Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Oct. 16, 2015 | |
Entity Information [Line Items] | ||
Entity Registrant Name | PORTLAND GENERAL ELECTRIC CO /OR/ | |
Entity Central Index Key | 784,977 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2015 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 88,772,420 | |
Trading Symbol | POR |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Revenues, net | $ 476 | $ 484 | $ 1,399 | $ 1,400 |
Operating expenses: | ||||
Purchased power and fuel | 181 | 202 | 490 | 528 |
Generation, transmission and distribution | 64 | 60 | 192 | 181 |
Administrative and other | 59 | 54 | 179 | 164 |
Depreciation and amortization | 76 | 76 | 227 | 224 |
Taxes other than income taxes | 28 | 27 | 86 | 82 |
Total operating expenses | 408 | 419 | 1,174 | 1,179 |
Income from operations | 68 | 65 | 225 | 221 |
Interest expense, net | 28 | 23 | 86 | 71 |
Other income: | ||||
Allowance for equity funds used during construction | 6 | 11 | 15 | 26 |
Miscellaneous income (expense), net | (2) | 1 | 0 | 1 |
Other income, net | 4 | 12 | 15 | 27 |
Income before income tax expense | 44 | 54 | 154 | 177 |
Income tax expense | 8 | 16 | 33 | 46 |
Net income and Comprehensive income | 36 | 38 | 121 | 131 |
Less: net loss attributable to noncontrolling interests | 0 | (1) | 0 | (1) |
Net income and Comprehensive income attributable to Portland General Electric Company | $ 36 | $ 39 | $ 121 | $ 132 |
Weighted-average shares outstanding (in thousands): | ||||
Basic | 88,766 | 78,203 | 82,633 | 78,170 |
Diluted | 88,766 | 80,225 | 82,633 | 79,977 |
Earnings per share: | ||||
Basic | $ 0.40 | $ 0.48 | $ 1.47 | $ 1.67 |
Diluted | 0.40 | 0.47 | 1.47 | 1.63 |
Dividends declared per common share | $ 0.300 | $ 0.280 | $ 0.880 | $ 0.835 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 92 | $ 127 |
Accounts receivable, net | 133 | 149 |
Unbilled revenues | 72 | 93 |
Inventories | 94 | 82 |
Regulatory assets - current | 122 | 133 |
Other current assets | 92 | 115 |
Total current assets | 605 | 699 |
Electric utility plant, net | 5,920 | 5,679 |
Regulatory assets - noncurrent | 547 | 494 |
Nuclear decommissioning trust | 40 | 90 |
Non-qualified benefit plan trust | 33 | 32 |
Other noncurrent assets | 52 | 48 |
Total assets | 7,197 | 7,042 |
Current liabilities | ||
Accounts payable | 96 | 156 |
Liabilities from price risk mangement activities - current | 115 | 106 |
Current portion of long-term debt | 0 | 375 |
Accrued expenses and other current liabilities | 254 | 236 |
Total current liabilities | 465 | 873 |
Long-term debt, net of current portion | 2,204 | 2,126 |
Regulatory liabilities - noncurrent | 939 | 906 |
Deferred income taxes | 664 | 625 |
Unfunded status of pension and postretirement plans | 246 | 237 |
Liabilities from price risk mangement activities - noncurrent | 184 | 122 |
Asset retirement obligations | 137 | 116 |
Non-qualified benefit plan liabilities | 105 | 105 |
Other noncurrent liabilities | 21 | 21 |
Total liabilities | $ 4,965 | $ 5,131 |
Commitments and contingencies (see notes) | ||
Equity: | ||
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2015 and December 31, 2014 | $ 0 | $ 0 |
Common stock, no par value, 160,000,000 shares authorized; 88.772,172 and 78,228,339 shares issued and outstanding as of September 30, 2015 and December 31, 2014, respectively | 1,193 | 918 |
Accumulated other comprehensive loss | (7) | (7) |
Retained earnings | 1,046 | 1,000 |
Total equity | 2,232 | 1,911 |
Total liabilities and equity | $ 7,197 | $ 7,042 |
Condensed Consolidated Balance4
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares | Sep. 30, 2015 | Dec. 31, 2014 |
Preferred stock, no par value | $ 0 | $ 0 |
Preferred stock, shares authorized | 30,000,000 | 30,000,000 |
Preferred stock, issued | 0 | 0 |
Preferred stock, outstanding | 0 | 0 |
Common stock, no par value | $ 0 | $ 0 |
Common stock, shares authorized | 160,000,000 | 160,000,000 |
Common stock, shares issued | 88,772,172 | 78,228,339 |
Common stock, shares outstanding | 88,772,172 | 78,228,339 |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Cash flows from operating activities: | ||
Net income | $ 121 | $ 131 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 227 | 224 |
Increase (decrease) in net liabilities from price risk management activities | 71 | (60) |
Regulatory deferrals-price risk management activities | (71) | 60 |
Deferred income taxes | 31 | 31 |
Pension and other postretirement benefits | 25 | 25 |
Allowance for equity funds used during construction | (15) | (26) |
Regulatory deferral of settled derivative instruments | 0 | 9 |
Decoupling mechanism deferrals, net of amortization | 10 | 4 |
Other non-cash income and expenses, net | 19 | 18 |
Changes in working capital: | ||
Decrease in accounts receivable and unbilled revenues | 37 | 32 |
Increase in Inventories | (12) | (18) |
(Increase) decrease in margin deposits, net | (9) | 4 |
Increase in accounts payable and accrued liabilities | 13 | 18 |
Other working capital items, net | 15 | 16 |
Cash (paid) received pursuant to the Residential Exchange Program | (3) | 13 |
Proceeds received from Trojan spent fuel legal settlement | 0 | 6 |
Other, net | (20) | (14) |
Net cash provided by operating activities | 439 | 473 |
Cash flows from investing activities: | ||
Capital expenditures | (452) | (824) |
Distribution from (contribution to) Nuclear decommissioning trust | 50 | (6) |
Sales tax refund received related to Tucannon River Wind Farm | 23 | 0 |
Sales of nuclear decommissioning trust securities | 11 | 13 |
Purchases of nuclear decommissioning trust securities | (10) | (15) |
Proceeds received from insurance recovery | 0 | 3 |
Proceeds from sale of property | 0 | 4 |
Other, net | 1 | 4 |
Net cash used in investing activities | (377) | (821) |
Cash flows from financing activities: | ||
Proceeds from Issuance of common stock, net of issuance costs | 271 | 0 |
Proceeds from issuance of long-term debt | 145 | 405 |
Payments on long-term debt | (442) | 0 |
Dividends paid | (70) | (66) |
Debt Issuance Costs | (1) | (1) |
Net cash (used in) provided by financing activities | (97) | 338 |
Decrease in cash and cash equivalents | (35) | (10) |
Cash and cash equivalents, beginning of period | 127 | 107 |
Cash and cash equivalents, end of period | 92 | 97 |
Supplemental cash flow information is as follows: | ||
Cash paid for interest, net of amounts capitalized | 67 | 52 |
Cash paid for income taxes | 3 | 16 |
Non-cash investing and financing activities: | ||
Accrued capital additions | 25 | 76 |
Accrued dividends payable | $ 28 | $ 23 |
Basis of Presentation (Notes)
Basis of Presentation (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Basis of Presentation [Abstract] | |
BASIS OF PRESENTATION | BASIS OF PRESENTATION Nature of Business Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, 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. PGE’s corporate headquarters are located in Portland, Oregon and its approximately 4,000 square mile, state-approved service area allocation is located entirely within the state of Oregon, encompassing 52 incorporated cities, of which Portland and Salem are the largest. As of September 30, 2015 , PGE served 851,650 retail customers with a service area population of approximately 1.8 million , comprising approximately 46% of the state’s population. Condensed Consolidated Financial Statements These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading. To conform with the 2015 presentation, PGE has separately presented Increase in inventories of $18 million from Other working capital items, net in the operating activities section of the condensed consolidated statement of cash flows for the nine months ended September 30, 2014 . The financial information included herein for the three and nine month periods ended September 30, 2015 and 2014 is unaudited; however, such information reflects all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary for a fair presentation of the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. The financial information as of December 31, 2014 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2014 , included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 13, 2015 , which should be read in conjunction with such condensed consolidated financial statements. Comprehensive Income PGE had no material components of other comprehensive income to report for the three and nine month periods ended September 30, 2015 and 2014 . Use of Estimates The preparation of condensed consolidated financial statements in accordance with 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 experienced by the Company could differ materially from those estimates. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas, interim financial results do not necessarily represent those to be expected for the year. 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 or as a cumulative-effect adjustment as of the date of adoption, which was originally January 1, 2017 for the Company. In August 2015, the Financial Accounting Standards Board (FASB) issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (ASU 2014-14) that defers the effective date by one year, although it permits early adoption as of the original effective date. 