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DEI Document - USD ($)	12 Months Ended
DEI Document - USD ($)	Dec. 31, 2016	Feb. 03, 2017	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	PORTLAND GENERAL ELECTRIC CO /OR/
Entity Central Index Key	0000784977
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
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		88,946,932
Entity Public Float			$ 3,905,668,556
Trading Symbol	POR

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues, net	$ 1,923	$ 1,898	$ 1,900
Operating expenses:
Purchased power and fuel	617	661	713
Generation, transmission and distribution	286	266	257
Administrative and other	247	241	227
Depreciation and amortization	321	305	301
Taxes other than income taxes	119	116	109
Total operating expenses	1,590	1,589	1,607
Income from operations	333	309	293
Interest expense, net	112	114	96
Other income:
Allowance for equity funds used during construction	21	21	37
Miscellaneous income, net	1	1	1
Other income, net	22	22	38
Income before income taxes	243	217	235
Income tax expense	50	45	61
Net income	193	172	174
Less: net loss attributable to noncontrolling interest	0	0	(1)
Net income attributable to Portland General Electric Company	$ 193	$ 172	$ 175
Weighted-average shares outstanding (in thousands):
Basic	88,896	84,180	78,180
Diluted	89,054	84,341	80,494
Earnings per share:
Basic	$ 2.17	$ 2.05	$ 2.24
Diluted	$ 2.16	$ 2.04	$ 2.18

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net income	$ 193	$ 172	$ 174
Other comprehensive income (loss) - Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2016 and 2015, and $2 in 2014	1	(1)	(2)
Comprehensive income	194	171	172
Less: comprehensive loss attributable to the noncontrolling interests	0	0	1
Comprehensive income attributable to Portland General Electric Company	$ 194	$ 171	$ 173

Consolidated Statements of Comprehensive Income Consolidated Statement of Comprehensive Income Parentheticals $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($)
Net Taxes on change in compensation retirement benefits liability and amortization	$ 2

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 6	$ 4
Accounts receivable, net	155	158
Unbilled revenues	107	95
Inventories, at average cost:
Materials and supplies	50	44
Fuel	32	39
Regulatory assets--current	36	129
Other current assets	77	88
Total current assets	463	557
Electric utility plant:
Generation	4,597	3,898
Transmission	521	451
Distribution	3,343	3,192
General	501	463
Intangible	572	556
Construction work-in-progress	213	545
Total electric utility plant	9,747	9,105
Accumulated depreciation and amortization	(3,313)	(3,093)
Electric utility plant, net	6,434	6,012
Regulatory assets--noncurrent	498	524
Nuclear decommissioning trust	41	40
Non-qualified benefit plan trust	34	33
Other noncurrent assets	57	44
Total assets	7,527	7,210
Current liabilities:
Accounts payable	129	98
Liabilities from price risk management activities-current	44	130
Short-term debt	0	6
Current portion of long-term debt	150	133
Accrued expenses and other current liabilities	254	259
Total current liabilities	577	626
Long-term debt, net of current portion	2,200	2,060
Regulatory liabilities--noncurrent	958	928
Deferred income taxes	669	632
Unfunded status of pension and postretirement plans	281	259
Liabilities from price risk management activities--noncurrent	125	161
Asset retirement obligations	161	151
Non-qualified benefit plan liabilities	105	106
Other noncurrent liabilities	107	29
Total liabilities	5,183	4,952
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; 88,946,704 and 88,792,751 shares issued and outstanding as of December 31, 2016 and 2015, respectively	1,201	1,196
Accumulated other comprehensive loss	(7)	(8)
Retained earnings	1,150	1,070
Total equity	2,344	2,258
Total liabilities and equity	$ 7,527	$ 7,210

Consolidated Balance Sheets Consolidated Balance Sheet Parentheticals - $ / shares	Dec. 31, 2016	Dec. 31, 2015
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	88,946,704	88,792,751
Common Stock, Shares, Outstanding	88,946,704	88,792,751

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Common Stock Shares	Common Stock Amount	Accumulated Other Comprehensive Loss	Retained Earnings	Noncontrolling Interests' Equity
Balance, shares at Dec. 31, 2013		78,085,559
Balance at Dec. 31, 2013			$ 911	$ (5)	$ 913	$ 1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		142,780
Proceeds from issuance of shares pursuant to equity-based plans			1
Stock-based compensation			6	0	0	0
Dividends declared			0	0	(88)	0
Net income (loss)	$ 174		0	0	175	(1)
Other comprehensive income (loss)			0	(2)	0	0
Balance, shares at Dec. 31, 2014		78,228,339
Balance at Dec. 31, 2014			918	(7)	1,000	0
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
Shares issued pursuant to equity-based plans		164,412
Proceeds from issuance of shares pursuant to equity-based plans			1
Stock-based compensation			6	0	0	0
Dividends declared			0	0	(102)	0
Net income (loss)	172		0	0	172	0
Other comprehensive income (loss)			0	(1)	0	0
Balance, shares at Dec. 31, 2015		88,792,751
Balance at Dec. 31, 2015	2,258		1,196	(8)	1,070	0
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
Stock-based compensation			4	0	0	0
Dividends declared			0	0	(113)	0
Net income (loss)	193		0	0	193	0
Other comprehensive income (loss)			0	1	0	0
Balance, shares at Dec. 31, 2016		88,946,704
Balance at Dec. 31, 2016	$ 2,344		$ 1,201	$ (7)	$ 1,150	$ 0

Consolidated Statements of Equity Consolidated Statement of Equity Parenthetical - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Issuance costs		$ 12
Common Stock, Dividends, Per Share, Declared	$ 1.260	$ 1.180	$ 1.115

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income	$ 193	$ 172	$ 174
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	321	305	301
Deferred income taxes	37	40	39
Allowance for equity funds used during construction	(21)	(21)	(37)
Pension and other postretirement benefits	28	34	33
Regulatory deferral of settled derivative instruments	2	2	10
Unrealized losses on non-qualified benefit plan trust assets	5	6	7
Decoupling mechanism deferrals, net of amortization	(6)	14	6
Other non-cash income and expenses, net	5	20	14
Changes in working capital:
(Increase) decrease in receivables and unbilled revenues	(9)	(11)	8
Decrease (increase) in margin deposits	25	(22)	(2)
Increase (decrease) in payables and accrued liabilities	15	6	(13)
Other working capital items, net	(4)	(4)	(12)
Cash received to be returned to customers pursuant to the Residential Exchange Program, net of amortization	(6)	(1)	13
Contribution to non-qualified employee benefit trust	(10)	(9)	(8)
Contribution to voluntary employees’ benefit association trust	(2)	(4)	(3)
Other, net	(20)	(7)	(10)
Net cash provided by operating activities	553	520	520
Cash flows from investing activities:
Capital expenditures	(584)	(598)	(1,007)
Purchases of nuclear decommissioning trust securities	(25)	(19)	(19)
Sales of nuclear decommissioning trust securities	27	22	17
Distribution from (contribution to) nuclear decommissioning trust	0	50	(6)
Sales tax refund received - Tucannon River Wind Farm	0	23	0
Cash received in connection with purchase of 10% interest in Boardman, net of cash paid	0	0	8
Other, net	(3)	0	13
Net cash used in investing activities	(585)	(522)	(994)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	290	145	585
Payments on long-term debt	(133)	(442)	0
Proceeds from issuance of common stock, net of issuance costs	0	271	0
(Maturities) issuances of commercial paper, net	(6)	6	0
Dividends paid	(110)	(97)	(87)
Other	(7)	(4)	(4)
Net cash provided by (used in) financing activities	34	(121)	494
Increase (decrease) in cash and cash equivalents	2	(123)	20
Cash and cash equivalents, beginning of year	4	127	107
Cash and cash equivalents, end of year	6	4	127
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	104	108	86
Cash paid for income taxes	16	3	22
Non-cash investing and financing activities:
Accrued capital additions	50	32	70
Accrued dividends payable	30	28	23
Accrued sales tax refund related to Tucannon River Wind Farm	0	0	23
Assets obtained under leasing arrangements	$ 78	$ 0	$ 0

Basis of Presentation	12 Months Ended
Basis of Presentation	Dec. 31, 2016
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, 2016, PGE served approximately 863,000 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, 2016, PGE had 2,752 employees, with 783 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 730 and 53 employees and expire March 2020 and August 2017, respectively. PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC) with respect to retail prices, utility services, accounting policies and practices, issuances of securities, and certain other matters. Retail prices are based on the Company’s cost to serve customers, including an opportunity to earn a reasonable rate of return, as determined by the OPUC. The Company is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in matters related to wholesale energy transactions, transmission services, reliability standards, natural gas pipelines, hydroelectric project licensing, accounting policies and practices, short-term debt issuances, and certain other matters. Consolidation Principles The consolidated financial statements include the accounts of PGE, its wholly-owned subsidiaries, and those variable interest entities (VIEs) in which PGE has determined it is the primary beneficiary. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. For further information on PGE’s jointly-owned plant, see Note 16, Jointly-Owned Plan. 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 2016 or 2015. 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 2016 presentation, PGE has reclassified Proceeds received from Trojan spent fuel legal settlement of $6 million to Other, net within the operating activities section, and Proceeds received from insurance recoveries of $3 million and Proceeds from sale of properties of $5 million to Other, net within the investing activities section of the consolidated statement of cash flows for the year ended December 31, 2014.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

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 $1 million as of December 31, 2016 and none as of December 31, 2015 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 2016, 2015, and 2014.

Price Risk Management

PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, oil, and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statement of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting.

Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers.

In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument.

Electricity and natural gas sale and purchase transactions that are physically settled are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement.

Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are included within Other current assets in the consolidated balance sheets and were $8 million and $33 million as of December 31, 2016 and 2015, respectively. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet and were $17 million and $63 million as of December 31, 2016 and 2015, 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 for use in its generating plants. Fuel inventories include natural gas, coal, and oil. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.

Electric Utility Plant

Capitalization Policy

Electric utility plant is capitalized at its original cost, which includes direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at the Company’s generating plants are charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining a FERC license for the Company’s hydroelectric projects are capitalized and amortized over the related license period.

During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. If any costs are expensed, the Company may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted. 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 2016 and 2015, and 7.4% in 2014. AFDC from borrowed funds was $11 million in 2016, $13 million in 2015, and $22 million in 2014 and is reflected as a reduction to Interest expense. AFDC from equity funds, included in Other income, net, was $21 million in 2016 and 2015, and $37 million in 2014.

On July 29, 2016, PGE placed Carty into service, a baseload natural gas-fired generating plant in Eastern Oregon, located adjacent to the Boardman coal-fired generating plant (Boardman). As of December 31, 2016, PGE had $634 million included in Electric utility plant for Carty. On November 3, 2015, the OPUC issued an order approving settlements reached in PGE’s 2016 GRC filing, including capital costs of up to $514 million, including AFDC, for Carty and that Carty would be included in customer prices when the plant was placed in service, provided that occurred by July 31, 2016. As Carty was placed in service on July 29, 2016, the Company has been authorized to include in customer prices, effective August 1, 2016, the revenue requirement necessary to allow for recovery of capital costs of up to $514 million, as well as Carty’s operating costs. See Note 17, Contingencies, for further information regarding Carty.

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 3.5% in 2016, and 3.6% in 2015 and 2014. 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 2013, with an order received from the OPUC in September 2014 authorizing new depreciation rates effective January 1, 2015. In December 2016, a depreciation study was completed, which will be incorporated into the Company’s planned 2018 general rate case to be filed with the OPUC by the end of February 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 the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years):



Generation, excluding thermal:
Hydro	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 $257 million and $227 million as of December 31, 2016 and 2015, respectively, with amortization expense of $44 million in 2016, and $38 million in 2015 and $25 million in 2014. Future estimated amortization expense as of December 31, 2016 is as follows: $45 million in 2017; $44 million in 2018; $38 million in 2019; $34 million in 2020; and $22 million in 2021.

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 the Company’s ability to establish prices to recover specific costs; and ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. PGE periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate. Based on a current evaluation of the various factors and conditions, management believes that recovery of the Company’s regulatory assets is probable.

For additional information concerning the Company’s regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities.

Power Cost Adjustment Mechanism

PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. NVPC consists of i) the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income; and is net of ii) wholesale sales, which are classified as Revenues, net in the consolidated statements of income.

To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from or refunded to customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. PGE’s authorized ROE was 9.6% for 2016, 9.68% for 2015, and 9.75% for 2014.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review. 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 a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred.

The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. Changes in the ARO resulting from the passage of time (accretion) is based on the original discount rate and recognized as an increase in the carrying amount of the liability and as a charge to accretion expense, which is classified as Depreciation and amortization expense in the Company’s consolidated statements of income.

For additional information concerning the Company’s AROs, see Note 7, Asset Retirement Obligations.

The difference between the timing of the recognition of the AROs’ depreciation and accretion expenses and the amount included in customers’ prices is recorded as a regulatory asset or liability in the Company’s consolidated balance sheets. PGE had a regulatory liability related to AROs in the amount of $49 million as of December 31, 2016 and $45 million as of December 31, 2015. 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 reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons.

If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period.

Gain contingencies are recognized when realized and are disclosed when material.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position.

Revenue Recognition

Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC) or state (OPUC) regulation. Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes and totaled $43 million in 2016 and 2015, and $42 million in 2014.

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 deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. Such amounts were recognized as net regulatory assets of $86 million as of December 31, 2016 and as of 2015 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 is evaluating which transition method it will elect. The Company does not anticipate any material changes to its revenue policy for tariff-based revenues, which comprises a majority of PGE’s retail revenues, as performance obligations are expected to be satisfied in a similar recognition pattern. PGE continues to evaluate the impacts the new guidance may have on its consolidated financial position, consolidated results of operations, and consolidated cash flows, particularly related to recognizing revenue for certain contracts where collectibility may be in question, the extent to which certain transactions such as contributions in aid of construction (CIAC) are within the scope of the standard, certain matters of presentation of alternative revenue programs (such as decoupling), wholesale, and other operating revenue contracts.

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 and must be applied on a modified retrospective basis as of the beginning of the earliest comparative period presented. The new standard also provides reporting entities the option to elect a package of practical expedients for existing leases that commenced before the effective date. Early adoption is permitted. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2016-02.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments (ASU 2016-15), with the intention to reduce diversity in practice, as well as simplify elements of classification within the statement of cash flows for certain transactions. The new ASU prescribes specific clarification guidance for the following eight classes of transactions: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance (COLI) policies, distributions received from equity method investments, beneficial interest in securitization transactions, and separately identifiable cash flows and application of the predominance principal. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2018 and requires application using a retrospective transition method. Early adoption is permitted. The Company is in the process of evaluating the impacts of adoption of ASU 2016-15 to the presentation of consolidated cash flows.

Recently Adopted Accounting Standard

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (ASU 2015-03), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Company has retrospectively adopted the provisions of ASU 2015-03 as of January 1, 2016, which was the original effective date for calendar year-end, public entities. As a result, unamortized debt expense of $11 million at December 31, 2015 has been reclassified from Other noncurrent assets to a deduction of Long-term debt, net of current portion on the consolidated balance sheets. Unamortized debt expense at December 31, 2016 is also $11 million. Adoption of this guidance had no impact on the Company’s consolidated results of operations or consolidated cash flows. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30): Presentation of Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (ASU 2015-15), which clarifies that the SEC staff would “not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement” given the lack of guidance on this topic in ASU 2015-03. Therefore, as allowed under this update, the Company records debt issuance costs associated with its line-of-credit arrangements as an asset within Other current assets, and amortizes the costs over the term of the agreement.

