FORM 10-K
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[x]
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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[ ]
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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PORTLAND GENERAL ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
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Oregon
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93-0256820
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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Common Stock, no par value
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New York Stock Exchange
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(Title of class)
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(Name of exchange on which registered)
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Large accelerated filer
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[x]
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Accelerated filer
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Non-accelerated filer
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Smaller reporting company
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[ ]
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Emerging growth company
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Part III, Items 10 - 14
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Portions of Portland General Electric Company’s definitive proxy statement to be filed pursuant to Regulation 14A for the Annual Meeting of Shareholders to be held on April 24, 2019.
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Item 1.
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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Item 5.
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Item 6.
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Item 7.
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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Item 15.
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Abbreviation or Acronym
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Definition
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AFDC
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Allowance for funds used during construction
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ARO
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Asset retirement obligation
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AUT
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Annual Power Cost Update Tariff
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Beaver
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Beaver natural gas-fired generating plant
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Biglow Canyon
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Biglow Canyon Wind Farm
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Boardman
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Boardman coal-fired generating plant
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BPA
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Bonneville Power Administration
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Carty
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Carty natural gas-fired generating plant
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Colstrip
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Colstrip Units 3 and 4 coal-fired generating plant
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Coyote Springs
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Coyote Springs Unit 1 natural gas-fired generating plant
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CPP
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U.S. Environmental Protection Agency’s Clean Power Plan
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CWIP
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Construction work-in-progress
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Dth
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Decatherm = 10 therms = 1,000 cubic feet of natural gas
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DEQ
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Oregon Department of Environmental Quality
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EIM
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Energy Imbalance Market
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EPA
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United States Environmental Protection Agency
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ESS
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Electricity Service Supplier
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FERC
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Federal Energy Regulatory Commission
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FMB
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First Mortgage Bond
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FPA
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Federal Power Act
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GRC
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General Rate Case for a specified test year
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IRP
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Integrated Resource Plan
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ISFSI
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Independent Spent Fuel Storage Installation
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kV
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Kilovolt = one thousand volts of electricity
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Moody’s
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Moody’s Investors Service
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MW
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Megawatts
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MWa
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Average megawatts
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MWh
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Megawatt hours
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NRC
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Nuclear Regulatory Commission
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NVPC
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Net Variable Power Costs
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OATT
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Open Access Transmission Tariff
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OPUC
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Public Utility Commission of Oregon
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PCAM
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Power Cost Adjustment Mechanism
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PW1
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Port Westward Unit 1 natural gas-fired generating plant
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PW2
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Port Westward Unit 2 natural gas-fired flexible capacity generating plant
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RPS
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Renewable Portfolio Standard
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S&P
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S&P Global Ratings
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SEC
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United States Securities and Exchange Commission
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Trojan
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Trojan nuclear power plant
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Tucannon River
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Tucannon River Wind Farm
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USDOE
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United States Department of Energy
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•
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General Rate Cases
. PGE periodically evaluates the need to change its retail electric price structure to sufficiently cover its operating costs and provide a reasonable rate of return to investors. Price changes are requested pursuant to a comprehensive general rate case process that reflects revenue requirements based on a forecasted test year. Through this public review process, the OPUC authorizes the Company’s debt-to-equity capital structure, return on equity, overall rate of return, and customer prices. For additional information regarding the Company’s most recent general rate cases, see “
General Rate Cases
” in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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•
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Power Costs
. In addition to price changes resulting from the general rate case process, the OPUC has approved an Annual Power Cost Update Tariff (AUT) by which PGE can adjust retail customer prices annually to reflect forecasted changes in the Company’s net variable power costs (NVPC). NVPC consists of the cost of power purchased and fuel used to generate electricity, as well as the cost of settled electric and natural gas financial contracts (all classified as Purchased power and fuel expense in the Company’s consolidated statements of income) and is net of wholesale revenues, which are classified as Revenues, net in the consolidated statements of income. The OPUC has also authorized a Power Cost Adjustment Mechanism (PCAM), under which PGE may share with customers a portion of actual cost variances associated with NVPC.
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•
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Renewable Energy.
In 2007, the State of Oregon established a Renewable Portfolio Standard (RPS), which requires that PGE serve a portion of its retail load with renewable resources. The RPS allows renewable energy certificates (RECs), resulting from energy generated from qualified renewable resources, and generation from certified low impact hydroelectric power resources, to be used to meet those requirements. In addition, a renewable adjustment clause (RAC) mechanism was established that allows for the recovery in customer prices of prudently incurred costs to comply with the RPS. In 2016, the State of Oregon passed a law referred to as the Oregon Clean Electricity and Coal Transition Plan (SB 1547), which, among its provision, increased the RPS percentages in certain future years.
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Years Ended December 31,
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2018
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2017
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2016
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Retail revenues
(1)
(dollars in millions):
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Residential
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$
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948
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53
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%
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$
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969
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52
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%
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$
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907
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51
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%
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Commercial
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665
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37
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669
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36
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665
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37
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Industrial
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210
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12
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212
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11
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208
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12
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Subtotal
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1,823
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102
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1,850
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99
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1,780
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100
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Alternative revenue programs, net of amortization
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3
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—
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—
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—
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—
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—
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Other accrued (deferred) revenues, net
(2)
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(45
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)
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(2
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10
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1
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3
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—
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Total retail revenues
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$
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1,781
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100
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%
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$
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1,860
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100
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%
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$
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1,783
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100
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%
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Retail energy deliveries
(3)
(MWh in thousands):
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Residential
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7,416
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39
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%
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7,880
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40
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%
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7,348
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39
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%
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Commercial
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7,430
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39
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7,555
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38
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7,457
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39
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Industrial
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4,376
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22
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4,283
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22
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4,166
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22
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Total retail energy deliveries
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19,222
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100
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%
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19,718
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100
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%
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18,971
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100
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%
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Average number of retail customers:
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Residential
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772,389
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88
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%
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762,211
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88
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%
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752,365
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88
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%
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Commercial
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109,107
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12
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107,855
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12
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106,773
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12
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Industrial
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270
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—
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267
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—
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258
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—
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Total
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881,766
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100
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%
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870,333
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100
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%
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859,396
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100
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%
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(1)
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Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those commercial and industrial customers that purchase their energy from ESSs.
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(2)
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Activity for the year ended December 31, 2018 primarily relates to the regulatory liability deferral of the 2018 net tax benefits due to the change in corporate tax rate under the Tax Cuts and Jobs Act of 2018 (TCJA). For further information, see Note 12, Income Taxes in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”
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(3)
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Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.
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Years Ended December 31,
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2018
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2017
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2016
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Residential
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Revenue per customer (in dollars):
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$
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1,153
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$
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1,181
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$
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1,114
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Usage per customer (in kilowatt hours):
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9,601
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10,338
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9,766
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Revenue per kilowatt hour (in cents):
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12.01
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¢
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11.42
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¢
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11.40
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¢
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Commercial
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Revenue per customer (in dollars):
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$
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6,051
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$
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6,142
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$
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6,166
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Usage per customer (in kilowatt hours):
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68,096
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70,046
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69,839
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Revenue per kilowatt hour (in cents):
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8.89
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¢
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8.77
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¢
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8.83
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¢
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Industrial
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Revenue per customer (in dollars):
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$
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776,245
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$
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792,466
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$
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804,953
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Usage per customer (in kilowatt hours):
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16,207,263
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16,041,461
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16,146,371
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Revenue per kilowatt hour (in cents):
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4.79
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¢
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4.94
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¢
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4.99
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¢
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Heating
Degree-Days
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Cooling
Degree-Days
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2018
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3,702
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692
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2017
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4,558
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700
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2016
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3,552
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548
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15-year average
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4,117
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514
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Winter Loads
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Summer Loads
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Average
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Peak
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Month
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Average
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Peak
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Month
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2018
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2,519
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3,399
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February
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2,349
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3,816
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August
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2017
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2,698
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3,727
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January
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2,380
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3,976
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August
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2016
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2,537
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3,716
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December
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2,246
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3,726
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August
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As of December 31,
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2018
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2017
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2016
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Capacity
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%
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Capacity
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%
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Capacity
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%
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Generation:
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Thermal:
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Natural gas
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1,830
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38
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%
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1,831
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39
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%
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1,805
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38
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%
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Coal
|
814
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17
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|
814
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17
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814
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17
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Total thermal
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2,644
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55
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2,645
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56
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2,619
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55
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Wind
(1)
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717
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15
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717
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15
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717
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15
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Hydro
(2)
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495
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10
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495
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10
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495
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|
11
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Total generation
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3,856
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|
80
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3,857
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81
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3,831
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81
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Purchased power:
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Long-term contracts:
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Capacity/exchange
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100
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2
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|
100
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2
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250
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5
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Hydro
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518
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11
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531
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12
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534
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12
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Wind
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39
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1
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39
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1
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39
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1
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Solar
|
46
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1
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13
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—
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13
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—
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Other
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27
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—
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18
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—
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18
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—
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Total long-term contracts
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730
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15
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701
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15
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854
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18
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Short-term contracts
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273
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5
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185
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4
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45
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|
1
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Total purchased power
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1,003
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|
20
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|
886
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19
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|
899
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19
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Total resource capacity
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4,859
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|
100
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%
|
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4,743
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100
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%
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4,730
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|
100
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%
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(1)
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Capacity represents nameplate and differs from expected energy to be generated, which is expected to range from
215
MWa to
290
MWa, dependent upon wind conditions.
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(2)
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Capacity represents net capacity and differs from expected energy to be generated, which is expected to range from
200
MWa to
250
MWa, dependent upon river flows.
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Thermal
|
The Company has five natural gas-fired generating facilities: PW1, PW2, Beaver, Coyote Springs Unit 1 (Coyote Springs), and Carty. These natural gas-fired generating plants provided approximately
41%
of PGE’s total retail load requirement in
2018
,
33%
in
2017
, and
32%
in
2016
.
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Wind
|
PGE owns and operates two wind farms, Biglow Canyon Wind Farm (Biglow Canyon) and Tucannon River Wind Farm (Tucannon River). Biglow Canyon, located in Sherman County, Oregon, is PGE’s largest renewable energy resource consisting of 217 wind turbines with a total nameplate capacity of approximately
450
MW. Tucannon River, placed in service in December 2014, is located in southeastern Washington and consists of 116 wind turbines with a total nameplate capacity of
267
MW.