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 2014-09. 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 provisions of ASU 2015-03 are effective for fiscal years beginning after December 15, 2015, or January 1, 2016 for PGE, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. The provisions should be applied on a retrospective basis. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle, which includes: i) the nature of and reason for the change in accounting principle; ii) the transition method; iii) a description of the prior-period information that has been retrospectively adjusted; and iv) the effect of the change on the financial statement line items. 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. The adoption of the provisions of ASU 2015-03 and ASU 2015-15 are not expected to have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows. 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 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 practical expedient. Instead, such disclosures are restricted only to investments that the entity has decided to measure using the practical expedient. This standard is effective for interim and annual periods beginning after December 15, 2015. PGE will adopt the amendments contained in ASU 2015-07 on January 1, 2016, which is not expected to have an impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows. In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory (ASU 2015-11), which changes the measurement principle for inventory from the lower of cost or market to lower of cost and net realizable value . Net realizable value is defined as the “estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation.” ASU 2015-11 eliminates the guidance that entities consider replacement cost or net realizable value less an approximately normal profit margin in the subsequent measurement of inventory when cost is determined on a first-in, first-out or average cost basis. The provisions of ASU 2015-11 are effective for public entities with fiscal years beginning after December 15, 2016, or January 1, 2017 for PGE, and interim periods within those fiscal years. 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 2015-11. |
Balance Sheet Components (Notes
Balance Sheet Components (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Balance Sheet Components [Abstract] | |
BALANCE SHEET COMPONENTS | BALANCE SHEET COMPONENTS 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 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. During the nine months ended September 30, 2015, the Company’s inventory balance increased largely as a result of contractual deliveries of coal exceeding usage due to plant maintenance and economic dispatch decisions. Other Current Assets Other current assets consist of the following (in millions): September 30, December 31, 2014 Prepaid expenses $ 24 $ 39 Current deferred income tax asset 39 33 Margin deposits 20 11 Accrued sales tax refund related to Tucannon River Wind Farm — 23 Assets from price risk management activities 7 6 Other 2 3 Other current assets $ 92 $ 115 Electric Utility Plant, Net Electric utility plant, net consists of the following (in millions): September 30, December 31, Electric utility plant $ 8,458 $ 8,161 Construction work-in-progress 508 417 Total cost 8,966 8,578 Less: accumulated depreciation and amortization (3,046 ) (2,899 ) Electric utility plant, net $ 5,920 $ 5,679 Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $219 million and $191 million as of September 30, 2015 and December 31, 2014 , respectively. Amortization expense related to intangible assets was $10 million and $6 million for the three months ended September 30, 2015 and 2014 , respectively, and $28 million and $18 million for the nine months ended September 30, 2015 and 2014 , respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs. Regulatory Assets and Liabilities Regulatory assets and liabilities consist of the following (in millions): September 30, 2015 December 31, 2014 Current Noncurrent Current Noncurrent Regulatory assets: Price risk management $ 108 $ 184 $ 100 $ 121 Pension and other postretirement plans — 232 — 247 Deferred income taxes — 87 — 86 Debt issuance costs — 17 — 15 Deferred capital projects 5 — 19 — Other 9 27 14 25 Total regulatory assets $ 122 $ 547 $ 133 $ 494 Regulatory liabilities: Asset retirement removal costs $ — $ 833 $ — $ 804 Trojan decommissioning activities 19 21 23 34 Asset retirement obligations — 44 — 39 Other 26 41 37 29 Total regulatory liabilities $ 45 * $ 939 $ 60 * $ 906 * Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets. Accrued Expenses and Other Current Liabilities Accrued expenses and other current liabilities consist of the following (in millions): September 30, December 31, 2014 Regulatory liabilities—current $ 45 $ 60 Accrued employee compensation and benefits 44 51 Accrued interest payable 40 26 Accrued dividends payable 28 23 Accrued taxes payable 40 22 Other 57 54 Total accrued expenses and other current liabilities $ 254 $ 236 Asset Retirement Obligations Asset retirement obligations (AROs) consist of the following (in millions): September 30, December 31, 2014 Trojan decommissioning activities $ 43 $ 41 Utility plant 83 64 Non-utility property 11 11 Asset retirement obligations $ 137 $ 116 Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites and distribution and transmission assets where disposal is governed by environmental regulation. 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 plants and not closed. The rule’s requirements for covered CCR impoundments and landfills 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 new EPA rule. PGE is evaluating its disposal strategy, however the Company believes the new EPA rule will not have a material effect on operations at Boardman. Colstrip utilizes wet scrubbers and a number of settlement ponds that will require upgrading or closure to meet the new regulatory requirements. The operator of Colstrip has provided an initial cost estimate related to the impacts of the new EPA rule. As a result, during the second quarter of 2015, the Company recorded an increase to the existing Colstrip AROs in the amount of $15 million , with a corresponding increase in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. PGE plans to seek recovery in customer prices of the incremental costs associated with the new EPA rule. Credit Facilities During the first quarter of 2015, PGE determined that a $500 million aggregate revolving credit facility capacity would be sufficient to meet its liquidity needs and accordingly reduced its aggregate revolving credit capacity from $700 million to $500 million . As of September 30, 2015 , PGE has a $500 million revolving credit facility, which is scheduled to expire in November 2019 . Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes and as backup for commercial paper borrowings, and also permits 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 credit facility. The revolving credit facility contains provisions 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% of total capitalization. As of September 30, 2015 , PGE was in compliance with this covenant with a 49.7% 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 on the condensed consolidated balance sheets. Under the credit facility, as of September 30, 2015 , PGE had no borrowings or commercial paper outstanding, $3 million of letters of credit issued, and an aggregate available capacity under the credit facility of $497 million . In addition, PGE has four letter of credit facilities providing $135 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 four facilities, $93 million of letters of credit were outstanding, as of September 30, 2015 . Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2016 . The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested. In September 2015, PGE filed an application with the FERC to extend the authorization for two additional years. An order from the FERC is expected by year end. Long-term Debt During the nine months ended September 30, 2015 , PGE had the following long-term debt transactions: • In July, repaid $55 million of long-term bank loans; • In June, repaid $200 million of long-term bank loans; • In May, issued $70 million of 3.50% Series First Mortgage Bonds (FMBs) due 2035 and repaid $67 million of 6.80% Series FMBs, due January 2016; • In February, repaid $50 million of long-term bank loans; and • In January, issued $75 million of 3.55% Series FMBs due 2030 and repaid $70 million of 3.46% Series FMBs. Defined Benefit Pension Plan Costs Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Service cost $ 4 $ 4 $ 13 $ 11 Interest cost 8 8 24 25 Expected return on plan assets (10 ) (9 ) (30 ) (29 ) Amortization of net actuarial loss 5 4 15 13 Net periodic benefit cost $ 7 $ 7 $ 22 $ 20 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value of Financial Instruments [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 condensed consolidated balance sheets, for which it is practicable to estimate fair value as of September 30, 2015 and December 31, 2014 , and then classifies these financial assets and liabilities based on a fair value hierarchy. The fair value hierarchy is utilized to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are discussed below. Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 2 Pricing inputs include those that are directly or indirectly observable in the marketplace as of the reporting date. Level 3 Pricing inputs include significant inputs that are unobservable for the asset or liability. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all 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 three and nine month periods ended September 30, 2015 and 2014 , except those transfers from Level 3 to Level 2 presented in this note. The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions): As of September 30, 2015 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trust: (1) Money market funds $ — $ 17 $ — $ 17 Debt securities: Domestic government 5 8 — 13 Corporate credit — 10 — 10 Non-qualified benefit plan trust: (2) Equity securities—domestic 4 2 — 6 Debt securities—domestic government 1 — — 1 Assets from price risk management activities: (1) (3) Electricity — 5 — 5 Natural gas — 2 — 2 $ 10 $ 44 $ — $ 54 Liabilities from price risk management activities: (1) (3) Electricity $ — $ 31 $ 117 $ 148 Natural gas — 99 52 151 $ — $ 130 $ 169 $ 299 (1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate. (2) Excludes insurance policies of $26 million , which are recorded at cash surrender value. (3) For further information, see Note 4, Price Risk Management. As of December 31, 2014 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trust: (1) Money market funds $ — $ 65 $ — $ 65 Debt securities: Domestic government 7 7 — 14 Corporate credit — 11 — 11 Non-qualified benefit plan trust: (2) Equity securities: Domestic 4 1 — 5 International 1 — — 1 Assets from price risk management activities: (1) (3) Electricity — 4 1 5 Natural gas — 2 — 2 $ 12 $ 90 $ 1 $ 103 Liabilities from price risk management activities: (1) (3) Electricity $ — $ 32 $ 80 $ 112 Natural gas — 95 21 116 $ — $ 127 $ 101 $ 228 (1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate. (2) Excludes insurance policies of $26 million , which are recorded at cash surrender value. (3) For further information, see Note 4, Price Risk Management. Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors: Money market funds —PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. Money market funds are classified as Level 2 in the fair value hierarchy as the securities are traded in active markets of similar securities but are not directly valued using quoted market prices. Debt securities —PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yields and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. Equity securities —Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as the NASDAQ and the New York Stock Exchange. Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy because pricing inputs are directly or indirectly observable in the marketplace. Assets and liabilities from price risk management activities are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 4, 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: Fair Value Valuation Technique Significant Unobservable Input Price per Unit Commodity Contracts Assets Liabilities Low High Weighted Average (in millions) As of September 30, 2015: Electricity physical forward $ — $ 117 Discounted cash flow Electricity forward price (per MWh) $ 11.00 $ 71.77 $ 29.82 Natural gas financial swaps — 52 Discounted cash flow Natural gas forward price (per Decatherm) 2.06 3.83 2.56 Electricity financial futures — — Discounted cash flow Electricity forward price (per MWh) 21.07 31.00 27.21 $ — $ 169 As of December 31, 2014: Electricity physical forward $ — $ 77 Discounted cash flow Electricity forward price (per MWh) $ 11.97 $ 122.72 $ 37.43 Natural gas financial swaps — 21 Discounted cash flow Natural gas forward price (per Decatherm) 2.88 4.86 3.41 Electricity financial futures 1 3 Discounted cash flow Electricity forward price (per MWh) 11.97 39.26 27.88 $ 1 $ 101 The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter term contracts, the Company 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 aggregated 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 monthly basis by the Company. This process includes analytical review of changes in commodity prices as well as procedures to analyze and identify the reasons for the changes over specific reporting periods. The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and the Company’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows: Significant Unobservable Input Position Change to Input Impact on Fair Value Measurement Market price Buy Increase (decrease) Gain (loss) Market price Sell Increase (decrease) Loss (gain) Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions): Three Months Ended Nine Months Ended 2015 2014 2015 2014 Balance as of the beginning of the period $ 168 $ 89 $ 100 $ 139 Net realized and unrealized losses (gains) * 15 9 85 (45 ) Settlements — (1 ) — (1 ) Transfers out of Level 3 to Level 2 (14 ) 1 (16 ) 5 Balance as of the end of the period $ 169 $ 98 $ 169 $ 98 * Contains nominal amounts of realized losses. Both realized and unrealized losses (gains), of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income. 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 three and nine months ended September 30, 2015 and 2014 , there were no transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its financial 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 condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. The fair value of PGE’s unsecured term bank loans, which were fully repaid in July 2015, was classified as Level 3 based on the terms of the loans and the Company’s creditworthiness. These 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 September 30, 2015 , the carrying amount of PGE’s long-term debt was $2,204 million and its estimated aggregate fair value was $2,530 million , classified as Level 2 in the fair value hierarchy. As of December 31, 2014 , the carrying amount of PGE’s long-term debt was $2,501 million and its estimated aggregate fair value was $2,901 million , consisting of $2,596 million and $305 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy. |
Price Risk Management (Notes)
Price Risk Management (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
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 and manage risk. Such activities include purchases and sales of both power and fuel resulting from economic dispatch decisions for Company-owned generation. As a result, 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 flows. PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign currency exchange rate risk in order to reduce volatility in NVPC for its retail customers. These derivative instruments may include forwards, futures, swaps, and option contracts, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, oil, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery processes authorized by the Public Utility Commission of Oregon (OPUC), PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative instruments 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): September 30, December 31, Current assets: Commodity contracts: Electricity $ 5 $ 4 Natural gas 2 2 Total current derivative assets 7 (1) 6 (1) Noncurrent assets: Commodity contracts: Electricity — 1 Total noncurrent derivative assets — (2) 1 (2) Total derivative assets not designated as hedging instruments $ 7 $ 7 Total derivative assets $ 7 $ 7 Current liabilities: Commodity contracts: Electricity $ 38 $ 54 Natural gas 77 52 Total current derivative liabilities 115 106 Noncurrent liabilities: Commodity contracts: Electricity 110 58 Natural gas 74 64 Total noncurrent derivative liabilities 184 122 Total derivative liabilities not designated as hedging instruments $ 299 $ 228 Total derivative liabilities $ 299 $ 228 (1) Included in Other current assets on the condensed consolidated balance sheets. (2) Included in Other noncurrent assets on the condensed 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 through 2035, were as follows (in millions): September 30, 2015 December 31, 2014 Commodity contracts: Electricity 13 MWh 16 MWh Natural gas 124 Decatherms 127 Decatherms Foreign currency $ 7 Canadian $ 7 Canadian PGE has elected to report gross on the condensed consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of September 30, 2015 and December 31, 2014, gross amounts included as Price risk management liabilities subject to master netting agreements were $128 million and $72 million , respectively, for which PGE posted collateral of $14 million and $11 million , which consisted primarily of letters of credit and a nominal amount of cash. As of September 30, 2015, of the gross amounts recognized, $118 million was for electricity and $10 million was for natural gas compared to $55 million for electricity and $17 million for natural gas recognized as of December 31, 2014. Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are recorded in Purchased power and fuel in the condensed consolidated statements of income and were as follows (in millions): Three Months Ended Nine Months Ended 2015 2014 2015 2014 Commodity contracts: Electricity $ 7 $ 8 $ 77 $ (21 ) Natural Gas 35 25 79 (17 ) Net unrealized and certain net realized losses (gains) presented in the preceding table are offset within the condensed consolidated statements of income by the effects of regulatory accounting. Of the net losses (gains) recognized in Net income for the three month periods ended September 30, 2015 and 2014 , net losses of $34 million have been offset. Net losses of $150 million and gains of $30 million have been offset for the nine month periods ended September 30, 2015 and 2014 , respectively. Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of September 30, 2015 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions): 2015 2016 2017 2018 2019 Thereafter Total Commodity contracts: Electricity $ 10 $ 24 $ 7 $ 7 $ 7 $ 88 $ 143 Natural gas 18 77 42 10 2 — 149 Net unrealized loss $ 28 $ 101 $ 49 $ 17 $ 9 $ 88 $ 292 PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and Standard and Poor’s Ratings Services (S&P). Should Moody’s and/or S&P reduce their rating on PGE’s unsecured debt to below investment grade, the Company 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 derivative instruments with credit-risk-related contingent features that were in a liability position as of September 30, 2015 was $291 million , for which PGE has posted $62 million in collateral, consisting of $51 million in letters of credit and $11 million in cash. If the credit-risk-related contingent features underlying these agreements were triggered at September 30, 2015 , the cash requirement to either post as collateral or settle the instruments immediately would have been $278 million . As of September 30, 2015 , 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 condensed consolidated balance sheet. Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows: September 30, December 31, Assets from price risk management activities: Counterparty A 65 % 63 % Counterparty B 8 14 73 % 77 % Liabilities from price risk management activities: Counterparty C 39 % 22 % Counterparty D 6 12 45 % 34 % See Note 3, Fair Value of Financial Instruments, for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities. |
Earnings Per Share (Notes)
Earnings Per Share (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
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 period. 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 period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; ii) unvested time-based and performance-based restricted stock units, along with related dividend equivalent rights; and iii) shares issuable pursuant to an equity forward sale agreement (EFSA). See Note 6, Equity, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met. For the three and nine month periods ended September 30, 2015 , unvested performance-based restricted stock units and related dividend equivalent rights of approximately 308,000 were excluded from the dilutive calculation because the performance goals had not been met, with 361,000 excluded for the three and nine month periods ended September 30, 2014 . Net income attributable to common shareholders is the same for both the basic and diluted earnings per share computations. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands): Three Months Ended Nine Months Ended 2015 2014 2015 2014 Weighted-average common shares outstanding—basic 88,766 78,203 82,633 78,170 Dilutive effect of potential common shares — 2,022 — 1,807 Weighted-average common shares outstanding—diluted 88,766 80,225 82,633 79,977 |
Equity (Notes)
Equity (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Equity [Abstract] | |
Equity | EQUITY The activity in equity during the nine months ended September 30, 2015 and 2014 is as follows (dollars in millions): Common Stock Accumulated Other Comprehensive Loss Retained Earnings Shares Amount Total Balances as of December 31, 2014 78,228,339 $ 918 $ (7 ) $ 1,000 $ 1,911 Issuance of common stock, net of issuance costs of $12 10,400,000 271 — — 271 Issuances of shares pursuant to equity-based plans 143,833 1 — — 1 Stock-based compensation — 3 — — 3 Dividends declared — — — (75 ) (75 ) Net income — — — 121 121 Balances as of September 30, 2015 88,772,172 $ 1,193 $ (7 ) $ 1,046 $ 2,232 Balances as of December 31, 2013 78,085,559 $ 911 $ (5 ) $ 913 $ 1,819 Issuances of shares pursuant to equity-based plans 123,869 1 — — 1 Stock-based compensation — 4 — — 4 Dividends declared — — — (67 ) (67 ) Net income — — — 132 132 Balances as of September 30, 2014 78,209,428 $ 916 $ (5 ) $ 978 $ 1,889 During the second quarter of 2015, PGE physically settled in full the EFSA, with the issuance of 10,400,000 shares of common stock in exchange for net proceeds 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 are increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period). |
Contingencies (Notes)
Contingencies (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Contingencies [Abstract] | |
CONTINGENCIES | CONTINGENCIES PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted. Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) there are significant facts in dispute; vi) there are a large number of parties (including circumstances in which it is uncertain how liability, if any, will be shared among multiple defendants); or vii) there are a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact. Trojan Investment Recovery 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. On July 27, 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. The court has yet to issue a decision on the motion. PGE believes that the October 2, 2014 OSC decision has reduced the risk of a loss to the Company in excess of the amounts previously recorded and discussed above. However, because the class actions remain pending, management believes that it is 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 have filed petitions for appeal of these procedural orders with the Ninth Circuit. Those appeals remain pending. In response to the evidence and arguments presented during the hearing, in May 2015, the FERC issued an order upholding the decision of an Administrative Law Judge that the refund proponents had failed to meet the Mobile-Sierra burden with respect to all but one respondent. That order is subject to requests for rehearing. 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 have not fully eliminated 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.” However, the FERC has acknowledged that the potential for such ripple claims is “speculative” and the Company believes that ripple claims made against it, if any, are unlikely to be successful under the FERC orders currently in effect. Accordingly, unless those FERC orders are overturned or modified, the Company does not believe that it will incur any material loss in connection with this matter. Management cannot predict the outcome of the various pending appeals and remands concerning this matter. If, on rehearing, appeal, or subsequent remand, the Ninth Circuit or the FERC were to reverse previous FERC rulings and find that the Mobile-Sierra standard is not applicable or that a market-wide remedy is appropriate, it is possible that additional refund claims could be asserted against the Company. However, management cannot predict, under such circumstances, which contracts would be subject to refunds, the basis on which refunds would be ordered, or how such refunds, if any, would be calculated. Further, management cannot predict whether any current respondents, if ordered to make refunds, would pursue additional refund claims against their suppliers, and, if so, what the basis or amounts of such potential refund claims against the Company would be. Due to these uncertainties, sufficient information is currently not available to determine PGE’s liability, if any, or to estimate a range of reasonably possible loss. EPA Investigation of Portland Harbor In 1997, an investigation by the 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 continues to undergo a remedial investigation (RI) and feasibility study (FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE. In 2012, the LWG submitted a draft FS to the EPA for review and approval. The draft FS, rewritten by the EPA, is now completed and, along with the RI, will provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision, which the EPA is not expected to issue before 2017. The completed draft FS evaluates several alternative clean-up approaches, which would take from four to 18 years with the present value of estimated costs ranging from $800 million to $2.4 billion , depending on the selected remedial action levels and the choice of remedy. The draft FS does not address responsibility for the costs of clean-up, allocate such costs among PRPs, or define precise boundaries for the clean-up. Responsibility for funding and implementing the EPA ’ s selected remedy will be determined after the issuance of the Record of Decision. Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties discussed above, sufficient information is currently not available to determine PGE’s liability for the cost of any required investigation or remediation of the Portland Harbor site or to estimate a range of potential loss. DEQ Investigation of Downtown Reach The Oregon Department of Environmental Quality (DEQ) has executed a memorandum of understanding with the EPA to administer and enforce clean-up activities for portions of the Willamette River that are upriver from the Portland Harbor Superfund site (the Downtown Reach). In 2010, the DEQ issued an order requiring PGE to perform an investigation of certain portions of the Downtown Reach. PGE completed this investigation and entered into a consent order with the DEQ in 2012 to conduct an FS of alternatives for remedial action for the portions of the Downtown Reach that were included within the scope of PGE’s investigation. PGE submitted a final feasibility study report to the DEQ in September 2014, which described possible remediation alternatives that ranged in estimated cost from $3 million to $8 million . Based on the estimated cost of the alternative recommended by the Company in the FS report, PGE recorded a $3 million reserve for this matter in 2014 and established a regulatory asset of $3 million for future recovery in prices. In April 2015, the DEQ issued its Record of Decision in which it selected the remedy recommended in the FS report. Remediation activity began in the third quarter of 2015 and is expected to be completed during 2016 at a total cost of approximately $3 million . The final order issued by the OPUC in the 2015 General Rate Case (GRC) included revenues to offset the amortization of the regulatory asset over a two year period that began January 1, 2015. As of September 30, 2015, the Company has a regulatory asset of $2 million remaining for future recovery of costs related to the Downtown Reach. Alleged Violation of Environmental Regulations at Colstrip In July 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (CSES) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other CSES co-owners, including PPL Montana, LLC, the operator of CSES. PGE has a 20% ownership interest in Units 3 and 4 of CSES. The Notice alleged certain violations of the CAA, including New Source Review, Title V, and opacity requirements, and stated that the Sierra Club and MEIC would: i) request a United States District Court to impose injunctive relief and civil penalties; ii) require a beneficial environmental project in the areas affected by the alleged air pollution; and iii) seek reimbursement of Sierra Club’s and MEIC’s costs of litigation and attorney’s fees. The Sierra Club and MEIC asserted that the CSES owners violated the Title V air quality operating permit during portions of 2008 and 2009 and that the owners have violated the CAA by failing to timely submit a complete air quality operating permit application to the Montana Department of Environmental Quality (MDEQ). The Sierra Club and MEIC also asserted violations of opacity provisions of the CAA. On March 6, 2013, the Sierra Club and MEIC sued the CSES co-owners, including PGE, for these and additional alleged violations of various environmental related regulations. The plaintiffs are seeking relief that includes an injunction preventing the co-owners from operating CSES except in accordance with the CAA, the Montana State Implementation Plan, and the plant’s federally enforceable air quality permits. In addition, plaintiffs are seeking civil penalties against the co-owners including $32,500 per day for each violation occurring through January 12, 2009, and $37,500 per day for each violation occurring thereafter. In May 2013, the defendants filed a motion to dismiss 36 of 39 claims alleged in the complaint. In September 2013, the plaintiffs filed a motion for partial summary judgment regarding the appropriate method of calculating emission increases. Also in September 2013, the plaintiffs filed an amended complaint that withdrew Title V and opacity claims, added claims associated with two 2011 projects, and expanded the scope of certain claims to encompass approximately 40 additional projects. In July 2014, the court denied both the defendants’ motion to dismiss and the plaintiffs’ motion for partial summary judgment. In August 2014, the plaintiffs filed a second amended complaint to which the defendants’ response was filed in September 2014. The second amended complaint continues to seek injunctive relief, declaratory relief, and civil penalties for alleged violations of the federal Clean Air Act. The plaintiffs state in the second amended complaint that it was filed, in part, to comply with the court’s ruling on the defendants’ motion to dismiss and plaintiffs’ motion for partial summary judgment. Discovery in this matter is complete. Oral argument on a variety of motions for summary judgment is scheduled for December 1, 2015, with trial now set for May 2016. Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome, estimate a range of potential loss, or determine whether it would have a material impact on the Company. 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 that 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. |
Guarantees (Notes)
Guarantees (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Guarantees [Abstract] | |
GUARANTEES | 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 September 30, 2015 , 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 condensed consolidated balance sheets with respect to these indemnities. |
Basis of Presentation (Policies
Basis of Presentation (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Basis of Presentation [Abstract] | |
Consolidation, Policy [Policy Text Block] | These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations |
Balance Sheet Components (Polic
Balance Sheet Components (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Balance Sheet Components [Abstract] | |
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 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. |
Debt, Policy [Policy Text Block] | PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets. Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. The fair value of PGE’s unsecured term bank loans, which were fully repaid in July 2015, was classified as Level 3 based on the terms of the loans and the Company’s creditworthiness. These 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. |
Fair Value of Financial Instr16
Fair Value of Financial Instruments (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value of Financial Instruments [Abstract] | |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. |
Allocation of Financial Asset to Hierarchy Levels [Policy Text Block] | Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors: Money market funds —PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. Money market funds are classified as Level 2 in the fair value hierarchy as the securities are traded in active markets of similar securities but are not directly valued using quoted market prices. Debt securities —PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yields and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. Equity securities —Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as the NASDAQ and the New York Stock Exchange. Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy because pricing inputs are directly or indirectly observable in the marketplace. Assets and liabilities from price risk management activities are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 4, 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. |
Fair Value Transfer, Policy [Policy Text Block] | 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 financial instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements. |
Debt, Policy [Policy Text Block] | PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets. Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. The fair value of PGE’s unsecured term bank loans, which were fully repaid in July 2015, was classified as Level 3 based on the terms of the loans and the Company’s creditworthiness. These 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. |
Price Risk Management (Policies
Price Risk Management (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Price Risk Management [Abstract] | |
Derivatives, Policy [Policy Text Block] | PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign currency exchange rate risk in order to reduce volatility in NVPC for its retail customers. These derivative instruments may include forwards, futures, swaps, and option contracts, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, oil, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery processes authorized by the Public Utility Commission of Oregon (OPUC), PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative instruments 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. |
Contingencies (Policies)
Contingencies (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Contingencies [Abstract] | |
Commitments and Contingencies, Policy [Policy Text Block] | PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted. Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) there are significant facts in dispute; vi) there are a large number of parties (including circumstances in which it is uncertain how liability, if any, will be shared among multiple defendants); or vii) there are 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. |
Guarantees (Policies)
Guarantees (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Guarantees [Abstract] | |
