Cover Page
Cover Page - shares | 9 Months Ended | |
Sep. 30, 2019 | Oct. 25, 2019 | |
Cover page. | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Sep. 30, 2019 | |
Document Transition Report | false | |
Entity File Number | 001-5532-99 | |
Entity Registrant Name | PORTLAND GENERAL ELECTRIC COMPANY | |
Entity Incorporation, State or Country Code | OR | |
Entity Tax Identification Number | 93-0256820 | |
Entity Address, Address Line One | 121 SW Salmon Street | |
Entity Address, City or Town | Portland | |
Entity Address, State or Province | OR | |
Entity Address, Postal Zip Code | 97204 | |
City Area Code | 503 | |
Local Phone Number | 464-8000 | |
Title of 12(b) Security | Common Stock, no par value | |
Trading Symbol | POR | |
Security Exchange Name | NYSE | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 89,372,125 | |
Entity Central Index Key | 0000784977 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | Q3 | |
Current Fiscal Year End Date | --12-31 |
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, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Revenue, net | $ 538 | $ 525 | $ 1,570 | $ 1,469 |
Alternative revenue programs, net of amortization | 4 | 0 | 5 | (2) |
Total Revenues | 542 | 525 | 1,575 | 1,467 |
Operating expenses: | ||||
Purchased power and fuel | 165 | 186 | 449 | 420 |
Generation, transmission and distribution | 78 | 72 | 241 | 212 |
Administrative and other | 74 | 49 | 223 | 188 |
Depreciation and amortization | 103 | 96 | 305 | 281 |
Taxes other than income taxes | 34 | 31 | 101 | 95 |
Total operating expenses | 454 | 434 | 1,319 | 1,196 |
Income from operations | 88 | 91 | 256 | 271 |
Interest expense, net | 32 | 31 | 95 | 93 |
Other income: | ||||
Allowance for equity funds used during construction | 2 | 2 | 7 | 8 |
Miscellaneous income, net | 3 | 0 | 5 | 0 |
Other income, net | 5 | 2 | 12 | 8 |
Income before income tax expense | 61 | 62 | 173 | 186 |
Income tax expense | 6 | 9 | 20 | 23 |
Net income | 55 | 53 | 153 | 163 |
Other Comprehensive Income | 0 | 0 | 2 | 0 |
Comprehensive Income | $ 55 | $ 53 | $ 155 | $ 163 |
Weighted-average common shares outstanding (in thousands): | ||||
Basic | 89,372 | 89,239 | 89,346 | 89,205 |
Diluted | 89,594 | 89,239 | 89,555 | 89,205 |
Earnings per share: | ||||
Basic | $ 0.61 | $ 0.59 | $ 1.71 | $ 1.82 |
Diluted | $ 0.61 | $ 0.59 | $ 1.70 | $ 1.82 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Current assets: | ||
Cash and cash equivalents | $ 11 | $ 119 |
Accounts receivable, net | 161 | 193 |
Unbilled revenues | 73 | 96 |
Inventories | 91 | 84 |
Regulatory assets - current | 26 | 61 |
Other current assets | 54 | 90 |
Total current assets | 416 | 643 |
Electric utility plant, net | 7,014 | 6,887 |
Regulatory assets - noncurrent | 483 | 401 |
Nuclear decommissioning trust | 46 | 42 |
Non-qualified benefit plan trust | 37 | 36 |
Other noncurrent assets | 158 | 101 |
Total assets | 8,154 | 8,110 |
Current liabilities | ||
Accounts payable | 128 | 168 |
Liabilities from price risk mangement activities - current | 26 | 55 |
Current portion of long-term debt | 50 | 300 |
Finance Lease, Liability, Current | 17 | 0 |
Accrued expenses and other current liabilities | 293 | 268 |
Total current liabilities | 514 | 791 |
Long-term debt, net of current portion | 2,328 | 2,178 |
Regulatory liabilities-noncurrent | 1,380 | 1,355 |
Deferred income taxes | 378 | 369 |
Unfunded status of pension and postretirement plans | 307 | 307 |
Liabilities from price risk management activities-noncurrent | 100 | 101 |
Asset retirement obligations | 268 | 197 |
Non-qualified benefit plan liabilities | 100 | 103 |
Finance lease obligations, net of current portion | 136 | 0 |
Other noncurrent liabilities | 79 | 203 |
Total liabilities | 5,590 | 5,604 |
Commitments and contingencies (see notes) | ||
Shareholders' Equity: | ||
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2019 and December 31, 2018 | 0 | 0 |
Common stock, no par value, 160,000,000 shares authorized; 89,371,974 and 89,267,959 shares issued and outstanding as of September 30, 2019 and December 31, 2018, respectively | 1,217 | 1,212 |
Accumulated other comprehensive loss | (7) | (7) |
Retained earnings | 1,354 | 1,301 |
Total shareholders' equity | 2,564 | 2,506 |
Total liabilities and shareholders' equity | $ 8,154 | $ 8,110 |
Condensed Consolidated Balanc_2
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares | Sep. 30, 2019 | Dec. 31, 2018 |
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 | 89,371,974 | 89,267,959 |
Common stock, shares outstanding | 89,371,974 | 89,267,959 |
Condensed Consolidated Statem_2
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
Cash flows from operating activities: | ||
Net income | $ 153 | $ 163 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 305 | 281 |
Deferred income taxes | 3 | 2 |
Pension and other postretirement benefits | 16 | 19 |
Allowance for equity funds used during construction | (7) | (8) |
Decoupling mechanism deferrals, net of amortization | (6) | 2 |
(Amortization) Deferral of net benefits due to Tax Reform | (16) | 37 |
Other non-cash income and expenses, net | 38 | 8 |
Changes in working capital: | ||
Decrease in accounts receivable and unbilled revenues | 50 | 12 |
(Increase) in inventories | (7) | 2 |
Decrease in margin deposits, net | 4 | 6 |
(Decrease)/increase in accounts payable and accrued liabilities | (25) | 17 |
Other working capital items, net | 25 | 19 |
Other, net | (31) | (24) |
Net cash provided by operating activities | 502 | 536 |
Cash flows from investing activities: | ||
Capital expenditures | (407) | (401) |
Sales of Nuclear decommissioning trust securities | 11 | 11 |
Purchases of Nuclear decommissioning trust securities | (8) | (9) |
Proceeds from Carty Settlement | 0 | 120 |
Other, net | (2) | 1 |
Net cash used in investing activities | (406) | (278) |
Cash flows from financing activities: | ||
Proceeds from Issuance of Long-term Debt | 200 | 0 |
Payments of Long-term Debt | (300) | 0 |
Dividends paid | (99) | (93) |
Other | (5) | (4) |
Net cash used in financing activities | (204) | (97) |
(Decrease) increase in cash and cash equivalents | (108) | 161 |
Cash and cash equivalents, beginning of period | 119 | 39 |
Cash and cash equivalents, end of period | 11 | 200 |
Supplemental cash flow information is as follows: | ||
Cash paid for interest, net of amounts capitalized | 73 | 72 |
Cash paid for income taxes | $ 21 | $ 20 |
Basis of Presentation (Notes)
Basis of Presentation (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
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, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its four thousand square mile, state-approved service area allocation, located entirely within the State of Oregon, encompasses 51 incorporated cities. As of September 30, 2019 , PGE served 892 thousand retail customers within a service area of 1.9 million residents. 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. The financial information included herein as of and for the three and nine months ended September 30, 2019 and 2018 is unaudited; however, in the opinion of management, such information reflects all adjustments necessary to fairly present the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. All such adjustments are of normal recurring nature, unless otherwise noted. The financial information as of December 31, 2018 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2018 , included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 15, 2019 , which should be read in conjunction with such condensed consolidated financial statements. Comprehensive Income No material change occurred in Other comprehensive income in the three and nine months ended September 30, 2019 and 2018 . 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 In August 2018, the FASB issued ASU 2018-13 Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement . ASU 2018-13 amends Topic 820 to add, remove, and clarify disclosure requirements related to fair value measurement disclosures. For calendar year-end entities, the update will be effective for annual periods beginning January 1, 2020, and interim periods within those fiscal years. Early adoption of the amendments is permitted, including adoption in any interim period. As the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the condensed consolidated financial statements and is still evaluating whether it will early adopt. In August 2018, the FASB issued ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract , to provide guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2020. Early adoption is permitted, including adoption in an interim period. The amendments in this update may be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PGE is in the process of evaluating potential impacts of these amendments and does not plan to early adopt. In August 2018, the FASB issued ASU 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans . ASU 2018-14 amends Topic 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2021. Early adoption is permitted. As the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the condensed consolidated financial statements and is still evaluating whether it will early adopt. Recently Adopted Accounting Pronouncements On January 1, 2019, PGE adopted ASU 2016-02, Leases (Topic 842), which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases . The Company elected the practical expedient provided under ASU 2018-11, Leases (Topic 842) Targeted Improvements , which amended ASU 2016-02 to provide entities an optional transition practical expedient to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. As a result, no adjustments were made to the balance sheet prior to January 1, 2019 and amounts are reported in accordance with historical accounting under Topic 840, while the balance sheet as of September 30, 2019 is presented under Topic 842. The Company also elected the practical expedient provided under ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 , which amended ASU 2016-02 to provide entities an optional transition practical expedient to not evaluate under Topic 842, existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. Effective January 1, 2019, PGE evaluates new or modified land easements under Topic 842. PGE's transition to the new lease standard did not result in a material adjustment to beginning retained earnings and the Company expects the adoption of the new standard to have an immaterial impact to its results of operations on an ongoing basis. Upon transition, PGE elected to reassess all arrangements that may contain a lease and their resulting lease classification which resulted in the following balance sheet adjustments as of January 1, 2019: i) the recognition of right-of-use assets and liabilities from operating and finance leases of $44 million pursuant to the new standard; ii) the derecognition of existing build-to-suit assets and liabilities of $131 million that were no longer considered to meet build-to-suit criteria under Topic 842 and were not recognized on the Company’s balance sheet until commencement, which occurred in the second quarter of 2019; and iii) the derecognition of $49 million in lease assets and liabilities related to an existing gas pipeline lateral capital lease that no longer met the definition of a lease under the new standard. The following table illustrates the adjustments made upon adoption of Topic 842 and the corresponding line items affected on the Company’s condensed consolidated balance sheets (in millions): January 1, 2019 Topic 842 Adoption Adjustments Increase due to existing operating and finance leases Decrease due to build-to-suit reassessment Decrease due to capital lease reassessment Total Increase/(Decrease) Assets Electric utility plant, net $ 2 $ (131 ) $ (49 ) $ (178 ) Other noncurrent assets 42 — — 42 Liabilities Accrued expenses and other current liabilities 5 — (2 ) 3 Other noncurrent liabilities 39 (131 ) (47 ) (139 ) For new required disclosures and further information see Note 11, Leases. The transition to the new standard did not have a material impact on the Company's financial position. On January 1, 2019 PGE adopted ASU 2018-02 Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02). ASU 2018-02 allows for a reclassification from accumulated other comprehensive income to retained earnings for the stranded tax effects resulting from the United States Tax Cuts and Jobs Act of 2017 (TCJA). The amendments only relate to the reclassification of the income tax effects of the TCJA, and therefore the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. As a result, PGE reclassified $2 million from Accumulated other compressive loss to Retained earnings during the period of adoption rather than applying the standard retrospectively. The implementation did not result in a material impact to the results of operation, financial position or statements of cash flows. |
Revenue Recognition (Notes)
Revenue Recognition (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
Revenue Recognition and Deferred Revenue [Abstract] | |
