Contractor’s breach of contract. The Company’s complaint disputes the Sureties’ assertion that the Company wrongfully terminated the Construction Agreement and asserts that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Sureties’ breach of contract, including damages in excess of the $145.6 million stated amount of the Performance Bond. Such damages include additional costs incurred by PGE to complete Carty. • A claim dated October 21, 2016, Portland General Electric Company v. Abeinsa EPC LLC, Abener Construction Services, LLC (formerly known as Abener Engineering and Construction Services, LLC), Teyma Construction USA LLC, and Abeinsa Abener Teyma General Partnership, U.S. District Court of the District of Oregon, brought by PGE in U.S. District Court against the Contractor for failure to satisfy its obligations under the Construction Agreement. PGE is seeking damages from the Contractor in excess of $200 million for: i) costs incurred to complete construction of Carty, settle claims with unpaid contractors and vendors, and remove liens; and ii) damages in excess of the construction costs, including a project management fee, liquidated damages under the Construction Agreement, legal fees and costs, damages due to delay of the project, warranty costs, and interest. • A claim dated December 31, 2015, In the Matter of an Arbitration Under the Rules of the International Chamber of Commerce’s Court of Arbitration, International Chamber of Commerce’s Court of Arbitration, by Abengoa S.A. in the ICC arbitration proceeding alleging that the Company’s termination of the Construction Agreement was wrongful and in breach of the terms of the agreement and did not give rise to any liability of Abengoa S.A.; and • A claim by the Contractor against PGE in the ICC arbitration proceeding seeking damages of $117 million based on a claim that PGE wrongfully terminated the Construction Agreement and $44 million based on a claim that PGE failed to disclose certain information to the Contractor, in connection with the Contractor’s bid submitted pursuant to the Company’s request for proposals. Following various procedural arguments in the ICC arbitration and the U.S. District Court, in July 2017, the Ninth Circuit held that the ICC arbitral tribunal had jurisdiction to determine what parties and what claims could be presented in the ICC arbitration as opposed to in court. A hearing before the ICC arbitral tribunal is expected to take place on April 9 and 10, 2018. The decision of the ICC arbitral tribunal is expected to determine the forum in which the above referenced claims will be heard. After exhausting all remedies against the aforementioned parties, the Company intends to seek approval to recover any remaining excess amounts in customer prices in a subsequent regulatory proceeding. However, there is no assurance that such recovery would be allowed by the OPUC. In accordance with GAAP and the Company’s accounting policies, any such excess costs may be charged to expense at the time disallowance of recovery becomes probable and a reasonable estimate of the amount of such disallowance can be made. As of the date of this report, the Company has concluded that the likelihood is less than probable that a portion of the cost of Carty will be disallowed for recovery in customer prices. Accordingly, no loss has been recorded to date related to the project. EPA Investigation of Portland Harbor An investigation by the United States Environmental Protection Agency (EPA) that began in 1997 of a segment of the Willamette River known as Portland Harbor has 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 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 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 remedial investigation had been completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the remedial investigation and feasibility study and stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy. The EPA has finalized the feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued on January 6, 2017. The ROD outlines the EPA’s selected remediation plan to clean-up for Portland Harbor, which has an estimated total cost of $1.7 billion , comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs, for a combined discounted present value of $1.1 billion . Remediation construction costs are estimated to be incurred over a 13-year period, with long-term operation and maintenance costs estimated to be incurred over a 30-year period from the start of construction. The EPA acknowledges the estimated costs are based on data that is now outdated and that a period of pre-remedial design sampling is necessary to gather updated baseline data to better refine the remedial design and estimated cost. In December 2017, the EPA announced that four PRPs have entered into an administrative order on consent to conduct this additional sampling, which is estimated to be completed in two years. PGE is not among the four PRPs performing this sampling. PGE is participating in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including results of the pre-remedial design sampling, a final allocation methodology and data with regard to property specific activities and history of ownership of sites within Portland Harbor. Based on the above facts and remaining uncertainties, PGE cannot reasonably estimate its potential liability or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor. Where injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which are referred to as natural resource damages. As it relates to the Portland Harbor, PGE has been participating in the Portland Harbor Natural Resource Damages assessment (NRDA) process. The EPA does not manage NRDA activities, but provides claims information and coordination support to the Natural Resource Damages (NRD) trustees. Damage assessment activities are typically conducted by a Trustee Council made up of the trustee entities for the site. The Portland Harbor NRD trustees are the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, and certain tribal entities. The NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate the trustees for costs incurred in assessing the damages. The NRD trustees are in the process of negotiating NRDA liability with several PRPs, including PGE. The Company believes that PGE’s portion of NRDA liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows. As discussed above, significant uncertainties still remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, the amount of natural resource damages, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. However, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of the Portland Harbor site, although such costs could be material. The Company plans to seek recovery of any costs resulting from the Portland Harbor proceeding through claims under insurance policies and regulatory recovery in customer prices. In July 2016, the Company filed a deferral application with the OPUC seeking the deferral of the future environmental remediation costs, as well as, seeking authorization to establish a regulatory cost recovery mechanism for such environmental costs. The Company reached an agreement with OPUC Staff and other parties regarding the details of the recovery mechanism, which the OPUC approved in the first quarter of 2017. The mechanism will allow the Company to defer and recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and through customer prices, as necessary. The mechanism establishes annual prudency reviews of environmental expenditures and is subject to an annual earnings test. Trojan Investment Recovery Class Actions In 1993, PGE closed the Trojan nuclear power plant (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 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the matter to the OPUC for reconsideration. In 2003, in two separate legal proceedings, lawsuits were filed against PGE on behalf of two classes of electric service customers: Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court; and Morgan v. Portland General Electric Company, Marion County Circuit Court. 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 August 2006, the Oregon Supreme Court (OSC) issued a ruling ordering the abatement of the class action proceedings. The OSC concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could 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. In 2008, the OPUC issued an order (2008 Order) that required PGE to provide refunds of $33 million , including interest, which were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in February 2013 and by the OSC in October 2014. In June 2015, based on a motion filed by PGE, the Marion County Circuit Court (Circuit Court) lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. In March 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. On April 14, 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon. Briefing on the appeal is now complete, with a Court of Appeals decision pending. PGE believes that the October 2, 2014 OSC decision and the recent Circuit Court decisions have 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 subject to a decision in the appeal, management believes that it is 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. Deschutes River Alliance Clean Water Act Claims On August 12, 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company, Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon, which seeks injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claims PGE has violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleges the violations are related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project. The SWW, located above Round Butte Dam, is, among other things, designed to blend water from the surface of the reservoir with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA has alleged that PGE’s operation of the SWW has caused the above-referenced violations of the CWA, which in turn have degraded the Deschutes River’s fish and wildlife habitat below the Project and harmed the economic and personal interests of DRA’s members and supporters. In September 2016, PGE filed a motion to dismiss, which asserted that the CWA does not allow citizen suits of this nature, and that the FERC has jurisdiction over all licensing issues, including the alleged CWA violations. On March 27, 2017, the court denied PGE’s motion to dismiss. On April 6, 2017, PGE filed a motion with the District Court for certification to file an interlocutory appeal with the Ninth Circuit and for a stay of the District Court proceeding. The District Court granted PGE’s request on May 19, 2017, but the Ninth Circuit denied the appeal on August 14, 2017. On April 7, 2017, the District Court granted an unopposed motion filed by the Confederated Tribes of Warm Springs (the Tribes) to appear in the case as a friend of the court. The Tribes share ownership of the Project with PGE, but have not been named as a defendant. Following conferences and negotiations involving various parties, and with the expiration of the stay, the District Court Judge, on January 17, 2018, established a briefing schedule for summary judgment motions. The Company cannot predict the outcome of this matter, but believes that it has strong defenses to DRA’s claims and intends to defend against them. Because i) this matter involves novel issues of law and ii) the mechanism and costs for achieving the relief sought in DRA’s claims have not yet been determined, the Company cannot, at this time, determine the likelihood of whether the outcome of this matter will result in a material loss. 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, 2017 | |
Basis of Presentation [Abstract] | |
Consolidation, Policy [Policy Text Block] | The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. For further information on PGE’s jointly-owned plant, see Note 16, Jointly-Owned Plant. Intercompany balances and transactions have been eliminated. For entities that are determined to meet the definition of a VIE and in which 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. |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