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Hydro
|
The Company’s FERC-licensed hydroelectric projects consist of Pelton/Round Butte on the Deschutes River near Madras, Oregon (discussed below), four plants on the Clackamas River, and one on the Willamette River. The licenses for these projects expire at various dates ranging from 2035 to 2055. Although these plants have a combined capacity of
495
MW, actual energy received is dependent upon river flows. Energy from these resources provided
8%
of the Company’s total retail load requirement in
2018
, and
9%
in both 2017 and
2016
, with availability of
93%
in
2018
, 95% in 2017, and
99%
in
2016
. Northwest hydro conditions have a significant impact on the region’s power supply, with water conditions significantly impacting PGE’s cost of power and its ability to economically displace more expensive thermal generation and spot market power purchases.
|
Natural Gas
|
Physical supplies of natural gas are generally purchased up to twelve months in advance of delivery and based on anticipated operation of the plants. PGE attempts to manage the price risk of natural gas supply through the use of financial contracts up to 60 months in advance of expected need of energy.
|
Coal
|
PGE has purchase agreements that, together with existing inventory, will provide coal sufficient for the anticipated operating needs for Boardman during 2019. The coal is obtained from surface mining operations in Wyoming and is delivered by rail under two
separate transportation contracts which extend through 2020.
|
•
|
Mid-Columbia hydro
—PGE has long-term power purchase contracts with certain public utility districts in the state of Washington for a portion of the output of two hydroelectric projects on the mid-Columbia River. One contract representing
159
MW of capacity that expires in 2028 and one contract representing
163
MW of capacity that expires in 2052. Although the projects currently provide a total of
322
MW of capacity, actual energy received is dependent upon river flows and capacity amounts may decline over time.
|
•
|
Confederated Tribes
—PGE has a long-term agreement under which the Company purchases, at index prices, the Tribes’ interest in the output of the Pelton/Round Butte hydroelectric project. Although the agreement provides approximately
159
MW of net capacity, actual energy received is dependent upon river flows. The term of the agreement coincides with the term of the FERC license for this project, which expires in 2055. In 2014, PGE entered into an agreement with the Tribes under which the Tribes have agreed to sell, on modified payment terms, their share of the energy generated from the Pelton/Round Butte hydroelectric project exclusively to the Company through 2024.
|
•
|
Other
— PGE has two contracts that provide for the purchase of power generated from hydroelectric projects with an aggregate capacity of
37
MW and contract expiration in 2032.
|
•
|
On property owned or leased by PGE;
|
•
|
Under or over streets, alleys, highways and other public places, the public domain and national forests, and federal and state lands primarily under franchises, easements or other rights that are generally subject to termination;
|
•
|
Under or over private property primarily pursuant to easements obtained from the record holder of title at the time of grant; and
|
•
|
Under or over Native American reservations under grant of easement by the Secretary of the Interior or lease or easement by Native American tribes.
|
•
|
Network integration transmission service, a service that integrates generating resources to serve retail loads;
|
•
|
Short- and long-term firm point-to-point transmission service, a service with fixed delivery and receipt points; and
|
•
|
Non-firm point-to-point service, an “as available” service with fixed delivery and receipt points.
|
Name
|
|
Age
|
|
Current Position and Previous Experience
|
|
Year Appointed Officer
|
|
|
|
|
|
|
|
Larry N. Bekkedahl
|
|
58
|
|
Vice President, Grid Architecture, Integration and Systems Operations (January 2019 to present), Vice President Transmission and Distribution (August 2014 to January 2019). Senior Vice President of Transmission Services at Bonneville Power Administration (“BPA”) (June 2012 to August 2014), Vice President of Engineering and Technical Services at BPA (2008 to August 2014).
|
|
2014
|
Bradley Y. Jenkins
|
|
55
|
|
Vice President, Utility Operations (January 2019 to present), Vice President, Generation and Power Operations (October 2017 to January 2019), Vice President, Power Supply Generation (September 2015 to October 2017), General Manager, Diversified Plant Operations, (November 2013 to August 2015), Plant General Manager, Boardman Power Plant (September 2012 to November 2013), Operations Manager, Boardman Power Plant (March 2012 to September 2012).
|
|
2015
|
Lisa A. Kaner
|
|
58
|
|
Vice President, General Counsel and Corporate Compliance Officer (July 2017 to present), trial attorney and shareholder at Markowitz Herbold PC (1994 to June 2017).
|
|
2017
|
John T. Kochavatr
|
|
45
|
|
Vice President, Information Technology and Chief Information Officer (February 2018 to present). Senior Vice President and Chief Information Officer at SUEZ Water Technologies & Solutions (formerly General Electric Water and Process Technologies) (October 2017 to January 2018), Chief Information Officer and Chief Digital Officer at General Electric Water and Process Technologies (November 2012 to September 2017).
|
|
2018
|
James F. Lobdell
|
|
60
|
|
Senior Vice President, Finance, Chief Financial Officer and Treasurer (March 2013 to present), Vice President, Power Operations and Resource Strategy (August 2004 to March 2013), Vice President, Power Operations (September 2002 to August 2, 2004), Vice President, Risk Management Reporting, Controls and Credit (May 2001 until September 2002).
|
|
2001
|
Anne F. Mersereau
|
|
56
|
|
Vice President, Human Resources, Diversity and Inclusion (January 2016 to present), Employee Services Manager (January 2014 to January 2016), Change Management Consultant (January 2012 to January 2014), Human Resources Business Partner (July 2009 to December 2011).
|
|
2016
|
William O. Nicholson
|
|
60
|
|
Vice President, Utility Technical Services (January 2019 to present), Vice President, Customer Service, Transmission and Distribution (April 2011 to January 2019), Vice President, Distribution Operations (August 2009 to April 2011), Vice President, Customers and Economic Development (May 2007 to August 2009). General Manager, Distribution Western Region (April 2004 to May 2007), General Manager, Distribution Line Operations and Services (February 2002 to April 2004).
|
|
2007
|
Maria M. Pope
|
|
54
|
|
President (October 2017 to present) and Chief Executive Officer (January 2018 to present), Senior Vice President, Power Supply, Operations and Resource Strategy (March 2013 to January 2018), Senior Vice President, Finance, Chief Financial Officer and Treasurer (January 2009 to February 2013). Board director (January 2006 to December 2008). Vice President and Chief Financial Officer for Mentor Graphics Corporation (July 2007 to December 2008).
|
|
2009
|
W. David Robertson
|
|
52
|
|
Vice President, Public Policy (August 2009 to present), Director of Government Affairs (June 2004 to August 2009).
|
|
2009
|
Kristin A. Stathis
|
|
55
|
|
Vice President, Customer Solutions (January 2019 to present), Vice President, Customer Service Operations (June 2011 to December 2018), General Manager of Revenue Operations (August 2009 to May 2011), Assistant Treasurer and Manager of Corporate Finance (October 2005 to July 2009), General Manager of Power Supply Risk Management (August 2003 to September 2005).
|
|
2011
|
Facility
|
|
Location
|
|
Net
Capacity
(1)
|
|
Wholly-owned:
|
|
|
|
|
|
Natural Gas or Oil:
|
|
|
|
|
|
Beaver
|
|
Clatskanie, Oregon
|
|
508
|
|
Carty
|
|
Boardman, Oregon
|
|
437
|
|
Port Westward Unit 1 (PW1)
|
|
Clatskanie, Oregon
|
|
411
|
|
Coyote Springs
|
|
Boardman, Oregon
|
|
249
|
|
Port Westward Unit 2 (PW2)
|
|
Clatskanie, Oregon
|
|
225
|
|
Wind:
|
|
|
|
|
|
Biglow Canyon
|
|
Sherman County, Oregon
|
|
450
|
|
Tucannon River
|
|
Columbia County, Washington
|
|
267
|
|
Hydro:
|
|
|
|
|
|
North Fork
|
|
Clackamas River
|
|
58
|
|
Faraday
|
|
Clackamas River
|
|
46
|
|
Oak Grove
|
|
Clackamas River
|
|
45
|
|
River Mill
|
|
Clackamas River
|
|
25
|
|
T.W. Sullivan
|
|
Willamette River
|
|
18
|
|
Jointly-owned
(2)
:
|
|
|
|
|
|
Coal:
|
|
|
|
|
|
Boardman
(3)
|
|
Boardman, Oregon
|
|
518
|
|
Colstrip
(4)
|
|
Colstrip, Montana
|
|
296
|
|
Hydro:
|
|
|
|
|
|
Round Butte
(5)
|
|
Deschutes River
|
|
230
|
|
Pelton
(5)
|
|
Deschutes River
|
|
73
|
|
Net capacity
|
|
|
|
3,856
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents net capacity of generating unit as demonstrated by actual operating or test experience, net of electricity used in the operation of a given facility. For wind-powered generating facilities, nameplate ratings are used in place of net capacity. A generator’s nameplate rating is its full-load capacity under normal operating conditions as defined by the manufacturer.
|
(2)
|
Net capacity reflects PGE’s ownership share.
|
(3)
|
PGE operates Boardman and has a 90% ownership interest.
|
(4)
|
PGE has a 20% ownership interest in the facility, which is operated by Talen Montana, LLC.
|
(5)
|
PGE operates Pelton and Round Butte and has a 66.67% ownership interest.
|
•
|
Approximately 15% of the Colstrip Transmission facilities from Colstrip to BPA’s transmission system; and
|
•
|
Approximately 20% of the Pacific Northwest Intertie, a 4,800 MW transmission facility between the John Day Substation near the Columbia River in northern Oregon, and Malin, Oregon, near the California border. The Pacific Northwest Intertie is used primarily for the transmission of interstate purchases and sales of electricity among utilities, including PGE.
|
•
|
Approximately 3,715 MW of firm BPA transmission on BPA’s system to PGE’s service territory in Oregon; and
|
•
|
150 MW of firm BPA transmission from the Mid-Columbia projects in Washington to the northern end of the Pacific Northwest AC Intertie, near John Day, Oregon, 5 MW to Tucannon River, and 5 MW to Biglow Canyon.
|
ITEM 5.
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(In millions, except per share amounts)
|
||||||||||||||||||
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
1,991
|
|
|
$
|
2,009
|
|
|
$
|
1,923
|
|
|
$
|
1,898
|
|
|
$
|
1,900
|
|
Income from operations*
|
346
|
|
|
380
|
|
|
340
|
|
|
318
|
|
|
303
|
|
|||||
Net income
|
212
|
|
|
187
|
|
|
193
|
|
|
172
|
|
|
174
|
|
|||||
Net income attributable to Portland General Electric Company
|
212
|
|
|
187
|
|
|
193
|
|
|
172
|
|
|
175
|
|
|||||
Earnings per share—basic
|
2.38
|
|
|
2.10
|
|
|
2.17
|
|
|
2.05
|
|
|
2.24
|
|
|||||
Earnings per share—diluted
|
2.37
|
|
|
2.10
|
|
|
2.16
|
|
|
2.04
|
|
|
2.18
|
|
|||||
Dividends declared per common share
|
1.4275
|
|
|
1.340
|
|
|
1.260
|
|
|
1.180
|
|
|
1.115
|
|
|||||
Statement of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
595
|
|
|
514
|
|
|
584
|
|
|
598
|
|
|
1,007
|
|
*
|
The years ended December 31, 2014 and 2015 include a $10 million and $9 million reclassification of the non-service cost component of net periodic pension and postretirement benefit costs, respectively, as such costs are no longer considered in the subtotal of Income from operations pursuant to the adoption of ASU 2017-07,
Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
. For information regarding this matter, see “Recently Adopted Accounting Pronouncements” in Note 2, Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”
|
|
As of December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(Dollars in millions)
|
||||||||||||||||||
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
8,110
|
|
|
$
|
7,838
|
|
|
$
|
7,527
|
|
|
$
|
7,210
|
|
|
$
|
7,030
|
|
Total long-term debt
|
2,478
|
|
|
2,426
|
|
|
2,350
|
|
|
2,193
|
|
|
2,489
|
|
|||||
Total capital lease obligations
|
49
|
|
|
51
|
|
|
54
|
|
|
—
|
|
|
—
|
|
|||||
Total shareholders’ equity
|
2,506
|
|
|
2,416
|
|
|
2,344
|
|
|
2,258
|
|
|
1,911
|
|
|||||
Common equity ratio
|
49.8
|
%
|
|
49.4
|
%
|
|
49.4
|
%
|
|
50.7
|
%
|
|
43.4
|
%
|
|
|
|
|
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
•
|
governmental policies, legislative action, and regulatory audits, investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition;
|
•
|
economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers and elevated levels of uncollectible customer accounts;
|
•
|
the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 18, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K;
|
•
|
unseasonable or extreme weather and other natural phenomena, which could affect customers’ demand for power and PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, and could increase the Company’s costs to maintain its generating facilities and transmission and distribution systems;
|
•
|
operational factors affecting PGE’s power generating facilities, including forced outages, hydro and wind conditions, and disruption of fuel supply, any of which may cause the Company to incur repair costs or purchase replacement power at increased costs;
|
•
|
the failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;
|
•
|
volatility in wholesale power and natural gas prices, which could require PGE to issue additional letters of credit or post additional cash as collateral with counterparties pursuant to power and natural gas purchase agreements;
|
•
|
changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes on the Company’s power costs;
|
•
|
capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE’s credit ratings, any of which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, and the repayments of maturing debt;
|
•
|
future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury and other gas emissions;
|
•
|
changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;
|
•
|
the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;
|
•
|
changes in residential, commercial, and industrial customer growth, and in demographic patterns, in PGE’s service territory;
|
•
|
the effectiveness of PGE’s risk management policies and procedures;
|
•
|
declines in the fair value of securities held for the defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such plans;
|
•
|
cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;
|
•
|
employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and a significant number of employees approaching retirement;
|
•
|
new federal, state, and local laws that could have adverse effects on operating results;
|
•
|
political and economic conditions;
|
•
|
natural disasters and other risks, such as earthquake, flood, drought, lightning, wind, and fire;
|
•
|
changes in financial or regulatory accounting principles or policies imposed by governing bodies; and
|
•
|
acts of war or terrorism.