In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), which removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share as a practical expedient. The amendments also remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share as a practical expedient. Instead, such disclosures are restricted only to investments that the entity has decided to measure using the practical expedient. The Company has retrospectively adopted the provisions of this update as of January 1, 2016, which was the original effective date for calendar year-end, public entities. As a result, certain investments have been retrospectively reclassified within the Company’s fair value disclosures of its Nuclear decommissioning trust and Non-qualified benefit plan trust. See Note 4, Fair Value of Financial Instruments for more information. Also, certain benefit plan assets have been reclassified by the Company as seen in Note 10, Employee Benefits. The adoption of this guidance had no impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which is designed to simplify the presentation and accounting for certain income tax effects, employer tax withholding requirements, forfeiture assumptions, and statement of cash flows presentation related to share-based payment awards. PGE has early adopted the provisions of this ASU effective January 1, 2016. The main provisions include the following:

•

On a prospective basis, all excess tax benefits and deficiencies are recognized within the consolidated statements of income in the year incurred, as opposed to equity, and shall be classified as operating activities in the consolidated statements of cash flows. As a result of adoption, PGE recognized less than $1 million of excess tax benefits related to its share-based payment awards, which was recorded as a reduction of Income tax expense in the consolidated statements of income for the period ended December 31, 2016.


•	Reporting entities are now allowed to make a policy election regarding its accounting for forfeitures either by estimating the number of awards that are expected to vest or account for forfeitures when they occur. PGE’s stock compensation expense will continue to reflect estimated forfeitures.

•

On a retrospective basis, cash paid on behalf of employees related to restricted shares withheld for tax purposes shall now be classified as a financing activity in the statement of cash flows. In the consolidated statements of cash flows for the twelve months ended December 31, 2015 and 2014, PGE has retrospectively reclassified $3 million and $2 million, respectively, from Other non-cash income and expenses, net within operating activities to Other financing outflow activities. For the twelve months ended December 31, 2016, $3 million is reflected as an outflow within the financing activities section.

Balance Sheet Components

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015. The following is the activity in the allowance for uncollectible accounts (in millions):



	Years Ended December 31,
	2016			2015			2014
Balance as of beginning of year	$	6		$	6		$	6
Increase in provision	5			6			6
Amounts written off, less recoveries	(5		)	(6		)	(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
	2016		2015		2016		2015
Cash equivalents	$	21	$	18	$	1	$	1
Marketable securities, at fair value:
Equity securities	—		—		6		5
Debt securities	20		22		1		1
Insurance contracts, at cash surrender value	—		—		26		26
	$	41	$	40	$	34	$	33

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,
	2016		2015
Other current assets:
Prepaid expenses	$	48	$	43
Margin deposits	8		33
Assets from price risk management activities	18		10
Other	3		2
	$	77	$	88
Accrued expenses and other current liabilities:
Regulatory liabilities—current	$	51	$	55
Accrued employee compensation and benefits	52		51
Accrued interest payable	25		25
Accrued dividends payable	30		28
Accrued taxes payable	25		25
Other	71		75
	$	254	$	259

Fair Value of FInancial Instruments

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015, 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. Pursuant to the adoption of ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities that Calculate Net Asset Value per share (or Its Equivalent), as disclosed in Note 2, Summary of Significant Accounting Policies, 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, and prior period amounts have been retrospectively reclassified to conform to current presentation.

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, 2016 and 2015, 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, 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⁾
Money market funds	—		—		—		—		—
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.



	As of December 31, 2015
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	6	$	8	$	—	$	—	$	14
Corporate credit	—		8		—		—		8
Money market funds measured at NAV⁽²⁾	—		—		—		18		18
Non-qualified benefit plan trust: ⁽³⁾
Money market funds	—		—		—		—		—
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	1		—		—		—		1
Investments measured at NAV:⁽²⁾
Money market funds	—		—		—		1		1
Collective trust—domestic equity	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		7		—		—		7
Natural gas	—		3		—		—		3
	$	10	$	26	$	—	$	21	$	57
Liabilities - Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	28	$	105	$	—	$	133
Natural gas	—		144		14		—		158
	$	—	$	172	$	119	$	—	$	291


(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, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 2, Summary of Significant Accounting Policies.


(3)	Excludes insurance policies of $26 million, which are recorded at cash surrender value.


(4)	For further information, see Note 5, Price Risk Management.

Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:

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.

For 2015 and most of 2016 money market funds in the NQ Plan were valued at NAV as a practical expedient and not included in the fair value hierarchy. As of December 31, 2016 the NQ Plan transitioned to exchange traded government money market funds and are 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 Plan continues to be 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. A majority of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as of the last day on each calendar month, with at least ten days prior written notice, and provides for a 95% payment to be made within 30 days, and the balance paid after the annual fund audit is complete. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient.

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, 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
As of December 31, 2015:
Electricity physical forward	$	—	$	105	Discounted cash flow	Electricity forward price (per MWh)	$	8.50	$	84.47	$	30.69
Natural gas financial swaps	—		14		Discounted cash flow	Natural gas forward price (per Dth)	2.06		3.70		2.54
Electricity financial futures	—		—		Discounted cash flow	Electricity forward price (per MWh)	9.98		27.36		19.26
	$	—	$	119

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,
	2016			2015
Net liabilities from price risk management activities as of beginning of year	$	119		$	100
Net realized and unrealized losses ^*	11			80
Net transfers in to Level 3 from Level 2	(1		)	—
Net transfers out of Level 3 to Level 2	(10		)	(61		)
Net liabilities from price risk management activities as of end of year	$	119		$	119
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	11		$	80

* Includes nominal net realized losses in 2016 and 2015, respectively.

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, 2016, there were $1 million of transfers into Level 3 from Level 2, as reflected in the table above. During 2015, there were no significant amounts 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, 2016, the carrying amount of PGE’s long-term debt was $2,350 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $2,693 million, consisting of $2,543 million and $150 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy. As of December 31, 2015, the carrying amount of PGE’s long-term debt was $2,193 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $2,455 million, classified as Level 2 in the fair value hierarchy.

For fair value information concerning the Company’s pension plan assets, see Note 10, Employee Benefits.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Price Risk Management (Notes)

12 Months Ended

Dec. 31, 2016

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,
	2016			2015
Current assets:
Commodity contracts:
Electricity	$	6		$	7
Natural gas	12			3
Total current derivative assets	18		⁽¹⁾	10		⁽¹⁾
Noncurrent assets:
Commodity contracts:
Electricity	1			—
Natural gas	4			—
Total noncurrent derivative assets	5		⁽²⁾	—		⁽²⁾
Total derivative assets not designated as hedging instruments	$	23		$	10
Total derivative assets	$	23		$	10
Current liabilities:
Commodity contracts:
Electricity	$	12		$	36
Natural gas	32			94
Total current derivative liabilities	44			130
Noncurrent liabilities:
Commodity contracts:
Electricity	106			97
Natural gas	19			64
Total noncurrent derivative liabilities	125			161
Total derivative liabilities not designated as hedging instruments	$	169		$	291
Total derivative liabilities	$	169		$	291


(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,
	2016			2015
Commodity contracts:
Electricity	8		MWh	12		MWh
Natural gas	107		Dth	124		Dth
Foreign currency exchange	$	22	Canadian	$	7	Canadian

PGE has elected to report gross on the consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, 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, 2016 and 2015, gross amounts included as Price risk management liabilities subject to master netting agreements were $115 million and $111 million, respectively, for which PGE posted collateral of $11 million and $14 million, which consisted entirely of letters of credit. As of December 31, 2016, of the gross amounts included, $112 million was for electricity and $3 million was for natural gas compared to $104 million for electricity and $7 million for natural gas recognized as of December 31, 2015.

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,
	2016			2015		2014
Commodity contracts:
Electricity	$	34		$	72	$	13
Natural Gas	(56		)	103		72
Foreign currency exchange	—			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 (gains) of $13 million and net losses of $160 million and $83 million for the years ended December 31, 2016, 2015, and 2014, 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, 2016 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions):



	2017		2018		2019		2020		2021		Thereafter		Total
Commodity contracts:
Electricity	$	6	$	7	$	7	$	7	$	7	$	77	$	111
Natural gas	20		7		6		2		—		—		35
Net unrealized loss	$	26	$	14	$	13	$	9	$	7	$	77	$	146

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, 2016 was $164 million, for which the Company had posted $14 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at December 31, 2016, the cash requirement to either post as collateral or settle the instruments immediately would have been $149 million. As of December 31, 2016, PGE had posted a nominal amount of 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,
	2016		2015
Assets from price risk management activities:
Counterparty A	22	%	5	%
Counterparty B	17		8
Counterparty C	12		8
Counterparty D	8		10
Counterparty E	1		59
	60	%	90	%
Liabilities from price risk management activities:
Counterparty F	66	%	36	%
Counterparty C	7	%	10	%
Counterparty B	5	%	10	%
	78	%	56	%

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.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2016

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,
		2016					2015
		Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management ⁽²⁾	6 years	$	26		$	120	$	120		$	161
Pension and other postretirement plans ⁽²⁾	⁽³⁾	—			235		—			239
Deferred income taxes ⁽²⁾	⁽⁴⁾	—			86		—			86
Debt issuance costs ⁽²⁾	6 years	—			22		—			16
Other ⁽⁵⁾	Various	10			35		9			22
Total regulatory assets		$	36		$	498	$	129		$	524
Regulatory liabilities:
Asset retirement removal costs ⁽⁶⁾	⁽⁴⁾	$	—		$	887	$	—		$	837
Trojan decommissioning activities	3 years	18			—		17			15
Asset retirement obligations ⁽⁶⁾	⁽⁴⁾	—			49		—			45
Other	Various	33			22		38			31
Total regulatory liabilities		$	51	⁽⁷⁾	$	958	$	55	⁽⁷⁾	$	928


(1)	As of December 31, 2016.


(2)	Does not include a return on investment.


(3)	Recovery expected over the average service life of employees.


(4)	Recovery expected over the estimated lives of the assets.


(5)	Of the total other unamortized regulatory asset balances, a return is recorded on $44 million and $29 million as of December 31, 2016 and 2015, 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, 2016, PGE had regulatory assets of $44 million earning a return on investment at the following rates: i) $22 million earning a return by inclusion in rate base; ii) $3 million at the approved rate for deferred accounts under amortization, ranging from 1.47% to 2.20%, depending on the year of approval; and iii) $19 million at PGE’s 2016 cost of capital of 7.56%.

Price risk management represents the difference between the net unrealized losses recognized on derivative instruments related to price risk management activities and their realization and subsequent recovery in customer prices. For further information regarding assets and liabilities from price risk management activities, see Note 5, Price Risk Management.

Pension and other postretirement plans represents unrecognized components of the benefit plans’ funded status, which are recoverable in customer prices when recognized in net periodic benefit cost. For further information, see Note 10, Employee Benefits.

Deferred income taxes represents income tax benefits resulting from property-related timing differences that previously flowed to customers and will be included in customer prices when the temporary differences reverse. For further information, see Note 11, Income Taxes.

Debt issuance costs represents unrecognized debt issuance costs related to debt instruments retired prior to the stipulated maturity date.

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. The USDOE settlement proceeds will be returned to customers over a three-year period that began January 1, 2015 and offset amounts previously collected from customers in relation to Trojan 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

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

AROs consist of the following (in millions):



	As of December 31,
	2016		2015
Trojan decommissioning activities	$	44	$	43
Utility plant	105		97
Non-utility property	12		11
Asset retirement obligations	$	161	$	151

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 agreed to reimburse the Plaintiffs $81 million for costs incurred through 2015 resulting from USDOE delays in accepting spent nuclear fuel. The Plaintiffs have received cumulative cash reimbursements of $79 million and expect to receive $2 million in 2017.

PGE has received proceeds of $50 million related to its share in this legal matter and expects to receive $1 million in 2017. 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.

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 2016, the Company recorded an overall increase in AROs, including Trojan, of $9 million, with the change comprised of an increase to revisions in estimated cash flows and incurred liabilities of $6 million, accretion of $6 million, and a reduction of $3 million due to settled liabilities.

In 2016, PGE decreased its ARO related to Boardman by $3 million due to changes in the timing of estimated settlement, with corresponding decreases in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. In 2015, PGE increased its ARO related to Boardman by $9 million, due primarily to changes in timing of estimated settlements and due to the acquisition of additional interests in Boardman. For additional information regarding the Company’s interests in Boardman, see Note 16, Jointly-owned Plant.

The United States Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCRs) under the Resource Conservation and Recovery Act, Subtitle D. The rule imposes extensive new requirements, including location restrictions, design and operating standards, groundwater monitoring and corrective action requirements, and closure and post-closure care requirements on CCR impoundments and landfills that are located on active power plant sites and not closed. The requirements for covered CCR impoundments and landfills under the final rule include commencement or completion of closure activities generally between three and ten years from certain triggering events.

The Boardman coal-fired generating plant (Boardman) produces dry CCRs as a by-product. Disposal of the dry CCRs has historically occurred at an on-site landfill that is permitted and regulated by the State of Oregon under requirements similar to the final EPA rule. PGE has determined that it will continue use of the on-site landfill in compliance with the new rule, and the Company believes the final EPA rule will not have a material effect on operations at Boardman.

In 2016, the Company recorded an increase in the ARO related to Colstrip of $6 million related to updated decommissioning estimates, with a corresponding increase in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. Colstrip utilizes wet scrubbers and a number of settlement ponds that will require upgrading or closure to meet new regulatory requirements. As a result, in 2015, the Company recorded an increase to the Colstrip AROs in the amount of $17 million. PGE plans to seek recovery in customer prices of the incremental costs associated with the final EPA rule.

In 2016 and 2015, PGE also recorded an increase in AROs totaling $3 million and $4 million, respectively, related to the Company’s Beaver natural gas-fired generating plant (Beaver) and Carty.

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,
	2016			2015			2014
Balance as of beginning of year	$	151		$	116		$	100
Liabilities incurred	1			2			15
Liabilities settled	(3		)	(4		)	(3		)
Accretion expense	7			7			6
Revisions in estimated cash flows	5			30			(2		)
Balance as of end of year	$	161		$	151		$	116

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

12 Months Ended

Dec. 31, 2016

Line of Credit Facility [Abstract]

Credit Facilities

CREDIT FACILITIES

As of December 31, 2016, PGE had a $500 million revolving credit facility scheduled to expire in November 2019.

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 contains a provision that allows for two, one-year extensions subject to approval by the banks, 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, 2016, PGE was in compliance with this covenant with a 51.0% 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.

Under the revolving credit facility, as of December 31, 2016, PGE had no borrowings outstanding and there was no commercial paper or letters of credit issued. As a result, as of December 31, 2016, 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 a total of $160 million capacity 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, $56 million of letters of credit was outstanding, as of December 31, 2016.

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, 2018.

Short-term borrowings under these credit facilities and related interest rates were as follows (dollars in millions):



	Years Ended December 31,
	2016			2015			2014
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

12 Months Ended

Dec. 31, 2016

Long-term Debt Disclosure [Abstract]

Long-term Debt

LONG-TERM DEBT

Long-term debt consists of the following (in millions):



	As of December 31,
	2016			2015
First Mortgage Bonds, rates range from 2.51% to 9.31%, with a weighted average rate of 4.86% in 2016 and 5.29% in 2015, due at various dates through 2048	$	2,090		$	2,083
Unsecured term bank loans, variable rates of approximately 1.37% due 2017	150			—
Pollution Control Revenue Bonds, 5% rate, due 2033	142			142
Pollution Control Revenue Bonds owned by PGE	(21		)	(21		)
Total long-term debt	2,361			2,204
Less: Unamortized debt expense	(11		)	(11		)
Less: Current portion of long-term debt	(150		)	(133		)
Long-term debt, net of current portion	$	2,200		$	2,060

First Mortgage Bonds and Unsecured term bank loans—During 2016, PGE issued a total of $140 million of FMBs and repaid long-term debt, in an aggregate amount of $133 million.