Revenue Recognition, Multiple-deliverable Arrangements [Table Text Block] | REVENUE RECOGNITION Disaggregated Revenue The following table presents PGE’s revenue, disaggregated by customer type (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Retail: Residential $ 218 $ 224 $ 713 $ 699 Commercial 167 171 479 484 Industrial 50 55 144 138 Direct access customers 13 9 34 32 Subtotal 448 459 1,370 1,353 Alternative revenue programs, net of amortization 4 — 5 (2 ) Other accrued (deferred) revenues, net (1) 4 (11 ) 17 (38 ) Total retail revenues 456 448 1,392 1,313 Wholesale revenues (2) 72 67 125 119 Other operating revenues 14 10 58 35 Total revenues $ 542 $ 525 $ 1,575 $ 1,467 (1) Amounts for the three months ended September 30, 2019 and 2018 primarily comprised of $6 million of amortization and $11 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. Amounts for the nine months ended September 30, 2019 and 2018 primarily comprised of $17 million of amortization and $36 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. (2) Wholesale revenues include $25 million and $29 million related to electricity commodity contract derivative settlements for the three months ended September 30, 2019 and 2018 , respectively, and $38 million and $35 million , respectively, for the nine months ended September 30, 2019 and 2018 . Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management. Retail Revenues The Company’s primary revenue source is the sale of electricity to customers at regulated tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single-family housing, multiple-family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers. Commercial customers include most businesses, small industrial companies, and public street and highway lighting accounts. Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers. Demand from industrial customers is primarily driven by economic conditions, with weather having little impact on energy use by this customer class. In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and are determined through general rate case proceedings and various tariff filings with the Public Utility Commission of Oregon (OPUC). Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options. Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that has not yet been billed to customers. This amount, which is classified as Unbilled revenues in the Company’s condensed consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices. PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct services that are substantially the same and have the same pattern of transfer to the customer that is satisfied over time as customers simultaneously receive and consume the benefits provided. PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations. Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers associated with activities for the benefit of the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and are not reflected in Revenues, net within the condensed consolidated statements of income and comprehensive income. Wholesale Revenues PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power, hydro, solar and wind conditions, and daily and seasonal retail demand. PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues. Other Operating Revenues Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, excess fuel sales, utility pole attachment revenues, and other electric services provided to customers. Arrangements with Multiple Performance Obligations Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. PGE generally determines standalone selling prices based on the prices charged to customers. |
Balance Sheet Components (Notes
Balance Sheet Components (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
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, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that inventories are recorded at the lower of average cost or net realizable value. Other Current Assets Other current assets consist of the following (in millions): September 30, 2019 December 31, 2018 Prepaid expenses $ 28 $ 54 Assets from price risk management activities 14 20 Margin deposits 12 16 Other current assets $ 54 $ 90 Electric Utility Plant, Net Electric utility plant, net consists of the following (in millions): September 30, 2019 December 31, 2018 Electric utility plant $ 10,778 $ 10,344 Construction work-in-progress 258 346 Total cost 11,036 10,690 Less: accumulated depreciation and amortization (4,022 ) (3,803 ) Electric utility plant, net $ 7,014 $ 6,887 Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $350 million and $302 million as of September 30, 2019 and December 31, 2018 , respectively. Amortization expense related to intangible assets was $16 million and $49 million for the three and nine months ended September 30, 2019 , respectively, and $16 million and $43 million for the three and nine months ended September 30, 2018 , 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, 2019 December 31, 2018 Current Noncurrent Current Noncurrent Regulatory assets: Price risk management $ 12 $ 96 $ 32 $ 99 Pension and other postretirement plans — 218 — 222 Debt issuance costs — 18 — 16 Trojan decommissioning activities — 93 — 26 Other 14 58 29 38 Total regulatory assets $ 26 $ 483 $ 61 $ 401 Regulatory liabilities: Asset retirement removal costs $ — $ 1,011 $ — $ 979 Deferred income taxes — 262 — 267 Asset retirement obligations — 54 — 53 Tax Reform Deferral (1) 23 6 23 22 Other 17 47 13 34 Total regulatory liabilities $ 40 (2) $ 1,380 $ 36 (2) $ 1,355 (1) Related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest. (2) 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, 2019 December 31, 2018 Accrued employee compensation and benefits $ 63 $ 66 Accrued taxes payable 45 34 Accrued interest payable 39 27 Accrued dividends payable 35 34 Regulatory liabilities—current 40 36 Other 71 71 Total accrued expenses and other current liabilities $ 293 $ 268 Asset Retirement Obligations Asset retirement obligations (AROs) consist of the following (in millions): September 30, 2019 December 31, 2018 Trojan decommissioning activities $ 137 $ 68 Utility plant 114 112 Non-utility property 17 17 Asset retirement obligations $ 268 $ 197 Trojan decommissioning activities represents the present value of future decommissioning costs for the plant, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the Independent Spent Fuel Storage Installation (ISFSI), an interim dry storage facility that is licensed by the Nuclear Regulatory Commission (NRC). The ISFSI is to house the spent nuclear fuel at the former plant site until an off-site storage facility is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a U.S. Department of Energy facility is complete, which is not expected prior to 2059. In the third quarter of 2019, the NRC issued PGE a renewed license to operate the ISFSI through the first quarter of 2059. PGE updated its ARO to reflect the estimated costs through this date, which increased the Trojan ARO by $69 million as of September 30, 2019. Credit Facilities As of December 31, 2018 , PGE had a $500 million revolving credit facility scheduled to terminate in November 2021 . On January 16, 2019, PGE executed an amendment to the credit facility extending the termination date to November 14, 2022 and allowing for unlimited extensions, provided that lenders with a pro-rata share of more than 50% approve the extension request. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, as backup for commercial paper borrowings, and to permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The revolving credit facility contains a provision that 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, 2019 , PGE was in compliance with this covenant with a 50.2% 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 revolving credit facility, as of September 30, 2019 , PGE had no borrowings outstanding or commercial paper issued. As a result, the aggregate unused available credit capacity under the revolving credit facility was $500 million . In addition, PGE has four letter of credit facilities that provide a total capacity of $220 million under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $60 million were outstanding as of September 30, 2019 . Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets. Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2020 . Long-term Debt On April 12, 2019, PGE issued $200 million of 4.30% Series First Mortgage Bonds (FMBs) due in 2049 . Proceeds from the transaction were used to repay the $300 million current portion of long-term debt on April 15, 2019. On October 25, 2019, PGE entered into an agreement to issue $270 million of privately placed FMBs in two tranches, both of which will bear interest from their issue date at an annual rate of 3.34%. The first tranche, $110 million , with a maturity in 2049, was issued on October 25, 2019, a portion of which was used to redeem $50 million of 6.75% FMBs that had a maturity date in 2023. Due to the anticipated repayment of the $50 million , this amount of long-term debt was classified as current on the Company’s balance sheets as of September 30, 2019. The second tranche, $160 million , with a maturity in 2050, is expected to be issued and funded on or about November 15, 2019. Defined Benefit Retirement 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, 2019 2018 2019 2018 Service cost $ 4 $ 5 $ 12 $ 15 Interest cost* 8 8 25 24 Expected return on plan assets* (10 ) (10 ) (30 ) (31 ) Amortization of net actuarial loss* 3 4 8 12 Net periodic benefit cost $ 5 $ 7 $ 15 $ 20 * The expense portion of non-service cost components are included in Miscellaneous income, net within Other income on the Company’s condensed consolidated statements of income and comprehensive income. PGE sponsors a health and welfare plan, under which it offers medical and life insurance benefits, as well as health reimbursement arrangements (HRAs). Retirees who participate in the Company’s postretirement health insurance plans are eligible for a Defined Dollar Medical Benefit (DDB), which limits PGE’s obligation pursuant to the postretirement health plan by establishing a maximum benefit per employee with employees responsible for the additional cost. In the third quarter of 2019, PGE announced an amendment to its HRAs and DDBs for non-represented employees, resulting in a $2 million curtailment gain, which has been recorded in Miscellaneous income, net on the condensed consolidated statement of income and comprehensive income. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
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, 2019 and December 31, 2018 . PGE then classifies these financial assets and liabilities based on a fair value hierarchy that is applied 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: Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the measurement date; Level 2 Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date; and 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 assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements. PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all 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 months ended September 30, 2019 and 2018 , except those presented in this note. The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions): As of September 30, 2019 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ — $ — $ — $ — $ — Nuclear decommissioning trust: (1) Debt securities: Domestic government 7 15 — — 22 Corporate credit — 12 — — 12 Money market funds measured at NAV (2) — — — 12 12 Non-qualified benefit plan trust: (3) Money market funds 2 — — — 2 Equity securities 6 — — — 6 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 6 1 — 7 Natural gas — 10 1 — 11 $ 16 $ 43 $ 2 $ 12 $ 73 Liabilities: Price risk management activities: (1) (4) Electricity $ — $ 5 $ 99 $ — $ 104 Natural gas — 18 4 — 22 $ — $ 23 $ 103 $ — $ 126 (1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate. (2) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $28 million , which are recorded at cash surrender value. (4) For further information, see Note 5, Risk Management. As of December 31, 2018 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 112 $ — $ — $ — $ 112 Nuclear decommissioning trust: (1) Debt securities: Domestic government 7 18 — — 25 Corporate credit — 10 — — 10 Money market funds measured at NAV (2) — — — 7 7 Non-qualified benefit plan trust: (3) Money market funds 2 — — — 2 Equity securities 6 — — — 6 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 9 3 — 12 Natural gas — 8 — — 8 $ 128 $ 45 $ 3 $ 7 $ 183 Liabilities: Interest rate swap derivatives $ — $ 4 $ — $ — $ 4 Price risk management activities: (1) (4) Electricity — 10 84 — 94 Natural gas — 51 7 — 58 $ — $ 65 $ 91 $ — $ 156 (1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate. (2) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $27 million , which are recorded at cash surrender value. (4) For further information, see Note 5, Risk Management. Cash equivalents are highly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted average maturity of securities holdings of such funds do not exceed 90 days and provide investors with the ability to redeem shares of the funds daily at their respective net asset value. These cash equivalents are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for money market fund prices include published exchanges such as the National Association of Securities Dealers Automated Quotations (NASDAQ) and the New York Stock Exchange (NYSE). Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) 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: Debt securities —PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark 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 classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the NYSE. Money market funds —PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice. The NQBP trust is invested in exchange-traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy. Liabilities from interest rate swap derivatives are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of forward starting interest rate swap lock agreements to hedge a portion of the interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. 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 risk exposure to commodity price and foreign currency exchange rate risk and to reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, 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, 2019 Electricity physical forwards $ — $ 96 Discounted cash flow Electricity forward price (per MWh) $ 11.57 $ 64.41 $ 42.98 Natural gas financial swaps 1 4 Discounted cash flow Natural gas forward price (per Decatherm) 1.23 3.74 1.69 Electricity financial futures 1 3 Discounted cash flow Electricity forward price (per MWh) 15.50 53.97 36.90 $ 2 $ 103 As of December 31, 2018 Electricity physical forwards $ 3 $ 84 Discounted cash flow Electricity forward price (per MWh) $ 14.60 $ 69.00 $ 45.00 Natural gas financial swaps — 7 Discounted cash flow Natural gas forward price (per Decatherm) 0.95 4.64 1.82 $ 3 $ 91 The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter term contracts, PGE employs the mid-point of the bid-ask spread of the market and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data from multiple sources. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed price curves, which derive longer term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a quarterly basis by the Company. The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and PGE’s position as either the buyer or seller under 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 September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Balance as of the beginning of the period $ 72 $ 129 $ 88 $ 139 Net realized and unrealized (gains)/losses * 30 (2 ) 14 (10 ) Transfers out of Level 3 to Level 2 (1 ) (2 ) (1 ) (4 ) Balance as of the end of the period $ 101 $ 125 $ 101 $ 125 * Both realized and unrealized (gains)/losses, 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 and comprehensive 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, 2019 and 2018 , 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 out of Level 3 at the end of the reporting period for all of its derivative instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur, as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements. Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement. As of September 30, 2019 , the carrying amount of PGE’s long-term debt was $2,378 million , net of $10 million of unamortized debt expense, and its estimated aggregate fair value was $2,754 million . As of December 31, 2018 , the carrying amount of PGE’s long-term debt was $2,478 million , net of $10 million of unamortized debt expense, and its estimated aggregate fair value was $2,760 million . |
Risk Management (Notes)
Risk Management (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
Price Risk Management [Abstract] | |
PRICE RISK MANAGEMENT | RISK MANAGEMENT Price Risk Management PGE participates in the wholesale marketplace to balance its supply of power, which consists of its own generation combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existing long-term wholesale contracts. Wholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions for Company-owned generation resources. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flows. PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk to reduce volatility in NVPC for its retail customers. Such derivative instruments, recorded at fair value on the condensed consolidated balance sheets, may include forward, futures, swaps, and option contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. In accordance with the ratemaking and cost recovery processes authorized by the OPUC, the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. The Company does not engage in trading activities for non-retail purposes. PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions): September 30, 2019 December 31, 2018 Current assets: Commodity contracts: Electricity $ 6 $ 11 Natural gas 8 7 Total current derivative assets (1) 14 18 Noncurrent assets: Commodity contracts: Electricity 1 1 Natural gas 3 1 Total noncurrent derivative assets (1) 4 2 Total derivative assets (2) $ 18 $ 20 Current liabilities: Commodity contracts: Electricity $ 12 $ 16 Natural gas 14 35 Total current derivative liabilities 26 51 Noncurrent liabilities: Commodity contracts: Electricity 92 78 Natural gas 8 23 Total noncurrent derivative liabilities 100 101 Total derivative liabilities (2) $ 126 $ 152 (1) Total current derivative assets is included in Other current assets, and Total noncurrent derivative assets is included in Other noncurrent assets on the condensed consolidated balance sheets. (2) As of September 30, 2019 and December 31, 2018 , no derivative assets or liabilities were designated as hedging instruments. PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions): September 30, 2019 December 31, 2018 Commodity contracts: Electricity 6 MWhs 5 MWhs Natural gas 140 Decatherms 123 Decatherms Foreign currency $ 21 Canadian $ 18 Canadian PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of September 30, 2019 , and December 31, 2018 , gross amounts included as Price risk management liabilities subject to master netting agreements were $2 million and $88 million , respectively, for which PGE posted no collateral as of September 30, 2019 and $11 million as of December 31, 2018 , which consisted entirely of letters of credit. As of September 30, 2019 , of the gross amounts recognized, none was for electricity and $2 million was for natural gas compared to $84 million for electricity and $4 million for natural gas recognized as of December 31, 2018 . Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the condensed consolidated statements of income and comprehensive income and were as follows (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Commodity contracts: Electricity $ 36 $ (3 ) $ 18 $ (5 ) Natural Gas (9 ) (3 ) (13 ) 11 Foreign currency exchange — — — 1 Net unrealized and certain net realized losses (gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three -month periods ended September 30, 2019 and 2018 , net losses of $24 million and net gains of $8 million , respectively, have been offset. Net losses of $5 million and net gains of $2 million have been offset for the nine months ended September 30, 2019 and 2018 , respectively. Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss (gain) recorded as of September 30, 2019 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions): 2019 2020 2021 2022 2023 Thereafter Total Commodity contracts: Electricity $ (3 ) $ 11 $ 9 $ 7 $ 7 $ 66 $ 97 Natural gas 2 5 4 — — — 11 Net unrealized loss $ (1 ) $ 16 $ 13 $ 7 $ 7 $ 66 $ 108 PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company. The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of September 30, 2019 was $118 million , for which PGE has posted $21 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at September 30, 2019 , the cash requirement to either post as collateral or settle the instruments immediately would have been $109 million . As of September 30, 2019 , PGE had no cash collateral posted 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, 2019 December 31, 2018 Assets from price risk management activities: Counterparty A 35 % 42 % Counterparty B — 15 Counterparty C 17 5 Counterparty D 11 9 63 % 71 % Liabilities from price risk management activities: Counterparty E 76 % 56 % See Note 4, 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. Interest Rate Risk In 2018 PGE entered into interest rate swap lock agreements to hedge a portion of its interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of December 31, 2018 , the fair value of the interest rate swaps was a $4 million liability, which was recorded in Liabilities from price risk management activities - current on the Company’s condensed consolidated balance sheets. The swaps settled at a $5 million loss in January 2019, which has been recorded in Regulatory assets - noncurrent on the condensed consolidated balance sheets. As of September 30, 2019 , the Company had no |
Earnings Per Share (Notes)
Earnings Per Share (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE | EARNINGS PER SHARE Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights. 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 months ended September 30, 2019 , unvested performance-based restricted stock units and related dividend equivalent rights of 265 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 229 thousand shares excluded for the three and nine months ended September 30, 2018 . Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Weighted-average common shares outstanding—basic 89,372 89,239 89,346 89,205 Dilutive effect of potential common shares 222 — 209 — Weighted-average common shares outstanding—diluted 89,594 89,239 89,555 89,205 |
Equity (Notes)
Equity (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
Equity [Abstract] | |
Equity | SHAREHOLDERS’ EQUITY The activity in equity during the three and nine -month periods ended September 30, 2019 and 2018 was as follows (dollars in millions, except per share amounts): Common Stock Accumulated Other Comprehensive Loss Retained Earnings Shares Amount Total Balances as of December 31, 2018 89,267,959 $ 1,212 $ (7 ) $ 1,301 $ 2,506 Issuances of shares pursuant to equity-based plans 88,352 — — — — Other comprehensive income — — 1 — 1 Dividends declared ($0.3625 per share) — — — (32 ) (32 ) Net income — — — 73 73 Reclassification of stranded tax effects due to Tax Reform — — (2 ) 2 — Balances as of March 31, 2019 89,356,311 $ 1,212 $ (8 ) $ 1,344 $ 2,548 Issuances of shares pursuant to equity-based plans 15,249 1 — — 1 Stock-based compensation — 2 — — 2 Other comprehensive income — — 1 — 1 Dividends declared ($0.3850 per share) — — — (35 ) (35 ) Net income — — — 25 25 Balances as of June 30, 2019 89,371,560 $ 1,215 $ (7 ) $ 1,334 $ 2,542 Issuances of shares pursuant to equity-based plans 414 — — — — Stock-based compensation — 2 — — 2 Dividends declared ($0.3850 per share) — — — (35 ) (35 ) Net income — — — 55 55 Balances as of September 30, 2019 89,371,974 $ 1,217 $ (7 ) $ 1,354 $ 2,564 Common Stock Accumulated Other Comprehensive Loss Retained Earnings Shares Amount Total Balances as of December 31, 2017 89,114,265 $ 1,207 $ (8 ) $ 1,217 $ 2,416 Issuances of shares pursuant to equity-based plans 99,854 — — — — Stock-based compensation — (1 ) — — (1 ) Dividends declared ($0.3400 per share) — — — (30 ) (30 ) Net income — — — 64 64 Balances as of March 31, 2018 89,214,119 $ 1,206 $ (8 ) $ 1,251 $ 2,449 Issuances of shares pursuant to equity-based plans 24,087 — — — — Stock-based compensation — 2 — — 2 Dividends declared ($0.3625 per share) — — — (32 ) (32 ) Net income — — — 46 46 Balances as of June 30, 2018 89,238,206 $ 1,208 $ (8 ) $ 1,265 $ 2,465 Issuances of shares pursuant to equity-based plans 6,453 — — — — Stock-based compensation — 1 — — 1 Dividends declared ($0.3625 per share) — — — (33 ) (33 ) Net income — — — 53 53 Balances as of September 30, 2018 89,244,659 $ 1,209 $ (8 ) $ 1,285 $ 2,486 |
Contingencies (Notes)
Contingencies (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