|
•
|
Decarbonization Study evaluating the potential impacts of reducing economy-wide GHG emissions in the PGE service area by 80% by 2050;
|
•
|
Market Capacity Study evaluating the potential for shifting regional loads and resources to impact the availability of market capacity in the Pacific Northwest over time;
|
•
|
Distributed Resource and Flexible Load Study, which provided a holistic view of potential Distributed Energy Resource adoption, electric vehicle adoption, and demand response and flexible load program participation among PGE customers; and
|
•
|
Supply-Side Option Study that provided costs and performance characteristics for supply-side renewables, storage, and thermal resources.
|
•
|
A new customer information system to provide better, more secure service;
|
•
|
Replacement and upgrades to equipment to ensure system safety and reliability;
|
•
|
Equipping substations with technology to address potential outages and shorten those that do occur;
|
•
|
Strengthening safeguards that protect against cyber attacks and other potential threats; and
|
•
|
Adding infrastructure to support rapid growth in the region.
|
|
2018
|
|
2017
|
|
Increase/
(Decrease)
in Energy
Deliveries
|
|||||||||
|
Average
Number of
Customers
|
|
Energy
Deliveries *
|
|
Average
Number of
Customers
|
|
Energy
Deliveries *
|
|
||||||
Residential
|
772,389
|
|
|
7,416
|
|
|
762,211
|
|
|
7,880
|
|
|
(5.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|||||
Commercial (PGE sales only)
|
108,570
|
|
|
6,783
|
|
|
107,364
|
|
|
6,932
|
|
|
(2.2
|
)%
|
Direct Access
|
537
|
|
|
647
|
|
|
491
|
|
|
623
|
|
|
3.9
|
%
|
Total Commercial
|
109,107
|
|
|
7,430
|
|
|
107,855
|
|
|
7,555
|
|
|
(1.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|||||
Industrial (PGE sales only)
|
203
|
|
|
2,987
|
|
|
199
|
|
|
2,943
|
|
|
1.5
|
%
|
Direct Access
|
67
|
|
|
1,389
|
|
|
68
|
|
|
1,340
|
|
|
3.7
|
%
|
Total Industrial
|
270
|
|
|
4,376
|
|
|
267
|
|
|
4,283
|
|
|
2.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|||||
Total (PGE sales only)
|
881,162
|
|
|
17,186
|
|
|
869,774
|
|
|
17,755
|
|
|
(3.2
|
)%
|
Total Direct Access
|
604
|
|
|
2,036
|
|
|
559
|
|
|
1,963
|
|
|
3.7
|
%
|
Total
|
881,766
|
|
|
19,222
|
|
|
870,333
|
|
|
19,718
|
|
|
(2.5
|
)%
|
|
|
|
|
|
*
|
In thousands of MWh.
|
•
|
For
2018
, actual NVPC was below baseline NVPC by
$3 million
, which was within the established deadband range. Accordingly,
no
estimated refund to customers was recorded as of December 31,
2018
. A final determination regarding the
2018
PCAM results will be made by the OPUC through a public filing and review in
2019
.
|
•
|
For
2017
, actual NVPC was above baseline NVPC by
$15 million
, which was within the established deadband range. Accordingly,
no
estimated collection from customers was recorded as of December 31, 2017. A final determination regarding the
2017
PCAM results was made by the OPUC through a public filing and review in
2018
, which confirmed no collection from customers pursuant to the PCAM for
2017
.
|
•
|
For
2016
, actual NVPC was below baseline NVPC by
$10 million
, which was within the established deadband range. Accordingly,
no
estimated refund to customers was recorded as of December 31, 2016. A final determination regarding the
2016
PCAM results was made by the OPUC through a public filing and review in
2017
, which confirmed no refund to customers pursuant to the PCAM for
2016
.
|
•
|
An increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
|
•
|
A limitation on the life of RECs generated from facilities that become operational after 2022 to five years, but continued unlimited lifespan for all existing RECs and allowance for the generation of additional unlimited RECs for a period of five years for projects on line before December 31, 2022; and
|
•
|
An allowance for energy storage costs related to renewable energy in the Company’s RAC filings.
|
•
|
Modify statewide greenhouse gas emissions reduction goals;
|
•
|
Require a program to place a cap on greenhouse gas emissions and provide a market-based mechanism for covered entities to demonstrate compliance with program; and
|
•
|
Authorize the OPUC to allow recovery in customer prices to reflect amounts for programs that enable public utilities to assist low-income residential customers.
|
•
|
Exploring performance-based ratemaking and other regulatory tools to align utility incentives with customer goals, industry trends, and statewide goals;
|
▪
|
Cooperating with other states to support and explore development of an organized regional market;
|
▪
|
Developing a strategy for low income and environmental justice groups’ engagement and inclusion in OPUC processes that will carry forward beyond the SB 978 proceeding; and
|
▪
|
Improving the Commission’s regulatory tools to value system costs and benefits, which enables customer choice and a strong utility system.
|
▪
|
Thermal—Expected operating conditions;
|
▪
|
Hydroelectric—Regional hydro generation based on historical stream flow data and current hydro operating parameters; and
|
•
|
Wind—Generation levels based on a five-year historical rolling average of the wind farm. To the extent historical information is not available for a given year, the projections are based on wind generation studies.
|
|
Years Ended December 31,
|
|||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|||||||||||||||
|
Amount
|
|
As %
of Rev
|
|
Amount
|
|
As %
of Rev
|
|
Amount
|
|
As %
of Rev
|
|||||||||
Total revenues
(1)
|
$
|
1,991
|
|
|
100
|
%
|
|
$
|
2,009
|
|
|
100
|
%
|
|
$
|
1,923
|
|
|
100
|
%
|
Purchased power and fuel
(1)
|
571
|
|
|
30
|
|
|
592
|
|
|
30
|
|
|
617
|
|
|
32
|
|
|||
Gross margin
|
1,420
|
|
|
70
|
|
|
1,417
|
|
|
70
|
|
|
1,306
|
|
|
68
|
|
|||
Other operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Generation, transmission and distribution
|
292
|
|
|
15
|
|
|
309
|
|
|
16
|
|
|
286
|
|
|
15
|
|
|||
Administrative and other
|
271
|
|
|
13
|
|
|
260
|
|
|
13
|
|
|
240
|
|
|
12
|
|
|||
Depreciation and amortization
|
382
|
|
|
19
|
|
|
345
|
|
|
17
|
|
|
321
|
|
|
17
|
|
|||
Taxes other than income taxes
|
129
|
|
|
6
|
|
|
123
|
|
|
6
|
|
|
119
|
|
|
6
|
|
|||
Total other operating expenses
|
1,074
|
|
|
53
|
|
|
1,037
|
|
|
52
|
|
|
966
|
|
|
50
|
|
|||
Income from operations
|
346
|
|
|
17
|
|
|
380
|
|
|
18
|
|
|
340
|
|
|
18
|
|
|||
Interest expense, net
(2)
|
124
|
|
|
6
|
|
|
120
|
|
|
6
|
|
|
112
|
|
|
6
|
|
|||
Other income:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Allowance for equity funds used during construction
|
11
|
|
|
1
|
|
|
12
|
|
|
1
|
|
|
21
|
|
|
1
|
|
|||
Miscellaneous income, net
|
(4
|
)
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|||
Other income, net
|
7
|
|
|
1
|
|
|
13
|
|
|
1
|
|
|
15
|
|
|
1
|
|
|||
Income before income taxes
|
229
|
|
|
12
|
|
|
273
|
|
|
13
|
|
|
243
|
|
|
13
|
|
|||
Income tax expense
|
17
|
|
|
1
|
|
|
86
|
|
|
4
|
|
|
50
|
|
|
3
|
|
|||
Net income
|
$
|
212
|
|
|
11
|
%
|
|
$
|
187
|
|
|
9
|
%
|
|
$
|
193
|
|
|
10
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|||||||||||||||
Revenues
(1)
(dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Residential
|
$
|
948
|
|
|
48
|
%
|
|
$
|
969
|
|
|
48
|
%
|
|
$
|
907
|
|
|
47
|
%
|
Commercial
|
647
|
|
|
32
|
|
|
652
|
|
|
32
|
|
|
652
|
|
|
34
|
|
|||
Industrial
|
185
|
|
|
9
|
|
|
192
|
|
|
10
|
|
|
193
|
|
|
10
|
|
|||
Direct Access
|
43
|
|
|
2
|
|
|
37
|
|
|
2
|
|
|
28
|
|
|
2
|
|
|||
Subtotal
|
1,823
|
|
|
91
|
|
|
1,850
|
|
|
92
|
|
|
1,780
|
|
|
93
|
|
|||
Alternative revenue programs, net of amortization
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Other accrued (deferred) revenues, net
(2)
|
(45
|
)
|
|
(2
|
)
|
|
10
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|||
Total retail revenues
|
1,781
|
|
|
89
|
|
|
1,860
|
|
|
93
|
|
|
1,783
|
|
|
93
|
|
|||
Wholesale revenues
|
159
|
|
|
8
|
|
|
105
|
|
|
5
|
|
|
103
|
|
|
5
|
|
|||
Other operating revenues
|
51
|
|
|
3
|
|
|
44
|
|
|
2
|
|
|
37
|
|
|
2
|
|
|||
Total revenues
|
$
|
1,991
|
|
|
100
|
%
|
|
$
|
2,009
|
|
|
100
|
%
|
|
$
|
1,923
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Energy deliveries (MWh in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Residential
|
7,416
|
|
|
31
|
%
|
|
7,880
|
|
|
34
|
%
|
|
7,348
|
|
|
33
|
%
|
|||
Commercial
|
6,783
|
|
|
29
|
|
|
6,932
|
|
|
30
|
|
|
6,932
|
|
|
31
|
|
|||
Industrial
|
2,987
|
|
|
13
|
|
|
2,943
|
|
|
13
|
|
|
2,968
|
|
|
13
|
|
|||
Subtotal
|
17,186
|
|
|
73
|
|
|
17,755
|
|
|
77
|
|
|
17,248
|
|
|
77
|
|
|||
Direct access:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Commercial
|
647
|
|
|
3
|
|
|
623
|
|
|
3
|
|
|
525
|
|
|
2
|
|
|||
Industrial
|
1,389
|
|
|
6
|
|
|
1,340
|
|
|
6
|
|
|
1,198
|
|
|
6
|
|
|||
Subtotal
|
2,036
|
|
|
9
|
|
|
1,963
|
|
|
9
|
|
|
1,723
|
|
|
8
|
|
|||
Total retail energy deliveries
|
19,222
|
|
|
82
|
|
|
19,718
|
|
|
86
|
|
|
18,971
|
|
|
85
|
|
|||
Wholesale energy deliveries
|
4,290
|
|
|
18
|
|
|
3,193
|
|
|
14
|
|
|
3,352
|
|
|
15
|
|
|||
Total energy deliveries
|
23,512
|
|
|
100
|
%
|
|
22,911
|
|
|
100
|
%
|
|
22,323
|
|
|
100
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Average number of retail customers:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Residential
|
772,389
|
|
|
88
|
%
|
|
762,211
|
|
|
88
|
%
|
|
752,365
|
|
|
88
|
%
|
|||
Commercial
|
108,570
|
|
|
12
|
|
|
107,364
|
|
|
12
|
|
|
106,460
|
|
|
12
|
|
|||
Industrial
|
203
|
|
|
—
|
|
|
199
|
|
|
—
|
|
|
195
|
|
|
—
|
|
|||
Direct access
|
604
|
|
|
—
|
|
|
559
|
|
|
—
|
|
|
376
|
|
|
—
|
|
|||
Total
|
881,766
|
|
|
100
|
%
|
|
870,333
|
|
|
100
|
%
|
|
859,396
|
|
|
100
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those customers that purchase their energy from ESSs. Commercial revenues from ESS customers were $18
million,
$17 million, and $13 million for 2018, 2017, and 2016, respectively. Industrial revenues from ESS customers were
$25
million, $20 million, and $15 million for 2018, 2017, and 2016, respectively.