In January 2016, the Company issued $140 million of 2.51% Series FMBs due 2021 and repaid $58 million of 3.81% Series FMBs, due in 2017 and $75 million of 5.80% Series FMBs due in 2018. Due to the anticipated repayment of this $133 million in early January 2016, this amount of long-term debt was classified as current on the Company’s consolidated balance sheets as of December 31, 2015.

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 May 2016, PGE entered into an unsecured credit agreement with certain financial institutions, under which the Company had the opportunity to obtain three separate term loans in an aggregate principal amount of up to $200 million by October 31, 2016. Under the agreement, PGE obtained the following term loans:


•	$50 million on May 4, 2016;


•	$75 million on June 15, 2016; and


•	$25 million on October 31, 2016.

The term loan interest rates are 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, approximately 1.37% as of December 31, 2016, with no other fees.

The credit agreement expires November 30, 2017, at which time any amounts outstanding under the term loans become due and payable. Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults and other customary defaults for financings of this type.

Pollution Control Revenue Bonds—The Company has the option to remarket through 2033 the $21 million of PCBs held by PGE as of December 31, 2016. 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, 2016, the future minimum principal payments on long-term debt are as follows (in millions):



Years ending December 31:
2017	$	150
2018	—
2019	300
2020	—
2021	160
Thereafter	1,751
	$	2,361

Employee Benefits

12 Months Ended

Dec. 31, 2016

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 made no contributions to the pension plan in 2016, 2015, and 2014. PGE expects to contribute $3 million to the pension plan in 2017.

In 2014, the Company offered certain eligible participants in the pension plan the option to select a lump sum distribution. As a result of this offering, PGE made lump sum distributions totaling $16 million on July 1, 2014.

Other Postretirement Benefits—PGE has non-contributory postretirement health and life insurance plans, as well as Health Reimbursement Accounts (HRAs) for its employees (collectively, “Other Postretirement Benefits” in the following tables). Employees are covered under a Defined Dollar Medical Benefit Plan, which limits PGE’s obligation pursuant to the postretirement health plan by establishing a maximum benefit per employee with employees 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.

Contributions to the HRAs provide for claims by retirees for qualified medical costs. For bargaining employees employed as of April 9, 2004, the participants’ accounts are credited with 58% of the value of the employee’s accumulated sick time, a stated amount per compensable hour worked, plus 100% of their earned time off accumulated at the time of retirement. For active non-bargaining employees, the Company grants a fixed dollar amount that will become available for qualified medical expenses upon their retirement.

Non-Qualified Benefit Plans—The non-qualified benefit plans (NQBP) in the following tables include obligations for a Supplemental Executive Retirement Plan and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also include pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in a non-qualified benefit plan trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. 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 non-qualified benefit plans is December 31.

Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. PGE holds investments in a non-qualified benefit plan trust 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):



	2016						2015
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust	$	16	$	18	$	34	$	15	$	18	$	33
Non-qualified benefit plan liabilities *	25		80		105		25		81		106


*	For the NQBP, excludes the current portion of $2 million in 2016 and 2015, 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 Non-qualified benefit plan trust.

Investment Policy and Asset Allocation—The Board of Directors of PGE appoints an Investment Committee, which is comprised of officers of the Company, and establishes the Company’s asset allocation. The Investment Committee is then responsible for implementation and oversight of the asset allocation. The Company’s investment policy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities, and other alternative investments. The commitments to each class are controlled by an asset deployment and cash management strategy that takes profits from asset classes whose allocations have shifted above their target ranges to fund benefit payments and investments in asset classes whose allocations have shifted below their target ranges.

The asset allocations for the plans, and the target allocation, are as follows:



	As of December 31,
	2016				2015
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	68	%	67	%	67	%	67	%
Debt securities	32		33		33		33
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	60	%	62	%	60	%	64	%
Debt securities	40		38		40		36
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	15	%	11	%	15	%	14	%
Debt securities	7		11		7		8
Insurance contracts	78		78		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 Non-Qualified Benefit Plans, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and Non-Qualified Benefit Plans, reported percentages are affected by the fair market values of the investments within the pools.

The Company’s overall investment strategy is to meet the goals and objectives of the individual plans through a wide diversification of asset types, fund strategies, and fund managers. Equity securities primarily include investments across the capitalization ranges and style biases, both domestically and internationally. Fixed income securities include, but are not limited to, corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other types of investments include investments in hedge funds and private equity funds that follow several different strategies.

Pursuant to the adoption of ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities that Calculate Net Asset Value per share (or Its Equivalent), as disclosed in Note 2, Summary of Significant Accounting Policies, 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. As required by this ASU, prior period amounts have been retrospectively reclassified to conform to current presentation, including all of the investments previously classified as Level 3. As a result, the Level 3 reconciliation is no longer applicable for such investments and has been excluded from this footnote.

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, 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
As of December 31, 2015:
Defined Benefit Pension Plan assets:
Equity securities—Domestic	$	44	$	—	$	—	$	—	$	44
Investments measured at NAV:
Money market funds	—		—		—		5		5
Collective trust funds	—		—		—		479		479
Private equity funds	—		—		—		22		22
	$	44	$	—	$	—	$	506	$	550
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	—	$	—	$	—	$	—
Equity securities:
Domestic	—		3		—		—		3
International	8		—		—		—		8
Debt securities—Domestic government	—		5		—		—		5
Investments measured at NAV:
Money market funds	—		—		—		7		7
Collective trust funds	—		—		—		7		7
	$	8	$	8	$	—	$	14	$	30


*	Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 2, Summary of Significant Accounting Policies.

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 not 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 non-qualified benefit plans as of and for the years ended December 31, 2016 and 2015. 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
	2016			2015			2016			2015			2016			2015
Benefit obligation:
As of January 1	$	758		$	777		$	81		$	83		$	27		$	27
Service cost	16			18			2			2			—			—
Interest cost	33			31			4			3			1			1
Participants’ contributions	—			—			2			2			—			—
Actuarial (gain) loss	26			(31		)	(11		)	(4		)	1			1
Contractual termination benefits	—			—			—			1			—			—
Benefit payments	(34		)	(35		)	(5		)	(6		)	(2		)	(2		)
Administrative expenses	(2		)	(2		)	—			—			—			—
As of December 31	$	797		$	758		$	73		$	81		$	27		$	27
Fair value of plan assets:
As of January 1	$	550		$	591		$	30		$	32		$	15		$	15
Actual return on plan assets	45			(4		)	1			(2		)	1			—
Company contributions	—			—			2			4			2			2
Participants’ contributions	—			—			2			2			—			—
Benefit payments	(34		)	(35		)	(5		)	(6		)	(2		)	(2		)
Administrative expenses	(2		)	(2		)	—			—			—			—
As of December 31	$	559		$	550		$	30		$	30		$	16		$	15
Unfunded position as of December 31	$	(238	)	$	(208	)	$	(43	)	$	(51	)	$	(11	)	$	(12	)
Accumulated benefit plan obligation as of December 31	$	714		$	681		N/A			N/A			$	27		$	27
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	16		$	15
Current liability	—			—			—			—			(2		)	(2		)
Noncurrent liability	(238		)	(208		)	(43		)	(51		)	(25		)	(25		)
Net liability	$	(238	)	$	(208	)	$	(43	)	$	(51	)	$	(11	)	$	(12	)
Amounts included in comprehensive income:
Net actuarial loss (gain)	$	21		$	13		$	(10	)	$	—		$	1		$	1
Amortization of net actuarial loss	(14		)	(20		)	—			(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			(1		)	(1		)	—			—
	$	7		$	(7	)	$	(11	)	$	(2	)	$	—		$	—
Amounts included in AOCL*:
Net actuarial loss (gain)	$	236		$	228		$	(2	)	$	9		$	13		$	13
Prior service cost	—			—			1			1			—			—
	$	236		$	228		$	(1	)	$	10		$	13		$	13



	Defined Benefit Pension Plan				Other Postretirement Benefits						Non-Qualified Benefit Plans
	2016		2015		2016			2015			2016		2015
Assumptions used:
Discount rate for benefit obligation	4.17	%	4.36	%	3.75	%	-	3.90	%	-	4.17	%	4.36	%
					4.23	%		4.45	%
Discount rate for benefit cost	4.36	%	4.02	%	3.90	%	-	3.07	%	-	4.36	%	4.02	%
					4.45	%		4.10	%
Weighted average rate of compensation increase for benefit obligation	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Weighted average rate of compensation increase for benefit cost	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Long-term rate of return on plan assets for benefit obligation	7.50	%	7.50	%	6.26	%		6.29	%		N/A		N/A
Long-term rate of return on plan assets for benefit cost	7.50	%	7.50	%	6.29	%		6.37	%		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
	2016			2015			2014			2016			2015			2014			2016		2015		2014
Service cost	$	16		$	18		$	15		$	2		$	2		$	2		$	—	$	—	$	—
Interest cost on benefit obligation	33			31			34			4			3			4			1		1		1
Expected return on plan assets	(40		)	(40		)	(39		)	(2		)	(2		)	(2		)	—		—		—
Amortization of prior service cost	—			—			—			1			1			1			—		—		—
Amortization of net actuarial loss	14			20			17			—			1			1			1		1		1
Net periodic benefit cost	$	23		$	29		$	27		$	5		$	5		$	6		$	2	$	2	$	2

PGE estimates that $15 million will be amortized from AOCL into net periodic benefit cost in 2017, consisting of a net actuarial loss of $13 million for pension benefits, $1 million for non-qualified benefits, and $1 million for prior service costs for other postretirement benefits. Amounts related to the pension and other postretirement benefits are offset with the amortization of the corresponding regulatory asset.

The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions):



	Payments Due
	2017		2018		2019		2020		2021		2022 - 2026
Defined benefit pension plan	$	37	$	39	$	40	$	42	$	43	$	229
Other postretirement benefits	5		5		5		4		5		22
Non-qualified benefit plans	3		2		3		2		2		10
Total	$	45	$	46	$	48	$	48	$	50	$	261

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 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% in 2023;


•	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% in 2021; and


•	For 2014, 7% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019.

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 $19 million in 2016, $17 million in 2015, and $16 million in 2014.

Income Taxes

12 Months Ended

Dec. 31, 2016

Income Taxes Note [Abstract]

Income Taxes

INCOME TAXES

Income tax expense consists of the following (in millions):



	Years Ended December 31,
	2016		2015		2014
Current:
Federal	$	10	$	4	$	20
State and local	3		1		2
	13		5		22
Deferred:
Federal	23		26		26
State and local	14		14		13
	37		40		39
Income tax expense	$	50	$	45	$	61

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,
	2016		2015		2014
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
Federal tax credits *	(18.2	)	(19.0	)	(11.4	)
State and local taxes, net of federal tax benefit	4.8		4.2		3.9
Flow through depreciation and cost basis differences	0.2		—		(2.3	)
Other	(1.2	)	0.5		0.8
Effective tax rate	20.6	%	20.7	%	26.0	%

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. The PTCs are generated for 10 years from the corresponding facility’s in service date. PGE’s PTCs end at various dates between 2017 and 2024.

Deferred income tax assets and liabilities consist of the following (in millions):



	As of December 31,
	2016			2015
Deferred income tax assets:
Employee benefits	$	181		$	170
Price risk management	59			112
Regulatory liabilities	29			42
Tax credits	56			46
Other	5			—
Total deferred income tax assets	330			370
Deferred income tax liabilities:
Depreciation and amortization	829			781
Regulatory assets	170			220
Other	—			1
Total deferred income tax liabilities	999			1,002
Deferred income tax liability, net	$	(669	)	$	(632	)

As of December 31, 2016, PGE has federal credit carryforwards of $56 million, which will expire at various dates through 2036.

PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 2016 and 2015 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 2016 and 2015, 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	12 Months Ended
Equity-Based Plans	Dec. 31, 2016
Equity Based Plans [Abstract]
Stock Purchase Plan [Text Block]	EQUITY-BASED PLANS Equity Forward Sale Agreement PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 11,100,000 shares of its common stock in June 2013. In 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). 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 purchase shares of PGE common stock at a price equal to 95% of the fair value of the stock on the purchase date, the last day of the offering period. As of December 31, 2016, there were 369,419 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, 2016, there were 2,474,164 shares available for future issuance pursuant to the DRIP.

Stock-based Compensation Expense

12 Months Ended

Dec. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

STOCK-BASED COMPENSATION EXPENSE

Pursuant to the Portland General Electric Company 2006 Stock Incentive Plan (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units (RSUs) with time-based vesting conditions (time-based RSUs) and performance-based vesting conditions (performance-based RSUs), to non-employee directors, officers, and certain key employees. Service requirements generally must be met for RSUs to vest. For each grant, the number of RSUs is determined by dividing the specified award amount for each grantee by the closing stock price on the date of grant. RSU activity is summarized in the following table:



	Units		Weighted Average Grant Date Fair Value
Outstanding as of December 31, 2013	431,090		$	26.31
Granted	203,410		31.49
Forfeited	(12,278	)	29.90
Vested	(158,329	)	24.95
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

A total of 4,687,500 shares of common stock were registered for issuance under the Plan, of which 3,305,920 shares remain available for future issuance as of December 31, 2016.

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, 2016, 2015, and 2014.

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; and iii) a relative total shareholder return (TSR) of PGE’s common stock as compared to the Edison Electric Institute Regulated Index (EEI Index) during the performance period. Vesting of performance-based RSUs is calculated by multiplying the number of units granted by a performance percentage determined by the Compensation and Human Resources Committee of PGE’s Board of Directors. The performance percentage is calculated based on the extent to which the performance goals are met. In accordance with the Plan, however, the committee may disregard or offset the effect of extraordinary, unusual or non-recurring items in determining results relative to these goals. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

For the return on equity and regulated asset base growth portions of the performance-based RSUs, fair value is measured based on the closing price of PGE common stock on the date of grant. For the TSR portion of the performance-based RSUs, fair value is determined using a Monte Carlo simulation model utilizing actual information for the common shares of PGE and its peer group for the period from the beginning of the performance period to the grant date and estimated future stock volatility over the remaining performance period. The fair value of stock-based compensation related to the TSR component of performance-based RSUs was determined using the Monte Carlo model and the following weighted average assumptions:



	2016					2015
Risk-free interest rate				0.9	%				1.0	%
Expected dividend yield				—	%				—	%
Expected term (in years)				3.0					3.0
Volatility	14.5	%	-	25.9	%	13.2	%	-	19.2	%

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 121.2%, 117.3%, and 111.2% of awarded performance-based RSUs for the respective 2016, 2015, and 2014 grants, with an estimated 5% forfeiture rate.

The total value of performance-based RSUs vested was $5 million for the year ended December 31, 2016, $4 million for 2015, and $3 million for 2014.

Stock-based compensation, included in Administrative and other expense in the consolidated statements of income, was $6 million for the years ended December 31, 2016, 2015, and 2014. 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 $2 million in 2016 and 2015, and $1 million in 2014.

As of December 31, 2016, unrecognized stock-based compensation expense was $6 million, of which approximately $4 million and $2 million is expected to be expensed in 2017 and 2018, 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, 2016, 2015, or 2014.