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 condensed consolidated financial statements are prepared. 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 determined, then PGE: 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 why the estimate cannot be made. 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 either the current or the subsequent reporting period, depending on the nature of the underlying event. PGE 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) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact. EPA Investigation of Portland Harbor An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site. PGE has been included among more than one hundred Potentially Responsible Parties (PRPs) as it historically owned or operated property near the river. The Portland Harbor site remedial investigation had been completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the remedial investigation and feasibility study and stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy. The EPA finalized the feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued in January 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion , comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs, for a combined discounted present value of $1.1 billion . Remediation construction costs were estimated to be incurred over a 13-year period, with long-term operation and maintenance costs estimated to be incurred over a 30-year period from the start of construction. The EPA acknowledged the estimated costs were based on data that was outdated and that pre-remedial design sampling was necessary to gather updated baseline data to better refine the remedial design and estimated cost. A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of the Portland Harbor Superfund site have improved substantially over the past ten years. In response, the EPA indicated that while it accepted the data and would use it to inform implementation of the ROD, it did not agree that the data collected, or the analysis offered, supported many of the conclusions reached in the sampling update. PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, remedial design, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up. It is probable that PGE will share in a portion of the costs related to Portland Harbor. However, based on the above facts and remaining uncertainties, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor, although such costs could be material to PGE’s financial position. In cases in which injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which are referred to as Natural Resource Damages (NRD). The EPA does not manage NRD assessment activities but does provide claims information and coordination support to the NRD trustees. NRD assessment activities are typically conducted by a Council made up of the trustee entities for the site. The Portland Harbor NRD trustees consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, the Confederated Tribes of the Grand Ronde Community of Oregon, the Confederated Tribes of Siletz Indians, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon, and the Nez Perce Tribe. The NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate the trustees for costs incurred in assessing the damages. The Company believes that PGE’s portion of NRD liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows. The impact of such costs to the Company’s results of operations is mitigated by the Portland Harbor Environmental Remediation Account (PHERA) mechanism. As approved by the OPUC in 2017, the PHERA allows the Company to defer and recover incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, such as insurance recoveries, and if necessary, through customer prices. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds. Annual expenditures in excess of $6 million , excluding expenses related to contingent liabilities, are subject to an annual earnings test and would be ineligible for recovery to the extent PGE’s actual regulated return on equity exceeds its return on equity as authorized by the OPUC in PGE’s most recent general rate case. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or ineligible per the prescribed earnings test. The Company plans to seek recovery of any costs resulting from EPA’s determination of liability for Portland Harbor through application of the PHERA. At this time, PGE is not recovering any Portland Harbor cost from the PHERA through customer prices. Trojan Investment Recovery Class Actions In 1993, PGE closed the Trojan nuclear power plant (Trojan) and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan. Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the matter to the OPUC for reconsideration. In 2003, in two separate legal proceedings, lawsuits were filed against PGE on behalf of two classes of electric service customers: i) Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court (Circuit Court); and ii) Morgan v. Portland General Electric Company, Marion County Circuit Court. The class action lawsuits seek damages totaling $260 million , plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan. In 2006, the Oregon Supreme Court (OSC) issued a ruling ordering abatement of the class action proceedings. The OSC concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could be offered to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment that the Company collected in prices. In 2008, the OPUC issued an order (2008 Order) that required PGE to provide refunds, including interest, which refunds were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in 2013 and by the OSC in 2014. In 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement on the class action proceedings and heard oral argument on the Company’s motion for Summary Judgment. In March 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. In April 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon. A Court of Appeals decision remains pending. PGE believes that the 2014 OSC decision and the Circuit Court decisions that followed have reduced the risk of any loss to the Company beyond the amounts previously recorded and refunds discussed above. However, because the class actions remain subject to a decision in the appeal, management believes that it is reasonably possible that such a loss to the Company could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss. Deschutes River Alliance Clean Water Act Claims In 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company (Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon) that sought injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claimed PGE had violated certain conditions contained in PGE’s Water Quality Certification for the Pelton Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleged the violations were related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project. The SWW, located above Round Butte Dam on the Deschutes River in central Oregon, is, among other things, designed to blend water from the surface with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements, for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA alleged that PGE’s operation of the SWW had caused the above-referenced violations of the CWA, which in turn had degraded the fish and wildlife habitat of the Deschutes River below the Project and harmed the economic and personal interests of DRA’s members and supporters. In March and April 2018, DRA and PGE filed cross-motions for summary judgment and PGE and the Confederated Tribes of Warm Springs (CTWS), which co-own the Project, filed separate motions to dismiss. CTWS initially appeared as a friend of the court, but subsequently was found to be a necessary party to the lawsuit and joined as a defendant. In August 2018, the U.S. District Court of the District of Oregon (District Court) denied DRA’s motions for partial summary judgment and granted PGE’s and CTWS’s cross-motions for summary judgment, ruling in favor of PGE and CTWS. The District Court found that DRA had not shown a genuine dispute of material fact sufficient to support its contention that PGE and CTWS were operating the Project in violation of the CWA, and accordingly dismissed the case. In October 2018, DRA filed an appeal, and PGE and the CTWS filed cross-appeals, to the Ninth Circuit Court of Appeals. Briefing has been rescheduled to begin in January 2020. The Company cannot predict the outcome of this matter or determine the likelihood of whether the outcome will result in a material loss. Other Matters PGE is subject to other regulatory, environmental, and legal proceedings, investigations, and claims that arise from time to time in the ordinary course of business 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, 2019 | |
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, 2019 , 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. |
Income tax Income tax (Notes)
Income tax Income tax (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | INCOME TAXES Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table: Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Federal statutory tax rate 21.0 % 21.0 % 21.0 % 21.0 % Federal tax credits * (14.8 ) (12.3 ) (13.8 ) (15.8 ) State and local taxes, net of federal tax benefit 6.5 6.5 6.5 6.5 Flow through depreciation and cost basis differences 1.0 (0.1 ) 1.2 (2.3 ) Amortization of excess deferred income tax (3.9 ) — (3.5 ) — Other — (0.6 ) 0.2 3.0 Effective tax rate 9.8 % 14.5 % 11.6 % 12.4 % * Federal tax credits consists of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2024. Carryforwards Federal tax credit carryforwards as of September 30, 2019 and December 31, 2018 were $55 million and $52 million , respectively. These credits consist of PTCs which will expire at various dates through 2039. PGE believes that it is more likely than not that its deferred income tax assets as of September 30, 2019 will be realized; accordingly, no valuation allowance has been recorded. As of September 30, 2019 , and December 31, 2018 , PGE had no unrecognized tax benefits. |
Leases Leases (Notes)
Leases Leases (Notes) | 9 Months Ended |
Sep. 30, 2019 | |
Leases [Abstract] | |
Disclosure Text Block [Abstract] | LEASES PGE determines if an arrangement is a lease at inception and whether the arrangement is classified as an operating or finance lease. At commencement of the lease, PGE records a right-of-use (ROU) asset and lease liability in the condensed consolidated balance sheets based on the present value of lease payments over the term of the arrangement. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent PGE's obligation to make lease payments arising from the lease. If the implicit rate is not readily determinable in the contract, PGE uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Contract terms may include options to extend or terminate the lease, and, when the Company deems it is reasonably certain that PGE will exercise that option, it is included in the ROU asset and lease liability. Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability and amortization expense of the ROU asset. Any material differences between expense recognition and timing of payments will be deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes. PGE does not record leases with a term of 12-months or less in the condensed consolidated balance sheet. Total short-term lease costs for the three and nine months ended September 30, 2019 are immaterial. PGE has lease agreements with lease and non-lease components, which are accounted for separately. The Company’s leases relate primarily to the use of land, support facilities, gas storage, and power purchase agreements that rely on identified plant. Variable payments are generally related to gas storage and power purchase agreements for components dependent upon variable factors, such as energy production and property taxes, and are not included in the determination of the present value of lease payments. The components of lease cost were as follows (in millions): Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating lease cost $ 3 $ 6 Finance lease cost: Amortization of right-of-use assets $ 1 $ 2 Interest on lease liabilities 3 4 Total finance lease cost $ 4 $ 6 Variable lease cost $ 4 $ 15 Supplemental information related to amounts and presentation of leases in the condensed consolidated balance sheets is presented below (in millions): Balance Sheet Classification September 30, 2019 Operating Leases: Operating lease right-of-use assets Other noncurrent assets $ 52 Current liabilities Accrued expenses and other current liabilities 8 Noncurrent liabilities Other noncurrent liabilities 44 Total operating lease liabilities $ 52 Finance Leases: Finance lease right-of-use assets Electric utility plant, net $ 152 Current liabilities Current portion of finance lease obligations 17 Noncurrent liabilities Finance lease obligations, net of current portion 136 Total finance lease liabilities $ 153 Lease term and discount rates were as follows: September 30, 2019 Weighted Average Remaining Lease Term Operating leases 24 years Finance leases 29 years Weighted Average Discount Rate Operating leases 3.5 % Finance leases 7.3 % PGE’s gas storage finance lease contains five 10-year renewal periods which have not been included in the finance lease obligation. As of September 30, 2019 , maturities of lease liabilities were as follows (in millions): Operating Leases Finance Leases 2019 $ 2 $ 4 2020 8 16 2021 8 16 2022 8 16 2023 8 14 Thereafter 53 249 Total lease payments 87 315 Less imputed interest (35 ) (162 ) Total $ 52 $ 153 Supplemental cash flow information related to leases was as follows (in millions): Nine Months Ended September 30, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 5 Operating cash flows from finance leases 3 Financing cash flows from finance leases 2 Right-of-use assets obtained in leasing arrangements: Operating leases $ 56 Finance leases 154 2018 Lease Obligations As of December 31, 2018, and pursuant to historical lease accounting under Topic 840, PGE’s estimated future minimum lease payments pursuant to capital, build-to-suit, and operating leases for the following five years and thereafter are as follows (in millions): Future Minimum Lease Payments Capital Leases Build-to-Suit Operating Leases 2019 $ 6 $ 11 $ 4 2020 6 14 5 2021 6 13 5 2022 6 13 6 2023 5 13 7 Thereafter 67 225 97 Total minimum lease payments 96 $ 289 $ 124 Less imputed interest (47 ) Present value of net minimum lease payments 49 Less current portion (2 ) Noncurrent portion $ 47 Capital Leases —PGE entered into agreements to purchase natural gas transportation capacity via a 24-mile natural gas pipeline, Carty Lateral, that was constructed to serve the Carty natural gas-fired generating plant. The Company has entered into a 30-year agreement to