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, 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, the Company recognizes a realized gain or loss on the derivative instrument. Physically settled electricity and natural gas sale and purchase transactions are recorded in Revenues, net and Purchased power and fuel expense, respectively, upon settlement, 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 within 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, as well as fuel, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that it is recorded at the lower of average cost or net realizable value. |
Property, Plant and Equipment, Policy [Policy Text Block] | Electric utility plant is capitalized at 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 PGE’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 FERC licenses 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, 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 PGE’s other classes of plant in service over their estimated average service lives, |
Plant Retirement and Abandonment, Policy [Policy Text Block] | When property is retired and removed from service, the original cost of the depreciable property units, net of any related salvage value, is charged to accumulated depreciation. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, if applicable, and included in Regulatory liabilities. |
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 treatment. The cost of securities sold is based on the average cost method. |
Public Utilities, Policy [Policy Text Block] | PGE applies regulatory accounting, which results in the creation of regulatory assets and 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 PGE’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. The Company 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 net variable power costs (NVPC) forecast each year and included in customer prices (baseline NVPC) and actual NVPC. NVPC consists of 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 wholesale sales, which are classified as Revenues, net in the consolidated statements of income. The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC. 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 the given 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. |
Asset Retirement Obligation [Policy Text Block] | An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and market-risk premiums are not available. The present value of estimated future decommissioning 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 included in Depreciation and amortization expense in the Company’s 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. Legal costs incurred in connection with loss contingencies are expensed as incurred. 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 determined, 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. 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 circumstances in which 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 that are reviewed annually and 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. |
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 time of the last meter read date through the last day of the month, a period that has not been billed as of the last day of the month. Unbilled revenue is calculated based on actual net retail system load each month, 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, PGE, in certain situations, 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 would be established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns. Because PGE is a rate-regulated enterprise, changes in certain deferred tax assets and liabilities 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. |
Fair Value of Financial Instr28
Fair Value of Financial Instruments (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 and 2016 , and then classifies these financial assets and liabilities based on a fair value hierarchy that is used to prioritize the inputs to the valuation techniques used to measure fair value. The three 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 measurement date. Level 2 Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement 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. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements. 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] | Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) 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: 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 measurement 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 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 measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE). 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. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice. The NQBP trust is invested in exchange traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy. Common and collective trust funds —PGE invests in common and collective trust funds that invests in equity securities. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value as a practical expedient. The funds allow for daily liquidity with appropriate notice. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient. All collective trusts for the NQBP were liquidated during 2017. 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 NVPC 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 year ended December 31, 2017 , there were no transfers into Level 3 from Level 2, as reflected in the table above. During 2016 , there was $1 million transferred into Level 3. 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 First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds (PCBs) 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 was classified as Level 3 fair value measurement and was estimated based on the terms of the loans and the Company’s creditworthiness. |
Price Risk Management (Policies
Price Risk Management (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
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, such agreements provide for the net settlement of all related contractual obligations with a given 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, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation [Policy Text Block] | An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and market-risk premiums are not available. The present value of estimated future decommissioning 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 included in Depreciation and amortization expense in the Company’s 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, 2017 | |
Employee Benefits [Abstract] | |
pension and other postretirement benefits valuation methodology [Policy Text Block] | The following discussion provides information regarding the methods used in valuation of the various asset class 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, or certificates of deposit. Some of the money market funds held in the trusts are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market. The remaining money market funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy. 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 separately managed accounts are classified as Level 2 securities due to pricing inputs that are directly or indirectly observable in the marketplace. Collective trust funds— Domestic and international mutual fund assets included in commingled trusts or separately managed accounts are valued at NAV as a practical expedient and not included in the fair value hierarchy. Debt securities, including municipal debt and corporate credit securities, mortgage-backed securities, and asset-backed securities included in commingled trusts are valued at NAV as a practical expedient and not included in the fair value hierarchy. 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, partnerships, joint ventures, venture capital, buyout, and special situations. Private equity investments are valued at NAV as a practical expedient. |
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 that are reviewed annually and 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 that are reviewed annually by PGE and updated as appropriate, with measurement dates of December 31. |
Non-qualified benefit [Policy Text Block] | Non-Qualified Benefit Plan —The 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 includes pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in the NQBP trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. The assets of such trust 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 NQBP is December 31. Other NQBP —In addition to the NQBP 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 NQBP trust that are intended to be a funding source for these plans. |
Commitments and Guarantees (Pol
Commitments and Guarantees (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 | |
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. Legal costs incurred in connection with loss contingencies are expensed as incurred. 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 determined, 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. 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 circumstances in which 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 Accoun34
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Abstract] | |
Estimated average service lives [Table Text Block] | Depreciation is provided on PGE’s other classes of plant in service over their estimated average service lives, which are as follows (in years): Generation, excluding thermal: Hydro 95 Wind 30 Transmission 57 Distribution 45 General 12 |
Balance Sheet Components (Table
Balance Sheet Components (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 2016 2015 Balance as of beginning of year $ 6 $ 6 $ 6 Increase in provision 6 5 6 Amounts written off, less recoveries (6 ) (5 ) (6 ) Balance as of end of year $ 6 $ 6 $ 6 |
Investments held in trust [Table Text Block] | The trusts are comprised of the following investments as of December 31 (in millions): Nuclear Decommissioning Trust Non-Qualified Benefit Plan Trust 2017 2016 2017 2016 Cash equivalents $ 25 $ 21 $ 1 $ 1 Marketable securities, at fair value: Equity securities — — 7 6 Debt securities 17 20 1 1 Insurance contracts, at cash surrender value — — 28 26 $ 42 $ 41 $ 37 $ 34 |
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, 2017 2016 Other current assets: Prepaid expenses $ 50 $ 48 Margin deposits 11 8 Assets from price risk management activities 6 18 Other 6 3 $ 73 $ 77 Accrued expenses and other current liabilities: Regulatory liabilities—current $ 31 $ 51 Accrued employee compensation and benefits 60 52 Accrued dividends payable 31 30 Accrued interest payable 27 25 Accrued taxes payable 31 25 Other 61 71 $ 241 $ 254 |
Fair Value of Financial Instr36
Fair Value of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 Level 1 Level 2 Level 3 Other (2) Total Assets: Nuclear decommissioning trust: (1) Debt securities: Domestic government $ 4 $ 7 $ — $ — $ 11 Corporate credit — 6 — — 6 Money market funds measured at NAV (2) — — — 25 25 Non-qualified benefit plan trust: (3) Money market funds 1 — — — 1 Equity securities—domestic 7 — — — 7 Debt securities—domestic government 1 — — — 1 Investments measured at NAV: (2) Collective trust—domestic equity — — — — — Assets from price risk management activities: (1) (4) Electricity — 3 — — 3 Natural gas — 3 — — 3 $ 13 $ 19 $ — $ 25 $ 57 Liabilities - Liabilities from price risk management activities: (1) (4) Electricity $ — $ 5 $ 130 $ — $ 135 Natural gas — 66 9 — 75 $ — $ 71 $ 139 $ — $ 210 (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) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $28 million , which are recorded at cash surrender value. (4) For further information, see Note 5, Price Risk Management. As of December 31, 2016 Level 1 Level 2 Level 3 Other (2) Total Assets: Nuclear decommissioning trust: (1) Debt securities: Domestic government $ 2 $ 10 $ — $ — $ 12 Corporate credit — 8 — — 8 Money market funds measured at NAV (2) — — — 21 21 Non-qualified benefit plan trust: (3) Money market funds 1 — — — 1 Equity securities—domestic 4 — — — 4 Debt securities—domestic government 1 — — — 1 Investments measured at NAV: (2) Collective trust—domestic equity — — — 2 2 Assets from price risk management activities: (1) (4) Electricity — 6 1 — 7 Natural gas — 15 1 — 16 $ 8 $ 39 $ 2 $ 23 $ 72 Liabilities - Liabilities from price risk management activities: (1) (4) Electricity $ — $ 6 $ 112 $ — $ 118 Natural gas — 42 9 — 51 $ — $ 48 $ 121 $ — $ 169 (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) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $26 million , which are recorded at cash surrender value. (4) 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 Other * Total As of December 31, 2017: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 83 $ — $ — $ — $ 83 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 528 528 Private equity funds — — — 13 13 $ 83 $ — $ — $ 546 $ 629 Other Postretirement Benefit Plans assets: Money market funds $ 3 $ — $ — $ — $ 3 Equity securities: Domestic — 3 — — 3 International 10 — — — 10 Debt securities—Domestic government — 5 — — 5 Investments measured at NAV: Money market funds — — — 4 4 Collective trust funds — — — 8 8 $ 13 $ 8 $ — $ 12 $ 33 As of December 31, 2016: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 52 $ — $ — $ — $ 52 Investments measured at NAV: Money market funds — — — 6 6 Collective trust funds — — — 483 483 Private equity funds — — — 18 18 $ 52 $ — $ — $ 507 $ 559 Other Postretirement Benefit Plans assets: Money market funds $ 4 $ — $ — $ — $ 4 Equity securities: Domestic — 3 — — 3 International 8 — — — 8 Debt securities—Domestic government — 4 — — 4 Investments measured at NAV: Money market funds — — — 4 4 Collective trust funds $ — $ — $ — $ 7 $ 7 $ 12 $ 7 $ — $ 11 $ 30 * Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. |