|
|||
(2)
|
Amount at December 31, 2018 primarily relates to the regulatory liability deferral of the 2018 net tax benefits due to the change in corporate tax rate under the Tax Cuts and Jobs Act of 2018 (TCJA). For further information, see Note 12, Income Taxes in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”
|
•
|
Temperature contrasts contributed to lower energy demand in 2018 as customers used less energy in the warmer 2018 heating season compared with the colder than average 2017 period.
|
•
|
While retail deliveries were lower in 2018, lower Purchased power and fuel cost contributed to hold Gross margin comparable to 2017, as Wholesale revenues increased.
|
•
|
The reduction in Generation, transmission and distribution expense reflects the significant storm related costs recorded in 2017 as well as lower plant maintenance expenses in 2018.
|
•
|
The increase in Administrative and general expenses in 2018 was partially offset by a $14 million expense reduction due to the conclusion of the Carty litigation and cash settlement.
|
•
|
The increase in Depreciation and amortization largely reflects capital additions, including $8 million higher amortization due to the new customer information system.
|
•
|
The Company recorded $9 million lower revenues under the decoupling mechanism in 2018 than in 2017.
|
•
|
$47 million reduction resulted from the 2.5% overall decrease in retail energy deliveries consisting of a
5.9%
decrease in residential deliveries, and a
1.7%
decrease in commercial deliveries, partially offset by a
2.2%
in
crease in industrial deliveries. The effects of weather on electricity demand is reflected predominantly in the Residential revenue line in the table above. Considerably warmer temperatures in the first quarter of 2018 than experienced in 2017, which was colder than average, along with more moderate temperatures in the balance of 2018 than 2017, combined to drive deliveries lower. For further information on customer demand, see
“Customers and Demand”
in the Overview section of this Item 7;
|
•
|
$45 million decrease to reflect the deferral of revenues for refund to customers as a result of the TCJA, which is reflected in the Other accrued (deferred) revenues, net line in the table above. This reduction in revenues is offset with lower income tax expense; and
|
•
|
$9 million decrease from the results of the decoupling mechanism, net of amortization, as a $2 million collection from customers was deferred into revenue in 2018, as opposed to a $11 million collection from customers deferred into revenue in 2017; partially offset by
|
•
|
$14 million increase as a result of the expiration of the credits to customers for the Trojan spent fuel refund, the effect of which is offset in Depreciation and amortization expense; and
|
•
|
$9 million increase in revenues as a result of price changes, which includes a $47 million reduction in revenues attributable to lower estimated NVPC, as filed in the 2018 GRC.
|
|
Heating Degree-Days
|
|
Cooling Degree-Days
|
||||||||||||||
|
2018
|
|
2017
|
|
15-Year Average
|
|
2018
|
|
2017
|
|
15-Year Average
|
||||||
1st quarter
|
1,766
|
|
|
2,171
|
|
|
1,813
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2nd quarter
|
471
|
|
|
686
|
|
|
656
|
|
|
116
|
|
|
129
|
|
|
85
|
|
3rd quarter
|
69
|
|
|
78
|
|
|
75
|
|
|
575
|
|
|
571
|
|
|
426
|
|
4th quarter
|
1,396
|
|
|
1,623
|
|
|
1,573
|
|
|
1
|
|
|
—
|
|
|
3
|
|
Total
|
3,702
|
|
|
4,558
|
|
|
4,117
|
|
|
692
|
|
|
700
|
|
|
514
|
|
Increase (decrease) from the 15-year average
|
(10
|
)%
|
|
11
|
%
|
|
|
|
35
|
%
|
|
36
|
%
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
Runoff as a Percent of 30-year Average
|
||||
Location
|
2018
Actual
|
|
2017
Actual
|
||
Columbia River at The Dalles, Oregon
|
98
|
%
|
|
98
|
%
|
Mid-Columbia River at Grand Coulee, Washington
|
99
|
|
|
98
|
|
Clackamas River at Estacada, Oregon
|
97
|
|
|
97
|
|
Deschutes River at Moody, Oregon
|
96
|
|
|
98
|
|
•
|
A $71 million increase due to a 3.9% increase in retail energy deliveries consisting of a 7.2% increase in residential deliveries, a 2.8%
increase in industrial deliveries, and a 1.3% increase in commercial deliveries. Considerably cooler temperatures in the first half of 2017 than experienced in 2016 combined with warmer temperatures in the summer cooling season in 2017, both drove deliveries higher in 2017 than in 2016. For further information on customer demand, see
“Customers and Demand”
in the Overview section of this Item 7;
|
•
|
A $10 million increase resulting from the decoupling mechanism, net of amortization as an estimated $11 million collection was deferred into revenue in 2017; and
|
•
|
A $5 million increase, directly offset in Depreciation and amortization expense, related to the accelerated cost recovery of Colstrip, partially offset by
|
•
|
A $5 million reduction as a result of overall price changes, which includes a $55 million reduction in revenues attributable to lower NVPC, as filed in the 2017 AUT; and
|
•
|
A $3 million decrease due to higher customer credits related to the USDOE settlement in connection with operation of the ISFSI at the former Trojan nuclear power plant site. Such credits are directly offset in Depreciation and amortization expense.
|
|
Heating Degree-Days
|
|
Cooling Degree-Days
|
||||||||||||||
|
2017
|
|
2016
|
|
15-Year Average
|
|
2017
|
|
2016
|
|
15-Year Average
|
||||||
1st quarter
|
2,171
|
|
|
1,585
|
|
|
1,866
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2nd quarter
|
686
|
|
|
403
|
|
|
689
|
|
|
129
|
|
|
154
|
|
|
70
|
|
3rd quarter
|
78
|
|
|
78
|
|
|
78
|
|
|
571
|
|
|
394
|
|
|
399
|
|
4th quarter
|
1,623
|
|
|
1,486
|
|
|
1,600
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Total
|
4,558
|
|
|
3,552
|
|
|
4,233
|
|
|
700
|
|
|
548
|
|
|
471
|
|
Increase (decrease) from the 15-year average
|
8
|
%
|
|
(16
|
)%
|
|
|
|
|
49
|
%
|
|
16
|
%
|
|
|
|
|
Runoff as a Percent of 30-year Average
|
||||
Location
|
2017
Actual
|
|
2016
Actual
|
||
Columbia River at The Dalles, Oregon
|
98
|
%
|
|
89
|
%
|
Mid-Columbia River at Grand Coulee, Washington
|
98
|
|
|
91
|
|
Clackamas River at Estacada, Oregon
|
97
|
|
|
71
|
|
Deschutes River at Moody, Oregon
|
98
|
|
|
91
|
|
|
Years Ending December 31,
|
||||||||||||||||||||||
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
||||||||||||
Ongoing capital expenditures
(1)
|
$
|
580
|
|
|
$
|
580
|
|
|
$
|
500
|
|
|
$
|
500
|
|
|
$
|
500
|
|
|
$
|
500
|
|
Customer information system
(2)
|
26
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Wheatridge Renewable Energy Facility
|
—
|
|
|
—
|
|
|
140
|
|
|
15
|
|
|
—
|
|
|
—
|
|
||||||
Total capital expenditures
|
$
|
606
|
|
(3)
|
$
|
580
|
|
|
$
|
640
|
|
|
$
|
515
|
|
|
$
|
500
|
|
|
$
|
500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Long-term debt maturities
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
(1)
|
Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connects, and the non-utility purchase of PGE’s corporate headquarters in 2018.
|
(2)
|
Total capital expenditures for the customer information system through December 31, 2018 were $140
million, excluding AFDC.
|
(3)
|
Includes preliminary engineering and removal costs, which are included in other net operating activities in the consolidated statements of cash flows.
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash and cash equivalents, beginning of year
|
$
|
39
|
|
|
$
|
6
|
|
|
$
|
4
|
|
Net cash provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
630
|
|
|
597
|
|
|
562
|
|
|||
Investing activities
|
(471
|
)
|
|
(514
|
)
|
|
(585
|
)
|
|||
Financing activities
|
(79
|
)
|
|
(50
|
)
|
|
25
|
|
|||
Net change in cash and cash equivalents
|
80
|
|
|
33
|
|
|
2
|
|
|||
Cash and cash equivalents, end of year
|
$
|
119
|
|
|
$
|
39
|
|
|
$
|
6
|
|
|
|
|
|
|
|
Declaration Date
|
|
Record Date
|
|
Payment Date
|
|
Declared Per
Common Share
|
||
February 14, 2018
|
|
March 26, 2018
|
|
April 16, 2018
|
|
$
|
0.3400
|
|
April 25, 2018
|
|
June 25, 2018
|
|
July 16, 2018
|
|
0.3625
|
|
|
July 25, 2018
|
|
September 25, 2018
|
|
October 15, 2018
|
|
0.3625
|
|
|
October 24, 2018
|
|
December 26, 2018
|
|
January 15, 2019
|
|
0.3625
|
|
|
Moody’s
|
|
S&P
|
First Mortgage Bonds
|
A1
|
|
A
|
Senior unsecured debt
|
A3
|
|
BBB+
|
Commercial paper
|
P-2
|
|
A-2
|
Outlook
|
Stable
|
|
Positive
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
There-
after
|
|
Total
|
||||||||||||||
Long-term debt
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,028
|
|
|
$
|
2,488
|
|
Interest on long-term debt
(1)
|
112
|
|
|
106
|
|
|
102
|
|
|
101
|
|
|
100
|
|
|
1,549
|
|
|
2,070
|
|
|||||||
Capital and other purchase commitments
|
143
|
|
|
9
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
58
|
|
|
213
|
|
|||||||
Purchased power and fuel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity purchases
|
167
|
|
|
190
|
|
|
186
|
|
|
194
|
|
|
193
|
|
|
1,853
|
|
|
2,783
|
|
|||||||
Capacity contracts
|
1
|
|
|
—
|
|
|
9
|
|
|
9
|
|
|
9
|
|
|
18
|
|
|
46
|
|
|||||||
Public Utility Districts
|
12
|
|
|
11
|
|
|
9
|
|
|
8
|
|
|
8
|
|
|
35
|
|
|
83
|
|
|||||||
Natural gas
|
54
|
|
|
42
|
|
|
31
|
|
|
31
|
|
|
30
|
|
|
208
|
|
|
396
|
|
|||||||
Coal and transportation
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|||||||
Pension Plan Contributions
(2)
|
—
|
|
|
41
|
|
|
26
|
|
|
30
|
|
|
31
|
|
|
—
|
|
|
128
|
|
|||||||
Capital leases
|
6
|
|
|
6
|
|
|
6
|
|
|
6
|
|
|
5
|
|
|
67
|
|
|
96
|
|
|||||||
Build-to-suit lease
|
11
|
|
|
14
|
|
|
13
|
|
|
13
|
|
|
13
|
|
|
225
|
|
|
289
|
|
|||||||
Operating leases
|
4
|
|
|
5
|
|
|
5
|
|
|
6
|
|
|
7
|
|
|
97
|
|
|
124
|
|
|||||||
Total
|
$
|
816
|
|
|
$
|
424
|
|
|
$
|
548
|
|
|
$
|
399
|
|
|
$
|
397
|
|
|
$
|
6,138
|
|
|
$
|
8,722
|
|
|
|
|
|
|
•
|
PGE has
four letter of credit facilities that provide capacity up to a total of
$220 million
under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities,
$84 million
has been issued as of
December 31, 2018
; and
|
•
|
As a co-owner of Colstrip, PGE has provided surety bonds of $8 million in December 2018 and $10 million in January 2019 on behalf of the operator to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the Montana Department of Environmental Quality. It is currently anticipated that each co-owner of Colstrip will be required, at some future point, to post a third tranche of financial assurance to support additional performance by the operator of closure and remediation actions under the AOC.