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References + Details

Earnings Per Share

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

Basic earnings per share is computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share is computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; ii) 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,
	2016	2015	2014
Weighted average common shares outstanding—basic	88,896	84,180	78,180
Dilutive effect of potential common shares	158	161	2,314
Weighted average common shares outstanding—diluted	89,054	84,341	80,494

Commitments and Guarantees

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Guarantees [Text Block]

COMMITMENTS AND GUARANTEES

Purchase Commitments

As of December 31, 2016, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):



	Payments Due
	2017		2018		2019		2020		2021		Thereafter		Total
Capital and other purchase commitments	$	176	$	8	$	2	$	9	$	1	$	60	$	256
Purchased power and fuel:
Electricity purchases	221		157		181		256		239		1,750		2,804
Capacity contracts	7		6		5		4		4		12		38
Public utility districts	4		4		1		—		1		11		21
Natural gas	53		39		32		27		24		158		333
Coal and transportation	17		9		5		—		—		—		31
Total	$	478	$	223	$	226	$	296	$	269	$	1,991	$	3,483

Capital and other purchase commitments—Certain commitments have been made for 2017 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 2049, and power capacity contracts through 2024.

Public utility districts—PGE has long-term power purchase agreements with certain public utility districts in the state of Washington and with the City of Portland, Oregon. Under the agreements, the Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether or not they are operable. The future minimum payments for the public utility districts in the preceding table reflect the principal payment only and do not include interest, operation, or maintenance expenses.

Selected information regarding these projects is summarized as follows (dollars in millions):



	Revenue Bonds as of December 31, 2016		PGE’s Share as of December 31, 2016			Contract Expiration	PGE Cost, including Debt Service
	Revenue Bonds as of December 31, 2016		Output		Capacity	Contract Expiration	2016		2015		2014
					(in MW)
Priest Rapids and Wanapum	$	1,190	8.6	%	163	2052	$	16	$	18	$	14
Wells	177		19.4		150	2018	10		10		10
Portland Hydro	—		100.0		36	2017	1		2		4

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. 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, 2016, 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
2017	$	7	$	—	$	10
2018	7		4		9
2019	6		14		6
2020	6		13		6
2021	6		13		7
Thereafter	77		237		177
Total minimum lease payments	$	109	$	281	$	215
Less imputed interest	55
Present value of net minimum lease payments	$	54
Less current portion	3
Non-current portion	$	51

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, 2016, a capital lease asset of $57 million was reflected within Electric utility plant and accumulated amortization of such assets of $3 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 $3 million within Accrued expenses and other current liabilities and $51 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.

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 $128 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 $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 $10 million in 2016 and 2015, and $11 million in 2014.

The future minimum operating lease payments presented is net of sublease income of $4 million in each of 2017, 2018, 2019, and 2020; and $3 million in 2021. Sublease income was $4 million in 2016, and $3 million in 2015 and 2014.

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, 2016, 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

12 Months Ended

Dec. 31, 2016

Jointly-owned Plant [Abstract]

Jointly-owned Plant [Text Block]

JOINTLY-OWNED PLANT

As of December 31, 2016, 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			$	514	$	400	$	—
Colstrip	20.00		1986			528		342		9
Pelton/Round Butte	66.67		1958	/	1964	255		63		5
Total						$	1,297	$	805	$	14


*	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

12 Months Ended

Dec. 31, 2016

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.

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

Construction Litigation—In 2013, the Company entered into an agreement (Construction Agreement) with its engineering, procurement and construction contractor - Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership, an affiliate of Abengoa S.A. (collectively, the “Contractor”) - for the construction of Carty, a baseload natural gas-fired generating plant in Eastern Oregon, located adjacent to Boardman. Liberty Mutual Insurance Company and Zurich American Insurance Company (hereinafter referred to collectively as the “Sureties”) provided a performance bond of $145.6 million (Performance Bond) under the Construction Agreement.

On December 18, 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. Following termination of the Construction Agreement, PGE, in consultation with the Sureties, brought on new contractors and construction resumed during the week of December 21, 2015.

On January 28, 2016, the Company received notice from the International Chamber of Commerce (ICC) International Court of Arbitration that Abengoa S.A. had submitted a request for arbitration. In the request, Abengoa S.A. alleged that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and does not give rise to any liability of Abengoa S.A. under the terms of a guaranty in favor of PGE and pursuant to which Abengoa S.A. agreed to guaranty certain obligations of the Contractor under the Construction Agreement. PGE disagrees with the assertions in the request for arbitration and on February 29, 2016 filed a complaint and motion for preliminary injunction in the U.S. District Court for the District of Oregon seeking to have the arbitration claim dismissed on the grounds that the Company has not made a demand under the Abengoa S.A. guaranty, and therefore the matter is not ripe for arbitration.

On March 28, 2016, Abengoa S.A. and several of its foreign affiliates filed petitions for recognition under Chapter 15 of the U.S. Bankruptcy Code requesting interim relief, including an injunction precluding the prosecution of any proceedings against the Chapter 15 debtors. On March 29, 2016, a number of Abengoa S.A.’s U.S. subsidiaries, including the four entities that collectively comprise the Contractor, filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. As a result, on April 5, 2016, the U.S. District Court issued an order stating that the Company’s District Court action against Abengoa S.A. was stayed. In early October 2016, the bankruptcy court in the Chapter 11 proceeding granted the Company’s motion for relief from stay with respect to the four entities that collectively comprise the Contractor, which allows the Company to bring claims against such entities in the U.S. District Court. On October 21, 2016, PGE filed a complaint in the U.S. District Court for the District of Oregon against Abeinsa for failure to satisfy its obligations under the Construction Agreement. PGE is seeking damages from Abeinsa 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.

On March 9, 2016, the Sureties delivered a letter to the Company denying liability in whole under the Performance Bond. In the letter, the Sureties make the following assertions in support of their determination:


1.	that, because Abengoa S.A. has alleged that PGE wrongfully terminated the Construction Agreement, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and


2.	that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond.

The Company disagrees with the foregoing assertions and, on March 23, 2016, filed a breach of contract action against the Sureties in the U.S. District Court for the District of Oregon. 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.

On April 15, 2016, the Sureties filed a motion to stay this U.S. District Court proceeding, alleging that PGE’s claims should be addressed in the arbitration proceeding initiated by Abengoa S.A. and referenced above because PGE’s claims are intertwined with the issues involved in such arbitration and all parties necessary to resolve PGE’s claims are parties to the arbitration. PGE opposed the motion and filed a motion to enjoin the Sureties from pursuing, in the ICC arbitration proceeding, claims relating to the Performance Bond. On July 27, 2016, the court denied the Sureties’ motion to stay and granted PGE’s motion for a preliminary injunction. The Sureties appealed the rulings to the Ninth Circuit Court of Appeals. On December 13, 2016, the Ninth Circuit issued an Order staying the district court proceeding, pending a decision on the Sureties’ appeal. Oral argument on the Sureties’ appeal is scheduled for May 2017.

Recovery of Capital Costs in Excess of $514 million—Following termination of the Construction Agreement, PGE brought on new contractors and resumed construction. Carty was placed into service on July 29, 2016 and the Company began including its revenue requirement, based on the approved cost of $514 million, in customer prices on August 1. Costs for Carty have exceeded the $514 million approved for inclusion in customer prices by the OPUC. 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, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, and procuring additional materials. Costs also increased as a result of PGE’s discovery through the construction process of latent defects in work performed by the former Contractor and the corresponding labor and materials required to correct the work. 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 resulting from poor storage and maintenance on the part of the former Contractor.

As of December 31, 2016, PGE has capitalized $634 million for Carty classified as Electric utility plant. PGE currently estimates the total cost of Carty will be approximately $640 million. This cost estimate does not reflect any offsetting amounts that may be received from the Sureties pursuant to the Performance Bond. This estimate also excludes approximately $17 million of lien claims filed against PGE for goods and services provided under contracts with the former Contractor. The Company believes these liens are invalid and is contesting the claims in the courts.

In the event the total project costs incurred by PGE, net of offsetting amounts that may be received from the Sureties, Abengoa S.A., or the Contractor, exceed the $514 million amount approved by the OPUC for inclusion in customer prices, the Company intends to seek approval to recover the excess amounts in customer prices in a subsequent rate proceeding after exhausting all remedies against the aforementioned parties. 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 would 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 that a portion of the cost of Carty will be disallowed for recovery in customer prices is less than probable. Accordingly, no loss has been recorded to date related to the project.

As actual project costs for Carty exceed $514 million, the Company is incurring a higher cost than what is reflected in the current authorized revenue requirement amount, primarily due to higher depreciation and interest expense. On July 29, 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 GRC proceeding. The Company has requested that the OPUC delay its review of this deferral request until the Company’s claims against the Sureties have been resolved. Until such time, the effects of this higher cost are recognized in the Company’s results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP. Any amounts approved by the OPUC for recovery under the deferral filing will 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 consolidated balance sheet were prudently incurred. There have been no settlement discussions with regulators related to such costs.

EPA Investigation of Portland Harbor

A 1997 investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) as a federal Superfund site and listed 69 Potentially Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river. In 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 (RI) has been completed pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE. The LWG has funded the RI and feasibility study (FS) and has stated that it has 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 FS, along with the RI, and these documents 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 alternative 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 $1.05 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 Company anticipates that prior to the commencement of remediation activities, a phase of resampling of the river will be necessary to better refine the remedial design and may impact estimated costs.

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 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, and claims are not concluded until a final remedy for clean-up has been settled. 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.

After the claimed damages at a site are assessed, 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 assigning initial NRDA liability allocations to PRPs, which the Company anticipates will occur throughout the first half of 2017. PGE believes that the Company’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.

On July 15, 2016, the Company filed a deferral application with the OPUC to allow for the deferral of the future environmental remediation costs, as well as, seek authorization to establish a regulatory cost recovery mechanism for such environmental costs. The Company has reached an agreement with OPUC Staff and other parties regarding the details of the recovery mechanism, subject to OPUC final decision, which is expected in the first quarter of 2017. The mechanism, as proposed, would allow the Company to recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and through customer prices, as necessary. The mechanism would establish annual prudency reviews of environmental expenditures and be 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 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 Oregon Supreme Court (OSC) in October 2014.

In 2003, in two separate legal proceedings, lawsuits were filed in Marion County Circuit Court (Circuit Court) against PGE on behalf of two classes of electric service customers. The class action lawsuits seek damages totaling $260 million, plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan.

In August 2006, the 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.

The OSC further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The OSC added that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The OSC also ruled that the plaintiffs retain the right to return to the Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. In October 2006, the Circuit Court abated the class actions in response to the ruling of the OSC.

In June 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. Following oral argument on PGE’s motion for summary judgment, the plaintiffs moved to amend the complaints. On February 22, 2016, the Circuit Court denied the plaintiff’s motion to amend the complaint and on March 16, 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.

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.

Pacific Northwest Refund Proceeding

In response to the Western energy crisis of 2000-2001, the FERC initiated, beginning in 2001, a series of proceedings to determine whether refunds are warranted for bilateral sales of electricity in the Pacific Northwest wholesale spot market during the period December 25, 2000 through June 20, 2001. In an order issued in 2003, the FERC denied refunds. Various parties appealed the order to the Ninth Circuit Court of Appeals (Ninth Circuit) and, on appeal, the Ninth Circuit remanded the issue of refunds to the FERC for further consideration.

On remand, in 2011 and thereafter, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, expanded the refund period to include January 1, 2000 through December 24, 2000 for certain types of claims, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. Those orders included a finding by the FERC that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest. The FERC also held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Refund proponents appealed these procedural orders at the Ninth Circuit. On December 17, 2015, the Ninth Circuit held that the FERC reasonably applied the Mobile-Sierra presumption to the class of contracts at issue in the proceedings and dismissed evidentiary challenges related to the scope of the proceeding. Plaintiffs on behalf of the California Energy Resources Scheduling division of the California Department of Water Resources filed a request for rehearing on February 1, 2016. By order issued April 18, 2016, the Ninth Circuit denied Plaintiffs’ request for panel rehearing of its decision regarding application of the Mobile-Sierra presumption.

In response to the evidence and arguments presented during the hearing, in May 2015, the FERC issued an order finding that the refund proponents had failed to meet the Mobile-Sierra burden with respect to all but one respondent. In December 2015, the FERC denied all requests for rehearing of its order. With respect to the remaining respondent, FERC ordered additional proceedings, and in an order issued October 18, 2016, rejected the Plaintiffs’ request for refunds from the respondent, finding that the Plaintiffs had not met their Mobile-Sierra burden of proof.

The Company has settled all of the direct claims asserted against it in the proceedings for an immaterial amount. The settlements and associated FERC orders did not fully eliminate the potential for so-called “ripple claims,” which have been described by the FERC as “sequential claims against a succession of sellers in a chain of purchases that are triggered if the last wholesale purchaser in the chain is entitled to a refund.” As a result of the FERC orders to date, there are only two sellers from whom ripple claims could arise if those orders are overturned on appeal. Both of these sellers have now authorized on-the- record representations that they would not pursue ripple claims if they were required to pay refunds. As a result, the Company does not believe that it will incur any material loss in connection with this matter.

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 Presentation (Policies)	12 Months Ended
Basis of Presentation Basis of Presentation (Policies)	Dec. 31, 2016
Basis of Presentation [Abstract]
Consolidation, Policy [Policy Text Block]	The consolidated financial statements include the accounts of PGE, its wholly-owned subsidiaries, and those variable interest entities (VIEs) in which PGE has determined it is the primary beneficiary. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. For further information on PGE’s jointly-owned plant, see Note 16, Jointly-Owned Plan. 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 Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2016
Summary of Significant Accounting Policies [Abstract]
Cash and Cash Equivalents, Policy [Policy Text Block]	Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents,
Trade and Other Accounts Receivable, Policy [Policy Text Block]	Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 16 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice. Provisions for uncollectible accounts receivable related to retail sales are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on management’s assessment of the probability of collection, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors. Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable.
Derivatives, Policy [Policy Text Block]	PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, oil, and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statement of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting. Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers. In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument. Electricity and natural gas sale and purchase transactions that are physically settled are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement. Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	Cash deposits provided as collateral are included 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 for use in its generating plants. Fuel inventories include natural gas, coal, and oil. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.
Property, Plant and Equipment, Policy [Policy Text Block]	Electric utility plant is capitalized at its original cost, which includes direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at the Company’s generating plants are charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining a FERC license for the Company’s hydroelectric projects are capitalized and amortized over the related license period. During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made.
Allowance for Funds Used During Construction, Policy [Policy Text Block]	PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes, based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income.
Regulatory Depreciation and Amortization, Policy [Policy Text Block]	Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage.
Depreciation Lives [Policy Text Block]	Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives,
Plant Retirement and Abandonment, Policy [Policy Text Block]	the original cost of 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 the Company’s ability to establish prices to recover specific costs; and ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. PGE periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate.
Power Cost [Policy Text Block]	PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband,” which ranges from $15 million below to $30 million above baseline NVPC. NVPC consists of i) the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income; and is net of ii) wholesale sales, which are classified as Revenues, net in the consolidated statements of income. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from or refunded to customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. PGE’s authorized ROE was 9.6% for 2016, 9.68% for 2015, and 9.75% for 2014. Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review. The PCAM has resulted in no collection from, or refund to, customers since 2011.
Asset Retirement Obligations, Policy [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 a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred. The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability.
Commitments and Contingencies, Policy [Policy Text Block]	Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. 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 reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. Gain contingencies are recognized when realized and are disclosed when material. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted. Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or ii) discloses that an estimate cannot be made and the reasons. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) there are significant facts in dispute; vi) there are a large number of parties (including 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. The prices charged to customers are subject to federal (FERC) or state (OPUC) regulation.
Franchise Tax [Policy Text Block]	Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]	Retail revenue is billed monthly based on meter readings taken throughout the month. Unbilled revenue represents the revenue earned from the 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. For additional information concerning the Company’s Stock-Based Compensation, see Note 13, Stock-Based Compensation Expense.
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 deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability.
Income Tax Uncertainties, Policy [Policy Text Block]	Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheet.
Interest and Penalties Related to Income Taxes [Policy Text Block]	PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income.