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, 2017: Electricity physical forward $ — $ 130 Discounted cash flow Electricity forward price (per MWh) $ 7.79 $ 41.23 $ 30.95 Natural gas financial swaps — 9 Discounted cash flow Natural gas forward price (per Dth) 1.26 2.92 1.90 Electricity financial futures — — Discounted cash flow Electricity forward price (per MWh) 7.79 29.74 21.74 $ — $ 139 As of December 31, 2016: Electricity physical forward $ — $ 112 Discounted cash flow Electricity forward price (per MWh) $ 14.25 $ 54.73 $ 38.18 Natural gas financial swaps 1 9 Discounted cash flow Natural gas forward price (per Dth) 1.85 4.92 2.64 Electricity financial futures 1 — Discounted cash flow Electricity forward price (per MWh) 8.57 33.60 25.10 $ 2 $ 121 |
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, 2017 2016 Net liabilities from price risk management activities as of beginning of year $ 119 $ 119 Net realized and unrealized losses * 35 11 Net transfers in to Level 3 from Level 2 — (1 ) Net transfers out of Level 3 to Level 2 (15 ) (10 ) Net liabilities from price risk management activities as of end of year $ 139 $ 119 Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting $ 41 $ 11 * Includes $6 million in net realized losses in 2017 and none in 2016 . |
Price Risk Management (Tables)
Price Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 2016 Current assets: Commodity contracts: Electricity $ 3 $ 6 Natural gas 3 12 Total current derivative assets 6 (1) 18 (1) Noncurrent assets: Commodity contracts: Electricity — 1 Natural gas — 4 Total noncurrent derivative assets — (2) 5 (2) Total derivative assets not designated as hedging instruments $ 6 $ 23 Total derivative assets $ 6 $ 23 Current liabilities: Commodity contracts: Electricity $ 13 $ 12 Natural gas 46 32 Total current derivative liabilities 59 44 Noncurrent liabilities: Commodity contracts: Electricity 122 106 Natural gas 29 19 Total noncurrent derivative liabilities 151 125 Total derivative liabilities not designated as hedging instruments $ 210 $ 169 Total derivative liabilities $ 210 $ 169 (1) Included in Other current assets on the consolidated balance sheets. (2) Included in Other noncurrent assets on the consolidated balance sheets. |
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, 2017 2016 Commodity contracts: Electricity 7 MWh 8 MWh Natural gas 114 Dth 107 Dth Foreign currency exchange $ 21 Canadian $ 22 Canadian |
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 (gains) 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, 2017 2016 2015 Commodity contracts: Electricity $ 41 $ 34 $ 72 Natural Gas 85 (56 ) 103 Foreign currency exchange (1 ) — 1 Net unrealized and certain net realized losses (gains) presented in the table above are offset within the consolidated statements of income by the effects of regulatory accounting. Net losses of $82 million , net gains of $13 million , and net losses of $160 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, have been offset in Net income. |
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, 2017 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions): 2018 2019 2020 2021 2022 Thereafter Total Commodity contracts: Electricity $ 10 $ 8 $ 8 $ 8 $ 7 $ 91 $ 132 Natural gas 43 20 7 2 — — 72 Net unrealized loss $ 53 $ 28 $ 15 $ 10 $ 7 $ 91 $ 204 |
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, 2017 2016 Assets from price risk management activities: Counterparty A 39 % 22 % Counterparty B 12 17 Counterparty C 3 12 54 % 51 % Liabilities from price risk management activities: Counterparty D 62 % 66 % 62 % 66 % |
Regulatory Assets and Liabili38
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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 Life (1) As of December 31, 2017 2016 Current Noncurrent Current Noncurrent Regulatory assets: Price risk management (2) 6 years $ 53 $ 151 $ 26 $ 120 Pension and other postretirement plans (2) (3) — 218 — 235 Deferred income taxes (6) (4) — — — 86 Debt issuance costs (2) 6 years — 19 — 22 Other (5) Various 9 50 10 35 Total regulatory assets $ 62 $ 438 $ 36 $ 498 Regulatory liabilities: Asset retirement removal costs (6) (4) $ — $ 933 $ — $ 887 Deferred income taxes (6) (4) — 277 — — Trojan decommissioning activities 5 years 3 — 18 — Asset retirement obligations (6) (4) — 52 — 49 Other Various 28 26 33 22 Total regulatory liabilities $ 31 (7) $ 1,288 $ 51 (7) $ 958 (1) As of December 31, 2017 . (2) Does not include a return on investment. (3) Recovery expected over the average service life of employees. (4) Recovery or refund expected over the estimated lives of the net balance. (5) Of the total other unamortized regulatory asset balances, a return is recorded on $51 million and $44 million as of December 31, 2017 and 2016 , 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, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations [Table Text Block] | AROs consist of the following (in millions): As of December 31, 2017 2016 Trojan decommissioning activities $ 45 $ 44 Utility plant 109 105 Non-utility property 13 12 Asset retirement obligations $ 167 $ 161 |
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, 2017 2016 2015 Balance as of beginning of year $ 161 $ 151 $ 116 Liabilities incurred 2 1 2 Liabilities settled (3 ) (3 ) (4 ) Accretion expense 7 7 7 Revisions in estimated cash flows — 5 30 Balance as of end of year $ 167 $ 161 $ 151 |
Credit Facilities (Tables)
Credit Facilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Line of Credit Facility [Abstract] | |
Schedule of Short-term Debt [Table Text Block] | Short-term borrowings under these credit facilities and related interest rates are reflected in the following table (dollars in millions). The Company had no short-term borrowings during 2017. Years Ended December 31, 2017 2016 2015 Average daily amount of short-term debt outstanding $ — $ 1 $ — Weighted daily average interest rate * — % 0.7 % 0.6 % Maximum amount outstanding during the year $ — $ 23 $ 11 * 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, 2017 | |
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, 2017 2016 First Mortgage Bonds , rates range from 2.51% to 9.31%, with a weighted average rate of 5.03% in 2017 and 4.86% in 2016, due at various dates through 2048 $ 2,315 $ 2,090 Unsecured term bank loans , variable rates of approximately 1.87% at 11/27/2017 and 1.37% at 12/31/2016 — 150 Pollution Control Revenue Bonds , 5% rate, due 2033 142 142 Pollution Control Revenue Bonds owned by PGE (21 ) (21 ) Total long-term debt 2,436 2,361 Less: Unamortized debt expense (10 ) (11 ) Less: Current portion of long-term debt — (150 ) Long-term debt, net of current portion $ 2,426 $ 2,200 |
Schedule of Maturities of Long-term Debt [Table Text Block] | As of December 31, 2017 , the future minimum principal payments on long-term debt are as follows (in millions): Years ending December 31: 2018 $ — 2019 300 2020 — 2021 160 2022 — Thereafter 1,976 $ 2,436 |
Employee Benefits (Tables)
Employee Benefits (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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): 2017 2016 NQBP Other NQBP Total NQBP Other NQBP Total Non-qualified benefit plan trust $ 17 $ 20 $ 37 $ 16 $ 18 $ 34 Non-qualified benefit plan liabilities * 25 81 106 25 80 105 * For the NQBP, excludes the current portion of $2 million in 2017 and 2016 , respectively, which are 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, 2017 2016 Actual Target * Actual Target * Defined Benefit Pension Plan: Equity securities 68 % 67 % 68 % 67 % Debt securities 32 33 32 33 Total 100 % 100 % 100 % 100 % Other Postretirement Benefit Plans: Equity securities 63 % 62 % 60 % 62 % Debt securities 37 38 40 38 Total 100 % 100 % 100 % 100 % Non-Qualified Benefits Plans: Equity securities 18 % 12 % 15 % 11 % Debt securities 6 12 7 11 Insurance contracts 76 76 78 78 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 NQBP, 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 NQBP, 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, 2017 Level 1 Level 2 Level 3 Other (2) Total Assets: Nuclear decommissioning trust: (1) Debt securities: Domestic government $ 4 $ 7 $ — $ — $ 11 Corporate credit — 6 — — 6 Money market funds measured at NAV (2) — — — 25 25 Non-qualified benefit plan trust: (3) Money market funds 1 — — — 1 Equity securities—domestic 7 — — — 7 Debt securities—domestic government 1 — — — 1 Investments measured at NAV: (2) Collective trust—domestic equity — — — — — Assets from price risk management activities: (1) (4) Electricity — 3 — — 3 Natural gas — 3 — — 3 $ 13 $ 19 $ — $ 25 $ 57 Liabilities - Liabilities from price risk management activities: (1) (4) Electricity $ — $ 5 $ 130 $ — $ 135 Natural gas — 66 9 — 75 $ — $ 71 $ 139 $ — $ 210 (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) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $28 million , which are recorded at cash surrender value. (4) For further information, see Note 5, Price Risk Management. As of December 31, 2016 Level 1 Level 2 Level 3 Other (2) Total Assets: Nuclear decommissioning trust: (1) Debt securities: Domestic government $ 2 $ 10 $ — $ — $ 12 Corporate credit — 8 — — 8 Money market funds measured at NAV (2) — — — 21 21 Non-qualified benefit plan trust: (3) Money market funds 1 — — — 1 Equity securities—domestic 4 — — — 4 Debt securities—domestic government 1 — — — 1 Investments measured at NAV: (2) Collective trust—domestic equity — — — 2 2 Assets from price risk management activities: (1) (4) Electricity — 6 1 — 7 Natural gas — 15 1 — 16 $ 8 $ 39 $ 2 $ 23 $ 72 Liabilities - Liabilities from price risk management activities: (1) (4) Electricity $ — $ 6 $ 112 $ — $ 118 Natural gas — 42 9 — 51 $ — $ 48 $ 121 $ — $ 169 (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) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $26 million , which are recorded at cash surrender value. (4) 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 Other * Total As of December 31, 2017: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 83 $ — $ — $ — $ 83 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 528 528 Private equity funds — — — 13 13 $ 83 $ — $ — $ 546 $ 629 Other Postretirement Benefit Plans assets: Money market funds $ 3 $ — $ — $ — $ 3 Equity securities: Domestic — 3 — — 3 International 10 — — — 10 Debt securities—Domestic government — 5 — — 5 Investments measured at NAV: Money market funds — — — 4 4 Collective trust funds — — — 8 8 $ 13 $ 8 $ — $ 12 $ 33 As of December 31, 2016: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 52 $ — $ — $ — $ 52 Investments measured at NAV: Money market funds — — — 6 6 Collective trust funds — — — 483 483 Private equity funds — — — 18 18 $ 52 $ — $ — $ 507 $ 559 Other Postretirement Benefit Plans assets: Money market funds $ 4 $ — $ — $ — $ 4 Equity securities: Domestic — 3 — — 3 International 8 — — — 8 Debt securities—Domestic government — 4 — — 4 Investments measured at NAV: Money market funds — — — 4 4 Collective trust funds $ — $ — $ — $ 7 $ 7 $ 12 $ 7 $ — $ 11 $ 30 * Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. |