Guarantees, Indemnifications and Warranties Policies [Policy Text Block] | 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. |
Balance Sheet Components (Table
Balance Sheet Components (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Balance Sheet Components [Abstract] | |
Schedule of Other Current Assets [Table Text Block] | Other current assets consist of the following (in millions): September 30, December 31, 2014 Prepaid expenses $ 24 $ 39 Current deferred income tax asset 39 33 Margin deposits 20 11 Accrued sales tax refund related to Tucannon River Wind Farm — 23 Assets from price risk management activities 7 6 Other 2 3 Other current assets $ 92 $ 115 |
Schedule of Public Utility Property, Plant, and Equipment [Table Text Block] | Electric utility plant, net consists of the following (in millions): September 30, December 31, Electric utility plant $ 8,458 $ 8,161 Construction work-in-progress 508 417 Total cost 8,966 8,578 Less: accumulated depreciation and amortization (3,046 ) (2,899 ) Electric utility plant, net $ 5,920 $ 5,679 |
Schedule of Regulatory Assets and Liabilities [Text Block] | Regulatory assets and liabilities consist of the following (in millions): September 30, 2015 December 31, 2014 Current Noncurrent Current Noncurrent Regulatory assets: Price risk management $ 108 $ 184 $ 100 $ 121 Pension and other postretirement plans — 232 — 247 Deferred income taxes — 87 — 86 Debt issuance costs — 17 — 15 Deferred capital projects 5 — 19 — Other 9 27 14 25 Total regulatory assets $ 122 $ 547 $ 133 $ 494 Regulatory liabilities: Asset retirement removal costs $ — $ 833 $ — $ 804 Trojan decommissioning activities 19 21 23 34 Asset retirement obligations — 44 — 39 Other 26 41 37 29 Total regulatory liabilities $ 45 * $ 939 $ 60 * $ 906 * Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets. |
Other Liabilities Disclosure [Text Block] | Accrued expenses and other current liabilities consist of the following (in millions): September 30, December 31, 2014 Regulatory liabilities—current $ 45 $ 60 Accrued employee compensation and benefits 44 51 Accrued interest payable 40 26 Accrued dividends payable 28 23 Accrued taxes payable 40 22 Other 57 54 Total accrued expenses and other current liabilities $ 254 $ 236 |
Schedule of Asset Retirement Obligations [Table Text Block] | Asset retirement obligations (AROs) consist of the following (in millions): September 30, December 31, 2014 Trojan decommissioning activities $ 43 $ 41 Utility plant 83 64 Non-utility property 11 11 Asset retirement obligations $ 137 $ 116 |
Pension and Other Postretirement Benefits Disclosure [Text Block] | Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Service cost $ 4 $ 4 $ 13 $ 11 Interest cost 8 8 24 25 Expected return on plan assets (10 ) (9 ) (30 ) (29 ) Amortization of net actuarial loss 5 4 15 13 Net periodic benefit cost $ 7 $ 7 $ 22 $ 20 |
Fair Value of Financial Instr21
Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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 September 30, 2015 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trust: (1) Money market funds $ — $ 17 $ — $ 17 Debt securities: Domestic government 5 8 — 13 Corporate credit — 10 — 10 Non-qualified benefit plan trust: (2) Equity securities—domestic 4 2 — 6 Debt securities—domestic government 1 — — 1 Assets from price risk management activities: (1) (3) Electricity — 5 — 5 Natural gas — 2 — 2 $ 10 $ 44 $ — $ 54 Liabilities from price risk management activities: (1) (3) Electricity $ — $ 31 $ 117 $ 148 Natural gas — 99 52 151 $ — $ 130 $ 169 $ 299 (1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate. (2) Excludes insurance policies of $26 million , which are recorded at cash surrender value. (3) For further information, see Note 4, Price Risk Management. As of December 31, 2014 Level 1 Level 2 Level 3 Total Assets: Nuclear decommissioning trust: (1) Money market funds $ — $ 65 $ — $ 65 Debt securities: Domestic government 7 7 — 14 Corporate credit — 11 — 11 Non-qualified benefit plan trust: (2) Equity securities: Domestic 4 1 — 5 International 1 — — 1 Assets from price risk management activities: (1) (3) Electricity — 4 1 5 Natural gas — 2 — 2 $ 12 $ 90 $ 1 $ 103 Liabilities from price risk management activities: (1) (3) Electricity $ — $ 32 $ 80 $ 112 Natural gas — 95 21 116 $ — $ 127 $ 101 $ 228 (1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate. (2) Excludes insurance policies of $26 million , which are recorded at cash surrender value. (3) For further information, see Note 4, Price Risk Management. |
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: Fair Value Valuation Technique Significant Unobservable Input Price per Unit Commodity Contracts Assets Liabilities Low High Weighted Average (in millions) As of September 30, 2015: Electricity physical forward $ — $ 117 Discounted cash flow Electricity forward price (per MWh) $ 11.00 $ 71.77 $ 29.82 Natural gas financial swaps — 52 Discounted cash flow Natural gas forward price (per Decatherm) 2.06 3.83 2.56 Electricity financial futures — — Discounted cash flow Electricity forward price (per MWh) 21.07 31.00 27.21 $ — $ 169 As of December 31, 2014: Electricity physical forward $ — $ 77 Discounted cash flow Electricity forward price (per MWh) $ 11.97 $ 122.72 $ 37.43 Natural gas financial swaps — 21 Discounted cash flow Natural gas forward price (per Decatherm) 2.88 4.86 3.41 Electricity financial futures 1 3 Discounted cash flow Electricity forward price (per MWh) 11.97 39.26 27.88 $ 1 $ 101 |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions): Three Months Ended Nine Months Ended 2015 2014 2015 2014 Balance as of the beginning of the period $ 168 $ 89 $ 100 $ 139 Net realized and unrealized losses (gains) * 15 9 85 (45 ) Settlements — (1 ) — (1 ) Transfers out of Level 3 to Level 2 (14 ) 1 (16 ) 5 Balance as of the end of the period $ 169 $ 98 $ 169 $ 98 * Contains nominal amounts of realized losses. Both realized and unrealized losses (gains), of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income. |
Price Risk Management (Tables)
Price Risk Management (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Derivative [Line Items] | |
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): September 30, December 31, Current assets: Commodity contracts: Electricity $ 5 $ 4 Natural gas 2 2 Total current derivative assets 7 (1) 6 (1) Noncurrent assets: Commodity contracts: Electricity — 1 Total noncurrent derivative assets — (2) 1 (2) Total derivative assets not designated as hedging instruments $ 7 $ 7 Total derivative assets $ 7 $ 7 Current liabilities: Commodity contracts: Electricity $ 38 $ 54 Natural gas 77 52 Total current derivative liabilities 115 106 Noncurrent liabilities: Commodity contracts: Electricity 110 58 Natural gas 74 64 Total noncurrent derivative liabilities 184 122 Total derivative liabilities not designated as hedging instruments $ 299 $ 228 Total derivative liabilities $ 299 $ 228 (1) Included in Other current assets on the condensed consolidated balance sheets. (2) Included in Other noncurrent assets on the condensed consolidated balance sheets. |
Schedule of Derivative Instruments [Table Text Block] | PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle through 2035, were as follows (in millions): September 30, 2015 December 31, 2014 Commodity contracts: Electricity 13 MWh 16 MWh Natural gas 124 Decatherms 127 Decatherms Foreign currency $ 7 Canadian $ 7 Canadian |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are recorded in Purchased power and fuel in the condensed consolidated statements of income and were as follows (in millions): Three Months Ended Nine Months Ended 2015 2014 2015 2014 Commodity contracts: Electricity $ 7 $ 8 $ 77 $ (21 ) Natural Gas 35 25 79 (17 ) Net unrealized and certain net realized losses (gains) presented in the preceding table are offset within the condensed consolidated statements of income by the effects of regulatory accounting. |
Schedule of Price Risk Derivatives [Table Text Block] | Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of September 30, 2015 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions): 2015 2016 2017 2018 2019 Thereafter Total Commodity contracts: Electricity $ 10 $ 24 $ 7 $ 7 $ 7 $ 88 $ 143 Natural gas 18 77 42 10 2 — 149 Net unrealized loss $ 28 $ 101 $ 49 $ 17 $ 9 $ 88 $ 292 |
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: September 30, December 31, Assets from price risk management activities: Counterparty A 65 % 63 % Counterparty B 8 14 73 % 77 % Liabilities from price risk management activities: Counterparty C 39 % 22 % Counterparty D 6 12 45 % 34 % |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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): Three Months Ended Nine Months Ended 2015 2014 2015 2014 Weighted-average common shares outstanding—basic 88,766 78,203 82,633 78,170 Dilutive effect of potential common shares — 2,022 — 1,807 Weighted-average common shares outstanding—diluted 88,766 80,225 82,633 79,977 |
Equity (Tables)
Equity (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Equity [Abstract] | |