Fair Value of Financial Instruments (Policies)

12 Months Ended

Dec. 31, 2016

Fair Value of Financial Instruments [Abstract]

Fair Value of Financial Instruments, Policy [Policy Text Block]


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.

Allocation of Financial Asset to Hierarchy Levels [Policy Text Block]

Transfers in and out of Level 3 [Policy Text Block]

Debt, Policy [Policy Text Block]

Price Risk Management (Policies)	12 Months Ended
Price Risk Management (Policies)	Dec. 31, 2016
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 (Policies)	12 Months Ended
Asset Retirement Obligations (Policies)	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations, Policy [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 a market-risk premium are not available. The present value of estimated future dismantlement and restoration costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. Such estimates are revised periodically, with actual expenditures charged to the ARO as incurred. The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability.

Employee Benefits (Policies)	12 Months Ended
Employee Benefits (Policies)	Dec. 31, 2016
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 not 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 Plans—The non-qualified benefit plans (NQBP) in the following tables include obligations for a Supplemental Executive Retirement Plan and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also include pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in a non-qualified benefit plan trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. 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 non-qualified benefit plans is December 31. Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. PGE holds investments in a non-qualified benefit plan trust that are intended to be a funding source for these plans.

Commitments and Guarantees (Policies)	12 Months Ended
Commitments and Guarantees (Policies)	Dec. 31, 2016
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)	12 Months Ended
Contingencies (Policies)	Dec. 31, 2016
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 reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. Gain contingencies are recognized when realized and are disclosed when material. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted. Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or ii) discloses that an estimate cannot be made and the reasons. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) there are significant facts in dispute; vi) there are a large number of parties (including 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 Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Summary of Significant Accounting Policies [Abstract]

Estimated average service lives [Table Text Block]

Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years):



Generation, excluding thermal:
Hydro	95
Wind	30
Transmission	57
Distribution	45
General	12

Balance Sheet Components (Tables)

12 Months Ended

Dec. 31, 2016

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,
	2016			2015			2014
Balance as of beginning of year	$	6		$	6		$	6
Increase in provision	5			6			6
Amounts written off, less recoveries	(5		)	(6		)	(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
	2016		2015		2016		2015
Cash equivalents	$	21	$	18	$	1	$	1
Marketable securities, at fair value:
Equity securities	—		—		6		5
Debt securities	20		22		1		1
Insurance contracts, at cash surrender value	—		—		26		26
	$	41	$	40	$	34	$	33

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,
	2016		2015
Other current assets:
Prepaid expenses	$	48	$	43
Margin deposits	8		33
Assets from price risk management activities	18		10
Other	3		2
	$	77	$	88
Accrued expenses and other current liabilities:
Regulatory liabilities—current	$	51	$	55
Accrued employee compensation and benefits	52		51
Accrued interest payable	25		25
Accrued dividends payable	30		28
Accrued taxes payable	25		25
Other	71		75
	$	254	$	259

Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2016

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, 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⁾
Money market funds	—		—		—		—		—
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.



	As of December 31, 2015
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	6	$	8	$	—	$	—	$	14
Corporate credit	—		8		—		—		8
Money market funds measured at NAV⁽²⁾	—		—		—		18		18
Non-qualified benefit plan trust: ⁽³⁾
Money market funds	—		—		—		—		—
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	1		—		—		—		1
Investments measured at NAV:⁽²⁾
Money market funds	—		—		—		1		1
Collective trust—domestic equity	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		7		—		—		7
Natural gas	—		3		—		—		3
	$	10	$	26	$	—	$	21	$	57
Liabilities - Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	28	$	105	$	—	$	133
Natural gas	—		144		14		—		158
	$	—	$	172	$	119	$	—	$	291


(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, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 2, Summary of Significant Accounting Policies.


(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, 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
As of December 31, 2015:
Defined Benefit Pension Plan assets:
Equity securities—Domestic	$	44	$	—	$	—	$	—	$	44
Investments measured at NAV:
Money market funds	—		—		—		5		5
Collective trust funds	—		—		—		479		479
Private equity funds	—		—		—		22		22
	$	44	$	—	$	—	$	506	$	550
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	—	$	—	$	—	$	—
Equity securities:
Domestic	—		3		—		—		3
International	8		—		—		—		8
Debt securities—Domestic government	—		5		—		—		5
Investments measured at NAV:
Money market funds	—		—		—		7		7
Collective trust funds	—		—		—		7		7
	$	8	$	8	$	—	$	14	$	30

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, 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
As of December 31, 2015:
Electricity physical forward	$	—	$	105	Discounted cash flow	Electricity forward price (per MWh)	$	8.50	$	84.47	$	30.69
Natural gas financial swaps	—		14		Discounted cash flow	Natural gas forward price (per Dth)	2.06		3.70		2.54
Electricity financial futures	—		—		Discounted cash flow	Electricity forward price (per MWh)	9.98		27.36		19.26
	$	—	$	119

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]



	Years Ended December 31,
	2016			2015
Net liabilities from price risk management activities as of beginning of year	$	119		$	100
Net realized and unrealized losses ^*	11			80
Net transfers in to Level 3 from Level 2	(1		)	—
Net transfers out of Level 3 to Level 2	(10		)	(61		)
Net liabilities from price risk management activities as of end of year	$	119		$	119
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	11		$	80

* Includes nominal net realized losses in 2016 and 2015, respectively.

- Definition

Tabular disclosure of the application of the fair value option for measurement and reporting of eligible financial assets and liabilities (as defined), as well as certain other eligible items (as defined) included in the statement of financial position, whether such option is elected for a single eligible item or a group of similar eligible items and is in addition to other disclosures concerning fair value which the company may be required to provide. Such disclosure might be expected to include: (1) for items included in the statement of financial position: (a) for each line item in the statement of financial position that includes an item or items for which the fair value option has been elected, provide the aggregate carrying amount of ineligible items included in each line item in the balance sheet, if any; (b) the difference between the aggregate fair value and the aggregate unpaid principal balance (assuming contractual principal amounts and fair value option elected) of: (i) loans and long-term receivables (other than securities otherwise reported at fair value) and (ii) long-term debt instruments; (c) for loans held as assets for which the fair value option has been elected: (i) the aggregate fair value of loans that are 90 days or more past due, (ii) if the policy is to recognize interest income separately from other changes in fair value, the aggregate fair value of loans in nonaccrual status, and (iii) the difference between the aggregate fair value and the aggregate unpaid principal balance for loans that are 90 days or more past due, in nonaccrual status, or both; (2) for items included in the income statement: (a) the amounts of gains and losses from fair value changes included in earnings and in which line in the income statement those gains and losses are reported whether or not combined with gains and losses from items required to be accounted for at fair value; (b) for loans and other receivables held as assets, the estimated amount of gains or losses included in earnings attributable to changes in instrument-specific credit risk; (c) for liabilities with fair values that have been significantly affected during the reporting period by changes in the instrument-specific credit risk, the estimated amount of gains and losses from fair value changes included in earnings that are attributable to changes in the instrument-specific credit risk; and (3) certain other disclosures as required or determined to be provided.

+ References + Details

Price Risk Management (Tables)

12 Months Ended

Dec. 31, 2016

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,
	2016			2015
Current assets:
Commodity contracts:
Electricity	$	6		$	7
Natural gas	12			3
Total current derivative assets	18		⁽¹⁾	10		⁽¹⁾
Noncurrent assets:
Commodity contracts:
Electricity	1			—
Natural gas	4			—
Total noncurrent derivative assets	5		⁽²⁾	—		⁽²⁾
Total derivative assets not designated as hedging instruments	$	23		$	10
Total derivative assets	$	23		$	10
Current liabilities:
Commodity contracts:
Electricity	$	12		$	36
Natural gas	32			94
Total current derivative liabilities	44			130
Noncurrent liabilities:
Commodity contracts:
Electricity	106			97
Natural gas	19			64
Total noncurrent derivative liabilities	125			161
Total derivative liabilities not designated as hedging instruments	$	169		$	291
Total derivative liabilities	$	169		$	291


(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]



	As of December 31,
	2016			2015
Commodity contracts:
Electricity	8		MWh	12		MWh
Natural gas	107		Dth	124		Dth
Foreign currency exchange	$	22	Canadian	$	7	Canadian

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]



	Years Ended December 31,
	2016			2015		2014
Commodity contracts:
Electricity	$	34		$	72	$	13
Natural Gas	(56		)	103		72
Foreign currency exchange	—			1		—

Schedule of Price Risk Derivatives [Table Text Block]



	2017		2018		2019		2020		2021		Thereafter		Total
Commodity contracts:
Electricity	$	6	$	7	$	7	$	7	$	7	$	77	$	111
Natural gas	20		7		6		2		—		—		35
Net unrealized loss	$	26	$	14	$	13	$	9	$	7	$	77	$	146

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,
	2016		2015
Assets from price risk management activities:
Counterparty A	22	%	5	%
Counterparty B	17		8
Counterparty C	12		8
Counterparty D	8		10
Counterparty E	1		59
	60	%	90	%
Liabilities from price risk management activities:
Counterparty F	66	%	36	%
Counterparty C	7	%	10	%
Counterparty B	5	%	10	%
	78	%	56	%

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
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-Paragraph 1
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-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

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,
		2016					2015
		Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management ⁽²⁾	6 years	$	26		$	120	$	120		$	161
Pension and other postretirement plans ⁽²⁾	⁽³⁾	—			235		—			239
Deferred income taxes ⁽²⁾	⁽⁴⁾	—			86		—			86
Debt issuance costs ⁽²⁾	6 years	—			22		—			16
Other ⁽⁵⁾	Various	10			35		9			22
Total regulatory assets		$	36		$	498	$	129		$	524
Regulatory liabilities:
Asset retirement removal costs ⁽⁶⁾	⁽⁴⁾	$	—		$	887	$	—		$	837
Trojan decommissioning activities	3 years	18			—		17			15
Asset retirement obligations ⁽⁶⁾	⁽⁴⁾	—			49		—			45
Other	Various	33			22		38			31
Total regulatory liabilities		$	51	⁽⁷⁾	$	958	$	55	⁽⁷⁾	$	928


(1)	As of December 31, 2016.


(2)	Does not include a return on investment.


(3)	Recovery expected over the average service life of employees.


(4)	Recovery expected over the estimated lives of the assets.


(5)	Of the total other unamortized regulatory asset balances, a return is recorded on $44 million and $29 million as of December 31, 2016 and 2015, 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 (Tables)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

AROs consist of the following (in millions):



	As of December 31,
	2016		2015
Trojan decommissioning activities	$	44	$	43
Utility plant	105		97
Non-utility property	12		11
Asset retirement obligations	$	161	$	151

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,
	2016			2015			2014
Balance as of beginning of year	$	151		$	116		$	100
Liabilities incurred	1			2			15
Liabilities settled	(3		)	(4		)	(3		)
Accretion expense	7			7			6
Revisions in estimated cash flows	5			30			(2		)
Balance as of end of year	$	161		$	151		$	116

Credit Facilities (Tables)

12 Months Ended

Dec. 31, 2016

Line of Credit Facility [Abstract]

Schedule of Short-term Debt [Table Text Block]

Short-term borrowings under these credit facilities and related interest rates were as follows (dollars in millions):



	Years Ended December 31,
	2016			2015			2014
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)

12 Months Ended

Dec. 31, 2016

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,
	2016			2015
First Mortgage Bonds, rates range from 2.51% to 9.31%, with a weighted average rate of 4.86% in 2016 and 5.29% in 2015, due at various dates through 2048	$	2,090		$	2,083
Unsecured term bank loans, variable rates of approximately 1.37% due 2017	150			—
Pollution Control Revenue Bonds, 5% rate, due 2033	142			142
Pollution Control Revenue Bonds owned by PGE	(21		)	(21		)
Total long-term debt	2,361			2,204
Less: Unamortized debt expense	(11		)	(11		)
Less: Current portion of long-term debt	(150		)	(133		)
Long-term debt, net of current portion	$	2,200		$	2,060

Schedule of Maturities of Long-term Debt [Table Text Block]

As of December 31, 2016, the future minimum principal payments on long-term debt are as follows (in millions):



Years ending December 31:
2017	$	150
2018	—
2019	300
2020	—
2021	160
Thereafter	1,751
	$	2,361

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
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-Subparagraph (SX 210.5-02.22)
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+ Details

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2016

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):



	2016						2015
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust	$	16	$	18	$	34	$	15	$	18	$	33
Non-qualified benefit plan liabilities *	25		80		105		25		81		106


*	For the NQBP, excludes the current portion of $2 million in 2016 and 2015, 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,
	2016				2015
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	68	%	67	%	67	%	67	%
Debt securities	32		33		33		33
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	60	%	62	%	60	%	64	%
Debt securities	40		38		40		36
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	15	%	11	%	15	%	14	%
Debt securities	7		11		7		8
Insurance contracts	78		78		78		78
Total	100	%	100	%	100	%	100	%

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, 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⁾
Money market funds	—		—		—		—		—
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.



	As of December 31, 2015
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	6	$	8	$	—	$	—	$	14
Corporate credit	—		8		—		—		8
Money market funds measured at NAV⁽²⁾	—		—		—		18		18
Non-qualified benefit plan trust: ⁽³⁾
Money market funds	—		—		—		—		—
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	1		—		—		—		1
Investments measured at NAV:⁽²⁾
Money market funds	—		—		—		1		1
Collective trust—domestic equity	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		7		—		—		7
Natural gas	—		3		—		—		3
	$	10	$	26	$	—	$	21	$	57
Liabilities - Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	28	$	105	$	—	$	133
Natural gas	—		144		14		—		158
	$	—	$	172	$	119	$	—	$	291


(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, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 2, Summary of Significant Accounting Policies.