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 NQBP as of and for the years ended December 31, 2017 and 2016 . Information related to the Other NQBP is not included in the following tables (dollars in millions): Defined Benefit Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2017 2016 2017 2016 2017 2016 Benefit obligation: As of January 1 $ 797 $ 758 $ 73 $ 81 $ 27 $ 27 Service cost 17 16 2 2 — — Interest cost 33 33 3 4 1 1 Participants’ contributions — — 2 2 — — Actuarial loss (gain) 60 26 3 (11 ) 1 1 Contractual termination benefits — — 1 — — — Benefit payments (36 ) (34 ) (6 ) (5 ) (2 ) (2 ) Administrative expenses (2 ) (2 ) — — — — As of December 31 $ 869 $ 797 $ 78 $ 73 $ 27 $ 27 Fair value of plan assets: As of January 1 $ 559 $ 550 $ 30 $ 30 $ 16 $ 15 Actual return on plan assets 106 45 4 1 1 1 Company contributions 2 — 3 2 2 2 Participants’ contributions — — 2 2 — — Benefit payments (36 ) (34 ) (6 ) (5 ) (2 ) (2 ) Administrative expenses (2 ) (2 ) — — — — As of December 31 $ 629 $ 559 $ 33 $ 30 $ 17 $ 16 Unfunded position as of December 31 $ (240 ) $ (238 ) $ (45 ) $ (43 ) $ (10 ) $ (11 ) Accumulated benefit plan obligation as of December 31 $ 778 $ 714 N/A N/A $ 27 $ 27 Classification in consolidated balance sheet: Noncurrent asset $ — $ — $ — $ — $ 17 $ 16 Current liability — — — — (2 ) (2 ) Noncurrent liability (240 ) (238 ) (45 ) (43 ) (25 ) (25 ) Net liability $ (240 ) $ (238 ) $ (45 ) $ (43 ) $ (10 ) $ (11 ) Amounts included in comprehensive income: Net actuarial loss (gain) $ (4 ) $ 21 $ — $ (10 ) $ 1 $ 1 Amortization of net actuarial loss (13 ) (14 ) — — (1 ) (1 ) Amortization of prior service cost — — — (1 ) — — $ (17 ) $ 7 $ — $ (11 ) $ — $ — Amounts included in AOCL*: Net actuarial loss (gain) $ 218 $ 236 $ (1 ) $ (2 ) $ 13 $ 13 Prior service cost — — — 1 — — $ 218 $ 236 $ (1 ) $ (1 ) $ 13 $ 13 Defined Benefit Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2017 2016 2017 2016 2017 2016 Assumptions used: Discount rate for benefit obligation 3.65 % 4.17 % 3.42 % - 3.75 % - 3.65 % 4.17 % 3.70 % 4.23 % Discount rate for benefit cost 4.17 % 4.36 % 3.75 % - 3.90 % - 4.17 % 4.36 % 4.23 % 4.45 % Weighted average rate of compensation increase for benefit obligation 4.58 % 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 7.50 % 7.50 % 6.26 % 6.26 % N/A N/A Long-term rate of return on plan assets for benefit cost 7.50 % 7.50 % 6.26 % 6.29 % 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 Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2017 2016 2015 2017 2016 2015 2017 2016 2015 Service cost $ 17 $ 16 $ 18 $ 2 $ 2 $ 2 $ — $ — $ — Interest cost on benefit obligation 33 33 31 3 4 3 1 1 1 Expected return on plan assets (42 ) (40 ) (40 ) (2 ) (2 ) (2 ) — — — Amortization of prior service cost — — — — 1 1 — — — Amortization of net actuarial loss 13 14 20 — — 1 1 1 1 Net periodic benefit cost $ 21 $ 23 $ 29 $ 3 $ 5 $ 5 $ 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 2018 2019 2020 2021 2022 2023 - 2026 Defined benefit pension plan $ 39 $ 41 $ 42 $ 43 $ 44 $ 234 Other postretirement benefits 5 5 5 4 5 22 Non-qualified benefit plans 2 3 2 2 2 10 Total $ 46 $ 49 $ 49 $ 49 $ 51 $ 266 |
Income Taxes Income Taxes (Tabl
Income Taxes Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 2016 2015 Current: Federal $ 4 $ 10 $ 4 State and local 12 3 1 16 13 5 Deferred: Federal 61 23 26 State and local 9 14 14 70 37 40 Income tax expense $ 86 $ 50 $ 45 |
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, 2017 2016 2015 Federal statutory tax rate 35.0 % 35.0 % 35.0 % Federal tax credits (1) (14.0 ) (18.2 ) (19.0 ) Change in federal tax law (2) 6.1 — — State and local taxes, net of federal tax benefit 5.0 4.8 4.2 Flow through depreciation and cost basis differences 1.5 0.2 — Other (2.1 ) (1.2 ) 0.5 Effective tax rate 31.5 % 20.6 % 20.7 % (1) Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in service dates. PGE’s PTC generation ends at various dates between 2017 and 2024. (2) Includes a $17 million increase to Income tax expense related to the remeasurement of deferred income taxes as a result of the enacted tax rate change under the TCJA. |
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, 2017 2016 Deferred income tax assets: Employee benefits $ 128 $ 181 Price risk management 56 59 Regulatory liabilities 14 29 Tax credits 50 56 Other 4 5 Total deferred income tax assets 252 330 Deferred income tax liabilities: Depreciation and amortization 496 829 Regulatory assets 132 170 Other — — Total deferred income tax liabilities 628 999 Deferred income tax liability, net $ (376 ) $ (669 ) |
Stock-based Compensation Expe44
Stock-based Compensation Expense Restricted and Performance Stock Unit activity (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2014 463,893 $ 28.96 Granted 181,797 34.77 Forfeited (14,988 ) 34.10 Vested (187,709 ) 25.82 Outstanding as of December 31, 2015 442,993 32.84 Granted 193,734 35.89 Forfeited (3,044 ) 28.62 Vested (174,891 ) 31.47 Outstanding as of December 31, 2016 458,792 34.68 Granted 202,145 41.96 Forfeited (64,840 ) 39.57 Vested (196,721 ) 31.78 Outstanding as of December 31, 2017 399,376 37.98 |
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: 2017 2016 Risk-free interest rate 1.5 % 0.9 % Expected dividend yield — % — % Expected term (in years) 3.0 3.0 Volatility 15.6 % - 22.9 % 14.5 % - 25.9 % |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 2016 2015 Weighted average common shares outstanding—basic 89,056 88,896 84,180 Dilutive effect of potential common shares 120 158 161 Weighted average common shares outstanding—diluted 89,176 89,054 84,341 |
Commitments and Guarantees (Tab
Commitments and Guarantees (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Purchase Commitment [Line Items] | |
Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block] | As of December 31, 2017 , PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions): Payments Due 2018 2019 2020 2021 2022 Thereafter Total Capital and other purchase commitments $ 191 $ 2 $ 10 $ 2 $ 2 $ 58 $ 265 Purchased power and fuel: Electricity purchases 156 156 201 200 187 1,733 2,633 Capacity contracts 6 5 4 4 4 8 31 Public utility districts 9 17 16 16 15 85 158 Natural gas 51 35 28 25 24 140 303 Coal and transportation 15 5 — — — — 20 Total $ 428 $ 220 $ 259 $ 247 $ 232 $ 2,024 $ 3,410 |
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 including, Grant County PUD for the Priest Rapids and Wanapum projects, and Douglas County PUD for the Wells project, in the state of Washington. 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. In addition, although PGE’s current agreement with Douglas County ends on August 31, 2018, a new contract becomes effective on September 1, 2018 that does not require contributions to Douglas County debt obligation or other costs, including the operation and maintenance costs of the projects. The new contract requires monthly payments for capacity that will not vary with annual project generation provided to PGE. The Company has estimated the capacity payments, which are subject to annual adjustments based on Douglas loads, and included the estimated amounts in the table above. The future minimum payments for the public utility districts in the preceding table reflect the principal and capacity payments 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, 2017 PGE’s Share as of December 31, 2017 Contract Expiration PGE Cost, including Debt Service Output Capacity 2017 2016 2015 (in MW) Priest Rapids and Wanapum $ 1,269 8.6 % 163 2052 $ 16 $ 16 $ 18 Wells 160 19.4 150 2018 11 10 10 Portland Hydro — — — 2017 1 1 2 |
Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block] | As of December 31, 2017 , PGE’s estimated future minimum lease payments pursuant to capital, build-to-suit, and operating leases for the following five years and thereafter are as follows (in millions): Future Minimum Lease Payments Capital Leases Build-to-Suit Operating Leases 2018 $ 7 $ — $ 9 2019 6 15 8 2020 6 15 6 2021 6 14 6 2022 5 14 8 Thereafter 72 260 165 Total minimum lease payments $ 102 $ 318 $ 202 Less imputed interest 51 Present value of net minimum lease payments $ 51 Less current portion 2 Non-current portion $ 49 |
Jointly-owned Plant (Tables)
Jointly-owned Plant (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Jointly-owned Plant [Abstract] | |
Schedule of Jointly Owned Utility Plants [Table Text Block] | As of December 31, 2017 , PGE had the following investments in jointly-owned plant (dollars in millions): PGE Share In-service Date Plant In-service Accumulated Depreciation* Construction Work In Progress Boardman 90.00 % 1980 $ 515 $ 426 $ — Colstrip 20.00 1986 546 351 5 Pelton/Round Butte 66.67 1958 / 1964 251 68 7 Total $ 1,312 $ 845 $ 12 * Excludes AROs and accumulated asset retirement removal costs. |
Basis of Presentation (Details)
Basis of Presentation (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2017mi²sharesretail_customers | |
Basis of Presentation [Abstract] | |||
Service Area Sq Miles | mi² | 4,000 | ||
Incorporated Cities | 51 | ||
Number of Retail Customers | retail_customers | 875,000 | ||
Service area population | 1,900,000 | ||
Percent of State's Population | 46.00% | ||
Entity Number of Employees | 2,906 | ||
Number of Union Employees | 785 | ||
Number of Union Employees Subject to Agreement A | 732 | ||
Number of Union Employees Subject to Agreement B | 53 | ||
Cash received to be returned to customers pursuant to the Residential Exchange Program | $ | $ 6 | $ 1 | |
Contribution to the voluntary employees’ beneficiary association trust | $ | 2 | 4 | |
Regulatory deferral of settled derivative instruments | $ | $ 2 | $ 2 |
Summary of Significant Accoun49
Summary of Significant Accounting Policies Estimated average service lives (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Generation, excluding thermal: | |
Hydro | 95 |
Wind | 30 |
Transmission | 57 |
Distribution | 45 |
General | 12 |
Summary of Significant Accoun50
Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment [Line Items] | |||
Other Investments | $ 30 | $ 1 | |
Business days after the invoice date | 16 | ||
Days after the due date | 45 | ||
Wholesale accounts receivable written off | $ 0 | 0 | $ 0 |
Margin deposit | 11 | 8 | |
Letters of Credit Outstanding, Amount | $ 31 | $ 17 | |
Public Utilities, Allowance for Funds Used During Construction, Rate | 7.30% | 7.30% | 7.30% |
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest | $ 6 | $ 11 | $ 13 |
Allowance for equity funds used during construction | $ 12 | $ 21 | $ 21 |
Depreciation expense rate | 3.60% | 3.50% | 3.60% |
Finite-Lived Intangible Assets, Accumulated Amortization | $ 296 | $ 257 | |
Amortization of Intangible Assets | 46 | $ 44 | $ 38 |
Future Amortization Expense, Year One | 49 | ||
Future Amortization Expense, Year Two | 48 | ||
Future Amortization Expense, Year Three | 43 | ||
Future Amortization Expense, Year Four | 35 | ||
Future Amortization Expense, Year Five | 28 | ||
Power Cost Deadband - Lower Threshold | 15 | ||
Power Cost Deadband - Upper Threshold | $ 30 | ||
Public Utilities, Approved Return on Equity, Percentage | 9.60% | 9.60% | 9.68% |
Regulatory Liability, Noncurrent | $ 1,288 | $ 958 | |
Franchise taxes | 43 | 43 | $ 43 |
Regulatory Assets, Noncurrent | 438 | 498 | |
Defined Benefit Plan, Interest Cost | 3 | ||
Deferred Income Tax Charge [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Regulatory Assets, Noncurrent | 0 | 86 | |
Asset Retirement Obligation Costs [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Regulatory Liability, Noncurrent | 52 | 49 | |
Deferred Income Tax Charge [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Regulatory Liability, Noncurrent | $ 277 | $ 0 |
Balance Sheet Components Allowa
Balance Sheet Components Allowance for Uncollectible accounts activity (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Balance as of beginning of year | $ 6 | $ 6 | $ 6 |
Increase in provision | 6 | 5 | 6 |
Amounts written off, less recoveries | (6) | (5) | (6) |