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
||||||||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity
|
$
|
4
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
55
|
|
|
$
|
83
|
|
Natural gas
|
28
|
|
|
14
|
|
|
6
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
49
|
|
|||||||
|
$
|
32
|
|
|
$
|
20
|
|
|
$
|
12
|
|
|
$
|
7
|
|
|
$
|
6
|
|
|
$
|
55
|
|
|
$
|
132
|
|
|
Total
Fair
Value
|
|
Carrying Amounts by Maturity Date
|
||||||||||||||||||||||||
|
Total
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
There-
after
|
||||||||||||||||
First Mortgage Bonds
|
$
|
2,662
|
|
|
$
|
2,390
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
—
|
|
|
$
|
1,930
|
|
Pollution Control Revenue Bonds
|
98
|
|
|
98
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
98
|
|
|||||||
Total
|
$
|
2,760
|
|
|
$
|
2,488
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
—
|
|
|
$
|
2,028
|
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Revenues, net
|
$
|
1,988
|
|
|
$
|
2,009
|
|
|
$
|
1,923
|
|
Alternative revenue programs, net of amortization
|
3
|
|
|
—
|
|
|
—
|
|
|||
Total Revenues
|
1,991
|
|
|
2,009
|
|
|
1,923
|
|
|||
Operating expenses:
|
|
|
|
|
|
||||||
Purchased power and fuel
|
571
|
|
|
592
|
|
|
617
|
|
|||
Generation, transmission and distribution
|
292
|
|
|
309
|
|
|
286
|
|
|||
Administrative and other
|
271
|
|
|
260
|
|
|
240
|
|
|||
Depreciation and amortization
|
382
|
|
|
345
|
|
|
321
|
|
|||
Taxes other than income taxes
|
129
|
|
|
123
|
|
|
119
|
|
|||
Total operating expenses
|
1,645
|
|
|
1,629
|
|
|
1,583
|
|
|||
Income from operations
|
346
|
|
|
380
|
|
|
340
|
|
|||
Interest expense, net
|
124
|
|
|
120
|
|
|
112
|
|
|||
Other income:
|
|
|
|
|
|
||||||
Allowance for equity funds used during construction
|
11
|
|
|
12
|
|
|
21
|
|
|||
Miscellaneous income (expense), net
|
(4
|
)
|
|
1
|
|
|
(6
|
)
|
|||
Other income, net
|
7
|
|
|
13
|
|
|
15
|
|
|||
Income before income taxes
|
229
|
|
|
273
|
|
|
243
|
|
|||
Income tax expense
|
17
|
|
|
86
|
|
|
50
|
|
|||
Net income
|
$
|
212
|
|
|
$
|
187
|
|
|
$
|
193
|
|
|
|
|
|
|
|
||||||
Weighted-average shares outstanding (in thousands):
|
|
|
|
|
|
||||||
Basic
|
89,215
|
|
|
89,056
|
|
|
88,896
|
|
|||
Diluted
|
89,347
|
|
|
89,176
|
|
|
89,054
|
|
|||
|
|
|
|
|
|
||||||
Earnings per share:
|
|
|
|
|
|
||||||
Basic
|
$
|
2.38
|
|
|
$
|
2.10
|
|
|
$
|
2.17
|
|
Diluted
|
$
|
2.37
|
|
|
$
|
2.10
|
|
|
$
|
2.16
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Net income
|
$
|
212
|
|
|
$
|
187
|
|
|
$
|
193
|
|
Other comprehensive income (loss)—Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2018, 2017, and 2016
|
1
|
|
|
(1
|
)
|
|
1
|
|
|||
Comprehensive income
|
$
|
213
|
|
|
$
|
186
|
|
|
$
|
194
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2018
|
|
2017
|
||||
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
168
|
|
|
$
|
132
|
|
Liabilities from price risk management activities—current
|
55
|
|
|
59
|
|
||
Current portion of long-term debt
|
300
|
|
|
—
|
|
||
Accrued expenses and other current liabilities
|
268
|
|
|
241
|
|
||
Total current liabilities
|
791
|
|
|
432
|
|
||
Long-term debt, net of current portion
|
2,178
|
|
|
2,426
|
|
||
Regulatory liabilities—noncurrent
|
1,355
|
|
|
1,288
|
|
||
Deferred income taxes
|
369
|
|
|
376
|
|
||
Unfunded status of pension and postretirement plans
|
307
|
|
|
284
|
|
||
Liabilities from price risk management activities—noncurrent
|
101
|
|
|
151
|
|
||
Asset retirement obligations
|
197
|
|
|
167
|
|
||
Non-qualified benefit plan liabilities
|
103
|
|
|
106
|
|
||
Other noncurrent liabilities
|
203
|
|
|
192
|
|
||
Total liabilities
|
5,604
|
|
|
5,422
|
|
||
Commitments and contingencies (see notes)
|
|
|
|
|
|||
Shareholders’ equity:
|
|
|
|
||||
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding
|
—
|
|
|
—
|
|
||
Common stock, no par value, 160,000,000 shares authorized;
89,267,959 and 89,114,265 shares issued and outstanding as of December 31, 2018 and 2017, respectively
|
1,212
|
|
|
1,207
|
|
||
Accumulated other comprehensive loss
|
(7
|
)
|
|
(8
|
)
|
||
Retained earnings
|
1,301
|
|
|
1,217
|
|
||
Total shareholders’ equity
|
2,506
|
|
|
2,416
|
|
||
Total liabilities and shareholders’ equity
|
$
|
8,110
|
|
|
$
|
7,838
|
|
|
|
|
|
|
Common Stock
|
|
Accumulated
Other
Comprehensive
Loss
|
|
Retained
Earnings
|
|
Total
|
|||||||||||
|
Shares
|
|
Amount
|
|
||||||||||||||
Balance as of December 31, 2015
|
88,792,751
|
|
|
$
|
1,196
|
|
|
$
|
(8
|
)
|
|
$
|
1,070
|
|
|
$
|
2,258
|
|
Shares issued pursuant to equity-based plans
|
153,953
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Stock-based compensation
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
Dividends declared ($1.26 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(113
|
)
|
|
(113
|
)
|
||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
193
|
|
|
193
|
|
||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
Balance as of December 31, 2016
|
88,946,704
|
|
|
1,201
|
|
|
(7
|
)
|
|
1,150
|
|
|
2,344
|
|
||||
Shares issued pursuant to equity-based plans
|
167,561
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Stock-based compensation
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
Dividends declared ($1.34 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(120
|
)
|
|
(120
|
)
|
||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
187
|
|
|
187
|
|
||||
Other comprehensive (loss)
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
||||
Balance as of December 31, 2017
|
89,114,265
|
|
|
1,207
|
|
|
(8
|
)
|
|
1,217
|
|
|
2,416
|
|
||||
Shares issued pursuant to equity-based plans
|
153,694
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Stock-based compensation
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
Dividends declared ($1.4275 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(128
|
)
|
|
(128
|
)
|
||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
212
|
|
|
212
|
|
||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
Balance as of December 31, 2018
|
89,267,959
|
|
|
$
|
1,212
|
|
|
$
|
(7
|
)
|
|
$
|
1,301
|
|
|
$
|
2,506
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
212
|
|
|
$
|
187
|
|
|
$
|
193
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
382
|
|
|
345
|
|
|
321
|
|
|||
Deferred income taxes
|
(17
|
)
|
|
70
|
|
|
37
|
|
|||
Allowance for equity funds used during construction
|
(11
|
)
|
|
(12
|
)
|
|
(21
|
)
|
|||
Pension and other postretirement benefits
|
30
|
|
|
24
|
|
|
28
|
|
|||
Decoupling mechanism deferrals, net of amortization
|
(2
|
)
|
|
(22
|
)
|
|
(6
|
)
|
|||
Deferral of net benefits due to Tax Reform
|
45
|
|
|
—
|
|
|
—
|
|
|||
Other non-cash income and expenses, net
|
21
|
|
|
31
|
|
|
12
|
|
|||
Changes in working capital:
|
|
|
|
|
|
||||||
(Increase) in receivables and unbilled revenues
|
(29
|
)
|
|
(3
|
)
|
|
(9
|
)
|
|||
(Increase) decrease in margin deposits
|
(5
|
)
|
|
(3
|
)
|
|
25
|
|
|||
Increase in payables and accrued liabilities
|
51
|
|
|
5
|
|
|
15
|
|
|||
Other working capital items, net
|
(11
|
)
|
|
1
|
|
|
(4
|
)
|
|||
Contribution to non-qualified employee benefit trust
|
(11
|
)
|
|
(8
|
)
|
|
(10
|
)
|
|||
Contribution to pension and other postretirement plans
|
(12
|
)
|
|
(5
|
)
|
|
(2
|
)
|
|||
Other, net
|
(13
|
)
|
|
(13
|
)
|
|
(17
|
)
|
|||
Net cash provided by operating activities
|
630
|
|
|
597
|
|
|
562
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(595
|
)
|
|
(514
|
)
|
|
(584
|
)
|
|||
Purchases of nuclear decommissioning trust securities
|
(12
|
)
|
|
(18
|
)
|
|
(25
|
)
|
|||
Sales of nuclear decommissioning trust securities
|
15
|
|
|
21
|
|
|
27
|
|
|||
Proceeds from Carty Settlement
|
120
|
|
|
—
|
|
|
—
|
|
|||
Other, net
|
1
|
|
|
(3
|
)
|
|
(3
|
)
|
|||
Net cash used in investing activities
|
(471
|
)
|
|
(514
|
)
|
|
(585
|
)
|
|||
|
|
|
|
|
|
||||||
See accompanying notes to consolidated financial statements.