purchase the entire capacity of Carty Lateral, which is approximately 175 thousand decatherms per day. At the end of the initial contract term, the Company has the option to renew the agreement in continuous three-year increments with at least 24 months prior written notice. As of December 31, 2018, a capital lease asset of $57 million and accumulated amortization of such assets of $8 million was reflected within Electric utility plant, net in the condensed consolidated balance sheets. The present value of the future minimum lease payments due under the agreement included $2 million within Accrued expenses and other current liabilities and $47 million in Other noncurrent liabilities on the condensed consolidated balance sheets. For ratemaking purposes capital leases are treated as operating leases; therefore, in accordance with the accounting rules for regulated operations, the amortization of the leased asset is based on the rental payments recovered from customers. Amortization of the leased asset of $3 million and interest expense of $4 million was recorded to Purchased power and fuel expense in the consolidated statements of income through December 31, 2018. Pursuant to the adoption of the new lease accounting standard, Topic 842, PGE derecognized the capital lease obligation and related capital lease asset as it no longer met the definition of a lease. Build-to-suit —PGE entered into a 30-year lease agreement with a local natural gas company, NW Natural, to expand their current natural gas storage facilities, including the development of an underground storage reservoir and construction of a new compressor station and 13-miles of pipeline, which are collectively designed to provide no-notice storage and transportation services to PGE’s Port Westward and Beaver natural gas-fired generating plants. Construction of the expansion project was completed in the second quarter of 2019 at a cost of $149 million . Due to the level of PGE’s involvement during the construction period, the Company was deemed to be the owner of the assets for accounting purposes during the construction period. As a result, PGE recorded $131 million to Construction work-in-progress within Electric utility plant, net and a corresponding liability for the same amount to Other noncurrent liabilities in the condensed consolidated balance sheets as of December 31, 2018. Pursuant to the adoption of the new lease accounting standard, Topic 842, PGE derecognized the build-to-suit assets and liabilities as they are no longer considered to meet the build-to-suit criteria under the new standard. The table above reflects PGE’s estimated future minimum lease payments pursuant to the agreement based on estimated costs. Operating leases —PGE has various operating leases associated with leases of land, support facilities, and power purchase agreements that rely on identified plant that expire in various years, extending through 2096. Rent expense was $7 million in 2018. Contingent rents related to power purchase agreements was $14 million in 2018. Sublease income was $4 million in 2018. |
Basis of Presentation (Policies
Basis of Presentation (Policies) | 9 Months Ended |
Sep. 30, 2019 | |
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 |
Inventory, Policy [Policy Text Block] | PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that inventories are recorded at the lower of average cost or net realizable value. |
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 |
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 assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements. |
Allocation of Financial Asset to Hierarchy Levels [Policy Text Block] | Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) trusts are recorded at fair value in PGE’s 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: Debt securities —PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark 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 classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the NYSE. Money market funds —PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice. The NQBP trust is invested in exchange-traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy. Liabilities from interest rate swap derivatives are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of forward starting interest rate swap lock agreements to hedge a portion of the interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. 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 risk exposure to commodity price and foreign currency exchange rate risk and to reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, 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. |
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 out of Level 3 at the end of the reporting period for all of its derivative instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur, as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements. |
Derivatives, Policy [Policy Text Block] | PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk to reduce volatility in NVPC for its retail customers. Such derivative instruments, recorded at fair value on the condensed consolidated balance sheets, may include forward, futures, swaps, and option contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. In accordance with the ratemaking and cost recovery processes authorized by the OPUC, the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. The Company does not engage in trading activities for non-retail purposes. |
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 condensed consolidated financial statements are prepared. 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 determined, then PGE: 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 why the estimate cannot be made. 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 either the current or the subsequent reporting period, depending on the nature of the underlying event. PGE 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) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact. |
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. |
Revenue Recognition (Policies)
Revenue Recognition (Policies) | 9 Months Ended |
Sep. 30, 2019 | |
Revenue Recognition and Deferred Revenue [Abstract] | |
Revenue Recognition, Multiple-deliverable Arrangements, Description [Policy Text Block] | Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. PGE generally determines standalone selling prices based on the prices charged to customers. |
Leases Leases (Policies)
Leases Leases (Policies) | 9 Months Ended |
Sep. 30, 2019 | |
Leases [Abstract] | |
Lessee, Leases [Policy Text Block] | PGE determines if an arrangement is a lease at inception and whether the arrangement is classified as an operating or finance lease. At commencement of the lease, PGE records a right-of-use (ROU) asset and lease liability in the condensed consolidated balance sheets based on the present value of lease payments over the term of the arrangement. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent PGE's obligation to make lease payments arising from the lease. If the implicit rate is not readily determinable in the contract, PGE uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Contract terms may include options to extend or terminate the lease, and, when the Company deems it is reasonably certain that PGE will exercise that option, it is included in the ROU asset and lease liability. Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability and amortization expense of the ROU asset. Any material differences between expense recognition and timing of payments will be deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes. |
Basis of Presentation Basis of
Basis of Presentation Basis of Presentation (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Accounting Changes and Error Corrections [Abstract] | |
Schedule of Changes for Adoption of New Accounting Pronouncements [Table Text Block] | The following table illustrates the adjustments made upon adoption of Topic 842 and the corresponding line items affected on the Company’s condensed consolidated balance sheets (in millions): January 1, 2019 Topic 842 Adoption Adjustments Increase due to existing operating and finance leases Decrease due to build-to-suit reassessment Decrease due to capital lease reassessment Total Increase/(Decrease) Assets Electric utility plant, net $ 2 $ (131 ) $ (49 ) $ (178 ) Other noncurrent assets 42 — — 42 Liabilities Accrued expenses and other current liabilities 5 — (2 ) 3 Other noncurrent liabilities 39 (131 ) (47 ) (139 ) |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Revenue Recognition and Deferred Revenue [Abstract] | |
Disaggregation of Revenue [Table Text Block] | The following table presents PGE’s revenue, disaggregated by customer type (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Retail: Residential $ 218 $ 224 $ 713 $ 699 Commercial 167 171 479 484 Industrial 50 55 144 138 Direct access customers 13 9 34 32 Subtotal 448 459 1,370 1,353 Alternative revenue programs, net of amortization 4 — 5 (2 ) Other accrued (deferred) revenues, net (1) 4 (11 ) 17 (38 ) Total retail revenues 456 448 1,392 1,313 Wholesale revenues (2) 72 67 125 119 Other operating revenues 14 10 58 35 Total revenues $ 542 $ 525 $ 1,575 $ 1,467 (1) Amounts for the three months ended September 30, 2019 and 2018 primarily comprised of $6 million of amortization and $11 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. Amounts for the nine months ended September 30, 2019 and 2018 primarily comprised of $17 million of amortization and $36 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. (2) Wholesale revenues include $25 million and $29 million related to electricity commodity contract derivative settlements for the three months ended September 30, 2019 and 2018 , respectively, and $38 million and $35 million , respectively, for the nine months ended September 30, 2019 and 2018 |
Balance Sheet Components (Table
Balance Sheet Components (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Balance Sheet Components [Abstract] | |
Schedule of Other Current Assets [Table Text Block] | Other current assets consist of the following (in millions): September 30, 2019 December 31, 2018 Prepaid expenses $ 28 $ 54 Assets from price risk management activities 14 20 Margin deposits 12 16 Other current assets $ 54 $ 90 |
Schedule of Public Utility Property, Plant, and Equipment [Table Text Block] | Electric utility plant, net consists of the following (in millions): September 30, 2019 December 31, 2018 Electric utility plant $ 10,778 $ 10,344 Construction work-in-progress 258 346 Total cost 11,036 10,690 Less: accumulated depreciation and amortization (4,022 ) (3,803 ) Electric utility plant, net $ 7,014 $ 6,887 |
Schedule of Regulatory Assets and Liabilities [Text Block] | Regulatory assets and liabilities consist of the following (in millions): September 30, 2019 December 31, 2018 Current Noncurrent Current Noncurrent Regulatory assets: Price risk management $ 12 $ 96 $ 32 $ 99 Pension and other postretirement plans — 218 — 222 Debt issuance costs — 18 — 16 Trojan decommissioning activities — 93 — 26 Other 14 58 29 38 Total regulatory assets $ 26 $ 483 $ 61 $ 401 Regulatory liabilities: Asset retirement removal costs $ — $ 1,011 $ — $ 979 Deferred income taxes — 262 — 267 Asset retirement obligations — 54 — 53 Tax Reform Deferral (1) 23 6 23 22 Other 17 47 13 34 Total regulatory liabilities $ 40 (2) $ 1,380 $ 36 (2) $ 1,355 (1) Related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest. (2) 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, 2019 December 31, 2018 Accrued employee compensation and benefits $ 63 $ 66 Accrued taxes payable 45 34 Accrued interest payable 39 27 Accrued dividends payable 35 34 Regulatory liabilities—current 40 36 Other 71 71 Total accrued expenses and other current liabilities $ 293 $ 268 |
Schedule of Asset Retirement Obligations [Table Text Block] | Asset Retirement Obligations Asset retirement obligations (AROs) consist of the following (in millions): September 30, 2019 December 31, 2018 Trojan decommissioning activities $ 137 $ 68 Utility plant 114 112 Non-utility property 17 17 Asset retirement obligations $ 268 $ 197 |
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, 2019 2018 2019 2018 Service cost $ 4 $ 5 $ 12 $ 15 Interest cost* 8 8 25 24 Expected return on plan assets* (10 ) (10 ) (30 ) (31 ) Amortization of net actuarial loss* 3 4 8 12 Net periodic benefit cost $ 5 $ 7 $ 15 $ 20 * The expense portion of non-service cost components are included in Miscellaneous income, net within Other income on the Company’s condensed consolidated statements of income and comprehensive income. PGE sponsors a health and welfare plan, under which it offers medical and life insurance benefits, as well as health reimbursement arrangements (HRAs). Retirees who participate in the Company’s postretirement health insurance plans are eligible for a Defined Dollar Medical Benefit (DDB), which limits PGE’s obligation pursuant to the postretirement health plan by establishing a maximum benefit per employee with employees responsible for the additional cost. In the third quarter of 2019, PGE announced an amendment to its HRAs and DDBs for non-represented employees, resulting in a $2 million curtailment gain, which has been recorded in Miscellaneous income, net on the condensed consolidated statement of income and comprehensive income. |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