Balance as of end of year | $ 6 | $ 6 | $ 6 |
Balance Sheet Components Invest
Balance Sheet Components Investments Held in Trust (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Marketable securities, at fair value: | ||
Decommissioning Fund Investments, Fair Value | $ 42 | $ 41 |
Non-qualified benefit plan trust | 37 | 34 |
Nuclear Decommissioning [Member] | ||
Cash equivalents | 25 | 21 |
Marketable securities, at fair value: | ||
Equity securities | 0 | 0 |
Debt securities | 17 | 20 |
Insurance contracts, at cash surrender value | 0 | 0 |
Decommissioning Fund Investments, Fair Value | 42 | 41 |
Non Qualified Benefit Plans [Member] | ||
Cash equivalents | 1 | 1 |
Marketable securities, at fair value: | ||
Equity securities | 7 | 6 |
Debt securities | 1 | 1 |
Insurance contracts, at cash surrender value | 28 | 26 |
Non-qualified benefit plan trust | $ 37 | $ 34 |
Balance Sheet Components Schedu
Balance Sheet Components Schedule of Other Asssets and Other Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Other current assets: | ||
Prepaid Expense, Current | $ 50 | $ 48 |
Margin Deposit Assets | 11 | 8 |
Assets from price risk management activities | 6 | 18 |
Other | 6 | 3 |
Other Assets, Current | 73 | 77 |
Accrued expenses and other current liabilities: | ||
Regulatory Liability, Current | 31 | 51 |
Accrued employee compensation and benefits | 60 | 52 |
Accrued interest payable | 27 | 25 |
Dividends payable | 31 | 30 |
Taxes Payable, Current | 31 | 25 |
Other | 61 | 71 |
Other Liabilities, Current | $ 241 | $ 254 |
Balance Sheet Components (Detai
Balance Sheet Components (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Sep. 30, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Regulatory Liability, Noncurrent | $ 1,288 | $ 958 | ||||
Allowance for Doubtful Accounts Receivable, Current | $ 6 | $ 6 | $ 6 | $ 6 | ||
Loss Contingency, Damages Awarded, Value | $ 50 | |||||
Jointly Owned Electricity Generation Plant [Member] | ||||||
Loss Contingency, Damages Awarded, Value | $ 6 | $ 44 |
Fair Value of FInancial Instr55
Fair Value of FInancial Instruments Schedule of Fair Value (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Domestic government, Debt securities | $ 11 | $ 12 |
Corporate debt securities held in decommissioning trust assets | 6 | 8 |
Money market funds | 25 | 21 |
Fair Value - Money market funds | 1 | 1 |
Domestic Equity Securities | 7 | 4 |
Debt securities - domestic government | 1 | 1 |
Investments, Fair Value Disclosure | 0 | 2 |
Electricity | 3 | 7 |
Natural gas | 3 | 16 |
Financial Instruments, Owned, at Fair Value | 25 | 23 |
Assets, Fair Value Disclosure | 57 | 72 |
Liabilities from price risk management activities: [Abstract] | ||
Electricity | 135 | 118 |
Natural gas | 75 | 51 |
Liabilities, Fair Value Disclosure | 210 | 169 |
Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Domestic government, Debt securities | 4 | 2 |
Corporate debt securities held in decommissioning trust assets | 0 | 0 |
Fair Value - Money market funds | 1 | 1 |
Domestic Equity Securities | 7 | 4 |
Debt securities - domestic government | 1 | 1 |
Electricity | 0 | 0 |
Natural gas | 0 | 0 |
Financial Instruments, Owned, at Fair Value | 13 | 8 |
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] | ||
Domestic government, Debt securities | 7 | 10 |
Corporate debt securities held in decommissioning trust assets | 6 | 8 |
Fair Value - Money market funds | 0 | 0 |
Domestic Equity Securities | 0 | 0 |
Debt securities - domestic government | 0 | 0 |
Electricity | 3 | 6 |
Natural gas | 3 | 15 |
Financial Instruments, Owned, at Fair Value | 19 | 39 |
Liabilities from price risk management activities: [Abstract] | ||
Electricity | 5 | 6 |
Natural gas | 66 | 42 |
Liabilities, Fair Value Disclosure | 71 | 48 |
Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Domestic government, Debt securities | 0 | 0 |
Corporate debt securities held in decommissioning trust assets | 0 | 0 |
Money market funds | 0 | |
Fair Value - Money market funds | 0 | |
Domestic Equity Securities | 0 | 0 |
Debt securities - domestic government | 0 | 0 |
Electricity | 0 | 1 |
Natural gas | 0 | 1 |
Financial Instruments, Owned, at Fair Value | 0 | 2 |
Liabilities from price risk management activities: [Abstract] | ||
Electricity | 130 | 112 |
Natural gas | 9 | 9 |
Liabilities, Fair Value Disclosure | 139 | 121 |
Non Qualified Benefit Plans [Member] | ||
Liabilities from price risk management activities: [Abstract] | ||
Insurance contracts, at cash surrender value | $ 28 | $ 26 |
Fair Value of FInancial Instr56
Fair Value of FInancial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Minimum [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | $ 7.79 | $ 14.25 |
Natural gas financial swaps | 1.26 | 1.85 |
Fnancial swaps - electricity | 7.79 | 8.57 |
Maximum [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | 41.23 | 54.73 |
Natural gas financial swaps | 2.92 | 4.92 |
Fnancial swaps - electricity | 29.74 | 33.60 |
Weighted Average [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | 30.95 | 38.18 |
Natural gas financial swaps | 1.90 | 2.64 |
Fnancial swaps - electricity | 21.74 | 25.10 |
Assets [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | 0 | 0 |
Natural gas financial swaps | 0 | 1,000,000 |
Fnancial swaps - electricity | 0 | 1,000,000 |
Total commodity contracts | 0 | 2,000,000 |
Liabilities [Member] | ||
Fair Value, Option, Quantitative Disclosures [Line Items] | ||
Electricity physical forward purchase | 130,000,000 | 112,000,000 |
Natural gas financial swaps | 9,000,000 | 9,000,000 |
Fnancial swaps - electricity | 0 | 0 |
Total commodity contracts | $ 139,000,000 | $ 121,000,000 |
Fair Value of FInancial Instr57
Fair Value of FInancial Instruments Fair Value Unobservable Input Reconciliation (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Net realized and unrealized losses | $ 35,000,000 | $ 11,000,000 | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3 | 0 | (1,000,000) | |
Net transfers out of Level 3 to Level 2 | (15,000,000) | (10,000,000) | |
Net liabilities from price risk management activities as of end of year | 139,000,000 | 119,000,000 | $ 119,000,000 |
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting | 41,000,000 | 11,000,000 | |
Net realized losses | $ 6,000,000 | $ 0 |
Fair Value of Financial Instr58
Fair Value of Financial Instruments (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Net realized losses | $ 6,000,000 | $ 0 |
Long-term Debt, Fair Value | 2,829,000,000 | 2,693,000,000 |
Long-term Debt | 2,436,000,000 | 2,361,000,000 |
Unamortized Debt Issuance Expense | 10,000,000 | 11,000,000 |
Defined Benefit Plan, Transfers Between Measurement Levels | 0 | 0 |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3 | 0 | 1,000,000 |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | 2,543,000,000 | |
Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Fair Value | 150,000,000 | |
Notes Payable to Banks [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt | $ 2,426,000,000 | $ 2,350,000,000 |
Fair values of price risk manag
Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets, Commodity Contracts: | ||
Electricity | $ 3 | $ 6 |
Natural Gas | 3 | 12 |
Total current derivative assets | 6 | 18 |
Noncurrent Assets, Commodity Contracts: [Abstract] | ||
Commodity Contract Asset, Noncurrent, Electricity | 0 | 1 |
Commodity Contract Asset, Noncurrent, Natural Gas | 0 | 4 |
Derivative Asset, Noncurrent | 0 | 5 |
Total derivative assets not designated as hedging instruments | 6 | 23 |
Total derivative assets | 6 | 23 |
Current Liabilities, Commodity Contracts: [Abstract] | ||
Electricity | 13 | 12 |
Natural Gas | 46 | 32 |
Total current derivative liabilities | 59 | 44 |
Noncurrent Liabilities, Commodity Contracts: [Abstract] | ||
Electricity | 122 | 106 |
Natural Gas | 29 | 19 |
Total noncurrent derivative liabilities | 151 | 125 |
Total derivative liabilities not designated as hedging instruments | 210 | 169 |
Total derivative liabilities | $ 210 | $ 169 |
Net volumes related to price ri
Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, CAD in Millions | Dec. 31, 2017CADMMBTUMWh | Dec. 31, 2016CADMMBTUMWh |
Commodity contracts: [Abstract] | ||
Electricity | MWh | 7 | 8 |
Natural gas | MMBTU | 114 | 107 |
Foreign currency exchange | CAD | CAD 21 | CAD 22 |
Net realized and unrealized gai
Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commodity contracts: [Abstract] | |||
Electricity | $ 41 | $ 34 | $ 72 |
Natural Gas | 85 | (56) | 103 |
Realized And Unrealized Losses Net Commodity Contracts, Foreign Currency | $ (1) | $ 0 | $ 1 |
Future year net unrealized gain
Future year net unrealized gain/loss recorded at balance sheet date expected to become realized (Details) $ in Millions | Dec. 31, 2017USD ($) |
Electricity [Member] | |
Commodity contracts: | |
Other Commitment, Due in Next Twelve Months | $ 10 |
Other Commitment, Due in Second Year | 8 |
Other Commitment, Due in Third Year | 8 |
Other Commitment, Due in Fourth Year | 8 |
Other Commitment, Due in Fifth Year | 7 |
Other Commitment, Due after Fifth Year | 91 |
Total | 132 |
Natural Gas [Member] | |
Commodity contracts: | |
Other Commitment, Due in Next Twelve Months | 43 |
Other Commitment, Due in Second Year | 20 |
Other Commitment, Due in Third Year | 7 |
Other Commitment, Due in Fourth Year | 2 |
Other Commitment, Due in Fifth Year | 0 |
Other Commitment, Due after Fifth Year | 0 |
Total | 72 |
Unrealized Gain Loss On Derivatives [Member] | |
Commodity contracts: | |
Other Commitment, Due in Next Twelve Months | 53 |
Other Commitment, Due in Second Year | 28 |
Other Commitment, Due in Third Year | 15 |
Other Commitment, Due in Fourth Year | 10 |
Other Commitment, Due in Fifth Year | 7 |
Other Commitment, Due after Fifth Year | 91 |
Total | $ 204 |
Counterparties representing 10%
Counterparties representing 10% or more (Details) | Dec. 31, 2017 | Dec. 31, 2016 |
Assets from price risk management activities: | ||
Counterparty A | 39.00% | 22.00% |
Counterparty B | 12.00% | 17.00% |
Counterparty C | 3.00% | 12.00% |
Concentration of Risk, Derivative Instruments, Assets | 54.00% | 51.00% |
Liabilities from price risk management activities: [Abstract] | ||
Counterparty D | 62.00% | 66.00% |
Concentration of Risk, Derivative Instruments, Liabilities | 62.00% | 66.00% |
Price Risk Management (Details)
Price Risk Management (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative [Line Items] | |||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $ 136 | $ 115 | |
Derivative, Collateral, Right to Reclaim Cash | 11 | 11 | |
Net gain or loss recognized in the statement of income offset by regulatory accounting | 82 | 13 | $ 160 |
Derivative, Net Liability Position, Aggregate Fair Value | 205 | ||
Collateral Already Posted, Aggregate Fair Value | 31 | ||
Collateral Aggregate Fair Value | 202 | ||
Margin Deposit Assets | 0 | ||
Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 130 | 112 | |
Natural Gas [Member] | |||
Derivative [Line Items] | |||
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $ 6 | $ 3 |
Regulatory Assets and Liabili65
Regulatory Assets and Liabilities Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulatory Assets [Line Items] | ||
Remaining Recovery Period of Regulatory Assets, Price Risk Management | 6 years | |
Regulatory Assets, Current | $ 62 | $ 36 |
Regulatory Assets, Noncurrent | 438 | 498 |
Regulatory Liability, Current | 31 | 51 |
Regulatory Liability, Noncurrent | $ 1,288 | 958 |
Remaining Recovery Period of Regulatory Asset, Debt Reacquisition Costs | 6 years | |
Remaining refund period of regulatory liability, Trojan decommissioning activities | 5Â years | |
Removal Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Liability, Current | $ 0 | 0 |
Regulatory Liability, Noncurrent | 933 | 887 |
Other Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Liability, Current | 28 | 33 |
Regulatory Liability, Noncurrent | 26 | 22 |
Asset Retirement Obligation Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Liability, Current | 0 | 0 |
Regulatory Liability, Noncurrent | 52 | 49 |
Environmental Restoration Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Liability, Current | 3 | 18 |
Regulatory Liability, Noncurrent | 0 | 0 |
Deferred Income Tax Charge [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Liability, Current | 0 | 0 |