|
|||||||||||
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from issuance of long-term debt
|
$
|
75
|
|
|
$
|
225
|
|
|
$
|
290
|
|
Payments on long-term debt
|
(24
|
)
|
|
(150
|
)
|
|
(133
|
)
|
|||
(Maturities) issuances of commercial paper, net
|
—
|
|
|
—
|
|
|
(6
|
)
|
|||
Dividends paid
|
(125
|
)
|
|
(118
|
)
|
|
(110
|
)
|
|||
Other
|
(5
|
)
|
|
(7
|
)
|
|
(16
|
)
|
|||
Net cash (used in) provided by financing activities
|
(79
|
)
|
|
(50
|
)
|
|
25
|
|
|||
Increase in cash and cash equivalents
|
80
|
|
|
33
|
|
|
2
|
|
|||
Cash and cash equivalents, beginning of year
|
39
|
|
|
6
|
|
|
4
|
|
|||
Cash and cash equivalents, end of year
|
$
|
119
|
|
|
$
|
39
|
|
|
$
|
6
|
|
|
|
|
|
|
|
||||||
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
||||||
Cash paid for:
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
|
$
|
117
|
|
|
$
|
110
|
|
|
$
|
104
|
|
Income taxes
|
25
|
|
|
18
|
|
|
16
|
|
|||
Non-cash investing and financing activities:
|
|
|
|
|
|
||||||
Accrued capital additions
|
61
|
|
|
53
|
|
|
50
|
|
|||
Accrued dividends payable
|
34
|
|
|
31
|
|
|
30
|
|
|||
Assets obtained under leasing arrangements
|
24
|
|
|
87
|
|
|
78
|
|
Generation, excluding thermal:
|
|
|
Hydro
|
99
|
|
Wind
|
30
|
|
Transmission
|
59
|
|
Distribution
|
46
|
|
General
|
12
|
|
|
Year Ended
December 31, 2018 |
||
Retail:
|
|
||
Residential
|
$
|
948
|
|
Commercial
|
647
|
|
|
Industrial
|
185
|
|
|
Direct access customers
|
43
|
|
|
Subtotal
|
1,823
|
|
|
Alternative revenue programs, net of amortization
|
3
|
|
|
Other accrued (deferred) revenues, net
(1)
|
(45
|
)
|
|
Total retail revenues
|
1,781
|
|
|
Wholesale revenues
(2)
|
159
|
|
|
Other operating revenues
|
51
|
|
|
Total revenues
|
$
|
1,991
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Balance as of beginning of year
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
Increase in provision
|
14
|
|
|
6
|
|
|
5
|
|
|||
Amounts written off, less recoveries
|
(5
|
)
|
|
(6
|
)
|
|
(5
|
)
|
|||
Balance as of end of year
|
$
|
15
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
|
|
|
|
|
|
Nuclear
Decommissioning Trust
|
|
Non-Qualified Benefit
Plan Trust
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Cash equivalents
|
$
|
7
|
|
|
$
|
25
|
|
|
$
|
2
|
|
|
$
|
1
|
|
Marketable securities, at fair value:
|
|
|
|
|
|
|
|
||||||||
Equity securities
|
—
|
|
|
—
|
|
|
6
|
|
|
7
|
|
||||
Debt securities
|
35
|
|
|
17
|
|
|
1
|
|
|
1
|
|
||||
Insurance contracts, at cash surrender value
|
—
|
|
|
—
|
|
|
27
|
|
|
28
|
|
||||
|
$
|
42
|
|
|
$
|
42
|
|
|
$
|
36
|
|
|
$
|
37
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2018
|
|
2017
|
||||
Other current assets:
|
|
|
|
||||
Prepaid expenses
|
$
|
54
|
|
|
$
|
50
|
|
Margin deposits
|
16
|
|
|
11
|
|
||
Assets from price risk management activities
|
20
|
|
|
6
|
|
||
Other
|
—
|
|
|
6
|
|
||
|
$
|
90
|
|
|
$
|
73
|
|
Accrued expenses and other current liabilities:
|
|
|
|
||||
Regulatory liabilities—current
|
$
|
36
|
|
|
$
|
31
|
|
Accrued employee compensation and benefits
|
66
|
|
|
60
|
|
||
Accrued dividends payable
|
34
|
|
|
31
|
|
||
Accrued interest payable
|
27
|
|
|
27
|
|
||
Accrued taxes payable
|
34
|
|
|
31
|
|
||
Other
|
71
|
|
|
61
|
|
||
|
$
|
268
|
|
|
$
|
241
|
|
|
|
|
|
Level 1
|
Quoted prices are available in active markets for identical assets or liabilities as of the measurement date.
|
Level 2
|
Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date.
|
Level 3
|
Pricing inputs include significant inputs which are unobservable for the asset or liability.
|
|
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—domestic
|
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 regarding price risk management derivatives, see Note 6, Risk Management.
|
|
As of December 31, 2017
|
||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other
(2)
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash equivalents
|
$
|
30
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
30
|
|
Nuclear decommissioning trust:
(1)
|
|
|
|
|
|
|
|
|
|
||||||||||
Debt securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic government
|
$
|
4
|
|
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11
|
|
Corporate credit
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|||||
Money market funds measured at NAV
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
25
|
|
|||||
Non-qualified benefit plan trust:
(3)
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Equity securities—domestic
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|||||
Debt securities—domestic government
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
Natural gas
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
|
$
|
43
|
|
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
25
|
|
|
$
|
87
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
130
|
|
|
$
|
—
|
|
|
$
|
135
|
|
Natural gas
|
—
|
|
|
66
|
|
|
9
|
|
|
—
|
|
|
75
|
|
|||||
|
$
|
—
|
|
|
$
|
71
|
|
|
$
|
139
|
|
|
$
|
—
|
|
|
$
|
210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.
|
(2)
|
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
|
(3)
|
Excludes insurance policies of
$28 million
, which are recorded at cash surrender value.
|
(4)
|
For further information regarding price risk management derivatives, see Note 6, Risk Management.
|
|
|
|
|
|
|
|
|
Significant
|
|
Price per Unit
|
||||||||||||||
|
|
Fair Value
|
|
Valuation
|
|
Unobservable
|
|
|
|
|
|
Weighted
|
||||||||||||
Commodity Contracts
|
|
Assets
|
|
Liabilities
|
|
Technique
|
|
Input
|
|
Low
|
|
High
|
|
Average
|
||||||||||
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of December 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Electricity physical forward
|
|
$
|
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 Dth)
|
|
0.95
|
|
|
4.64
|
|
|
1.82
|
|
|||||
Electricity financial futures
|
|
—
|
|
|
—
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
20.75
|
|
|
35.46
|
|
|
28.63
|
|
|||||
|
|
$
|
3
|
|
|
$
|
91
|
|
|
|
|
|
|
|
|
|
|
|
||||||
As of December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Electricity physical forward
|
|
$
|
—
|
|
|
$
|
130
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
$
|
7.79
|
|
|
$
|
41.23
|
|
|
$
|
30.95
|
|
Natural gas financial swaps
|
|
—
|
|
|
9
|
|
|
Discounted cash flow
|
|
Natural gas forward price (per Dth)
|
|
1.26
|
|
|
2.92
|
|
|
1.90
|
|
|||||
Electricity financial futures
|
|
—
|
|
|
—
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
7.79
|
|
|
29.74
|
|
|
21.74
|
|
|||||
|
|
$
|
—
|
|
|
$
|
139
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
Years Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Net liabilities from price risk management activities as of beginning of year
|
$
|
139
|
|
|
$
|
119
|
|
Net realized and unrealized losses
*
|
(40
|
)
|
|
35
|
|
||
Net transfers out of Level 3 to Level 2
|
(11
|
)
|
|
(15
|
)
|
||
Net liabilities from price risk management activities as of end of year
|
$
|
88
|
|
|
$
|
139
|
|
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting
|
$
|
32
|
|
|
$
|
41
|
|
|
|
|
|
|
|
As of December 31,
|
|
||||||
|
2018
|
|
2017
|
|
||||
Current assets:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
$
|
11
|
|
|
$
|
3
|
|
|
Natural gas
|
7
|
|
|
3
|
|
|
||
Total current derivative assets
|
18
|
|
(1)
|
6
|
|
(1)
|
||
Noncurrent assets:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
1
|
|
|
—
|
|
|
||
Natural gas
|
1
|
|
|
—
|
|
|
||
Total noncurrent derivative assets
|
2
|
|
(2)
|
—
|
|
(2)
|
||
Total derivative assets not designated as hedging instruments
|
$
|
20
|
|
|
$
|
6
|
|
|
Total derivative assets
|
$
|
20
|
|
|
$
|
6
|
|
|
Current liabilities:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
$
|
16
|
|
|
$
|
13
|
|
|
Natural gas
|
35
|
|
|
46
|
|
|
||
Total current derivative liabilities
|
51
|
|
|
59
|
|
|
||
Noncurrent liabilities:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
78
|
|
|
122
|
|
|
||
Natural gas
|
23
|
|
|
29
|
|
|
||
Total noncurrent derivative liabilities
|
101
|
|
|
151
|
|
|
||
Total derivative liabilities not designated as hedging instruments
|
$
|
152
|
|
|
$
|
210
|
|
|
Total derivative liabilities
|
$
|
152
|
|
|
$
|
210
|
|
|
|
|
|
|
|
(1)
|
Included in Other current assets on the consolidated balance sheets.
|
(2)
|
Included in Other noncurrent assets on the consolidated balance sheets.
|
|
As of December 31,
|
||||||||||
|
2018
|
|
2017
|
||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
||||
Electricity
|
5
|
|
|
MWh
|
|
7
|
|
|
MWh
|
||
Natural gas
|
123
|
|
|
Dth
|
|
114
|
|
|
Dth
|
||
Foreign currency exchange
|
$
|
18
|
|
|
Canadian
|
|
$
|
21
|
|
|
Canadian
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Commodity contracts:
|
|
|
|
|
|
||||||
Electricity
|
$
|
(34
|
)
|
|
$
|
41
|
|
|
$
|
34
|
|
Natural Gas
|
21
|
|
|
85
|
|
|
(56
|
)
|
|||
Foreign currency exchange
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
||||||||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity
|
$
|
4
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
55
|
|
|
$
|
83
|
|
Natural gas
|
28
|
|
|
14
|
|
|
6
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
49
|
|
|||||||
Net unrealized loss
|
$
|
32
|
|
|
$
|
20
|
|
|
$
|
12
|
|
|
$
|
7
|
|
|
$
|
6
|
|
|
$
|
55
|
|
|
$
|
132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||
|
2018
|
|
2017
|
||
Assets from price risk management activities:
|
|
|
|
||
Counterparty A
|
42
|
%
|
|
39
|
%
|
Counterparty B
|
15
|
|
|
—
|
|
Counterparty C
|
5
|
|
|
12
|
|
|
62
|
%
|
|
51
|
%
|
Liabilities from price risk management activities:
|
|
|
|
||
Counterparty D
|
56
|
%
|
|
62
|
%
|
|
56
|
%
|
|
62
|
%
|
|
Remaining Amortization Period
|
|
As of December 31,
|
||||||||||||||
|
2018
|
|
2017
|
||||||||||||||
|
Earning a Return
(1)
|
|
Not Earning a Return
|
|
Total
|
|
Total
|
||||||||||
Regulatory assets:
|
|
|
|
|
|
|
|
|
|
||||||||
Price risk management
|
2035
|
|
$
|
—
|
|
|
$
|
131
|
|
|
$
|
131
|
|
|
$
|
204
|
|
Pension and other postretirement plans
|
(2)
|
|
—
|
|
|
222
|
|
|
222
|
|
|
218
|
|
||||
Debt issuance costs
|
2036
|
|
—
|
|
|
16
|
|
|
16
|
|
|
19
|
|
||||
Trojan decommissioning activities
|
2039
|
|
26
|
|
|
—
|
|
|
26
|
|
|
—
|
|
||||
Other
|
Various
|
|
53
|
|
|
14
|
|
|
67
|
|
|
59
|
|
||||
Total regulatory assets
|
|
|
$
|
79
|
|
|
$
|
383
|
|
|
$
|
462
|
|
|
$
|
500
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||
Asset retirement removal costs
|
(3)
|
|
$
|
979
|
|
|
$
|
—
|
|
|
$
|
979
|
|
|
$
|
933
|
|
Deferred income taxes
|
(4)
|
|
267
|
|
|
—
|
|
|
267
|
|
|
277
|
|
||||
Trojan decommissioning activities
|
2019
|
|
1
|
|
|
—
|
|
|
1
|
|
|
3
|
|
||||
Asset retirement obligations
|
(3)
|
|
53
|
|
|
—
|
|
|
53
|
|
|
52
|
|
||||
Tax Reform Deferral
(5)
|
2020
|
|
45
|
|
|
—
|
|
|
45
|
|
|
—
|
|
||||
Other
|
Various
|
|
39
|
|
|
7
|
|
|
46
|
|
|
54
|
|
||||
Total regulatory liabilities
|
|
|
$
|
1,384
|
|
|
$
|
7
|
|
|
$
|
1,391
|
|
|
$
|
1,319
|
|
(1)
|
Earning a return includes either interest on the regulatory asset or liability, or inclusion of the regulatory asset or liability as an increase or decrease to rate base at the allowed rate of return.