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, 2019 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ — $ — $ — $ — $ — Nuclear decommissioning trust: (1) Debt securities: Domestic government 7 15 — — 22 Corporate credit — 12 — — 12 Money market funds measured at NAV (2) — — — 12 12 Non-qualified benefit plan trust: (3) Money market funds 2 — — — 2 Equity securities 6 — — — 6 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 6 1 — 7 Natural gas — 10 1 — 11 $ 16 $ 43 $ 2 $ 12 $ 73 Liabilities: Price risk management activities: (1) (4) Electricity $ — $ 5 $ 99 $ — $ 104 Natural gas — 18 4 — 22 $ — $ 23 $ 103 $ — $ 126 (1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate. (2) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $28 million , which are recorded at cash surrender value. (4) For further information, see Note 5, Risk Management. As of December 31, 2018 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 112 $ — $ — $ — $ 112 Nuclear decommissioning trust: (1) Debt securities: Domestic government 7 18 — — 25 Corporate credit — 10 — — 10 Money market funds measured at NAV (2) — — — 7 7 Non-qualified benefit plan trust: (3) Money market funds 2 — — — 2 Equity securities 6 — — — 6 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 9 3 — 12 Natural gas — 8 — — 8 $ 128 $ 45 $ 3 $ 7 $ 183 Liabilities: Interest rate swap derivatives $ — $ 4 $ — $ — $ 4 Price risk management activities: (1) (4) Electricity — 10 84 — 94 Natural gas — 51 7 — 58 $ — $ 65 $ 91 $ — $ 156 (1) Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate. (2) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. (3) Excludes insurance policies of $27 million , which are recorded at cash surrender value. (4) For further information, see Note 5, Risk Management. |
Fair Value Option, 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, 2019 Electricity physical forwards $ — $ 96 Discounted cash flow Electricity forward price (per MWh) $ 11.57 $ 64.41 $ 42.98 Natural gas financial swaps 1 4 Discounted cash flow Natural gas forward price (per Decatherm) 1.23 3.74 1.69 Electricity financial futures 1 3 Discounted cash flow Electricity forward price (per MWh) 15.50 53.97 36.90 $ 2 $ 103 As of December 31, 2018 Electricity physical forwards $ 3 $ 84 Discounted cash flow Electricity forward price (per MWh) $ 14.60 $ 69.00 $ 45.00 Natural gas financial swaps — 7 Discounted cash flow Natural gas forward price (per Decatherm) 0.95 4.64 1.82 $ 3 $ 91 |
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 September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Balance as of the beginning of the period $ 72 $ 129 $ 88 $ 139 Net realized and unrealized (gains)/losses * 30 (2 ) 14 (10 ) Transfers out of Level 3 to Level 2 (1 ) (2 ) (1 ) (4 ) Balance as of the end of the period $ 101 $ 125 $ 101 $ 125 * Both realized and unrealized (gains)/losses, 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 and comprehensive income. |
Price Risk Management (Tables)
Price Risk Management (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
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, 2019 December 31, 2018 Current assets: Commodity contracts: Electricity $ 6 $ 11 Natural gas 8 7 Total current derivative assets (1) 14 18 Noncurrent assets: Commodity contracts: Electricity 1 1 Natural gas 3 1 Total noncurrent derivative assets (1) 4 2 Total derivative assets (2) $ 18 $ 20 Current liabilities: Commodity contracts: Electricity $ 12 $ 16 Natural gas 14 35 Total current derivative liabilities 26 51 Noncurrent liabilities: Commodity contracts: Electricity 92 78 Natural gas 8 23 Total noncurrent derivative liabilities 100 101 Total derivative liabilities (2) $ 126 $ 152 (1) Total current derivative assets is included in Other current assets, and Total noncurrent derivative assets is included in Other noncurrent assets on the condensed consolidated balance sheets. (2) As of September 30, 2019 and December 31, 2018 , no derivative assets or liabilities were designated as hedging instruments. |
Schedule of Derivative Instruments [Table Text Block] | PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions): September 30, 2019 December 31, 2018 Commodity contracts: Electricity 6 MWhs 5 MWhs Natural gas 140 Decatherms 123 Decatherms Foreign currency $ 21 Canadian $ 18 Canadian |
Derivatives Not Designated as Hedging Instruments [Table Text Block] | Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the condensed consolidated statements of income and comprehensive income and were as follows (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Commodity contracts: Electricity $ 36 $ (3 ) $ 18 $ (5 ) Natural Gas (9 ) (3 ) (13 ) 11 Foreign currency exchange — — — 1 |
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 (gain) recorded as of September 30, 2019 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions): 2019 2020 2021 2022 2023 Thereafter Total Commodity contracts: Electricity $ (3 ) $ 11 $ 9 $ 7 $ 7 $ 66 $ 97 Natural gas 2 5 4 — — — 11 Net unrealized loss $ (1 ) $ 16 $ 13 $ 7 $ 7 $ 66 $ 108 |
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, 2019 December 31, 2018 Assets from price risk management activities: Counterparty A 35 % 42 % Counterparty B — 15 Counterparty C 17 5 Counterparty D 11 9 63 % 71 % Liabilities from price risk management activities: Counterparty E 76 % 56 % |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | The denominators of the basic and diluted earnings per share computations are as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Weighted-average common shares outstanding—basic 89,372 89,239 89,346 89,205 Dilutive effect of potential common shares 222 — 209 — Weighted-average common shares outstanding—diluted 89,594 89,239 89,555 89,205 |
Equity (Tables)
Equity (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Equity [Abstract] | |
Schedule of Stockholders Equity [Table Text Block] | The activity in equity during the three and nine -month periods ended September 30, 2019 and 2018 was as follows (dollars in millions, except per share amounts): Common Stock Accumulated Other Comprehensive Loss Retained Earnings Shares Amount Total Balances as of December 31, 2018 89,267,959 $ 1,212 $ (7 ) $ 1,301 $ 2,506 Issuances of shares pursuant to equity-based plans 88,352 — — — — Other comprehensive income — — 1 — 1 Dividends declared ($0.3625 per share) — — — (32 ) (32 ) Net income — — — 73 73 Reclassification of stranded tax effects due to Tax Reform — — (2 ) 2 — Balances as of March 31, 2019 89,356,311 $ 1,212 $ (8 ) $ 1,344 $ 2,548 Issuances of shares pursuant to equity-based plans 15,249 1 — — 1 Stock-based compensation — 2 — — 2 Other comprehensive income — — 1 — 1 Dividends declared ($0.3850 per share) — — — (35 ) (35 ) Net income — — — 25 25 Balances as of June 30, 2019 89,371,560 $ 1,215 $ (7 ) $ 1,334 $ 2,542 Issuances of shares pursuant to equity-based plans 414 — — — — Stock-based compensation — 2 — — 2 Dividends declared ($0.3850 per share) — — — (35 ) (35 ) Net income — — — 55 55 Balances as of September 30, 2019 89,371,974 $ 1,217 $ (7 ) $ 1,354 $ 2,564 Common Stock Accumulated Other Comprehensive Loss Retained Earnings Shares Amount Total Balances as of December 31, 2017 89,114,265 $ 1,207 $ (8 ) $ 1,217 $ 2,416 Issuances of shares pursuant to equity-based plans 99,854 — — — — Stock-based compensation — (1 ) — — (1 ) Dividends declared ($0.3400 per share) — — — (30 ) (30 ) Net income — — — 64 64 Balances as of March 31, 2018 89,214,119 $ 1,206 $ (8 ) $ 1,251 $ 2,449 Issuances of shares pursuant to equity-based plans 24,087 — — — — Stock-based compensation — 2 — — 2 Dividends declared ($0.3625 per share) — — — (32 ) (32 ) Net income — — — 46 46 Balances as of June 30, 2018 89,238,206 $ 1,208 $ (8 ) $ 1,265 $ 2,465 Issuances of shares pursuant to equity-based plans 6,453 — — — — Stock-based compensation — 1 — — 1 Dividends declared ($0.3625 per share) — — — (33 ) (33 ) Net income — — — 53 53 Balances as of September 30, 2018 89,244,659 $ 1,209 $ (8 ) $ 1,285 $ 2,486 |
Income tax Income tax (Tables)
Income tax Income tax (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table: Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Federal statutory tax rate 21.0 % 21.0 % 21.0 % 21.0 % Federal tax credits * (14.8 ) (12.3 ) (13.8 ) (15.8 ) State and local taxes, net of federal tax benefit 6.5 6.5 6.5 6.5 Flow through depreciation and cost basis differences 1.0 (0.1 ) 1.2 (2.3 ) Amortization of excess deferred income tax (3.9 ) — (3.5 ) — Other — (0.6 ) 0.2 3.0 Effective tax rate 9.8 % 14.5 % 11.6 % 12.4 % * Federal tax credits consists of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2024. |
Leases Leases (Tables)
Leases Leases (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Leases [Abstract] | |
Lease Cost [Table Text Block] | The components of lease cost were as follows (in millions): Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating lease cost $ 3 $ 6 Finance lease cost: Amortization of right-of-use assets $ 1 $ 2 Interest on lease liabilities 3 4 Total finance lease cost $ 4 $ 6 Variable lease cost $ 4 $ 15 |
Supplemental Information [Table Text Block] | Supplemental information related to amounts and presentation of leases in the condensed consolidated balance sheets is presented below (in millions): Balance Sheet Classification September 30, 2019 Operating Leases: Operating lease right-of-use assets Other noncurrent assets $ 52 Current liabilities Accrued expenses and other current liabilities 8 Noncurrent liabilities Other noncurrent liabilities 44 Total operating lease liabilities $ 52 Finance Leases: Finance lease right-of-use assets Electric utility plant, net $ 152 Current liabilities Current portion of finance lease obligations 17 Noncurrent liabilities Finance lease obligations, net of current portion 136 Total finance lease liabilities $ 153 |
Lease Term and Discount Rate [Table Text Block] | Lease term and discount rates were as follows: September 30, 2019 Weighted Average Remaining Lease Term Operating leases 24 years Finance leases 29 years Weighted Average Discount Rate Operating leases 3.5 % Finance leases 7.3 % |
Maturities of Lease Liabilities [Table Text Block] | As of September 30, 2019 , maturities of lease liabilities were as follows (in millions): Operating Leases Finance Leases 2019 $ 2 $ 4 2020 8 16 2021 8 16 2022 8 16 2023 8 14 Thereafter 53 249 Total lease payments 87 315 Less imputed interest (35 ) (162 ) Total $ 52 $ 153 |
Supplemental Cash Flow Information [Table Text Block] | Supplemental cash flow information related to leases was as follows (in millions): Nine Months Ended September 30, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 5 Operating cash flows from finance leases 3 Financing cash flows from finance leases 2 Right-of-use assets obtained in leasing arrangements: Operating leases $ 56 Finance leases 154 |
Future Minimum Lease Payments [Table Text Block] | As of December 31, 2018, and pursuant to historical lease accounting under Topic 840, PGE’s estimated future minimum lease payments pursuant to capital, build-to-suit, and operating leases for the following five years and thereafter are as follows (in millions): Future Minimum Lease Payments Capital Leases Build-to-Suit Operating Leases 2019 $ 6 $ 11 $ 4 2020 6 14 5 2021 6 13 5 2022 6 13 6 2023 5 13 7 Thereafter 67 225 97 Total minimum lease payments 96 $ 289 $ 124 Less imputed interest (47 ) Present value of net minimum lease payments 49 Less current portion (2 ) Noncurrent portion $ 47 |
Basis of Presentation Schedule
Basis of Presentation Schedule of Changes for Adoption of New Accounting Pronouncements (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2019USD ($) | |
Property, Plant and Equipment [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 178 |
Other Noncurrent Assets [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (42) |
Accrued Liabilities [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (3) |
Other Noncurrent Liabilities [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 139 |
Accounting Standards Update 2016-02 [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (44) |
Accounting Standards Update 2016-02 [Member] | Property, Plant and Equipment [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (2) |
Accounting Standards Update 2016-02 [Member] | Other Noncurrent Assets [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (42) |
Accounting Standards Update 2016-02 [Member] | Accrued Liabilities [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (5) |
Accounting Standards Update 2016-02 [Member] | Other Noncurrent Liabilities [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (39) |
Building [Member] | Property, Plant and Equipment [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (131) |
Building [Member] | Other Noncurrent Assets [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 0 |
Building [Member] | Accrued Liabilities [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 0 |
Building [Member] | Other Noncurrent Liabilities [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 131 |
Assets Held under Capital Leases [Member] | Property, Plant and Equipment [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (49) |