Schedule of Stockholders Equity [Table Text Block] | The activity in equity during the nine months ended September 30, 2015 and 2014 is as follows (dollars in millions): Common Stock Accumulated Other Comprehensive Loss Retained Earnings Shares Amount Total Balances as of December 31, 2014 78,228,339 $ 918 $ (7 ) $ 1,000 $ 1,911 Issuance of common stock, net of issuance costs of $12 10,400,000 271 — — 271 Issuances of shares pursuant to equity-based plans 143,833 1 — — 1 Stock-based compensation — 3 — — 3 Dividends declared — — — (75 ) (75 ) Net income — — — 121 121 Balances as of September 30, 2015 88,772,172 $ 1,193 $ (7 ) $ 1,046 $ 2,232 Balances as of December 31, 2013 78,085,559 $ 911 $ (5 ) $ 913 $ 1,819 Issuances of shares pursuant to equity-based plans 123,869 1 — — 1 Stock-based compensation — 4 — — 4 Dividends declared — — — (67 ) (67 ) Net income — — — 132 132 Balances as of September 30, 2014 78,209,428 $ 916 $ (5 ) $ 978 $ 1,889 |
Basis of Presentation (Details)
Basis of Presentation (Details) shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015USD ($)mi²retail_customersshares | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)mi²retail_customersshares | Sep. 30, 2014USD ($) | |
Basis of Presentation [Abstract] | ||||
Service Area Sq Miles | mi² | 4,000 | 4,000 | ||
Incorporated Cities | 52 | 52 | ||
Number of Retail Customers | retail_customers | 851,650 | 851,650 | ||
Service Area Population | shares | 1.8 | 1.8 | ||
Percent of State's Population | 46.00% | 46.00% | ||
Increase (Decrease) in Inventories | $ (12) | $ (18) | ||
Other Comprehensive Income | $ 0 | $ 0 | $ 0 | $ 0 |
Balance Sheet Components Other
Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Other Current Assets [Line Items] | ||
Prepaid expenses | $ 24 | $ 39 |
Current deferred income tax asset | 39 | 33 |
Margin deposits | 20 | 11 |
Accrued sales tax refund related to Tucannon River Wind Farm | 0 | 23 |
Assets from price risk management activities | 7 | 6 |
Other | 2 | 3 |
Other current assets | $ 92 | $ 115 |
Balance Sheet Components Electr
Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment [Line Items] | ||
Electric utility plant | $ 8,458 | $ 8,161 |
Construction work-in-progress | 508 | 417 |
Total cost | 8,966 | 8,578 |
Less: accumulated depreciation and amortization | (3,046) | (2,899) |
Electric utility plant, net | $ 5,920 | $ 5,679 |
Balance Sheet Components Regula
Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Current Regulatory Assets [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Price risk management | $ 108 | $ 100 |
Pension and other postretirement plans | 0 | 0 |
Deferred income taxes | 0 | 0 |
Debt issuance costs | 0 | 0 |
Deferred capital projects | 5 | 19 |
Other | 9 | 14 |
Total regulatory assets | 122 | 133 |
Noncurrent Regulatory Assets [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Price risk management | 184 | 121 |
Pension and other postretirement plans | 232 | 247 |
Deferred income taxes | 87 | 86 |
Debt issuance costs | 17 | 15 |
Deferred capital projects | 0 | 0 |
Other | 27 | 25 |
Total regulatory assets | 547 | 494 |
Current Regulatory Liabilities [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Asset retirement removal costs | 0 | 0 |
Trojan decommissioning activities | 19 | 23 |
Asset retirement obligations | 0 | 0 |
Other | 26 | 37 |
Total regulatory liabilities | 45 | 60 |
Noncurrent Regulatory Liabilities [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Asset retirement removal costs | 833 | 804 |
Trojan decommissioning activities | 21 | 34 |
Asset retirement obligations | 44 | 39 |
Other | 41 | 29 |
Total regulatory liabilities | $ 939 | $ 906 |
Balance Sheet Components Othe29
Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Regulatory liabilities—current | $ 45 | $ 60 |
Accrued employee compensation and benefits | 44 | 51 |
Accrued interest payable | 40 | 26 |
Accrued dividends payable | 28 | 23 |
Accrued taxes payable | 40 | 22 |
Other | 57 | 54 |
Total accrued expenses and other current liabilities | $ 254 | $ 236 |
Balance Sheet Components Asset
Balance Sheet Components Asset Retirement Obligations (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Asset Retirement Obligation Disclosure [Abstract] | ||
Trojan decommissioning activities | $ 43 | $ 41 |
Utility Plant | 83 | 64 |
Non-utility property | 11 | 11 |
Asset retirement obligations | $ 137 | $ 116 |
Balance Sheet Components Pensio
Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost | $ 4 | $ 4 | $ 13 | $ 11 |
Interest cost | 8 | 8 | 24 | 25 |
Expected return on plan assets | (10) | (9) | (30) | (29) |
Amortization of net actuarial loss | 5 | 4 | 15 | 13 |
Net periodic benefit cost | $ 7 | $ 7 | $ 22 | $ 20 |
Balance Sheet Components (Detai
Balance Sheet Components (Details) - USD ($) | May. 22, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | May. 21, 2015 | May. 19, 2015 | Jan. 31, 2015 | Dec. 31, 2014 |
Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||||||
Finite-Lived Intangible Assets, Accumulated Amortization | $ 219,000,000 | $ 219,000,000 | $ 191,000,000 | ||||||||
Amortization of Intangible Assets | 10,000,000 | $ 6,000,000 | 28,000,000 | $ 18,000,000 | |||||||
Asset Retirement Obligations, Significant Changes | 15 | ||||||||||
Line of Credit Facility, Current Borrowing Capacity | 135,000,000 | $ 500,000,000 | 135,000,000 | $ 700,000,000 | |||||||
Syndicated credit facility scheduled to expire in 2019 | $ 500,000,000 | $ 500,000,000 | |||||||||
Debt Instrument, Covenant Description | .65 | ||||||||||
Ratio of Indebtedness to Net Capital | 0.5 | 0.5 | |||||||||
Short-term Debt | $ 0 | $ 0 | |||||||||
Borrowings | 3,000,000 | 3,000,000 | |||||||||
Line of Credit Facility, Remaining Borrowing Capacity | 497,000,000 | 497,000,000 | |||||||||
Letters of credit issued | 93,000,000 | 93,000,000 | |||||||||
Authorized Short-Term Debt | $ 900,000,000 | $ 900,000,000 | |||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.46% | 3.46% | 6.80% | 3.50% | 3.55% | ||||||
Extinguishment of Debt, Amount | $ 442,000,000 | $ 0 | |||||||||
[Member] | |||||||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||||||
Proceeds from Issuance of Long-term Debt | 75,000,000 | $ 70,000,000 | |||||||||
Notes Payable to Banks [Member] | |||||||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||||||
Extinguishment of Debt, Amount | $ 67,000,000 | $ 55,000,000 | $ 200,000,000 | $ 50,000,000 | |||||||
Long-term Debt [Member] | |||||||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||||||
Extinguishment of Debt, Amount | $ 70,000,000 |
Fair Value of Financial Instr33
Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Nuclear decommissioning trust: (1) | ||
Money market funds | $ 17 | $ 65 |
Debt securities: | ||
Domestic government | 13 | 14 |
Corporate credit | 10 | 11 |
Equity securities: | ||
Domestic | 6 | 5 |
International | 1 | |
Debt securities—domestic government | 1 | |
Assets from price risk management activities: (1) (3) | ||
Electricity | 5 | 5 |
Natural gas | 2 | 2 |
Total | 54 | 103 |
Liabilities from price risk management activities: (1) (3) | ||
Electricity | 148 | 112 |
Natural gas | 151 | 116 |
Total | 299 | 228 |
Fair Value, Inputs, Level 1 [Member] | ||
Nuclear decommissioning trust: (1) | ||
Money market funds | 0 | 0 |
Debt securities: | ||
Domestic government | 5 | 7 |
Corporate credit | 0 | 0 |
Equity securities: | ||
Domestic | 4 | 4 |
International | 1 | |
Debt securities—domestic government | 1 | |
Assets from price risk management activities: (1) (3) | ||
Electricity | 0 | 0 |
Natural gas | 0 | 0 |
Total | 10 | 12 |
Liabilities from price risk management activities: (1) (3) | ||
Electricity | 0 | 0 |
Natural gas | 0 | 0 |
Total | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | ||
Nuclear decommissioning trust: (1) | ||
Money market funds | 17 | 65 |
Debt securities: | ||
Domestic government | 8 | 7 |
Corporate credit | 10 | 11 |
Equity securities: | ||
Domestic | 2 | 1 |
International | 0 | |
Debt securities—domestic government | 0 | |
Assets from price risk management activities: (1) (3) | ||
Electricity | 5 | 4 |
Natural gas | 2 | 2 |
Total | 44 | 90 |
Liabilities from price risk management activities: (1) (3) | ||
Electricity | 31 | 32 |
Natural gas | 99 | 95 |
Total | 130 | 127 |
Fair Value, Inputs, Level 3 [Member] | ||
Nuclear decommissioning trust: (1) | ||
Money market funds | 0 | 0 |
Debt securities: | ||
Domestic government | 0 | 0 |
Corporate credit | 0 | 0 |
Equity securities: | ||
Domestic | 0 | 0 |
International | 0 | |
Debt securities—domestic government | 0 | |
Assets from price risk management activities: (1) (3) | ||
Electricity | 0 | 1 |
Natural gas | 0 | 0 |
Total | 0 | 1 |
Liabilities from price risk management activities: (1) (3) | ||
Electricity | 117 | 80 |
Natural gas | 52 | 21 |
Total | $ 169 | $ 101 |
Fair Value of Financial Instr34
Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($) | Sep. 30, 2015 | Dec. 31, 2014 |
Low [Member] | ||
Commodity Contracts | ||
Electricity physical forward | $ 11 | $ 11.97 |
Natural gas financial swaps | 2.06 | 2.88 |
Electricity financial futures | 21.07 | 11.97 |
High [Member] | ||
Commodity Contracts | ||
Electricity physical forward | 71.77 | 122.72 |
Natural gas financial swaps | 3.83 | 4.86 |
Electricity financial futures | 31 | 39.26 |
Weighted Average [Member] | ||
Commodity Contracts | ||
Electricity physical forward | 29.82 | 37.43 |