Regulatory Liability, Noncurrent | 277 | 0 |
Other Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 9 | 10 |
Regulatory Assets, Noncurrent | 50 | 35 |
Loss on Reacquired Debt [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 0 | 0 |
Regulatory Assets, Noncurrent | 19 | 22 |
Deferred Derivative Gain (Loss) [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 53 | 26 |
Regulatory Assets, Noncurrent | 151 | 120 |
Pension and Other Postretirement Plans Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 0 | 0 |
Regulatory Assets, Noncurrent | 218 | 235 |
Deferred Income Tax Charge [Member] | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 0 | 0 |
Regulatory Assets, Noncurrent | $ 0 | $ 86 |
Regulatory Assets and Liabili66
Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | ||
Regulatory Assets Earning a Return, Other Category | $ 51 | $ 44 |
Regulatory Assets Earning a Return | 51 | |
Regulatory Assets Earning a Rate of Return at the Cost of Capital | $ 10 | |
Public Utilities, Approved Return on Equity, Percentage | 7.51% | |
Authorized Cost of Capital | 2.87% | |
Regulatory Assets Earning a Rate of Return by Inclusion in Rate Base | $ 14 | |
Regulatory Assets Earning a Rate of Return at the Approved Rate | $ 25 | |
Approved Rate for Deferred Account Under Amortization, Low End of Range | 1.47% | |
Approved Rate for Deferred Accounts under Amortization, High End of Range | 2.38% | |
Types of Net Regulatory Assets Earning Returns | $ 2 | |
Increase in net deferred tax regulatory liabilitily | $ 357 |
Schedule of Asset Retirement Ob
Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Asset Retirement Obligation Disclosure [Abstract] | ||||
Trojan decommissioning activities | $ 45 | $ 44 | ||
Utility plant | 109 | 105 | ||
Non-utility property | 13 | 12 | ||
Asset Retirement Obligation | $ 167 | $ 161 | $ 151 | $ 116 |
Schedule of Change in Asset Ret
Schedule of Change in Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |||
Asset Retirement Obligation | $ 161 | $ 151 | $ 116 |
Asset Retirement Obligation, Liabilities Incurred | 2 | 1 | 2 |
Asset Retirement Obligation, Liabilities Settled | (3) | (3) | (4) |
Asset Retirement Obligation, Accretion Expense | 7 | 7 | 7 |
Asset Retirement Obligation, Revision of Estimate | 0 | 5 | 30 |
Asset Retirement Obligation | $ 167 | $ 161 | $ 151 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Sep. 30, 2013 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Revision of Estimate | $ 0 | $ 5 | $ 30 | |
Asset Retirement Obligation, Accretion Expense | 7 | 7 | 7 | |
Asset Retirement Obligation, Liabilities Incurred | 2 | $ 1 | 2 | |
Litigation Settlement, Amount Awarded from Other Party | 85 | |||
Proceeds from Decommissioning Trust Fund Assets | 53 | |||
Loss Contingency, Damages Awarded, Value | $ 50 | |||
Customer Refund Liability, Current | 3 | |||
Asset Retirement Obligation, Period Increase (Decrease) | 6 | |||
Asset Retirement Obligations, Significant Changes | $ 17 | |||
Asset Retirement Obligation Rate Recovery related to Trojan Plant | 4 | |||
Utility Plant [Domain] | ||||
Asset Retirement Obligation, Revision of Estimate | 2 | |||
Asset Retirement Obligation, Accretion Expense | 7 | |||
Asset Retirement Obligation, Liabilities Incurred | $ 3 |
Credit Facilities Schedule of S
Credit Facilities Schedule of Short term debt (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Short-term Debt [Line Items] | |||
Average daily amount of short-term debt outstanding | $ 0 | $ 1 | $ 0 |
Weighted daily average interest rate | 0.00% | 0.70% | 0.60% |
Maximum amount outstanding during the year | $ 0 | $ 23 | $ 11 |
Credit Facilities (Details)
Credit Facilities (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Line of Credit Facility [Abstract] | |
Line of Credit Facility, Maximum Borrowing Capacity | $ 500 |
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 | .65 |
Ratio of Indebtedness to Net Capital | 0.518 |
Commercial Paper, Maximum Term | 270 |
Commercial Paper | $ 0 |
FERC Authorized Short-term Debt, effective through February 6, 2014 | 900 |
Line of Credit Facility, Amount Outstanding | 0 |
Line of Credit Facility, Remaining Borrowing Capacity | 500 |
letter of credit facility | 220 |
Letters of Credit Outstanding, Amount | $ 67 |
Long-term Debt Schedule of Long
Long-term Debt Schedule of Long Term Debt Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
First Mortgage Bonds, rates range from 2.51% to 9.31%, with a weighted average rate of 5.03% in 2017 and 4.86% in 2016, due at various dates through 2048 | $ 2,315 | $ 2,090 |
Unsecured term bank loans, variable rates of approximately 1.87% at 11/27/2017 and 1.37% at 12/31/2016 | 0 | 150 |
Pollution Control Revenue Bonds, 5% rate, due 2033 | 142 | 142 |
Pollution Control Revenue Bonds owned by PGE | (21) | (21) |
Debt Instrument, Unamortized Discount | (10) | (11) |
Total long-term debt | 2,436 | 2,361 |
Less: current portion of long-term debt | 0 | (150) |
Long-term debt, net of current portion | $ 2,426 | $ 2,200 |
Long-term Debt Schedule of Matu
Long-term Debt Schedule of Maturities of Long term debt (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Long-term Debt, Unclassified [Abstract] | ||
2,018 | $ 0 | |
2,019 | 300 | |
2,020 | 0 | |
2,021 | 160 | |
2,022 | 0 | |
Thereafter | 1,976 | |
Total long-term debt | $ 2,436 | $ 2,361 |
Long term debt (Details)
Long term debt (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||||||
Aug. 31, 2017 | Jan. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Nov. 27, 2017 | Oct. 30, 2017 | Aug. 21, 2017 | |
Debt Instrument [Line Items] | ||||||||
Proceeds from Issuance of First Mortgage Bond | $ 225 | |||||||
Repayments of Debt | 150 | |||||||
Debt Instrument, Face Amount | $ 75 | $ 25 | $ 50 | |||||
Long-term Pollution Control Bond | $ 21 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.98% | |||||||
Proceeds from Issuance of Long-term Debt | $ 75 | $ 150 | $ 225 | $ 290 | $ 145 | |||
First mortgage Bonds - minimum rate | 2.51% | |||||||
Unsecured Debt, Current | $ 0 | $ 150 | ||||||
First Mortgage Bonds - maximum rate | 9.31% | |||||||
Debt, Weighted Average Interest Rate | 5.03% | 4.86% | ||||||
Line of Credit Facility, Interest Rate During Period | 1.37% | |||||||
Line of Credit Facility, Interest Rate at Period End | 1.87% | 5.00% | ||||||
Line of Credit Facility, Commitment Fee Percentage | 0.00% | |||||||
Pollution Control Revenue Bonds owned by PGE | $ 21 | $ 21 |
Employee Benefits Assets and Li
Employee Benefits Assets and Liabilities associated with Non-qualified benefit plans (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-qualified benefit plan trust | $ 37 | $ 34 |
Non-qualified benefit plan liabilities | 106 | 105 |
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 | 20 | 18 |
Non-qualified benefit plan liabilities | 81 | 80 |
Non Qualified Benefit Plans [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-qualified benefit plan trust | 17 | 16 |
Non-qualified benefit plan liabilities | $ 25 | $ 25 |
Employee Benefits Schedule of A
Employee Benefits Schedule of Allocation of Plan Assets (Details) | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Pension Plan [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 100.00% | 100.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% |
Defined Benefit Pension Plan [Member] | Equity Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 67.00% | 67.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 68.00% | 68.00% |
Defined Benefit Pension Plan [Member] | Debt Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 33.00% | 33.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 32.00% | 32.00% |
Other Postretirement Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 100.00% | 100.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% |
Other Postretirement Benefit Plans [Member] | Equity Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 62.00% | 62.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 63.00% | 60.00% |
Other Postretirement Benefit Plans [Member] | Debt Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 38.00% | 38.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 37.00% | 40.00% |
Non Qualified Benefit Plans [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 100.00% | 100.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% |
Non Qualified Benefit Plans [Member] | Equity Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 12.00% | 11.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 18.00% | 15.00% |
Non Qualified Benefit Plans [Member] | Debt Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 12.00% | 11.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 6.00% | 7.00% |
Non Qualified Benefit Plans [Member] | Other Contract [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 76.00% | 78.00% |
Defined Benefit Plan, Actual Plan Asset Allocations | 76.00% | 78.00% |
Employee Benefits Schedule of F
Employee Benefits Schedule of Fair Value, Assets (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | |||
Money Market Funds, at Carrying Value | $ 25 | $ 21 | |
Investments, Fair Value Disclosure | 0 | 2 | |
Equity securities: | |||
Domestic | 83 | 52 | |
Defined Benefit Plan, Fair Value of Plan Assets | 559 | ||
Financial Instruments, Owned, at Fair Value | 25 | 23 | |
Other Postretirement Benefit Plans assets: [Abstract] | |||
Money market funds | 4 | ||
Domestic equity securities - Other postretirement benefit plan assets at fair value | 3 | ||
International equity securities - other post retirement assets at fair value | 8 | ||
Private Equity Funds, Domestic [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Money Market Funds, at Carrying Value | 5 | 6 | |
Investments, Fair Value Disclosure | 13 | 18 | |
Equity Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Investments, Fair Value Disclosure | 528 | 483 | |
Fair Value, Inputs, Level 1 [Member] | |||
Equity securities: | |||
Domestic | 83 | 52 | |
Private equity funds | 0 | 0 | |
Defined Benefit Plan, Fair Value of Plan Assets | 83 | 52 | |
Financial Instruments, Owned, at Fair Value | 13 | 8 | |
Other Postretirement Benefit Plans assets: [Abstract] | |||
Money market funds | 3 | 4 | |
Domestic equity securities - Other postretirement benefit plan assets at fair value | 0 | 0 | |
International equity securities - other post retirement assets at fair value | 10 | 8 | |
Other post retirement benefit plan assets total | 13 | 12 | |
Fair Value, Inputs, Level 2 [Member] | |||
Equity securities: | |||
Domestic | 0 | 0 | |
Private equity funds | 0 | 0 | |
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Financial Instruments, Owned, at Fair Value | 19 | 39 | |
Other Postretirement Benefit Plans assets: [Abstract] | |||
Money market funds | 0 | 0 | |
Domestic equity securities - Other postretirement benefit plan assets at fair value | 3 | 3 | |
International equity securities - other post retirement assets at fair value | 0 | 0 | |
Other post retirement benefit plan assets total | 8 | 7 | |
Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Money Market Funds, at Carrying Value | 0 | ||
Equity securities: | |||
Domestic | 0 | 0 | |
Private equity funds | 0 | 0 | |
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Financial Instruments, Owned, at Fair Value | 0 | 2 | |
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 | |
Other post retirement benefit plan assets total | 0 | 0 | |
Pension Plan [Member] | |||
Equity securities: | |||
Defined Benefit Plan, Fair Value of Plan Assets | 629 | 559 | $ 550 |
Financial Instruments, Owned, at Fair Value | 546 | 507 | |
Other Postretirement Benefit Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Money Market Funds, at Carrying Value | 4 | 4 | |
Investments, Fair Value Disclosure | 8 | 7 | |
Equity securities: | |||
Defined Benefit Plan, Fair Value of Plan Assets | 33 | 30 | $ 30 |
Financial Instruments, Owned, at Fair Value | 12 | $ 11 | |
Other Postretirement Benefit Plans assets: [Abstract] | |||
Money market funds | 3 | ||
Domestic equity securities - Other postretirement benefit plan assets at fair value | 3 | ||
International equity securities - other post retirement assets at fair value | $ 10 |
Employee Benefits Schedule of C