|
(2)
|
Recovery expected over the average service life of employees.
|
(3)
|
Recovery or refund expected over the estimated lives of the net balance and treated as a reduction to rate base.
|
(4)
|
Will be returned to customers using the average rate assumption method over the average life of the underlying assets and treated as a reduction to rate base.
|
(5)
|
Related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest.
|
|
As of December 31,
|
||||||
|
2018
|
|
2017
|
||||
Trojan decommissioning activities
|
$
|
68
|
|
|
$
|
45
|
|
Utility plant
|
112
|
|
|
109
|
|
||
Non-utility property
|
17
|
|
|
13
|
|
||
Asset retirement obligations
|
$
|
197
|
|
|
$
|
167
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Balance as of beginning of year
|
$
|
167
|
|
|
$
|
161
|
|
|
$
|
151
|
|
Liabilities incurred
|
—
|
|
|
2
|
|
|
1
|
|
|||
Liabilities settled
|
(5
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|||
Accretion expense
|
8
|
|
|
7
|
|
|
7
|
|
|||
Revisions in estimated cash flows
|
27
|
|
|
—
|
|
|
5
|
|
|||
Balance as of end of year
|
$
|
197
|
|
|
$
|
167
|
|
|
$
|
161
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Average daily amount of short-term debt outstanding
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Weighted daily average interest rate *
|
—
|
%
|
|
—
|
%
|
|
0.7
|
%
|
|||
Maximum amount outstanding during the year
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
23
|
|
|
|
|
|
|
*
|
Excludes the effect of commitment fees, facility fees and other financing fees.
|
|
As of December 31,
|
||||||
|
2018
|
|
2017
|
||||
First Mortgage Bonds
, rates range from 2.51% to 9.31%, with a weighted average rate of 5.01% in 2018 and 5.03% in 2017, due at various dates through 2048
|
$
|
2,390
|
|
|
$
|
2,315
|
|
Pollution Control Revenue Bonds
, 5% rate, due 2033
|
119
|
|
|
142
|
|
||
Pollution Control Revenue Bonds owned by PGE
|
(21
|
)
|
|
(21
|
)
|
||
Total long-term debt
|
2,488
|
|
|
2,436
|
|
||
Less: Unamortized debt expense
|
(10
|
)
|
|
(10
|
)
|
||
Less: Current portion of long-term debt
|
(300
|
)
|
|
—
|
|
||
Long-term debt, net of current portion
|
$
|
2,178
|
|
|
$
|
2,426
|
|
|
2018
|
|
2017
|
||||||||||||||||||||
|
NQBP
|
|
Other NQBP
|
|
Total
|
|
NQBP
|
|
Other NQBP
|
|
Total
|
||||||||||||
Non-qualified benefit plan trust
|
$
|
16
|
|
|
$
|
20
|
|
|
$
|
36
|
|
|
$
|
17
|
|
|
$
|
20
|
|
|
$
|
37
|
|
Non-qualified benefit plan liabilities *
|
22
|
|
|
81
|
|
|
103
|
|
|
25
|
|
|
81
|
|
|
106
|
|
|
|
|
|
|
*
|
For the NQBP, excludes the current portion of
$2 million
in
2018
and in
2017
, which are classified in Other current liabilities in the consolidated balance sheets.
|
|
As of December 31,
|
||||||||||
|
2018
|
|
2017
|
||||||||
|
Actual
|
|
Target *
|
|
Actual
|
|
Target *
|
||||
Defined Benefit Pension Plan:
|
|
|
|
|
|
|
|
||||
Equity securities
|
65
|
%
|
|
67
|
%
|
|
68
|
%
|
|
67
|
%
|
Debt securities
|
35
|
|
|
33
|
|
|
32
|
|
|
33
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
Other Postretirement Benefit Plans:
|
|
|
|
|
|
|
|
||||
Equity securities
|
58
|
%
|
|
59
|
%
|
|
63
|
%
|
|
62
|
%
|
Debt securities
|
42
|
|
|
41
|
|
|
37
|
|
|
38
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
Non-Qualified Benefits Plans:
|
|
|
|
|
|
|
|
||||
Equity securities
|
16
|
%
|
|
13
|
%
|
|
18
|
%
|
|
12
|
%
|
Debt securities
|
10
|
|
|
13
|
|
|
6
|
|
|
12
|
|
Insurance contracts
|
74
|
|
|
74
|
|
|
76
|
|
|
76
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
|
|
|
|
*
|
The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the NQBP, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and NQBP, reported percentages are affected by the fair market values of the investments within the pools.
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other *
|
|
Total
|
||||||||||
As of December 31, 2018:
|
|
|
|
|
|
|
|
|
|
||||||||||
Defined Benefit Pension Plan assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity securities—Domestic
|
$
|
67
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
67
|
|
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
463
|
|
|
463
|
|
|||||
Private equity funds
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
11
|
|
|||||
|
$
|
67
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
479
|
|
|
$
|
546
|
|
Other Postretirement Benefit Plans assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
International
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Debt securities—Domestic government
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|||||
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|||||
|
$
|
11
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
11
|
|
|
$
|
30
|
|
As of December 31, 2017:
|
|
|
|
|
|
|
|
|
|
||||||||||
Defined Benefit Pension Plan assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity securities—Domestic
|
$
|
83
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
83
|
|
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
528
|
|
|
528
|
|
|||||
Private equity funds
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
|||||
|
$
|
83
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
546
|
|
|
$
|
629
|
|
Other Postretirement Benefit Plans assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
International
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|||||
Debt securities—Domestic government
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|||||
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
8
|
|
|||||
|
$
|
13
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
12
|
|
|
$
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
|
|
Defined Benefit Pension Plan
|
|
Other Postretirement
Benefits
|
|
|
Non-Qualified
Benefit Plans
|
|||||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
2017
|
||||||||||||
Benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of January 1
|
$
|
869
|
|
|
$
|
797
|
|
|
$
|
78
|
|
|
|
$
|
73
|
|
|
|
$
|
27
|
|
|
$
|
27
|
|
Service cost
|
19
|
|
|
17
|
|
|
2
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||||
Interest cost
|
32
|
|
|
33
|
|
|
3
|
|
|
|
3
|
|
|
|
1
|
|
|
1
|
|
||||||
Participants’ contributions
|
—
|
|
|
—
|
|
|
2
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||||
Actuarial loss (gain)
|
(67
|
)
|
|
60
|
|
|
(7
|
)
|
|
|
3
|
|
|
|
(1
|
)
|
|
1
|
|
||||||
Contractual termination benefits
|
—
|
|
|
—
|
|
|
—
|
|
|
|
1
|
|
|
|
—
|
|
|
—
|
|
||||||
Benefit payments
|
(39
|
)
|
|
(36
|
)
|
|
(6
|
)
|
|
|
(6
|
)
|
|
|
(3
|
)
|
|
(2
|
)
|
||||||
Administrative expenses
|
(3
|
)
|
|
(2
|
)
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||||
As of December 31
|
$
|
811
|
|
|
$
|
869
|
|
|
$
|
72
|
|
|
|
$
|
78
|
|
|
|
$
|
24
|
|
|
$
|
27
|
|
Fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of January 1
|
$
|
629
|
|
|
$
|
559
|
|
|
$
|
33
|
|
|
|
$
|
30
|
|
|
|
$
|
17
|
|
|
$
|
16
|
|
Actual return on plan assets
|
(50
|
)
|
|
106
|
|
|
(2
|
)
|
|
|
4
|
|
|
|
(1
|
)
|
|
1
|
|
||||||
Company contributions
|
9
|
|
|
2
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
|
2
|
|
||||||
Participants’ contributions
|
—
|
|
|
—
|
|
|
2
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||||
Benefit payments
|
(39
|
)
|
|
(36
|
)
|
|
(6
|
)
|
|
|
(6
|
)
|
|
|
(3
|
)
|
|
(2
|
)
|
||||||
Administrative expenses
|
(3
|
)
|
|
(2
|
)
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||||
As of December 31
|
$
|
546
|
|
|
$
|
629
|
|
|
$
|
30
|
|
|
|
$
|
33
|
|
|
|
$
|
16
|
|
|
$
|
17
|
|
Unfunded position as of December 31
|
$
|
(265
|
)
|
|
$
|
(240
|
)
|
|
$
|
(42
|
)
|
|
|
$
|
(45
|
)
|
|
|
$
|
(8
|
)
|
|
$
|
(10
|
)
|
Accumulated benefit plan obligation as of December 31
|
$
|
734
|
|
|
$
|
778
|
|
|
N/A
|
|
|
N/A
|
|
|
$
|
24
|
|
|
$
|
27
|
|
||||
Classification in consolidated balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Noncurrent asset
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
16
|
|
|
$
|
17
|
|
Current liability
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||
Noncurrent liability
|
(265
|
)
|
|
(240
|
)
|
|
(42
|
)
|
|
|
(45
|
)
|
|
|
(22
|
)
|
|
(25
|
)
|
||||||
Net liability
|
$
|
(265
|
)
|
|
$
|
(240
|
)
|
|
$
|
(42
|
)
|
|
|
$
|
(45
|
)
|
|
|
$
|
(8
|
)
|
|
$
|
(10
|
)
|
Amounts included in comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial loss (gain)
|
$
|
25
|
|
|
$
|
(4
|
)
|
|
$
|
(4
|
)
|
|
|
$
|
—
|
|
|
|
$
|
(1
|
)
|
|
$
|
1
|
|
Amortization of net actuarial loss
|
(17
|
)
|
|
(13
|
)
|
|
—
|
|
|
|
—
|
|
|
|
(1
|
)
|
|
(1
|
)
|
||||||
|
$
|
8
|
|
|
$
|
(17
|
)
|
|
$
|
(4
|
)
|
|
|
$
|
—
|
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
Amounts included in AOCL*:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial loss (gain)
|
$
|
226
|
|
|
$
|
218
|
|
|
$
|
(4
|
)
|
|
|
$
|
(1
|
)
|
|
|
$
|
11
|
|
|
$
|
13
|
|
Prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||||
|
$
|
226
|
|
|
$
|
218
|
|
|
$
|
(4
|
)
|
|
|
$
|
(1
|
)
|
|
|
$
|
11
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit Pension Plan
|
|
Other Postretirement
Benefits
|
|
|
Non-Qualified
Benefit Plans
|
|||||||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
2017
|
||||||||||||
Assumptions used:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Discount rate for benefit obligation
|
4.25
|
%
|
|
3.65
|
%
|
|
4.10
|
%
|
-
|
|
3.42
|
%
|
-
|
|
4.25
|
%
|
|
3.65
|
%
|
||||||
|
|
|
|
|
4.26
|
%
|
|
|
3.70
|
%
|
|
|
|
|
|
||||||||||
Discount rate for benefit cost
|
3.65
|
%
|
|
4.17
|
%
|
|
3.42
|
%
|
-
|
|
3.75
|
%
|
-
|
|
3.65
|
%
|
|
4.17
|
%
|
||||||
|
|
|
|
|
3.70
|
%
|
|
|
4.23
|
%
|
|
|
|
|
|
||||||||||
Weighted average rate of compensation increase for benefit obligation
|
3.65
|
%
|
|
3.65
|
%
|
|
4.58
|
%
|
|
|
4.58
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
Weighted average rate of compensation increase for benefit cost
|
3.65
|
%
|
|
3.65
|
%
|
|
4.58
|
%
|
|
|
4.58
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
Long-term rate of return on plan assets for benefit cost
|
7.00
|
%
|
|
7.50
|
%
|
|
6.20
|
%
|
|
|
6.26
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit
Pension Plan
|
|
Other Postretirement
Benefits
|
|
Non-Qualified
Benefit Plans
|
||||||||||||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||||||||
Service cost
|
$
|
19
|
|
|
$
|
17
|
|
|
$
|
16
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest cost on benefit obligation
|
32
|
|
|
33
|
|
|
33
|
|
|
3
|
|
|
3
|
|
|
4
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|||||||||
Expected return on plan assets
|
(42
|
)
|
|
(42
|
)
|
|
(40
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Amortization of net actuarial loss
|
17
|
|
|
13
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|||||||||
Net periodic benefit cost
|
$
|
26
|
|
|
$
|
21
|
|
|
$
|
23
|
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
5
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due
|
||||||||||||||||||||||
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024 - 2028
|
||||||||||||
Defined benefit pension plan
|
$
|
41
|
|
|
$
|
42
|
|
|
$
|
44
|
|
|
$
|
45
|
|
|
$
|
45
|
|
|
$
|
238
|
|
Other postretirement benefits
|
5
|
|
|
5
|
|
|
5
|
|
|
5
|
|
|
6
|
|
|
22
|
|
||||||
Non-qualified benefit plans
|
2
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
10
|
|
||||||
Total
|
$
|
48
|
|
|
$
|
49
|
|
|
$
|
51
|
|
|
$
|
52
|
|
|
$
|
53
|
|
|
$
|
270
|
|
•
|
For
2018
,
6.5%
annual rate of increase in the per capita cost of covered health care benefits was assumed for
2019
and 2020, then decreasing
0.25%
per year thereafter, reaching
5.0%
in 2026;
|
•
|
For
2017
,
6.5%
annual rate of increase in the per capita cost of covered health care benefits was assumed for
2018
, decreasing to
6.0%
in 2019, then decreasing
0.25%
per year thereafter, reaching
5.0%
in 2023; and
|
•
|
For
2016
,
7%
annual rate of increase in the per capita cost of covered health care benefits was assumed for
2017
, decreasing to
6.5%
in 2018,
6.0%
in 2019, then decreasing
0.25%
per year thereafter, reaching
5.0%
in 2023.