Assets Held under Capital Leases [Member] | Other Noncurrent Assets [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 0 |
Assets Held under Capital Leases [Member] | Accrued Liabilities [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 2 |
Assets Held under Capital Leases [Member] | Other Noncurrent Liabilities [Member] | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 47 |
Basis of Presentation (Details)
Basis of Presentation (Details) retail_customers in Thousands, mi² in Thousands, $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019USD ($)mi²retail_customers | Mar. 31, 2019USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2019USD ($)mi²retail_customers | Sep. 30, 2018USD ($) | |
Basis of Presentation [Abstract] | |||||
Service Area Sq Miles | mi² | 4,000 | 4,000 | |||
Incorporated Cities | 51 | 51 | |||
Number of Retail Customers | retail_customers | 892 | 892 | |||
Alternative revenue programs, net of amortization | $ 4 | $ 0 | $ 5 | $ (2) | |
Reclassification of stranded tax effects due to Tax Reform | $ 0 | 2 | |||
Property, Plant and Equipment [Member] | |||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | (178) | ||||
Accounting Standards Update 2016-02 [Member] | |||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 44 | ||||
Accounting Standards Update 2016-02 [Member] | Property, Plant and Equipment [Member] | |||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 2 | ||||
Building [Member] | Property, Plant and Equipment [Member] | |||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 131 | ||||
Assets Held under Capital Leases [Member] | Property, Plant and Equipment [Member] | |||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 49 |
Revenue Recognition (Details)
Revenue Recognition (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Disaggregation of Revenue [Line Items] | ||||
Subtotal | $ 448 | $ 459 | $ 1,370 | $ 1,353 |
Alternative revenue programs, net of amortization | 4 | 0 | 5 | (2) |
Other accrued (deferred) revenues, net | 4 | (11) | 17 | (38) |
Total retail revenues | 456 | 448 | 1,392 | 1,313 |
Wholesale revenues | 72 | 67 | 125 | 119 |
Other operating revenue | 14 | 10 | 58 | 35 |
Total Revenues | 542 | 525 | 1,575 | 1,467 |
Gain on Derivative Instruments, Pretax | 25 | 29 | 38 | 35 |
Residential [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Subtotal | 218 | 224 | 713 | 699 |
Commercial [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Subtotal | 167 | 171 | 479 | 484 |
Industrial [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Subtotal | 50 | 55 | 144 | 138 |
Direct Access customers [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Subtotal | 13 | 9 | 34 | 32 |
Revenue Subject to Refund [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Net tax benefits due to the change in tax rate under the TCJA | $ 6 | $ 11 | $ 17 | $ 36 |
Balance Sheet Components Other
Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Other Current Assets [Line Items] | ||
Prepaid expenses | $ 28 | $ 54 |
Assets from price risk management activities | 14 | 20 |
Margin deposits | 12 | 16 |
Other current assets | $ 54 | $ 90 |
Balance Sheet Components Electr
Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Property, Plant and Equipment [Line Items] | ||
Electric utility plant | $ 10,778 | $ 10,344 |
Construction work-in-progress | 258 | 346 |
Total cost | 11,036 | 10,690 |
Less: accumulated depreciation and amortization | (4,022) | (3,803) |
Electric utility plant, net | $ 7,014 | $ 6,887 |
Balance Sheet Components Regula
Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Assets, Current | $ 26 | $ 61 |
Regulatory assets - noncurrent | 483 | 401 |
Regulatory Liability, Current | 40 | 36 |
Regulatory liabilities-noncurrent | 1,380 | 1,355 |
Removal Costs [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Liability, Current | 0 | 0 |
Regulatory liabilities-noncurrent | 1,011 | 979 |
Deferred Income Tax Charge [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Liability, Current | 0 | 0 |
Regulatory liabilities-noncurrent | 262 | 267 |
Asset Retirement Obligation Costs [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Liability, Current | 0 | 0 |
Regulatory liabilities-noncurrent | 54 | 53 |
Revenue Subject to Refund [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Liability, Current | 23 | 23 |
Regulatory liabilities-noncurrent | 6 | 22 |
Other Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Liability, Current | 17 | 13 |
Regulatory liabilities-noncurrent | 47 | 34 |
Deferred Derivative Gain (Loss) [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Assets, Current | 12 | 32 |
Regulatory assets - noncurrent | 96 | 99 |
Pension and Other Postretirement Plans Costs [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Assets, Current | 0 | 0 |
Regulatory assets - noncurrent | 218 | 222 |
Loss on Reacquired Debt [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Assets, Current | 0 | 0 |
Regulatory assets - noncurrent | 18 | 16 |
Environmental Restoration Costs [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Assets, Current | 0 | 0 |
Regulatory assets - noncurrent | 93 | 26 |
Other Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Assets, Current | 14 | 29 |
Regulatory assets - noncurrent | $ 58 | $ 38 |
Balance Sheet Components Othe_2
Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Accrued employee compensation and benefits | $ 63 | $ 66 |
Accrued taxes payable | 45 | 34 |
Accrued interest payable | 39 | 27 |
Accrued dividends payable | 35 | 34 |
Regulatory liabilities—current | 40 | 36 |
Other | 71 | 71 |
Total accrued expenses and other current liabilities | $ 293 | $ 268 |
Balance Sheet Components Schedu
Balance Sheet Components Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Asset Retirement Obligation Disclosure [Abstract] | ||
Decommissioning Liability, Noncurrent | $ 137 | $ 68 |
Accrued Capping, Closure, Post-closure and Environmental Costs, Noncurrent | 114 | 112 |
Asset Retirement Obligations, Noncurrent | 17 | 17 |
Asset Retirement Obligation | $ 268 | $ 197 |
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, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Service cost | $ 4 | $ 5 | $ 12 | $ 15 |
Interest cost | 8 | 8 | 25 | 24 |
Expected return on plan assets | (10) | (10) | (30) | (31) |
Amortization of net actuarial loss | 3 | 4 | 8 | 12 |
Net periodic benefit cost | $ 5 | $ 7 | $ 15 | $ 20 |
Balance Sheet Components (Detai
Balance Sheet Components (Details) | Nov. 15, 2019USD ($) | Oct. 25, 2019USD ($) | Apr. 12, 2019USD ($) | Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2018USD ($) |
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||||
Letters of Credit Outstanding, Amount | $ 0 | $ 0 | ||||||
Finite-Lived Intangible Assets, Accumulated Amortization | 350,000,000 | 350,000,000 | $ 302,000,000 | |||||
Amortization of Intangible Assets | 16,000,000 | $ 16,000,000 | $ 49,000,000 | $ 43,000,000 | ||||
Asset Retirement Obligation, Revision of Estimate | $ 69,000,000 | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | 500,000,000 | |||||||
Debt Instrument, Covenant Description | 65.00% | |||||||
Ratio of Indebtedness to Net Capital | 0.502 | 0.502 | ||||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 500,000,000 | $ 500,000,000 | ||||||
Line of Credit Facility, Current Borrowing Capacity | 220,000,000 | 220,000,000 | ||||||
Letters of credit issued | 60,000,000 | 60,000,000 | ||||||
Authorized Short-Term Debt | 900,000,000 | 900,000,000 | ||||||
Long-term Debt, Current Maturities | 50,000,000 | 50,000,000 | $ 300,000,000 | |||||
Proceeds from Issuance of Debt | $ 270,000,000 | |||||||
Proceeds from Issuance of Long-term Debt | $ 160,000,000 | $ 110,000,000 | $ 200,000,000 | 200,000,000 | $ 0 | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment | 2,000,000 | |||||||
Letter of Credit [Member] | ||||||||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||||
Short-term debt | $ 0 | $ 0 |
Fair Value of Financial Instr_3
Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Jan. 31, 2019 | Dec. 31, 2018 |
Assets: | |||
Cash equivalents | $ 0 | $ 112 | |
Debt securities: | |||
Domestic government | 22 | 25 | |
Corporate credit | 12 | 10 | |
Money market funds measured at NAV (2) | 12 | 7 | |
Non-qualified benefit plan trust: (2) | |||
Money market funds | 2 | 2 | |
Equity securities - domestic | 6 | 6 | |
Debt securities—domestic government | 1 | 1 | |
Assets from price risk management activities: (1) (3) | |||
Electricity | 7 | 12 | |
Natural gas | 11 | 8 | |
Total | 12 | 7 | |
Assets, Fair Value Disclosure | 73 | 183 | |
Liabilities from price risk management activities: (1) (3) | |||
Derivative Liability | 0 | $ 5 | 4 |
Electricity | 104 | 94 | |
Natural gas | 22 | 58 | |
Total | 126 | 156 | |
Fair Value, Inputs, Level 1 [Member] | |||
Assets: | |||
Cash equivalents | 0 | 112 | |
Debt securities: | |||
Domestic government | 7 | 7 | |
Corporate credit | 0 | 0 | |
Non-qualified benefit plan trust: (2) | |||
Money market funds | 2 | 2 | |
Equity securities - domestic | 6 | 6 | |
Debt securities—domestic government | 1 | 1 | |
Assets from price risk management activities: (1) (3) | |||
Electricity | 0 | 0 | |
Natural gas | 0 | 0 | |
Total | 16 | 128 | |
Liabilities from price risk management activities: (1) (3) | |||
Derivative Liability | 0 | ||
Electricity | 0 | 0 | |
Natural gas | 0 | 0 | |
Total | 0 | 0 | |
Fair Value, Inputs, Level 2 [Member] | |||
Assets: | |||
Cash equivalents | 0 | 0 | |
Debt securities: | |||
Domestic government | 15 | 18 | |
Corporate credit | 12 | 10 | |
Non-qualified benefit plan trust: (2) | |||
Money market funds | 0 | 0 | |
Equity securities - domestic | 0 | 0 | |
Debt securities—domestic government | 0 | 0 | |
Assets from price risk management activities: (1) (3) | |||
Electricity | 6 | 9 | |
Natural gas | 10 | 8 | |
Total | 43 | 45 | |
Liabilities from price risk management activities: (1) (3) | |||
Derivative Liability | 4 | ||
Electricity | 5 | 10 | |
Natural gas | 18 | 51 | |
Total | 23 | 65 | |
Fair Value, Inputs, Level 3 [Member] | |||
Assets: | |||
Cash equivalents | 0 | 0 | |
Debt securities: | |||
Domestic government | 0 | 0 | |
Corporate credit | 0 | 0 | |
Non-qualified benefit plan trust: (2) | |||
Money market funds | 0 | 0 | |
Equity securities - domestic | 0 | 0 | |
Debt securities—domestic government | 0 | 0 | |
Assets from price risk management activities: (1) (3) | |||
Electricity | 1 | 3 | |
Natural gas | 1 | 0 | |
Total | 2 | 3 | |
Liabilities from price risk management activities: (1) (3) | |||
Derivative Liability | 0 | ||
Electricity | 99 | 84 | |
Natural gas | 4 | 7 | |
Total | $ 103 | $ 91 |
Fair Value of Financial Instr_4
Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($) | Sep. 30, 2019 | Dec. 31, 2018 |
Low [Member] | ||
Commodity Contracts | ||
Electricity physical forwards | $ 11.57 | $ 14.60 |
Natural gas financial swaps | 1.23 | 0.95 |
Financial swaps - electricity | 15.50 | |
High [Member] | ||
Commodity Contracts | ||
Electricity physical forwards | 64.41 | 69 |
Natural gas financial swaps | 3.74 | 4.64 |
Financial swaps - electricity | 53.97 | |
Weighted Average [Member] | ||
Commodity Contracts | ||
Electricity physical forwards | 42.98 | 45 |
Natural gas financial swaps | 1.69 | 1.82 |
Financial swaps - electricity | 36.90 | |
Assets [Member] | ||
Commodity Contracts | ||
Electricity physical forwards | 0 | 3,000,000 |
Natural gas financial swaps | 1,000,000 | 0 |
Financial swaps - electricity | 1,000,000 | |
Total commodity contracts | 2,000,000 | 3,000,000 |
Liabilities [Member] | ||
Commodity Contracts | ||
Electricity physical forwards | 96,000,000 | 84,000,000 |
Natural gas financial swaps | 4,000,000 | 7,000,000 |
Financial swaps - electricity | 3,000,000 | |
Total commodity contracts | $ 103,000,000 | $ 91,000,000 |
Fair Value of Financial Instr_5
Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Balance as of the beginning of the period | $ 72 | $ 129 | $ 88 | $ 139 |
Net realized and unrealized (gains)/losses | 30 | (2) | 14 | (10) |
Transfers out of Level 3 to Level 2 | (1) | (2) | (1) | (4) |
Balance as of the end of the period | $ 101 | $ 125 | $ 101 | $ 125 |
Fair Value of Financial Instr_6
Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Dec. 31, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3 | $ 0 | $ 0 | $ 0 | $ 0 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net | 0 | $ 0 | 0 | $ 0 | |
Cash Surrender Value, Fair Value Disclosure | 28,000,000 | 28,000,000 | $ 27,000,000 | ||
Long-term Debt | 2,378,000,000 | 2,378,000,000 | 2,478,000,000 | ||
Unamortized Debt Issuance Expense | 10,000,000 | 10,000,000 | 10,000,000 | ||
Long-term Debt, Fair Value | $ 2,754,000,000 | $ 2,754,000,000 | $ 2,760,000,000 |
Risk Management Fair values of
Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Current Assets, Commodity Contracts: | ||
Electricity | $ 6 | $ 11 |
Natural gas | 8 | 7 |
Total current derivative assets | 14 | 18 |
Noncurrent Assets, Commodity Contracts: [Abstract] | ||
Commodity Contract Asset, Noncurrent, Electricity | 1 | 1 |
Commodity Contract Asset, Noncurrent, Natural Gas | 3 | 1 |
Derivative Asset, Noncurrent | 4 | 2 |
Total derivative assets | 18 | 20 |
Current Liabilities, Commodity Contracts: [Abstract] | ||
Electricity | 12 | 16 |