Employee Benefits Schedule of Changes in Fair Value of Plan Assets (Details) $ in Millions | Dec. 31, 2016USD ($) |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Defined Benefit Plan, Fair Value of Plan Assets | $ 559 |
Employee Benefits Schedule of D
Employee Benefits Schedule of Defined Benefit Plan Disclosures (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets | $ 5 | $ 4 | |
Fair value of plan assets: | |||
Interest cost on benefit obligation | 3 | ||
As of January 1 | 559 | ||
Classification in consolidated balance sheet: | |||
Noncurrent asset | (37) | (34) | |
Noncurrent liability | (284) | (281) | |
Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets | 0 | 0 | |
Fair value of plan assets: | |||
As of January 1 | 0 | 0 | |
Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets | 0 | 0 | |
Fair value of plan assets: | |||
As of January 1 | 83 | 52 | |
Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets | 5 | 4 | |
Fair value of plan assets: | |||
As of January 1 | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | |||
Benefit obligation: | |||
As of January 1 | 869 | 797 | $ 758 |
Fair value of plan assets: | |||
Service cost | 17 | 16 | 18 |
Interest cost on benefit obligation | 33 | 33 | 31 |
Participants’ contributions | 0 | 0 | |
Actuarial loss (gain) | 60 | 26 | |
Defined Benefit Plan, Benefit Obligation, Special and Contractual Termination Benefits | 0 | 0 | |
Benefit payments | (36) | (34) | |
Defined Benefit Plan, Plan Assets, Administration Expense | (2) | (2) | |
As of January 1 | 629 | 559 | 550 |
Unfunded position as of December 31 | 240 | 238 | |
Net actuarial loss (gain) included in comprehensive income | (4) | 21 | |
Defined Benefit Plan, Amortization of Gain (Loss) | (13) | (14) | (20) |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0 | 0 | 0 |
Total Amounts included in comprehensive income | (17) | 7 | |
Defined Benefit Plan, Accumulated Benefit Obligation | 778 | 714 | |
Actual return on plan assets | 106 | 45 | |
Company contributions | 2 | 0 | |
Classification in consolidated balance sheet: | |||
Noncurrent asset | 0 | 0 | |
Current liability | 0 | 0 | |
Noncurrent liability | (240) | (238) | |
Amounts included in AOCL: | |||
Net actuarial loss | 218 | 236 | |
Prior service cost | 0 | 0 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | $ 218 | $ 236 | |
Assumptions used: | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate | 3.65% | 4.17% | |
Discount rate used to calculate benefit obligation | 4.17% | 4.36% | |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Rate of Compensation Increase | 4.58% | 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 Rate of Return on Plan Assets | 7.50% | 7.50% | |
Other Postretirement Benefit Plans [Member] | |||
Benefit obligation: | |||
As of January 1 | $ 78 | $ 73 | 81 |
Fair value of plan assets: | |||
Service cost | 2 | 2 | 2 |
Interest cost on benefit obligation | 3 | 4 | 3 |
Participants’ contributions | 2 | 2 | |
Actuarial loss (gain) | 3 | (11) | |
Defined Benefit Plan, Benefit Obligation, Special and Contractual Termination Benefits | 1 | 0 | |
Benefit payments | (6) | (5) | |
Defined Benefit Plan, Plan Assets, Administration Expense | 0 | 0 | |
As of January 1 | 33 | 30 | 30 |
Unfunded position as of December 31 | 45 | 43 | |
Net actuarial loss (gain) included in comprehensive income | 0 | (10) | |
Defined Benefit Plan, Amortization of Gain (Loss) | 0 | 0 | (1) |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0 | (1) | (1) |
Total Amounts included in comprehensive income | 0 | (11) | |
Actual return on plan assets | 4 | 1 | |
Company contributions | 3 | 2 | |
Classification in consolidated balance sheet: | |||
Noncurrent asset | 0 | 0 | |
Current liability | 0 | 0 | |
Noncurrent liability | (45) | (43) | |
Amounts included in AOCL: | |||
Net actuarial loss | (1) | (2) | |
Prior service cost | 0 | 1 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | $ (1) | $ (1) | |
Assumptions used: | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate | 3.42% | 3.75% | |
Defined Benefit Plan Discount rate - upper range | 3.70% | 4.23% | |
Discount rate used to calculate benefit obligation | 3.75% | 3.90% | |
Defined Benefit Plan Cost Discount rate - upper range | 4.23% | 4.45% | |
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 | 6.26% | 6.26% | |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets | 6.26% | 6.29% | |
Non Qualified Benefit Plans [Member] | |||
Benefit obligation: | |||
As of January 1 | $ 27 | $ 27 | 27 |
Fair value of plan assets: | |||
Service cost | 0 | 0 | 0 |
Interest cost on benefit obligation | 1 | 1 | 1 |
Participants’ contributions | 0 | 0 | |
Actuarial loss (gain) | 1 | 1 | |
Defined Benefit Plan, Benefit Obligation, Special and Contractual Termination Benefits | 0 | 0 | |
Benefit payments | (2) | (2) | |
Defined Benefit Plan, Plan Assets, Administration Expense | 0 | 0 | |
As of January 1 | 17 | 16 | 15 |
Unfunded position as of December 31 | 10 | 11 | |
Net actuarial loss (gain) included in comprehensive income | 1 | 1 | |
Defined Benefit Plan, Amortization of Gain (Loss) | (1) | (1) | (1) |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0 | 0 | $ 0 |
Total Amounts included in comprehensive income | 0 | 0 | |
Defined Benefit Plan, Accumulated Benefit Obligation | 27 | 27 | |
Actual return on plan assets | 1 | 1 | |
Company contributions | 2 | 2 | |
Classification in consolidated balance sheet: | |||
Noncurrent asset | (17) | (16) | |
Current liability | (2) | (2) | |
Noncurrent liability | (25) | (25) | |
Amounts included in AOCL: | |||
Net actuarial loss | 13 | 13 | |
Prior service cost | 0 | 0 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | $ 13 | $ 13 | |
Assumptions used: | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate | 3.65% | 4.17% | |
Discount rate used to calculate benefit obligation | 4.17% | 4.36% |
Employee Benefits Schedule of N
Employee Benefits Schedule of Net Benefit Costs (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Interest cost on benefit obligation | $ 3 | ||
Other Postretirement Benefit Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 2 | $ 2 | $ 2 |
Interest cost on benefit obligation | 3 | 4 | 3 |
Expected return on plan assets | (2) | (2) | (2) |
Amortization of prior service cost | 0 | 1 | 1 |
Amortization of net actuarial loss | 0 | 0 | 1 |
Net periodic benefit cost | 3 | 5 | 5 |
Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 17 | 16 | 18 |
Interest cost on benefit obligation | 33 | 33 | 31 |
Expected return on plan assets | (42) | (40) | (40) |
Amortization of prior service cost | 0 | 0 | 0 |
Amortization of net actuarial loss | 13 | 14 | 20 |
Net periodic benefit cost | 21 | 23 | 29 |
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 E
Employee Benefits Schedule of Expected Benefit Payments (Details) $ in Millions | Dec. 31, 2017USD ($) |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | $ 46 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 49 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 49 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 49 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 51 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 266 |
Pension Plans, Defined Benefit [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | 39 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 41 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 42 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 43 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 44 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 234 |
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 | 4 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 5 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 22 |
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 | 3 |
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 | 2 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | $ 10 |
Employee Benefits (Details)
Employee Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Payment for Pension Benefits | $ 2 | $ 0 | $ 0 |
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year | 21 | ||
OtherPostretirementDefinedBenefitPlanLiabilityCurrent | 2 | $ 2 | |
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year | 18 | ||
Net actuarial loss portion of amortization from AOCL for pension benefits | 17 | ||
Net Actuarial Loss Portion of Amortization from AOCL for Non-qualified benefits | $ 1 | ||
Defined benefit plan, current annual rate of health care cost increase | 6.50% | 7.00% | 6.50% |
Defined Benefit Plan, Assumed Health Care Cost Trend Rate, Description | 0.06 | 0.065 | 0.06 |
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year | 0.25% | 0.25% | 0.25% |
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 | ||
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 | $ 21 | $ 19 | $ 17 |
Income Taxes Schedule of Compon
Income Taxes Schedule of Components of Income Tax Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Current: | |||
Federal | $ 4 | $ 10 | $ 4 |
State and local | 12 | 3 | 1 |
Current Income Tax Expense (Benefit) | 16 | 13 | 5 |
Deferred: | |||
Federal | 61 | 23 | 26 |
State and local | 9 | 14 | 14 |
deferred income tax expense | 70 | 37 | 40 |
Income tax expense | $ 86 | $ 50 | $ 45 |
Income Taxes Schedule of Effect
Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes [Abstract] | |||
Federal statutory tax rate | 35.00% | 35.00% | 35.00% |
Federal tax credits | (14.00%) | (18.20%) | (19.00%) |
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent | 6.10% | 0.00% | 0.00% |
State and local taxes, net of federal tax benefit | 5.00% | 4.80% | 4.20% |
Flow through depreciation and cost basis differences | 1.50% | 0.20% | 0.00% |
Other | (2.10%) | (1.20%) | 0.50% |
Effective tax rate | 31.50% | 20.60% | 20.70% |
Income Taxes Schedule of Deferr
Income Taxes Schedule of Deferred tax Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred income tax assets: | ||
Employee benefits | $ 128 | $ 181 |
Price risk management | 56 | 59 |
Deferred income taxes | 14 | 29 |
Deferred Tax Assets, tax credits, net of valuation allowance | 50 | 56 |
Deferred Tax Assets, Tax Deferred Expense, Other | 4 | 5 |
Total deferred income tax assets | 252 | 330 |
Deferred income tax liabilities: | ||
Depreciation and amortization | 496 | 829 |
Regulatory assets | 132 | 170 |
Deferred Tax Liabilities, Other | 0 | 0 |
Deferred Tax Liabilities, Gross, Noncurrent | 628 | 999 |
Total deferred income tax liabilities | $ (376) | $ (669) |
Income Taxes Income taxes (Deta
Income Taxes Income taxes (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Operating Loss Carryforwards [Line Items] | ||
Deferred Tax Liabilities, Regulatory Assets and Liabilities | $ 340 | |
Increase in net deferred tax regulatory liabilitily | 357 | |
Tax Credit Carryforward, Federal | 50 | |
Deferred Tax Assets, Valuation Allowance | 0 | $ 0 |
Unrecognized Tax Benefits | 0 | $ 0 |
Income Tax Expense (Benefit), Continuing Operations, Adjustment of Deferred Tax (Asset) Liability | $ 17 |
Equity-Based Plans (Details)
Equity-Based Plans (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||
Jun. 30, 2015 | Sep. 30, 2013 | Jun. 30, 2013 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2013 | |
stock offering | 10,400,000 | 11,100,000 | 700,000 | ||||
Proceeds from Issuance of Common Stock | $ 271,000,000 | $ 20,000,000 | $ 0 | $ 0 | $ 271,000,000 | ||
employee stock purchase plan shares authorized | 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 | 339,542 | ||||||
Dividend Reinvestment and Direct Stock Purchase Plan Shares | 2,500,000 | ||||||
Dividend Reinvestment and Direct Stock Purchase Plan, Number of Available Shares | 2,470,052 |
Stock-based Compensation Expe88
Stock-based Compensation Expense Restricted and Performance Stock Unit Activity (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract] | |||
Outstanding, Units | 458,792 | 442,993 | 463,893 |
Outstanding, Weighted Average Grant Date Fair Value | $ 34.68 | $ 32.84 | $ 28.96 |
Granted, Units | 202,145 | 193,734 | 181,797 |
Granted, Weighted Average Grant Date Fair Value | $ 41.96 | $ 35.89 | $ 34.77 |
Forfeited, Units | (64,840) | (3,044) | (14,988) |
Forfeited, Weighted Average Grant Date Fair Value | $ 39.57 | $ 28.62 | $ 34.10 |
Vested, Units | (196,721) | (174,891) | (187,709) |
Vested, Weighted Average Grant Date Fair Value | $ 31.78 | $ 31.47 | $ 25.82 |