Natural gas financial swaps | 2.56 | 3.41 |
Electricity financial futures | 27.21 | 27.88 |
Assets [Member] | ||
Commodity Contracts | ||
Electricity physical forward | 0 | 0 |
Natural gas financial swaps | 0 | 0 |
Electricity financial futures | 0 | 1,000,000 |
Total commodity contracts | 0 | 1,000,000 |
Liabilities [Member] | ||
Commodity Contracts | ||
Electricity physical forward | 117,000,000 | 77,000,000 |
Natural gas financial swaps | 52,000,000 | 21,000,000 |
Electricity financial futures | 0 | 3,000,000 |
Total commodity contracts | $ 169,000,000 | $ 101,000,000 |
Fair Value of Financial Instr35
Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Balance as of the beginning of the period | $ 168 | $ 89 | $ 100 | $ 139 |
Net realized and unrealized losses (gains) | 15 | 9 | 85 | (45) |
Settlements | 0 | (1) | 0 | (1) |
Transfers out of Level 3 to Level 2 | (14) | 1 | (16) | (5) |
Balance as of the end of the period | $ 169 | $ 98 | $ 169 | $ 98 |
Fair Value of Financial Instr36
Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net | $ 0 | $ 0 | $ 0 | $ 0 | |
Cash Surrender Value, Fair Value Disclosure | 26,000,000 | 26,000,000 | $ 26,000,000 | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3 | 0 | $ 0 | 0 | $ 0 | |
Long-term Debt | 2,204,000,000 | 2,204,000,000 | 2,501,000,000 | ||
Long-term Debt, Fair Value | $ 2,530,000,000 | $ 2,530,000,000 | 2,901,000,000 | ||
Fair Value, Inputs, Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Long-term Debt, Fair Value | 2,596,000,000 | ||||
Fair Value, Inputs, Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Long-term Debt, Fair Value | $ 305,000,000 |
Price Risk Management Fair valu
Price Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Current Assets, Commodity Contracts: | ||
Electricity | $ 5 | $ 4 |
Natural gas | 2 | 2 |
Total current derivative assets | 7 | 6 |
Noncurrent Assets, Commodity Contracts: [Abstract] | ||
Electricity | 0 | 1 |
Total noncurrent derivative assets | 0 | 1 |
Total derivative assets not designated as hedging instruments | 7 | 7 |
Total derivative assets | 7 | 7 |
Current Liabilities, Commodity Contracts: [Abstract] | ||
Electricity | 38 | 54 |
Natural gas | 77 | 52 |
Total current derivative liabilities | 115 | 106 |
Noncurrent Liabilities, Commodity Contracts: [Abstract] | ||
Electricity | 110 | 58 |
Natural gas | 74 | 64 |
Total noncurrent derivative liabilities | 184 | 122 |
Total derivative liabilities not designated as hedging instruments | 299 | 228 |
Total derivative liabilities | $ 299 | $ 228 |
Price Risk Management Net volum
Price Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, CAD in Millions | Sep. 30, 2015CADMMBTUMWh | Dec. 31, 2014CADMMBTUMWh |
Commodity contracts: | ||
Electricity | 13 | 16 |
Natural gas | MMBTU | 124 | 127 |
Foreign currency | CAD | CAD 7 | CAD 7 |
Price Risk Management Net reali
Price Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Commodity contracts: | ||||
Electricity | $ 7 | $ 8 | $ 77 | $ (21) |
Natural Gas | $ 35 | $ 25 | $ 79 | $ (17) |
Price Risk Management Future Ye
Price Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions | Sep. 30, 2015USD ($) |
Electricity [Member] | |
Commodity contracts: | |
2,015 | $ 10 |
2,016 | 24 |
2,017 | 7 |
2,018 | 7 |
2,019 | 7 |
Thereafter | 88 |
Total | 143 |
Natural Gas [Member] | |
Commodity contracts: | |
2,015 | 18 |
2,016 | 77 |
2,017 | 42 |
2,018 | 10 |
2,019 | 2 |
Thereafter | 0 |
Total | 149 |
Net Unrealized Loss [Member] | |
Commodity contracts: | |
2,015 | 28 |
2,016 | 101 |
2,017 | 49 |
2,018 | 17 |
2,019 | 9 |
Thereafter | 88 |
Total | $ 292 |
Price Risk Management Counterpa
Price Risk Management Counterparties Representing 10% or More (Details) | Sep. 30, 2015 | Dec. 31, 2014 |
Assets from price risk management activities: | ||
Counterparty A | 65.00% | 63.00% |
Counterparty B | 8.00% | 14.00% |
Total | 73.00% | 77.00% |
Liabilities from price risk management activities: | ||
Counterparty C | 39.00% | 22.00% |
Counterparty D | 6.00% | 12.00% |
Total | 45.00% | 34.00% |
Price Risk Management Price Ris
Price Risk Management Price Risk Management (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Collateral, Master Netting Arrangements, Letters of Credit | $ 14 | $ 14 | $ 11 | ||
Net gain or (loss) recognized in the statement of income offset by regulatory accounting | 34 | $ 34 | 150 | $ 30 | |
Derivative, Net Liability Position, Aggregate Fair Value | 291 | 291 | |||
Collateral Posted, Aggregate Fair Value | 62 | 62 | |||
Letters of Credit Outstanding, Amount | 51 | 51 | |||
Restricted Cash and Cash Equivalents, Current | 11 | 11 | |||
Collateral cash requirement | 278 | 278 | |||
Natural Gas [Member] | |||||
Derivative Instruments and Hedges, Liabilities | 10 | 10 | 17 | ||
4911 Electric Services [Member] | |||||
Derivative Instruments and Hedges, Liabilities | 118 | 118 | 55 | ||
Liabilities, Total [Member] | |||||
Derivative Instruments and Hedges, Liabilities | $ 128 | $ 128 | $ 72 |
Earnings Per Share Components o
Earnings Per Share Components of Earnings Per Share (Details) - shares shares in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Earnings Per Share [Abstract] | ||||
Weighted-average common shares outstanding - basic | 88,766 | 78,203 | 82,633 | 78,170 |
Dilutive effect of potential common shares | 0 | 2,022 | 0 | 1,807 |
Weighted-average common shares outstanding - diluted | 88,766 | 80,225 | 82,633 | 79,977 |
Earnings Per Share Earnings Per
Earnings Per Share Earnings Per Share (Details) - shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Earnings Per Share [Abstract] | ||||
Unvested performance-based restricted stock units and associated dividend equivalent rights | 308,000 | 361,000 | 308,000 | 361,000 |
Schedule of Equity (Details)
Schedule of Equity (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Payments of Stock Issuance Costs | $ 12 | |||
Proceeds from Issuance of Common Stock | $ 271 | $ 0 | ||
Common Stock, Shares, Outstanding beginning of period | 78,228,339 | |||
Stockholders' Equity | $ 1,911 | |||
Net Income | $ 36 | $ 39 | $ 121 | $ 132 |
Common Stock, Shares, Outstanding end of period | 88,772,172 | 88,772,172 | ||
Stockholders' Equity | $ 2,232 | $ 2,232 | ||
Common Stock [Member] | ||||
Stock Issued During Period, Shares, New Issues | 10,400,000 | |||
Common Stock, Shares, Outstanding beginning of period | 78,228,339 | 78,085,559 | ||
Issuances of shares pursuant to equity-based plans | 143,833 | 123,869 | ||
Common Stock, Shares, Outstanding end of period | 88,772,172 | 78,209,428 | 88,772,172 | 78,209,428 |
Common Stock Including Additional Paid in Capital [Member] | ||||
Proceeds from Issuance of Common Stock | $ 271 | |||
Issuance of shares pursuant to equity-based plans | 1 | $ 1 | ||
Adjustments Related to Tax Withholding for Share-based Compensation | 3 | |||
Stockholders' Equity | 918 | 911 | ||
Stock-based compensation | 4 | |||
Dividends declared | 0 | 0 | ||
Stockholders' Equity | $ 1,193 | $ 916 | 1,193 | 916 |
AOCI Attributable to Parent [Member] | ||||
Stockholders' Equity | (7) | (5) | ||
Stock-based compensation | 0 | 0 | ||
Dividends declared | 0 | 0 | ||
Stockholders' Equity | (7) | (5) | (7) | (5) |
Retained Earnings [Member] | ||||
Stockholders' Equity | 1,000 | 913 | ||
Stock-based compensation | 0 | 0 | ||
Dividends declared | (75) | (67) | ||
Net Income | 121 | 132 | ||
Stockholders' Equity | 1,046 | 978 | 1,046 | 978 |
Stockholders' Equity, Total [Member] | ||||
Proceeds from Issuance of Common Stock | 271 | |||
Issuance of shares pursuant to equity-based plans | 1 | 1 | ||
Stockholders' Equity | 1,911 | 1,819 | ||
Stock-based compensation | 3 | 4 | ||
Dividends declared | (75) | (67) | ||
Net Income | 121 | 132 | ||
Stockholders' Equity | $ 2,232 | $ 1,889 | $ 2,232 | $ 1,889 |
Equity (Details)
Equity (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Proceeds from Issuance of Common Stock | $ 271 | $ 0 |
Common Stock [Member] | ||
Stock Issued During Period, Shares, New Issues | 10,400,000 |
Contingencies (Details)
Contingencies (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Jun. 30, 2013claims | Sep. 30, 2015USD ($)claims | Dec. 31, 1997 | Dec. 31, 2014USD ($) | Sep. 30, 2008USD ($) | Dec. 31, 1993 | |
Loss Contingencies [Line Items] | ||||||
Investment in Trojan | 87.00% | |||||
Refund to customers for Trojan Investment including interest | $ 33,000,000 | |||||
Class action damages sought | $ 260,000,000 | |||||
Site Contingency, Names of Other Potentially Responsible Parties | 100 | 69 | ||||
Lower estimate of range of cost of Portland Harbor cleanup in total | $ 800,000,000 | |||||
Upper estimated range of total cost of Portland Harbor cleanup | 2,400,000,000 | |||||
Remediation cost estimate lower range | 3,000,000 | |||||
Remediation cost estimate upper range | 8,000,000 | |||||
Loss Contingency, Estimate of Possible Loss | 3,000,000 | $ 3,000,000 | ||||
Regulatory asset for recovery of loss contingencies | 2,000,000 | $ 3,000,000 | ||||
Civil Penalty Claim - Per day per violation through January 12, 2009 | 32,500 | |||||
Civil Penalty Claim - Per day per violation after January 12, 2009 | $ 37,500 | |||||
Loss Contingency, Actions Taken by Defendant | 36 | |||||
projects added to plaintiff's suit | claims | 2 | |||||
Loss Contingency, Pending Claims, Number | claims | 39 | 40 |