(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, 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
As of December 31, 2015:
Defined Benefit Pension Plan assets:
Equity securities—Domestic	$	44	$	—	$	—	$	—	$	44
Investments measured at NAV:
Money market funds	—		—		—		5		5
Collective trust funds	—		—		—		479		479
Private equity funds	—		—		—		22		22
	$	44	$	—	$	—	$	506	$	550
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	—	$	—	$	—	$	—
Equity securities:
Domestic	—		3		—		—		3
International	8		—		—		—		8
Debt securities—Domestic government	—		5		—		—		5
Investments measured at NAV:
Money market funds	—		—		—		7		7
Collective trust funds	—		—		—		7		7
	$	8	$	8	$	—	$	14	$	30

Schedule of Defined Benefit Plans Disclosures [Table Text Block]



	Defined Benefit Pension Plan						Other Postretirement Benefits						Non-Qualified Benefit Plans
	2016			2015			2016			2015			2016			2015
Benefit obligation:
As of January 1	$	758		$	777		$	81		$	83		$	27		$	27
Service cost	16			18			2			2			—			—
Interest cost	33			31			4			3			1			1
Participants’ contributions	—			—			2			2			—			—
Actuarial (gain) loss	26			(31		)	(11		)	(4		)	1			1
Contractual termination benefits	—			—			—			1			—			—
Benefit payments	(34		)	(35		)	(5		)	(6		)	(2		)	(2		)
Administrative expenses	(2		)	(2		)	—			—			—			—
As of December 31	$	797		$	758		$	73		$	81		$	27		$	27
Fair value of plan assets:
As of January 1	$	550		$	591		$	30		$	32		$	15		$	15
Actual return on plan assets	45			(4		)	1			(2		)	1			—
Company contributions	—			—			2			4			2			2
Participants’ contributions	—			—			2			2			—			—
Benefit payments	(34		)	(35		)	(5		)	(6		)	(2		)	(2		)
Administrative expenses	(2		)	(2		)	—			—			—			—
As of December 31	$	559		$	550		$	30		$	30		$	16		$	15
Unfunded position as of December 31	$	(238	)	$	(208	)	$	(43	)	$	(51	)	$	(11	)	$	(12	)
Accumulated benefit plan obligation as of December 31	$	714		$	681		N/A			N/A			$	27		$	27
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	16		$	15
Current liability	—			—			—			—			(2		)	(2		)
Noncurrent liability	(238		)	(208		)	(43		)	(51		)	(25		)	(25		)
Net liability	$	(238	)	$	(208	)	$	(43	)	$	(51	)	$	(11	)	$	(12	)
Amounts included in comprehensive income:
Net actuarial loss (gain)	$	21		$	13		$	(10	)	$	—		$	1		$	1
Amortization of net actuarial loss	(14		)	(20		)	—			(1		)	(1		)	(1		)
Amortization of prior service cost	—			—			(1		)	(1		)	—			—
	$	7		$	(7	)	$	(11	)	$	(2	)	$	—		$	—
Amounts included in AOCL*:
Net actuarial loss (gain)	$	236		$	228		$	(2	)	$	9		$	13		$	13
Prior service cost	—			—			1			1			—			—
	$	236		$	228		$	(1	)	$	10		$	13		$	13



	Defined Benefit Pension Plan				Other Postretirement Benefits						Non-Qualified Benefit Plans
	2016		2015		2016			2015			2016		2015
Assumptions used:
Discount rate for benefit obligation	4.17	%	4.36	%	3.75	%	-	3.90	%	-	4.17	%	4.36	%
					4.23	%		4.45	%
Discount rate for benefit cost	4.36	%	4.02	%	3.90	%	-	3.07	%	-	4.36	%	4.02	%
					4.45	%		4.10	%
Weighted average rate of compensation increase for benefit obligation	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Weighted average rate of compensation increase for benefit cost	3.65	%	3.65	%	4.58	%		4.58	%		N/A		N/A
Long-term rate of return on plan assets for benefit obligation	7.50	%	7.50	%	6.26	%		6.29	%		N/A		N/A
Long-term rate of return on plan assets for benefit cost	7.50	%	7.50	%	6.29	%		6.37	%		N/A		N/A

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
	2016			2015			2014			2016			2015			2014			2016		2015		2014
Service cost	$	16		$	18		$	15		$	2		$	2		$	2		$	—	$	—	$	—
Interest cost on benefit obligation	33			31			34			4			3			4			1		1		1
Expected return on plan assets	(40		)	(40		)	(39		)	(2		)	(2		)	(2		)	—		—		—
Amortization of prior service cost	—			—			—			1			1			1			—		—		—
Amortization of net actuarial loss	14			20			17			—			1			1			1		1		1
Net periodic benefit cost	$	23		$	29		$	27		$	5		$	5		$	6		$	2	$	2	$	2

Schedule of Expected Benefit Payments [Table Text Block]

The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions):



	Payments Due
	2017		2018		2019		2020		2021		2022 - 2026
Defined benefit pension plan	$	37	$	39	$	40	$	42	$	43	$	229
Other postretirement benefits	5		5		5		4		5		22
Non-qualified benefit plans	3		2		3		2		2		10
Total	$	45	$	46	$	48	$	48	$	50	$	261

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

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,
	2016		2015		2014
Current:
Federal	$	10	$	4	$	20
State and local	3		1		2
	13		5		22
Deferred:
Federal	23		26		26
State and local	14		14		13
	37		40		39
Income tax expense	$	50	$	45	$	61

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,
	2016		2015		2014
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
Federal tax credits *	(18.2	)	(19.0	)	(11.4	)
State and local taxes, net of federal tax benefit	4.8		4.2		3.9
Flow through depreciation and cost basis differences	0.2		—		(2.3	)
Other	(1.2	)	0.5		0.8
Effective tax rate	20.6	%	20.7	%	26.0	%

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,
	2016			2015
Deferred income tax assets:
Employee benefits	$	181		$	170
Price risk management	59			112
Regulatory liabilities	29			42
Tax credits	56			46
Other	5			—
Total deferred income tax assets	330			370
Deferred income tax liabilities:
Depreciation and amortization	829			781
Regulatory assets	170			220
Other	—			1
Total deferred income tax liabilities	999			1,002
Deferred income tax liability, net	$	(669	)	$	(632	)

Stock-based Compensation Expense Restricted and Performance Stock Unit activity (Tables)

12 Months Ended

Dec. 31, 2016

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, 2013	431,090		$	26.31
Granted	203,410		31.49
Forfeited	(12,278	)	29.90
Vested	(158,329	)	24.95
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

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:



	2016					2015
Risk-free interest rate				0.9	%				1.0	%
Expected dividend yield				—	%				—	%
Expected term (in years)				3.0					3.0
Volatility	14.5	%	-	25.9	%	13.2	%	-	19.2	%

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2016

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,
	2016	2015	2014
Weighted average common shares outstanding—basic	88,896	84,180	78,180
Dilutive effect of potential common shares	158	161	2,314
Weighted average common shares outstanding—diluted	89,054	84,341	80,494

Commitments and Guarantees (Tables)

12 Months Ended

Dec. 31, 2016

Long-term Purchase Commitment [Line Items]

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

As of December 31, 2016, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):



	Payments Due
	2017		2018		2019		2020		2021		Thereafter		Total
Capital and other purchase commitments	$	176	$	8	$	2	$	9	$	1	$	60	$	256
Purchased power and fuel:
Electricity purchases	221		157		181		256		239		1,750		2,804
Capacity contracts	7		6		5		4		4		12		38
Public utility districts	4		4		1		—		1		11		21
Natural gas	53		39		32		27		24		158		333
Coal and transportation	17		9		5		—		—		—		31
Total	$	478	$	223	$	226	$	296	$	269	$	1,991	$	3,483

Schedule of Long-term Contracts for Purchase of Electric Power [Table Text Block]

PGE has long-term power purchase agreements with certain public utility districts in the state of Washington and with the City of Portland, Oregon. Under the agreements, the Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether or not they are operable. The future minimum payments for the public utility districts in the preceding table reflect the principal payment only and do not include interest, operation, or maintenance expenses.

Selected information regarding these projects is summarized as follows (dollars in millions):



	Revenue Bonds as of December 31, 2016		PGE’s Share as of December 31, 2016			Contract Expiration	PGE Cost, including Debt Service
	Revenue Bonds as of December 31, 2016		Output		Capacity	Contract Expiration	2016		2015		2014
					(in MW)
Priest Rapids and Wanapum	$	1,190	8.6	%	163	2052	$	16	$	18	$	14
Wells	177		19.4		150	2018	10		10		10
Portland Hydro	—		100.0		36	2017	1		2		4

Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block]



	Future Minimum Lease Payments
	Capital Leases		Build-to-Suit		Operating Leases
2017	$	7	$	—	$	10
2018	7		4		9
2019	6		14		6
2020	6		13		6
2021	6		13		7
Thereafter	77		237		177
Total minimum lease payments	$	109	$	281	$	215
Less imputed interest	55
Present value of net minimum lease payments	$	54
Less current portion	3
Non-current portion	$	51

Jointly-owned Plant (Tables)

12 Months Ended

Dec. 31, 2016

Jointly-owned Plant [Abstract]

Schedule of Jointly Owned Utility Plants [Table Text Block]

As of December 31, 2016, 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			$	514	$	400	$	—
Colstrip	20.00		1986			528		342		9
Pelton/Round Butte	66.67		1958	/	1964	255		63		5
Total						$	1,297	$	805	$	14


*	Excludes AROs and accumulated asset retirement removal costs.

Basis of Presentation (Details) $ in Millions	12 Months Ended
Basis of Presentation (Details) $ in Millions	Dec. 31, 2014 USD ($)	Dec. 31, 2016 mi² shares retail_customers
Basis of Presentation [Abstract]
Proceeds from Legal Settlements \| $	$ 6
Incorporated Cities		51
Service Area Sq Miles \| mi²		4,000
Number of Retail Customers \| retail_customers		863,000
Service area population		1,900,000
Percent of State's Population		46.00%
Entity Number of Employees		2,752
Number of Union Employees		783
Number of Union Employees Subject to Agreement A		730
Number of Union Employees Subject to Agreement B		53
Proceeds from Insurance Settlement, Investing Activities \| $	3
Proceeds from Sale of Productive Assets \| $	$ 5

Summary of Significant Accounting Policies Estimated average service lives (Details)	12 Months Ended
	Dec. 31, 2016
Production, excluding thermal:
Hydro	95
Wind	30
Transmission	57
Distribution	45
General	12

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2016
Property, Plant and Equipment [Line Items]
Unamortized Debt Issuance Expense	$ 11	$ 11
Other Investments	$ 1	0
Business days after the invoice date	16
Days after the due date	45
Wholesale accounts receivable written off	$ 0	0	$ 0
Margin deposit	8	33
Letters of Credit Outstanding, Amount	$ 17	$ 63
Public Utilities, Allowance for Funds Used During Construction, Rate	7.30%	7.30%	7.40%
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest	$ 11	$ 13	$ 22
Allowance for equity funds used during construction	21	21	$ 37
Construction in Progress, Gross	634
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	$ 213	$ 545
Depreciation expense rate	3.50%	3.60%	3.60%
Finite-Lived Intangible Assets, Accumulated Amortization	$ 257	$ 227
Amortization of Intangible Assets	44	$ 38	$ 25
Future Amortization Expense, Year One	45
Future Amortization Expense, Year Two	44
Future Amortization Expense, Year Three	38
Future Amortization Expense, Year Four	34
Future Amortization Expense, Year Five	22
Power Cost Deadband - Lower Threshold	15
Power Cost Deadband - Upper Threshold	$ 30
Public Utilities, Approved Return on Equity, Percentage	9.60%	9.68%	9.75%
Franchise taxes	$ 43	$ 43	$ 42
Deferred Tax Assets, Regulatory Assets and Liabilities	29	42
Public Utilities, Property, Plant and Equipment, Amount of Construction Work in Process Included in Rate Base				$ 514
excess tax benefits recognized related to share-based payment awards	1
Proceeds and Excess Tax Benefit from Share-based Compensation	3	2
Type of Arrangement [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	514
Noncurrent Regulatory Assets [Member]
Property, Plant and Equipment [Line Items]
Deferred Tax Assets, Regulatory Assets and Liabilities	86	86
Noncurrent Regulatory Liabilities [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligations, Noncurrent	$ 49	$ 45

Balance Sheet Components Allowance for Uncollectible accounts activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance as of beginning of year	$ 6	$ 6	$ 6
Increase in provision	5	6	6
Amounts written off, less recoveries	(5)	(6)	(6)
Balance as of end of year	$ 6	$ 6	$ 6

Balance Sheet Components Investments Held in Trust (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Marketable securities, at fair value:
Decommissioning Fund Investments, Fair Value	$ 41	$ 40
Non-qualified benefit plan trust	34	33
Nuclear Decommissioning [Member]
Cash equivalents	21	18
Marketable securities, at fair value:
Equity securities	0	0
Debt securities	20	22
Insurance contracts, at cash surrender value	0	0
Decommissioning Fund Investments, Fair Value	41	40
Non Qualified Benefit Plans [Member]
Cash equivalents	1	1
Marketable securities, at fair value:
Equity securities	6	5
Debt securities	1	1
Insurance contracts, at cash surrender value	26	26
Non-qualified benefit plan trust	$ 34	$ 33

Balance Sheet Components Schedule of Other Asssets and Other Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other current assets:
Prepaid Expense, Current	$ 48	$ 43
Margin Deposit Assets	8	33
Assets from price risk management activities	18	10
Other	3	2
Other Assets, Current	77	88
Accrued expenses and other current liabilities:
Regulatory Liability, Current	51	55
Accrued employee compensation and benefits	52	51
Accrued interest payable	25	25
Dividends payable	30	28
Taxes Payable, Current	25	25
Other	71	75
Other Liabilities, Current	$ 254	$ 259

Balance Sheet Components (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
Balance Sheet Components (Details) - USD ($) $ in Millions	Sep. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2016	Dec. 31, 2015
Allowance for Doubtful Accounts Receivable, Current		$ 6	$ 6	$ 6	$ 6
Loss Contingency, Damages Awarded, Value	$ 81
Jointly Owned Electricity Generation Plant [Member]
Loss Contingency, Damages Awarded, Value		$ 6	$ 44

Fair Value of FInancial Instruments Schedule of Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	$ 21	$ 18
Domestic government, Debt securities	12	14
Corporate debt securities held in decommissioning trust assets	8	8
Fair Value - Money market funds	1	0
Domestic Equity Securities	4	3
Debt securities - domestic government	1	1
Alternative Investments, Fair Value Disclosure		1
Investments, Fair Value Disclosure	2	2
Electricity	7	7
Natural gas	16	3
Liabilities from price risk management activities: [Abstract]
Electricity	118	133
Natural gas	51	158
Liabilities, Fair Value Disclosure	169	291
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Assets, Fair Value Disclosure	72	57
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Domestic government, Debt securities	2	6
Corporate debt securities held in decommissioning trust assets	0	0
Fair Value - Money market funds	1	0
Domestic Equity Securities	4	3
Debt securities - domestic government	1	1
Electricity	0	0
Natural gas	0	0
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	10	8
Corporate debt securities held in decommissioning trust assets	8	8
Fair Value - Money market funds	0	0
Domestic Equity Securities	0	0
Debt securities - domestic government	0	0
Electricity	6	7
Natural gas	15	3
Liabilities from price risk management activities: [Abstract]
Electricity	6	28
Natural gas	42	144
Liabilities, Fair Value Disclosure	48	172
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	0
Domestic government, Debt securities	0	0
Corporate debt securities held in decommissioning trust assets	0	0
Fair Value - Money market funds		0
Domestic Equity Securities	0	0
Debt securities - domestic government	0	0
Electricity	1	0
Natural gas	1	0
Liabilities from price risk management activities: [Abstract]
Electricity	112	105
Natural gas	9	14
Liabilities, Fair Value Disclosure	121	119
Non Qualified Benefit Plans [Member]
Liabilities from price risk management activities: [Abstract]
Insurance contracts, at cash surrender value	$ 26	$ 26

Fair Value of FInancial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Minimum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	$ 14.25	$ 8.50
Natural gas financial swaps	1.85	2.06
Fnancial swaps - electricity	8.57	9.98
Maximum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	54.73	84.47
Natural gas financial swaps	4.92	3.70
Fnancial swaps - electricity	33.60	27.36
Weighted Average [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	38.18	30.69
Natural gas financial swaps	2.64	2.54
Fnancial swaps - electricity	25.10	19.26
Assets [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	0	0
Natural gas financial swaps	1,000,000	0
Fnancial swaps - electricity	1,000,000	0
Total commodity contracts	2,000,000	0
Liabilities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	112,000,000	105,000,000
Natural gas financial swaps	9,000,000	14,000,000
Fnancial swaps - electricity	0	0
Total commodity contracts	$ 121,000,000	$ 119,000,000

Fair Value of FInancial Instruments Fair Value Unobservable Input Reconciliation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net realized and unrealized losses	$ 11,000,000	$ 80,000,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	(1,000,000)	0
Net transfers out of Level 3 to Level 2	(10,000,000)	(61,000,000)
Net liabilities from price risk management activities as of end of year	119,000,000	119,000,000	$ 100,000,000
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	11,000,000	80,000,000
Net realized losses	$ 0	$ 0