Outstanding, Units | 399,376 | 458,792 | 442,993 |
Outstanding, Weighted Average Grant Date Fair Value | $ 37.98 | $ 34.68 | $ 32.84 |
Stock-based Compensation Expe89
Stock-based Compensation Expense Schedule Of Share Based Payment Award Stock Options Valuation Assumptions (Details) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
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 | 1.50% | 0.90% |
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 | 15.60% | 14.50% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum | 22.90% | 25.90% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | 0.00% | 0.00% |
Stock-based Compensation Expe90
Stock-based Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based Compensation | $ 7 | $ 6 | $ 6 | ||
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 | 3,229,476 | ||||
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 | 6 | 5 | 4 | ||
Adjustments Related to Tax Withholding for Share-based Compensation | 3 | $ 2 | $ 0 | ||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 7 | ||||
Stock-based Compensation, Attainment of Performance Goals That Allows Vesting | 107.00% | 120.80% | 118.20% | ||
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 | $ 5 |
Earnings Per Share Schedule of
Earnings Per Share Schedule of Earnings per Share, Basic and Diluted (Details) - shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||
Weighted Average Number of Shares Outstanding, Basic | 89,056 | 88,896 | 84,180 |
Weighted Average Number Diluted Shares Outstanding Adjustment | 120 | 158 | 161 |
Weighted Average Number of Shares Outstanding, Diluted | 89,176 | 89,054 | 84,341 |
Earnings Per Share Earnings Per
Earnings Per Share Earnings Per Share (Details) - shares | 3 Months Ended | 12 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2013 | Dec. 31, 2013 | |
Earnings Per Share [Abstract] | |||
stock offering | 10,400,000 | 11,100,000 | 700,000 |
Commitments and Guarantees Unre
Commitments and Guarantees Unrecorded Unconditional Purchase Obligations (Details) $ in Millions | Dec. 31, 2017USD ($) |
Capital Addition Purchase Commitments [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | $ 265 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 191 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 2 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 10 |
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 | 58 |
Long-term Contract for Purchase of Electric Power [Domain] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 2,633 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 156 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 156 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 201 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 200 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 187 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 1,733 |
Electric Transmission [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 31 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 6 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 5 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 4 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 4 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 4 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 8 |
Public Utility Districts [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 158 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 9 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 17 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 16 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 16 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 15 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 85 |
Natural gas [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 303 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 51 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 35 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 28 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 25 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 24 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 140 |
Coal and transportationSupply Agreements [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 20 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 15 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 5 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 0 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 0 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 0 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 0 |
Commitments [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Unrecorded Unconditional Purchase Obligation | 3,410 |
Unrecorded Unconditional Purchase Obligation, Due within One Year | 428 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 220 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 259 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 247 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 232 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | $ 2,024 |
Commitments and Guarantees Schd
Commitments and Guarantees Schdule of Long term contracts for purchase of electric power (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)MW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Priest Rapids and Wanapum [Member] | |||
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Revenue Bonds issued by the Public Utility Districts | $ 1,269 | ||
PGE Share of Output | 8.60% | ||
PGE Share of Capacity | MW | 163 | ||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Dec. 31, 2052 | ||
commitment costs | $ 16 | $ 16 | $ 18 |
Wells [Member] | |||
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Revenue Bonds issued by the Public Utility Districts | $ 160 | ||
PGE Share of Output | 19.40% | ||
PGE Share of Capacity | MW | 150 | ||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Aug. 31, 2018 | ||
commitment costs | $ 11 | 10 | 10 |
Portland Hydro [Member] | |||
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Revenue Bonds issued by the Public Utility Districts | $ 0 | ||
PGE Share of Output | 0.00% | ||
PGE Share of Capacity | MW | 0 | ||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Jun. 30, 2017 | ||
commitment costs | $ 1 | $ 1 | $ 2 |
Commitments and Guarantees Leas
Commitments and Guarantees Lease Obligations (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Long-term Purchase Commitment [Line Items] | ||||
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals | $ 4 | |||
Operating Leases, Rent Expense, Sublease Rentals | 4 | $ 4 | $ 3 | |
Capital Leases, Future Minimum Payments Due, Next Twelve Months | 7 | |||
Contractual Obligation, Due in Next Fiscal Year | 0 | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 9 | |||
Capital Leases, Future Minimum Payments Due in Two Years | 6 | |||
Contractual Obligation, Due in Second Year | 15 | |||
Operating Leases, Future Minimum Payments, Due in Two Years | 8 | |||
Capital Leases, Future Minimum Payments Due in Three Years | 6 | |||
Contractual Obligation, Due in Third Year | 15 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 6 | |||
Capital Leases, Future Minimum Payments Due in Four Years | 6 | |||
Contractual Obligation, Due in Fourth Year | 14 | |||
Operating Leases, Future Minimum Payments, Due in Four Years | 6 | |||
Capital Leases, Future Minimum Payments Due in Five Years | 5 | |||
Contractual Obligation, Due in Fifth Year | 14 | |||
Operating Leases, Future Minimum Payments, Due in Five Years | 8 | |||
Capital Leases, Future Minimum Payments Due Thereafter | 72 | |||
Contractual Obligation, Due after Fifth Year | 260 | |||
Operating Leases, Future Minimum Payments, Due Thereafter | 165 | |||
Capital Leases, Future Minimum Payments Due | 102 | |||
Contractual Obligation | 318 | |||
Operating Leases, Future Minimum Payments Due | 202 | |||
Capital Leases, Future Minimum Payments, Interest Included in Payments | 51 | |||
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments | 51 | |||
Deferred Costs, Leasing, Accumulated Amortization | $ 2 | 3 | 1 | |
Interest Expense, Lessee, Assets under Capital Lease | $ 3 | $ 4 | $ 2 |
Commitments and Guarantees (Det
Commitments and Guarantees (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
percentage of output | 25.00% | |||
Capital Leased Assets, Gross | $ 57 | |||
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation | 6 | |||
Capital Lease Obligations, Current | 2 | |||
Purchase Commitment, Remaining Minimum Amount Committed | 49 | |||
Deferred Costs, Leasing, Accumulated Amortization | $ 2 | 3 | $ 1 | |
Interest Expense, Lessee, Assets under Capital Lease | $ 3 | 4 | 2 | |
Long-term Purchase Commitment, Amount | 132 | |||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | 12 | |||
Operating Leases, Rent Expense | 9 | 10 | $ 0 | |
Operating Leases, Future Minimum Payments Receivable, in Two Years | 3 | |||
Operating Leases, Future Minimum Payments, Due in Three Years | 3 | |||
Operating Leases, Future Minimum Payments Receivable, in Five Years | 2 | |||
Contractual Obligation | 318 | |||
Operating Leases, Rent Expense, Sublease Rentals | 4 | 4 | $ 3 | |
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Three Years | 3 | |||
Capital Addition Purchase Commitments [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | $ 108 | $ 21 |
Jointly-owned Plant Schedule of
Jointly-owned Plant Schedule of Jointly-owned plant (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Jointly Owned Utility Plant Interests [Line Items] | |
Jointly Owned Utility Plant, Proportionate Ownership Share of Boardman | 90.00% |
Jointly Owned Plant, Boardman Plant In Service Year | 1,980 |
Jointly Owned Utility Plant, Gross Ownership Amount of Boardman Plant In Service | $ 515 |
Jointly Owned Utility Plant, Ownership Amount of Boardman Plant Accumulated Depreciation | 426 |
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 | 1,986 |
Jointly Owned Utility Plant, Gross Ownership Amount of Colstrip Plant In Service | $ 546 |
Jointly Owned Utility Plant, Ownership Amount of Colstrip Plant Accumulated Depreciation | 351 |
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Colstrip | $ 5 |
Jointly Owned Utility Plant, Proportionate Ownership Share of Pelton/Round Butte | 66.67% |
Jointly Owned Plant, Pelton Plant in Service Year | 1,958 |
Jointly Owned Plant, Round Butte in Service Year | 1,964 |
Jointly Owned Utility Plant, Gross Ownership Amount of Pelton/Round Butte Plant In Service | $ 251 |
Jointly Owned Utility Plant, Ownership Amount of Pelton/Round Butte Plant Accumulated Depreciation | 68 |
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Pelton/Round Butte | 7 |
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service | 1,312 |
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | 845 |
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | $ 12 |
Contingencies (Details)
Contingencies (Details) - USD ($) $ in Millions | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 1997 | Dec. 31, 2016 | Sep. 30, 2008 | Dec. 31, 1993 | |
Loss Contingencies [Line Items] | ||||||
Malpractice Loss Contingency, Letters of Credit and Surety Bonds | $ 145.6 | |||||
Long-term Purchase Commitment, Amount | $ 200 | |||||
Loss Contingency, Damages Sought, Value | 1,200 | |||||
Liability for Title Claims and Claims Adjustment Expense | $ 8 | |||||
Site Contingency, Names of Other Potentially Responsible Parties | 100 | 69 | ||||
Litigation Settlement, Expense | $ 115 | |||||
Loss Contingency, Range of Possible Loss, Maximum | 1,700 | |||||
Loss Contingency, Range of Possible Loss, Portion Not Accrued | 500 | |||||
Loss Contingency, Inestimable Loss | 1,100 | |||||
investment in Trojan | 87.00% | |||||
Class action damages sought | 260 | |||||
Refund to customers for Trojan Investment including interest | $ 33 | |||||
Public Utilities, Property, Plant and Equipment, Amount of Construction Work in Process Included in Rate Base | 514 | |||||
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment | 637 | |||||
Loss Contingency, Accrual, Current | $ 14 | $ 3 | ||||
Minimum [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Loss Contingency, Damages Sought, Value | 44 | |||||
Maximum [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Loss Contingency, Damages Sought, Value | $ 117 |