Natural gas | 14 | 35 |
Total current derivative liabilities | 26 | 51 |
Noncurrent Liabilities, Commodity Contracts: [Abstract] | ||
Electricity | 92 | 78 |
Natural gas | 8 | 23 |
Total noncurrent derivative liabilities | 100 | 101 |
Total derivative liabilities | $ 126 | $ 152 |
Risk Management Net volumes rel
Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions | Sep. 30, 2019CAD ($)MMBTUMWh | Dec. 31, 2018CAD ($)MMBTUMWh |
Commodity contracts: | ||
Electricity | MWh | 6 | 5 |
Natural gas | MMBTU | 140 | 123 |
Foreign currency | $ | $ 21 | $ 18 |
Risk Management Net realized an
Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Commodity contracts: | ||||
Electricity | $ 36 | $ (3) | $ 18 | $ (5) |
Natural Gas | (9) | (3) | (13) | 11 |
Foreign currency exchange | $ 0 | $ 0 | $ 0 | $ 1 |
Risk Management Future Year Net
Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions | Sep. 30, 2019USD ($) |
Electricity [Member] | |
Commodity contracts: | |
2019 | $ (3) |
2020 | 11 |
2021 | 9 |
2022 | 7 |
2023 | 7 |
Thereafter | 66 |
Total | 97 |
Natural Gas [Member] | |
Commodity contracts: | |
2019 | 2 |
2020 | 5 |
2021 | 4 |
2022 | 0 |
2023 | 0 |
Thereafter | 0 |
Total | 11 |
Net Unrealized Loss [Member] | |
Commodity contracts: | |
2019 | (1) |
2020 | 16 |
2021 | 13 |
2022 | 7 |
2023 | 7 |
Thereafter | 66 |
Total | $ 108 |
Risk Management Counterparties
Risk Management Counterparties Representing 10% or More of Assets and Liabilities from price risk management activities (Details) | Sep. 30, 2019 | Dec. 31, 2018 |
Assets from price risk management activities: | ||
Counterparty A | 35.00% | 42.00% |
Counterparty B | 0.00% | 15.00% |
Counterparty C | 17.00% | 5.00% |
Counterparty D | 11.00% | 9.00% |
Concentration of Risk, Derivative Instruments, Assets | 63.00% | 71.00% |
Liabilities from price risk management activities: | ||
Counterparty C | 76.00% | 56.00% |
Risk Management (Details)
Risk Management (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Jan. 31, 2019 | Dec. 31, 2018 | |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | $ 11 | |||||
Net gain or (loss) recognized in the statement of income offset by regulatory accounting | $ 24 | $ 8 | $ 5 | $ 2 | ||
Derivative, Net Liability Position, Aggregate Fair Value | 118 | 118 | ||||
Collateral Already Posted, Aggregate Fair Value | 21 | 21 | ||||
Collateral cash requirement | 109 | 109 | ||||
Deposit Assets | 0 | 0 | ||||
Derivative Liability | 0 | 0 | $ 5 | 4 | ||
Natural Gas [Member] | ||||||
Derivative Instruments and Hedges, Liabilities | 2 | 2 | 4 | |||
4911 Electric Services [Member] | ||||||
Derivative Instruments and Hedges, Liabilities | 0 | 0 | 84 | |||
Liabilities, Total [Member] | ||||||
Derivative Instruments and Hedges, Liabilities | $ 2 | $ 2 | 88 | |||
Fair Value, Inputs, Level 2 [Member] | ||||||
Derivative Liability | $ 4 |
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, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Earnings Per Share [Abstract] | ||||
Weighted Average Number of Shares Outstanding, Basic | 89,372 | 89,239 | 89,346 | 89,205 |
Dilutive effect of potential common shares | 222 | 0 | 209 | 0 |
Weighted Average Number of Shares Outstanding, Diluted | 89,594 | 89,239 | 89,555 | 89,205 |
Earnings Per Share Earnings Per
Earnings Per Share Earnings Per Share (Details) - shares shares in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Earnings Per Share [Abstract] | ||||
Incremental Common Shares Attributable to Dilutive Effect of Contingently Issuable Shares | 265 | 229 | 267 | 231 |
Schedule of Stockholders Equity
Schedule of Stockholders Equity (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Common Stock, Shares, Outstanding beginning of period | 89,267,959 | 89,267,959 | ||||||
Issuance of shares pursuant to equity-based plans | $ 0 | $ 1 | $ 0 | $ 0 | $ 0 | $ 0 | ||
Share-based Payment Arrangement, Decrease for Tax Withholding Obligation | 2 | 2 | 1 | 2 | (1) | |||
Stockholders' Equity | 2,542 | 2,548 | 2,506 | 2,465 | 2,449 | 2,416 | $ 2,506 | $ 2,416 |
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | 1 | 1 | ||||||
Dividends declared | (35) | (35) | (32) | (33) | (32) | (30) | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $ 55 | 25 | 73 | 53 | 46 | 64 | 153 | 163 |
Reclassification of stranded tax effects due to Tax Reform | 0 | $ (2) | ||||||
Common Stock, Shares, Outstanding end of period | 89,371,974 | 89,371,974 | ||||||
Stockholders' Equity | $ 2,564 | $ 2,542 | $ 2,548 | $ 2,486 | $ 2,465 | $ 2,449 | $ 2,564 | $ 2,486 |
Common Stock [Member] | ||||||||
Common Stock, Shares, Outstanding beginning of period | 89,371,560 | 89,356,311 | 89,267,959 | 89,238,206 | 89,214,119 | 89,114,265 | 89,267,959 | 89,114,265 |
Issuances of shares pursuant to equity-based plans | 414 | 15,249 | 88,352 | 6,453 | 24,087 | 99,854 | ||
Common Stock, Shares, Outstanding end of period | 89,371,974 | 89,371,560 | 89,356,311 | 89,244,659 | 89,238,206 | 89,214,119 | 89,371,974 | 89,244,659 |
Common Stock Including Additional Paid in Capital [Member] | ||||||||
Issuance of shares pursuant to equity-based plans | $ 0 | $ 1 | $ 0 | $ 0 | $ 0 | $ 0 | ||
Share-based Payment Arrangement, Decrease for Tax Withholding Obligation | 2 | 2 | 1 | 2 | (1) | |||
Stockholders' Equity | 1,215 | 1,212 | 1,212 | 1,208 | 1,206 | 1,207 | $ 1,212 | $ 1,207 |
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | 0 | |||||||
Dividends declared | 0 | |||||||
Stockholders' Equity | 1,217 | 1,215 | 1,212 | 1,209 | 1,208 | 1,206 | 1,217 | 1,209 |
AOCI Attributable to Parent [Member] | ||||||||
Stockholders' Equity | (7) | (8) | (7) | (8) | (8) | (7) | (8) | |
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | 1 | 1 | ||||||
Dividends declared | 0 | 0 | ||||||
Reclassification of stranded tax effects due to Tax Reform | (2) | |||||||
Stockholders' Equity | (7) | (7) | (8) | (8) | (8) | (7) | (8) | |
Retained Earnings [Member] | ||||||||
Stockholders' Equity | 1,334 | 1,344 | 1,301 | 1,265 | 1,251 | 1,217 | 1,301 | 1,217 |
Stock-based compensation | 0 | |||||||
Dividends declared | 35 | 35 | 32 | 33 | 32 | 30 | ||
Reclassification of stranded tax effects due to Tax Reform | (2) | |||||||
Stockholders' Equity | $ 1,354 | $ 1,334 | $ 1,344 | $ 1,285 | $ 1,265 | $ 1,251 | $ 1,354 | $ 1,285 |
Equity Equity (Details)
Equity Equity (Details) - $ / shares | 3 Months Ended | |||||
Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | |
Statement of Stockholders' Equity [Abstract] | ||||||
Common Stock, Dividends, Per Share, Declared | $ 0.3850 | $ 0.3850 | $ 0.3625 | $ 0.3625 | $ 0.3625 | $ 0.3400 |
Contingencies (Details)
Contingencies (Details) $ in Millions | 9 Months Ended | |
Sep. 30, 2019USD ($)party | Dec. 31, 1993 | |
Loss Contingencies [Line Items] | ||
Site Contingency, Names of Other Potentially Responsible Parties | party | 100 | |
Litigation Settlement, Expense | $ 115 | |
Loss Contingency, Estimate of Possible Loss | 1,700 | |
Loss Contingency, Damages Sought, Value | 1,200 | |
Loss Contingency, Range of Possible Loss, Portion Not Accrued | 500 | |
Environmental Remediation Expense | 6 | |
Investment in Trojan | 87.00% | |
Class action damages sought | 260 | |
Minimum [Member] | ||
Loss Contingencies [Line Items] | ||
Loss Contingency, Estimate of Possible Loss | $ 1,100 |
Income tax Effective Income Tax
Income tax Effective Income Tax Rate Reconcilitation (Details) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | ||||
Federal statutory tax rate | 21.00% | 21.00% | 21.00% | 21.00% |
Federal tax credits | (14.80%) | (12.30%) | (13.80%) | (15.80%) |
State and local taxes, net of federal tax benefit | 6.50% | 6.50% | 6.50% | 6.50% |
Flow through depreciation and cost basis differences | 1.00% | (0.10%) | 1.20% | (2.30%) |
Excess deferred tax amortization | (3.90%) | 0.00% | (3.50%) | 0.00% |
Other | 0.00% | (0.60%) | 0.20% | 3.00% |
Effective tax rate | 9.80% | 14.50% | 11.60% | 12.40% |
Income tax Income tax (Details)
Income tax Income tax (Details) - USD ($) | Sep. 30, 2019 | Dec. 31, 2018 |
Income Tax Disclosure [Abstract] | ||
Deferred Tax Assets, Operating Loss Carryforwards, Domestic | $ 55,000,000 | $ 52,000,000 |
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount | 0 | |
Unrecognized Tax Benefits | $ 0 | $ 0 |
Leases Lease Cost (Details)
Leases Lease Cost (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2019 | Sep. 30, 2019 | |
Leases [Abstract] | ||
Operating Lease, Cost | $ 3 | $ 6 |
Finance Lease, Right-of-Use Asset, Amortization | 1 | 2 |
Finance Lease, Interest Expense | 3 | 4 |
FinanceLeaseCost | 4 | 6 |
Variable Lease, Cost | $ 4 | $ 15 |
Leases Supplemental information
Leases Supplemental information (Details) - USD ($) $ in Millions | Sep. 30, 2019 | Dec. 31, 2018 |
Leases [Abstract] | ||
Operating Lease, Right-of-Use Asset | $ 52 | |
Operating Lease, Liability, Current | 8 | |
Operating Lease, Liability, Noncurrent | 44 | |
Operating Lease, Liability | 52 | |
Finance Lease, Right-of-Use Asset | 152 | |
Finance Lease, Liability, Current | 17 | $ 0 |
Finance Lease, Liability Noncurrent | 136 | $ 0 |
Finance Lease, Liability | $ 153 |
Leases Lease Term and Discount
Leases Lease Term and Discount Rate (Details) | Sep. 30, 2019 |
Leases [Abstract] | |
Operating Lease, Weighted Average Remaining Lease Term | 24 years |
Finance Lease, Weighted Average Remaining Lease Term | 29 years |
Operating Lease, Weighted Average Discount Rate, Percent | 3.50% |
Finance Lease, Weighted Average Discount Rate, Percent | 7.30% |
Leases Maturities of Lease Liab
Leases Maturities of Lease Liabilities (Details) $ in Millions | Sep. 30, 2019USD ($) |
Leases [Abstract] | |
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months | $ 2 |
Finance Lease, Liability, Payments, Remainder of Fiscal Year | 4 |
Lessee, Operating Lease, Liability, Payments, Due Year Two | 8 |
Finance Lease, Liability, Payments, Due Year Two | 16 |
Lessee, Operating Lease, Liability, Payments, Due Year Three | 8 |
Finance Lease, Liability, Payments, Due Year Three | 16 |
Lessee, Operating Lease, Liability, Payments, Due Year Four | 8 |
Finance Lease, Liability, Payments, Due Year Four | 16 |
Lessee, Operating Lease, Liability, Payments, Due Year Five | 8 |
Finance Lease, Liability, Payments, Due Year Five | 14 |
Lessee, Operating Lease, Liability, Payments, Due after Year Five | 53 |
Finance Lease, Liability, Payments, Due after Year Five | 249 |
Lessee, Operating Lease, Liability, Payments, Due | 87 |
Finance Lease, Liability, Payment, Due | 315 |
Lessee, Operating Lease, Liability, Undiscounted Excess Amount | (35) |
Finance Lease, Liability, Undiscounted Excess Amount | (162) |
Operating Lease, Liability | 52 |
Finance Lease, Liability | $ 153 |
Leases Supplemental Cash Flow I
Leases Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2019 | Sep. 30, 2019 | |
Leases [Abstract] | ||
Operating Lease, Payments | $ 5 | |
Finance Lease, Interest Payment on Liability | 3 | |
Finance Lease, Principal Payments | $ 2 | |
Variable Lease, Cost | 56 | |
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability | $ 154 |
Leases Future Minimum Lease Pay
Leases Future Minimum Lease Payments (Details) $ in Millions | Dec. 31, 2018USD ($) |
Leases [Abstract] | |
Capital Leases, Future Minimum Payments Due, Next Twelve Months | $ 6 |
Contractual Obligation, Due in Next Fiscal Year | 11 |
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 4 |
Capital Leases, Future Minimum Payments Due in Two Years | 6 |
Contractual Obligation, Due in Second Year | 14 |
Operating Leases, Future Minimum Payments, Due in Two Years | 5 |
Capital Leases, Future Minimum Payments Due in Three Years | 6 |
Contractual Obligation, Due in Third Year | 13 |
Operating Leases, Future Minimum Payments, Due in Three Years | 5 |
Capital Leases, Future Minimum Payments Due in Four Years | 6 |
Contractual Obligation, Due in Fourth Year | 13 |
Operating Leases, Future Minimum Payments, Due in Four Years | 6 |
Capital Leases, Future Minimum Payments Due in Five Years | 5 |
Contractual Obligation, Due in Fifth Year | 13 |
Operating Leases, Future Minimum Payments, Due in Five Years | 7 |
Capital Leases, Future Minimum Payments Due Thereafter | 67 |
Contractual Obligation, Due after Fifth Year | 225 |
Operating Leases, Future Minimum Payments, Due Thereafter | 97 |
Capital Leases, Future Minimum Payments Due | 96 |
Contractual Obligation | 289 |
Operating Leases, Future Minimum Payments Due | 124 |
Capital Leases, Future Minimum Payments, Interest Included in Payments | (47) |
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments | 49 |
Capital Lease Obligations, Current | (2) |
Purchase Commitment, Remaining Minimum Amount Committed | $ 47 |
Leases (Details)
Leases (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Leases [Abstract] | ||
Capital Leased Assets, Gross | $ 57 | |
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation | 8 | |
Capital Lease Obligations, Current | 2 | |
Purchase Commitment, Remaining Minimum Amount Committed | 47 | |
Deferred Costs, Leasing, Accumulated Amortization | $ 3 | |
Interest Expense, Lessee, Assets under Capital Lease | $ 4 | |
Long-term Purchase Commitment, Amount | 149 | |
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | 131 | |
Operating Leases, Rent Expense | 7 | |
Operating Leases, Rent Expense, Contingent Rentals | 14 | |
Operating Leases, Rent Expense, Sublease Rentals | $ 4 |