Fair Value of Financial Instruments (Details) - USD ($)	12 Months Ended
Fair Value of Financial Instruments (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Net realized losses	$ 0	$ 0
Long-term Debt, Fair Value	2,693,000,000	2,455,000,000
Long-term Debt	2,361,000,000	2,204,000,000
Unamortized Debt Issuance Expense	11,000,000	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	1,000,000	0
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	$ 2,350,000,000	$ 2,193,000,000

Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets, Commodity Contracts:
Electricity	$ 6	$ 7
Natural Gas	12	3
Total current derivative assets	18	10
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	1	0
Commodity Contract Asset, Noncurrent, Natural Gas	4	0
Derivative Asset, Noncurrent	5	0
Total derivative assets not designated as hedging instruments	23	10
Total derivative assets	23	10
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	12	36
Natural Gas	32	94
Total current derivative liabilities	44	130
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	106	97
Natural Gas	19	64
Total noncurrent derivative liabilities	125	161
Total derivative liabilities not designated as hedging instruments	169	291
Total derivative liabilities	$ 169	$ 291

Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Dec. 31, 2016 CAD ($) MMBTU MWh	Dec. 31, 2015 CAD ($) MMBTU MWh
Commodity contracts: [Abstract]
Electricity \| MWh	8	12
Natural gas \| MMBTU	107	124
Foreign currency exchange \| $	$ 22	$ 7

Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commodity contracts: [Abstract]
Electricity	$ 34	$ 72	$ 13
Natural Gas	(56)	103	72
Realized And Unrealized Losses Net Commodity Contracts, Foreign Currency	$ 0	$ 1	$ 0

Future year net unrealized gain/loss recorded at balance sheet date expected to become realized (Details) $ in Millions	Dec. 31, 2016 USD ($)
Electricity [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	$ 6
Other Commitment, Due in Second Year	7
Other Commitment, Due in Third Year	7
Other Commitment, Due in Fourth Year	7
Other Commitment, Due in Fifth Year	7
Other Commitment, Due after Fifth Year	77
Total	111
Natural Gas [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	20
Other Commitment, Due in Second Year	7
Other Commitment, Due in Third Year	6
Other Commitment, Due in Fourth Year	2
Other Commitment, Due in Fifth Year	0
Other Commitment, Due after Fifth Year	0
Total	35
Unrealized Gain Loss On Derivatives [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	26
Other Commitment, Due in Second Year	14
Other Commitment, Due in Third Year	13
Other Commitment, Due in Fourth Year	9
Other Commitment, Due in Fifth Year	7
Other Commitment, Due after Fifth Year	77
Total	$ 146

Counterparties representing 10% or more (Details)	Dec. 31, 2016	Dec. 31, 2015
Assets from price risk management activities:
Counterparty A	22.00%	5.00%
Counterparty B	17.00%	8.00%
Counterparty C	12.00%	8.00%
Counterparty D	8.00%	10.00%
Counterparty E	1.00%	59.00%
Concentration of Risk, Derivative Instruments, Assets	60.00%	90.00%
Liabilities from price risk management activities: [Abstract]
Counterparty F	66.00%	36.00%
Counterparty C for PRM Liabs	7.00%	10.00%
Counterparty B for PRM Liabs	5.00%	10.00%
Concentration of Risk, Derivative Instruments, Liabilities	78.00%	56.00%

Price Risk Management (Details) - USD ($) $ in Millions	12 Months Ended
Price Risk Management (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 115	$ 111
Derivative, Collateral, Right to Reclaim Cash	11	14
Net gain or loss recognized in the statement of income offset by regulatory accounting	13	160	$ 83
Derivative, Net Liability Position, Aggregate Fair Value	164
Collateral Already Posted, Aggregate Fair Value	14
Collateral Aggregate Fair Value	149
Margin Deposit Assets	0
Electricity [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	112	104
Natural Gas [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 3	$ 7

Regulatory Assets and Liabilities Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Remaining Recovery Period of Regulatory Assets, Price Risk Management	6 years
Remaining Recovery Period of Regulatory Asset, Debt Reacquisition Costs	6 years
Price risk management	$ 18	$ 10
Deferred income taxes	$ 29	42
Remaining refund period of regulatory liability, Trojan decommissioning activities	3 years
Current Regulatory Liabilities [Member]
Regulatory Assets [Line Items]
Asset retirement removal costs	$ 0	0
Proceeds from Legal Settlements	18	17
Asset retirement obligations	0	0
Other	33	38
Total regulatory liabilities	51	55
Noncurrent Regulatory Liabilities [Member]
Regulatory Assets [Line Items]
Asset retirement removal costs	887	837
Proceeds from Legal Settlements	0	15
Asset retirement obligations	49	45
Other	22	31
Total regulatory liabilities	958	928
Regulatory Assets, Current [Member]
Regulatory Assets [Line Items]
Price risk management	26	120
Pension and other postretirement plans	0	0
Deferred income taxes	0	0
Debt reacquisition costs	0	0
Other	10	9
Total regulatory assets	36	129
Noncurrent Regulatory Assets [Member]
Regulatory Assets [Line Items]
Price risk management	120	161
Pension and other postretirement plans	235	239
Deferred income taxes	86	86
Debt reacquisition costs	22	16
Other	35	22
Total regulatory assets	$ 498	$ 524

Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets Earning a Return, Other Category	$ 44	$ 29
Regulatory Assets Earning a Return	44
Regulatory Assets Earning a Rate of Return at the Cost of Capital	$ 19
Authorized Cost of Capital	7.56%
Regulatory Assets Earning a Rate of Return by Inclusion in Rate Base	$ 22
Regulatory Assets Earning a Rate of Return at the Approved Rate	$ 3
Approved Rate for Deferred Account Under Amortization, Low End of Range	1.47%
Approved Rate for Deferred Accounts under Amortization, High End of Range	2.20%

Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Trojan decommissioning activities	$ 44	$ 43
Utility plant	105	97
Non-utility property	12	11
Asset Retirement Obligation	$ 161	$ 151	$ 116	$ 100

Schedule of Change in Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation		$ 151	$ 116	$ 100
Asset Retirement Obligation, Liabilities Incurred		1	2	15
Asset Retirement Obligation, Liabilities Settled		(3)	(4)	(3)
Asset Retirement Obligation, Accretion Expense		7	7	6
Asset Retirement Obligation, Revision of Estimate	$ (3)	(5)	(30)	(2)
Asset Retirement Obligation	$ 151	$ 161	$ 151	$ 116

Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Proceeds from Decommissioning Trust Fund Assets				$ 50
Litigation Settlement, Amount	$ 1			79
Gain Contingency, Unrecorded Amount				2
Asset Retirement Obligation Rate Recovery related to Trojan Plant				4
Asset Retirement Obligation, Period Increase (Decrease)				$ 9
Asset Retirement Obligations, Significant Changes				6	17
Asset Retirement Obligation, Revision of Estimate		$ 3		$ 5	$ 30	$ 2
Asset Retirement Obligation, Accretion Expense				7	7	6
Asset Retirement Obligation, Liabilities Incurred				1	2	$ 15
Loss Contingency, Damages Awarded, Value			$ 81
Utility Plant [Domain]
Asset Retirement Obligation, Revision of Estimate				6	4
Asset Retirement Obligation, Accretion Expense				6
Asset Retirement Obligation, Liabilities Incurred				$ 3	$ 9

Credit Facilities Schedule of Short term debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Average daily amount of short-term debt outstanding	$ 1	$ 0	$ 0
Weighted daily average interest rate	0.70%	0.60%	0.00%
Maximum amount outstanding during the year	$ 23	$ 11	$ 0

Credit Facilities (Details) $ in Millions	12 Months Ended
Credit Facilities (Details) $ in Millions	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Line of Credit Facility [Abstract]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500
Line of Credit Facitlity, Covenant Terms, One Month Term	1
Line of Credit Facitlity, Covenant Terms, Two Month Term	2
Line of Credit Facitlity, Covenant Terms, Three Month Term	3
Line of Credit Facitlity, Covenant Terms, Six Month Term	6
Debt Instrument, Covenant Description	0.65
Ratio of Indebtedness to Net Capital	0.510
Commercial Paper, Maximum Term	270
Commercial Paper	$ 0	$ 6
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	160
Letters of Credit Outstanding, Amount	$ 56

Long-term Debt Schedule of Long Term Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.42% in 2014 and 5.62% in 2013, due at various dates through 2048	$ 2,090	$ 2,083
Unsecured Debt, Current	150	0
Pollution Control Revenue Bonds, 5% rate, due 2033	142	142
Pollution Control Revenue Bonds owned by PGE	(21)	(21)
Debt Instrument, Unamortized Discount	(11)	(11)
Total long-term debt	2,361	2,204
Less: current portion of long-term debt	(150)	(133)
Long-term debt, net of current portion	$ 2,200	$ 2,060

Long-term Debt Schedule of Maturities of Long term debt (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
2017	$ 150
2018	0
2019	300
2020	0
2021	160
Thereafter	1,751
Total long-term debt	$ 2,361	$ 2,204

Long term debt (Details) - USD ($) $ in Millions	1 Months Ended	2 Months Ended	12 Months Ended
Long term debt (Details) - USD ($) $ in Millions	Jan. 31, 2016	Feb. 29, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Oct. 31, 2016	Sep. 30, 2016	May 04, 2016	May 01, 2016	Jan. 29, 2016
Debt Instrument [Line Items]
Proceeds from Issuance of First Mortgage Bond			$ 140
Repayments of Debt	$ 133	$ 58	75
Long-term Line of Credit, Noncurrent			200
Debt Instrument, Face Amount						$ 25	$ 75	$ 50
Long-term Pollution Control Bond			$ 21
Debt Instrument, Interest Rate, Stated Percentage	2.51%		5.00%						5.80%	3.81%
Proceeds from Issuance of Long-term Debt	$ 140		$ 290	$ 145	$ 585
First mortgage Bonds - minimum rate			2.51%
Unsecured Debt, Current			$ 150	$ 0
First Mortgage Bonds - maximum rate			9.31%
Debt, Weighted Average Interest Rate			4.86%	5.29%
Line of Credit Facility, Interest Rate During Period			1.37%
Unsecured term bank loan rate - minimum			6300.00%
Line of Credit Facility, Interest Rate at Period End			1.37%
Line of Credit Facility, Commitment Fee Percentage			0.00%
Pollution Control Revenue Bonds owned by PGE			$ 21	$ 21

Employee Benefits Assets and Liabilities associated with Non-qualified benefit plans (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	$ 34	$ 33
Non-qualified benefit plan liabilities	105	106
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	18	18
Non-qualified benefit plan liabilities	80	81
Non Qualified Benefit Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	16	15
Non-qualified benefit plan liabilities	25	25
Total Non-qualified benefit plan trust assets [Domain]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	34
Non-qualified benefit plan liabilities	$ 105	$ 106

Employee Benefits Schedule of Allocation of Plan Assets (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Defined Benefit Pension Plan [Member] \| Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	67.00%	67.00%
Defined Benefit Plan, Actual Plan Asset Allocations	68.00%	67.00%
Defined Benefit Pension Plan [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	33.00%	33.00%
Defined Benefit Plan, Actual Plan Asset Allocations	32.00%	33.00%
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Other Postretirement Benefit Plans [Member] \| Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	62.00%	64.00%
Defined Benefit Plan, Actual Plan Asset Allocations	60.00%	60.00%
Other Postretirement Benefit Plans [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	38.00%	36.00%
Defined Benefit Plan, Actual Plan Asset Allocations	40.00%	40.00%
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Non Qualified Benefit Plans [Member] \| Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	11.00%	14.00%
Defined Benefit Plan, Actual Plan Asset Allocations	15.00%	15.00%
Non Qualified Benefit Plans [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	11.00%	8.00%
Defined Benefit Plan, Actual Plan Asset Allocations	7.00%	7.00%
Non Qualified Benefit Plans [Member] \| Other Contract [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	78.00%	78.00%
Defined Benefit Plan, Actual Plan Asset Allocations	78.00%	78.00%

Employee Benefits Schedule of Fair Value, Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Money Market Funds, at Carrying Value	$ 21	$ 18
Investments, Fair Value Disclosure	2	2
Equity securities:
Domestic	52	44
Defined Benefit Plan, Fair Value of Plan Assets		550
Financial Instruments, Owned, at Fair Value	23	21
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds		0
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	6	5
Investments, Fair Value Disclosure	18	22
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments, Fair Value Disclosure	483	479
Fair Value, Inputs, Level 1 [Member]
Equity securities:
Domestic	52	44
Private equity funds	0	0
Defined Benefit Plan, Fair Value of Plan Assets	52	44
Financial Instruments, Owned, at Fair Value	8	10
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds	4	0
Domestic equity securities - Other postretirement benefit plan assets at fair value	0	0
International equity securities - other post retirement assets at fair value	8	8
Other post retirement benefit plan assets total	12	8
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	39	26
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	7	8
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	2	0
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	559	550	$ 591
Financial Instruments, Owned, at Fair Value	507	506
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Money Market Funds, at Carrying Value	4	7
Investments, Fair Value Disclosure	7	7
Equity securities:
Defined Benefit Plan, Fair Value of Plan Assets	30	30	$ 32
Financial Instruments, Owned, at Fair Value	11	$ 14
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

Employee Benefits Schedule of Changes in Fair Value of Plan Assets (Details) $ in Millions	Dec. 31, 2015 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 550

Employee Benefits Schedule of Defined Benefit Plan Disclosures (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets		$ 4	$ 5
Fair value of plan assets:
Benefit payments	$ (16)
As of January 1			550
Classification in consolidated balance sheet:
Noncurrent asset		(34)	(33)
Noncurrent liability		(281)	(259)
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		52	44
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets		4	5
Fair value of plan assets:
As of January 1		0	0
Pension Plans, Defined Benefit [Member]
Benefit obligation:
As of January 1		797	758	$ 777
Fair value of plan assets:
Service cost		16	18	15
Interest cost on benefit obligation		33	31	34
Participants’ contributions		0	0
Actuarial loss (gain)		26	(31)
Defined Benefit Plan, Special Termination Benefits		0	0
Benefit payments		(34)	(35)
Defined Benefit Plan, Administration Expenses		(2)	(2)
As of January 1		559	550	591
Unfunded position as of December 31		238	208
Net actuarial loss (gain) included in comprehensive income		21	13
Defined Benefit Plan, Amortization of Gains (Losses)		(14)	(20)	(17)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0	0	0
Total Amounts included in comprehensive income		7	(7)
Defined Benefit Plan, Accumulated Benefit Obligation		714	681
Actual return on plan assets		45	(4)
Company contributions		0	0
Classification in consolidated balance sheet:
Noncurrent asset		0	0
Current liability		0	0
Noncurrent liability		(238)	(208)
Amounts included in AOCL:
Net actuarial loss		236	228
Prior service cost		0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		$ 236	$ 228
Assumptions used:
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate		4.17%	4.36%
Discount rate used to calculate benefit obligation		4.36%	4.02%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Rate of Compensation Increase		3.65%	3.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.65%	3.65%
Long-term rate of return on plan assets		7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		7.50%	7.50%
Other Postretirement Benefit Plans [Member]
Benefit obligation:
As of January 1		$ 73	$ 81	83
Fair value of plan assets:
Service cost		2	2	2
Interest cost on benefit obligation		4	3	4
Participants’ contributions		2	2
Actuarial loss (gain)		(11)	(4)
Defined Benefit Plan, Special Termination Benefits		0	1
Benefit payments		(5)	(6)
Defined Benefit Plan, Administration Expenses		0	0
As of January 1		30	30	32
Unfunded position as of December 31		43	51
Net actuarial loss (gain) included in comprehensive income		(10)	0
Defined Benefit Plan, Amortization of Gains (Losses)		0	(1)	(1)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		(1)	(1)	(1)
Total Amounts included in comprehensive income		(11)	(2)
Actual return on plan assets		1	(2)
Company contributions		2	4
Classification in consolidated balance sheet:
Noncurrent asset		0	0
Current liability		0	0
Noncurrent liability		(43)	(51)
Amounts included in AOCL:
Net actuarial loss		(2)	9
Prior service cost		1	1
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		$ (1)	$ 10
Assumptions used:
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Obligation, Discount Rate		3.75%	3.90%
Defined Benefit Plan Discount rate - upper range		4.23%	4.45%
Discount rate used to calculate benefit obligation		3.90%	3.07%
Defined Benefit Plan Cost Discount rate - upper range		4.45%	4.10%
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%	6.29%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		6.29%	6.37%
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, Special Termination Benefits		0	0
Benefit payments		(2)	(2)
Defined Benefit Plan, Administration Expenses		0	0
As of January 1		16	15	15
Unfunded position as of December 31		11	12
Net actuarial loss (gain) included in comprehensive income		1	1
Defined Benefit Plan, Amortization of Gains (Losses)		(1)	(1)	(1)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0	0	$ 0
Total Amounts included in comprehensive income		0	0
Defined Benefit Plan, Accumulated Benefit Obligation		27	27
Actual return on plan assets		1	0
Company contributions		2	2
Classification in consolidated balance sheet:
Noncurrent asset		(16)	(15)
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		4.17%	4.36%
Discount rate used to calculate benefit obligation		4.36%	4.02%

Employee Benefits Schedule of Net Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2	$ 2	$ 2
Interest cost on benefit obligation	4	3	4
Expected return on plan assets	(2)	(2)	(2)
Amortization of prior service cost	1	1	1
Amortization of net actuarial loss	0	1	1
Net periodic benefit cost	5	5	6
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	16	18	15
Interest cost on benefit obligation	33	31	34
Expected return on plan assets	(40)	(40)	(39)
Amortization of prior service cost	0	0	0
Amortization of net actuarial loss	14	20	17
Net periodic benefit cost	23	29	27
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 Expected Benefit Payments (Details) $ in Millions	Dec. 31, 2016 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 45
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	46
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	48
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	48
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	50
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	261
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	37
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	39
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	40
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	42
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	43
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	229
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	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	3
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) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
Employee Benefits (Details) - USD ($) $ in Millions	Sep. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Pension Contributions		$ 0	$ 0	$ 0
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year		$ 3
Defined Benefit Plan, Benefits Paid	$ 16
Contribution to health reimbursement account - sick time		58.00%
Contribution to health reimbursement account - earned time off		100.00%
OtherPostretirementDefinedBenefitPlanLiabilityCurrent		$ 2	$ 2
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year		15
Net actuarial loss portion of amortization from AOCL for pension benefits		13
Net Actuarial Loss Portion of Amortization from AOCL for Non-qualified benefits		1
Net actuarial loss portion of amortiztion of AOCL for other postretirement benefits		$ 1
Defined benefit plan, current annual rate of health care cost increase		7.00%	6.50%	7.00%
Defined Benefit Plan, Description of Direction and Pattern of Change for Assumed Health Care Cost Trend Rate		0.065	0.06
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year		0.25%	0.25%	0.50%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components		$ 0
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		$ 19	$ 17	$ 16

Income Taxes Schedule of Components of Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current:
Federal	$ 10	$ 4	$ 20
State and local	3	1	2
Current Income Tax Expense (Benefit)	13	5	22
Deferred:
Federal	23	26	26
State and local	14	14	13
deferred income tax expense	37	40	39
Income tax expense	$ 50	$ 45	$ 61

Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Abstract]
Federal statutory tax rate	35.00%	35.00%	35.00%
Federal tax credits	(18.20%)	(19.00%)	(11.40%)
State and local taxes, net of federal tax benefit	4.80%	4.20%	3.90%
Flow through depreciation and cost basis differences	0.20%	0.00%	(2.30%)
Other	(1.20%)	0.50%	0.80%
Effective tax rate	20.60%	20.70%	26.00%

Income Taxes Schedule of Deferred tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Deferred income tax assets:
Employee benefits	$ 181	$ 170
Price risk management	59	112
Deferred income taxes	29	42
Deferred Tax Assets, tax credits, net of valuation allowance	56	46
Deferred Tax Assets, Tax Deferred Expense, Other	5	0
Total deferred income tax assets	330	370
Deferred income tax liabilities:
Depreciation and amortization	829	781
Regulatory assets	170	220
Deferred Tax Liabilities, Other	0	1
Deferred Tax Liabilities, Gross, Noncurrent	999	1,002
Total deferred income tax liabilities	$ (669)	$ (632)

Income Taxes Income taxes (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Federal	$ 56
Deferred Tax Assets, Valuation Allowance	0	$ 0
Unrecognized Tax Benefits	$ 0	$ 0

Equity-Based Plans (Details) - USD ($)	3 Months Ended			12 Months Ended
Equity-Based Plans (Details) - USD ($)	Jun. 30, 2015	Sep. 30, 2013	Jun. 30, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	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	$ 271,000,000	$ 0
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				369,419
Dividend Reinvestment and Direct Stock Purchase Plan Shares				2,500,000
Dividend Reinvestment and Direct Stock Purchase Plan, Number of Available Shares				2,474,164

Stock-based Compensation Expense Restricted and Performance Stock Unit Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract]
Outstanding, Units	442,993	463,893	431,090
Outstanding, Weighted Average Grant Date Fair Value	$ 32.84	$ 28.96	$ 26.31
Granted, Units	193,734	181,797	203,410
Granted, Weighted Average Grant Date Fair Value	$ 35.89	$ 34.77	$ 31.49
Forfeited, Units	(3,044)	(14,988)	(12,278)
Forfeited, Weighted Average Grant Date Fair Value	$ 28.62	$ 34.10	$ 29.90
Vested, Units	(174,891)	(187,709)	(158,329)
Vested, Weighted Average Grant Date Fair Value	$ 31.47	$ 25.82	$ 24.95
Outstanding, Units	458,792	442,993	463,893
Outstanding, Weighted Average Grant Date Fair Value	$ 34.68	$ 32.84	$ 28.96

Stock-based Compensation Expense Schedule Of Share Based Payment Award Stock Options Valuation Assumptions (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	0.90%	1.00%
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	14.50%	13.20%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum	25.90%	19.20%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	0.00%	0.00%

Stock-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation			$ 6	$ 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			3,305,920
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			5	4	3
Adjustments Related to Tax Withholding for Share-based Compensation			2	$ 0	$ 1
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized			$ 6
Stock-based Compensation, Attainment of Performance Goals That Allows Vesting			121.20%	117.30%	111.20%
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	$ 4

Earnings Per Share Schedule of Earnings per Share, Basic and Diluted (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Weighted Average Number of Shares Outstanding, Basic	88,896	84,180	78,180
Weighted Average Number Diluted Shares Outstanding Adjustment	158	161	2,314
Weighted Average Number of Shares Outstanding, Diluted	89,054	84,341	80,494

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 Unrecorded Unconditional Purchase Obligations (Details) $ in Millions	Dec. 31, 2016 USD ($)
Capital Additions [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	$ 256
Unrecorded Unconditional Purchase Obligation, Due within One Year	176
Unrecorded Unconditional Purchase Obligation, Due within Two Years	8
Unrecorded Unconditional Purchase Obligation, Due within Three Years	2
Unrecorded Unconditional Purchase Obligation, Due within Four Years	9
Unrecorded Unconditional Purchase Obligation, Due within Five Years	1
Unrecorded Unconditional Purchase Obligation, Due after Five Years	60
Long-term Contract for Purchase of Electric Power [Domain]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	2,804
Unrecorded Unconditional Purchase Obligation, Due within One Year	221
Unrecorded Unconditional Purchase Obligation, Due within Two Years	157
Unrecorded Unconditional Purchase Obligation, Due within Three Years	181
Unrecorded Unconditional Purchase Obligation, Due within Four Years	256
Unrecorded Unconditional Purchase Obligation, Due within Five Years	239
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,750
Electric Transmission [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	38
Unrecorded Unconditional Purchase Obligation, Due within One Year	7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	6
Unrecorded Unconditional Purchase Obligation, Due within Three Years	5
Unrecorded Unconditional Purchase Obligation, Due within Four Years	4
Unrecorded Unconditional Purchase Obligation, Due within Five Years	4
Unrecorded Unconditional Purchase Obligation, Due after Five Years	12
Public Utility Districts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	21
Unrecorded Unconditional Purchase Obligation, Due within One Year	4
Unrecorded Unconditional Purchase Obligation, Due within Two Years	4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	1
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	1
Unrecorded Unconditional Purchase Obligation, Due after Five Years	11
Natural gas [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	333
Unrecorded Unconditional Purchase Obligation, Due within One Year	53
Unrecorded Unconditional Purchase Obligation, Due within Two Years	39
Unrecorded Unconditional Purchase Obligation, Due within Three Years	32
Unrecorded Unconditional Purchase Obligation, Due within Four Years	27
Unrecorded Unconditional Purchase Obligation, Due within Five Years	24
Unrecorded Unconditional Purchase Obligation, Due after Five Years	158
Coal and transportationSupply Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	31
Unrecorded Unconditional Purchase Obligation, Due within One Year	17
Unrecorded Unconditional Purchase Obligation, Due within Two Years	9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	5
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	3,483
Unrecorded Unconditional Purchase Obligation, Due within One Year	478
Unrecorded Unconditional Purchase Obligation, Due within Two Years	223
Unrecorded Unconditional Purchase Obligation, Due within Three Years	226
Unrecorded Unconditional Purchase Obligation, Due within Four Years	296
Unrecorded Unconditional Purchase Obligation, Due within Five Years	269
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 1,991

Commitments and Guarantees Schdule of Long term contracts for purchase of electric power (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) MW	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Priest Rapids and Wanapum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 1,190
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	$ 18	$ 14
Wells [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 177
PGE Share of Output	19.40%
PGE Share of Capacity \| MW	150
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2018
commitment costs	$ 10	10	10
Portland Hydro [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 0
PGE Share of Output	100.00%
PGE Share of Capacity \| MW	36
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2017
commitment costs	$ 1	$ 2	$ 4

Commitments and Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Future Minimum Payments Receivable, in Five Years	$ 3
Unrecorded Unconditional Purchase Obligation [Line Items]
Operating Leases, Future Minimum Payments Receivable, in Two Years	3
Operating Leases, Future Minimum Payments, Due in Three Years	$ 3
percentage of output	25.00%
Contractual Obligation	$ 281
Operating Leases, Rent Expense	10	$ 0	$ 11
Operating Leases, Rent Expense, Sublease Rentals	4	$ 3	$ 3
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Three Years	$ 3

Commitments and Guarantees Lease Obligations (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Dec. 31, 2016

Jun. 30, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Long-term Purchase Commitment [Line Items]

Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress

$ 14

Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals

Operating Leases, Rent Expense, Sublease Rentals

$ 3

Capital Leases, Future Minimum Payments Due, Next Twelve Months

Contractual Obligation, Due in Next Fiscal Year

Operating Leases, Future Minimum Payments Due, Next Twelve Months

$ 10

Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block]



	Future Minimum Lease Payments
	Capital Leases		Build-to-Suit		Operating Leases
2017	$	7	$	—	$	10
2018	7		4		9
2019	6		14		6
2020	6		13		6
2021	6		13		7
Thereafter	77		237		177
Total minimum lease payments	$	109	$	281	$	215
Less imputed interest	55
Present value of net minimum lease payments	$	54
Less current portion	3
Non-current portion	$	51

Capital Leased Assets, Gross

$ 57

Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation

Capital Leases, Future Minimum Payments Due in Two Years

Contractual Obligation, Due in Second Year

Operating Leases, Future Minimum Payments, Due in Two Years

Capital Leases, Future Minimum Payments Due in Three Years

Contractual Obligation, Due in Third Year

Operating Leases, Future Minimum Payments, Due in Three Years

Capital Leases, Future Minimum Payments Due in Four Years

Contractual Obligation, Due in Fourth Year

Operating Leases, Future Minimum Payments, Due in Four Years

Capital Leases, Future Minimum Payments Due in Five Years

Contractual Obligation, Due in Fifth Year

Operating Leases, Future Minimum Payments, Due in Five Years

Capital Leases, Future Minimum Payments Due Thereafter

Contractual Obligation, Due after Fifth Year

237

Operating Leases, Future Minimum Payments, Due Thereafter

177

Capital Leases, Future Minimum Payments Due

109

Contractual Obligation

281

Operating Leases, Future Minimum Payments Due

215

Capital Leases, Future Minimum Payments, Interest Included in Payments

Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments

Capital Lease Obligations, Current

Purchase Commitment, Remaining Minimum Amount Committed

Deferred Costs, Leasing, Accumulated Amortization

$ 2

Interest Expense, Lessee, Assets under Capital Lease

$ 3

Long-term Purchase Commitment, Amount

128

Capital Addition Purchase Commitments [Member]

Long-term Purchase Commitment [Line Items]

Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress

$ 21

Jointly-owned Plant Schedule of Jointly-owned plant (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
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	1980
Jointly Owned Utility Plant, Gross Ownership Amount of Boardman Plant In Service	$ 514
Jointly Owned Utility Plant, Ownership Amount of Boardman Plant Accumulated Depreciation	400
Jointly Owned Utility Plant Ownership Amount of Construction Work In Progress Boardman	$ 0
Jointly Owned Utility Plant, Proportionate Ownership Share of Colstrip	20.00%
Jointly Owned Plant, Colstrip Plant In Service Year	1986
Jointly Owned Utility Plant, Gross Ownership Amount of Colstrip Plant In Service	$ 528
Jointly Owned Utility Plant, Ownership Amount of Colstrip Plant Accumulated Depreciation	342
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Colstrip	$ 9
Jointly Owned Utility Plant, Proportionate Ownership Share of Pelton/Round Butte	66.67%
Jointly Owned Plant, Pelton Plant in Service Year	1958
Jointly Owned Plant, Round Butte in Service Year	1964
Jointly Owned Utility Plant, Gross Ownership Amount of Pelton/Round Butte Plant In Service	$ 255
Jointly Owned Utility Plant, Ownership Amount of Pelton/Round Butte Plant Accumulated Depreciation	63
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Pelton/Round Butte	5
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	1,297
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	805
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 14

Contingencies (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
Contingencies (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 1997	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2008	Dec. 31, 1993
Loss Contingencies [Line Items]
Malpractice Loss Contingency, Letters of Credit and Surety Bonds	$ 145.6	$ 145.6
Long-term Purchase Commitment, Amount	200.0	200.0
Loss Contingency, Damages Sought, Value		1,200.0
Construction in Progress, Gross	634.0	634.0
Total capital spending on new generation asset	640.0	640.0
Liability for Title Claims and Claims Adjustment Expense	17.0	17.0
Loss Contingency Accrual	0.0	$ 0.0
Site Contingency, Names of Other Potentially Responsible Parties		100	69
Litigation Settlement, Expense		$ 115.0
Loss Contingency, Range of Possible Loss, Maximum	1,700.0	1,700.0
Loss Contingency, Range of Possible Loss, Portion Not Accrued	500.0	500.0
Loss Contingency, Inestimable Loss	1,050.0	1,050.0
investment in Trojan							87.00%
Refund to customers for Trojan Investment including interest						$ 33.0
Class action damages sought					$ 260.0
Litigation Settlement, Amount	$ 1.0	$ 79.0
Jointly Owned Utility Plant, Proportionate Ownership Share of Colstrip	20.00%	20.00%
Public Utilities, Property, Plant and Equipment, Amount of Construction Work in Process Included in Rate Base				$ 514.0