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
12
|
|
|
$
|
4
|
|
|
$
|
10
|
|
State and local
|
22
|
|
|
12
|
|
|
3
|
|
|||
|
34
|
|
|
16
|
|
|
13
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
(15
|
)
|
|
61
|
|
|
23
|
|
|||
State and local
|
(2
|
)
|
|
9
|
|
|
14
|
|
|||
|
(17
|
)
|
|
70
|
|
|
37
|
|
|||
Income tax expense
|
$
|
17
|
|
|
$
|
86
|
|
|
$
|
50
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Federal statutory tax rate
|
21.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
Federal tax credits
(1)
|
(16.7
|
)
|
|
(14.0
|
)
|
|
(18.2
|
)
|
Change in federal tax law
(2)
|
—
|
|
|
6.1
|
|
|
—
|
|
State and local taxes, net of federal tax benefit
|
6.5
|
|
|
5.0
|
|
|
4.8
|
|
Flow through depreciation and cost basis differences
|
1.5
|
|
|
1.5
|
|
|
0.2
|
|
Excess deferred tax amortization
(3)
|
(4.1
|
)
|
|
—
|
|
|
—
|
|
Other
|
(0.8
|
)
|
|
(2.1
|
)
|
|
(1.2
|
)
|
Effective tax rate
|
7.4
|
%
|
|
31.5
|
%
|
|
20.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in-service dates. PGE’s PTC generation ended or will end
at various dates between 2017 and 2024.
|
|
As of December 31,
|
||||||
|
2018
|
|
2017
|
||||
Deferred income tax assets:
|
|
|
|
||||
Employee benefits
|
$
|
134
|
|
|
$
|
128
|
|
Price risk management
|
36
|
|
|
56
|
|
||
Regulatory liabilities
|
26
|
|
|
14
|
|
||
Tax credits
|
52
|
|
|
50
|
|
||
Other
|
9
|
|
|
4
|
|
||
Total deferred income tax assets
|
257
|
|
|
252
|
|
||
Deferred income tax liabilities:
|
|
|
|
||||
Depreciation and amortization
|
511
|
|
|
496
|
|
||
Regulatory assets
|
115
|
|
|
132
|
|
||
Total deferred income tax liabilities
|
626
|
|
|
628
|
|
||
Deferred income tax liability, net
|
$
|
369
|
|
|
$
|
376
|
|
|
Units
|
|
Weighted Average
Grant Date
Fair Value
|
|||
Outstanding as of December 31, 2015
|
442,993
|
|
|
$
|
32.84
|
|
Granted
|
193,734
|
|
|
35.89
|
|
|
Forfeited
|
(3,044
|
)
|
|
28.62
|
|
|
Vested
|
(174,891
|
)
|
|
31.47
|
|
|
Outstanding as of December 31, 2016
|
458,792
|
|
|
34.68
|
|
|
Granted
|
202,145
|
|
|
41.96
|
|
|
Forfeited
|
(64,840
|
)
|
|
39.57
|
|
|
Vested
|
(196,721
|
)
|
|
31.78
|
|
|
Outstanding as of December 31, 2017
|
399,376
|
|
|
37.98
|
|
|
Granted
|
198,864
|
|
|
37.99
|
|
|
Forfeited
|
(8,556
|
)
|
|
39.73
|
|
|
Vested
|
(160,771
|
)
|
|
36.77
|
|
|
Outstanding as of December 31, 2018
|
428,913
|
|
|
38.43
|
|
|
Years Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Weighted average common shares outstanding—basic
|
89,215
|
|
|
89,056
|
|
|
88,896
|
|
Dilutive effect of potential common shares
|
132
|
|
|
120
|
|
|
158
|
|
Weighted average common shares outstanding—diluted
|
89,347
|
|
|
89,176
|
|
|
89,054
|
|
|
Payments Due
|
||||||||||||||||||||||||||
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
||||||||||||||
Capital and other purchase commitments
|
$
|
143
|
|
|
$
|
9
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
58
|
|
|
$
|
213
|
|
Purchased power and fuel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity purchases
|
167
|
|
|
190
|
|
|
186
|
|
|
194
|
|
|
193
|
|
|
1,853
|
|
|
2,783
|
|
|||||||
Capacity contracts
|
1
|
|
|
—
|
|
|
9
|
|
|
9
|
|
|
9
|
|
|
18
|
|
|
46
|
|
|||||||
Public utility districts
|
12
|
|
|
11
|
|
|
9
|
|
|
8
|
|
|
8
|
|
|
35
|
|
|
83
|
|
|||||||
Natural gas
|
54
|
|
|
42
|
|
|
31
|
|
|
31
|
|
|
30
|
|
|
208
|
|
|
396
|
|
|||||||
Coal and transportation
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|||||||
Total
|
$
|
383
|
|
|
$
|
252
|
|
|
$
|
236
|
|
|
$
|
243
|
|
|
$
|
241
|
|
|
$
|
2,172
|
|
|
$
|
3,527
|
|
•
|
Grant County PUD for the Priest Rapids and Wanapum projects, and
|
•
|
Douglas County PUD for the Wells project.
|
|
Capacity Charges and Revenue Bonds as of December 31, 2018
|
|
PGE’s Share as of December 31, 2018
|
|
Contract
Expiration
|
|
PGE Capacity Charges and Debt Service Costs
|
||||||||||||||||
|
Output
|
|
Capacity
|
|
|
2018
|
|
2017
|
|
2016
|
|||||||||||||
|
|
|
|
|
(in MW)
|
|
|
|
|
|
|
|
|
||||||||||
Priest Rapids and Wanapum
|
$
|
1,236
|
|
|
8.6
|
%
|
|
163
|
|
|
2052
|
|
$
|
17
|
|
|
$
|
16
|
|
|
$
|
16
|
|
Wells
|
757
|
|
|
9.0
|
|
|
135
|
|
|
2028
|
|
11
|
|
|
11
|
|
|
10
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|||||
Non-current portion
|
$
|
47
|
|
|
|
|
|
|
PGE
Share
|
|
In-service Date
|
|
Plant
In-service
|
|
Accumulated
Depreciation*
|
|
Construction
Work In
Progress
|
|||||||||
Boardman
|
90.00
|
%
|
|
1980
|
|
$
|
516
|
|
|
$
|
451
|
|
|
$
|
—
|
|
||
Colstrip
|
20.00
|
|
|
1986
|
|
549
|
|
|
363
|
|
|
10
|
|
|||||
Pelton/Round Butte
|
66.67
|
|
|
1958
|
/
|
1964
|
|
270
|
|
|
73
|
|
|
2
|
|
|||
Total
|
|
|
|
|
|
|
$
|
1,335
|
|
|
$
|
887
|
|
|
$
|
12
|
|
|
|
|
|
|
*
|
Excludes AROs and accumulated asset retirement removal costs.
|
|
Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
(In millions, except per share amounts)
|
||||||||||||||
2018
|
|
|
|
|
|
|
|
||||||||
Total revenues
|
$
|
493
|
|
|
$
|
449
|
|
|
$
|
525
|
|
|
$
|
524
|
|
Income from operations
|
100
|
|
|
80
|
|
|
91
|
|
|
75
|
|
||||
Net income
|
64
|
|
|
46
|
|
|
53
|
|
|
49
|
|
||||
Earnings per share:
*
|
|
|
|
|
|
|
|
||||||||
Basic
|
0.72
|
|
|
0.51
|
|
|
0.59
|
|
|
0.55
|
|
||||
Diluted
|
0.72
|
|
|
0.51
|
|
|
0.59
|
|
|
0.55
|
|
||||
2017
|
|
|
|
|
|
|
|
||||||||
Revenues, net
|
$
|
530
|
|
|
$
|
449
|
|
|
$
|
515
|
|
|
$
|
515
|
|
Income from operations
|
123
|
|
|
68
|
|
|
77
|
|
|
112
|
|
||||
Net income
|
73
|
|
|
32
|
|
|
40
|
|
|
42
|
|
||||
Earnings per share:
*
|
|
|
|
|
|
|
|
||||||||
Basic
|
0.82
|
|
|
0.36
|
|
|
0.44
|
|
|
0.48
|
|
||||
Diluted
|
0.82
|
|
|
0.36
|
|
|
0.44
|
|
|
0.48
|
|
|
|
|
|
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
|
•
|
Permit the Company to hold virtual shareholder meetings (Section 2.3);
|
•
|
Establish a process for setting a record date for determining shareholders entitled to take corporate action without a meeting (Section 2.6);
|
•
|
Establish a deadline for shareholders seeking to take action without a meeting to deliver the requisite number of written shareholder consents to the Company (Section 2.15);
|
•
|
Update and enhance our advance notice bylaws by, among other things, expanding the scope of disclosures required of a shareholder seeking to bring a nomination or propose other business for consideration at a meeting of shareholders (Sections 2.13 and 2.14); and
|
•
|
Provide for certain other technical or minor updates and revisions.
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
|
Exhibit
Number
|
Description
|
(3)
|
Articles of Incorporation and Bylaws
|
3.1*
|
|
3.2
|
|
(4)
|
Instruments defining the rights of security holders, including indentures
|
4.1*
|
Portland General Electric Company Indenture of Mortgage and Deed of Trust dated July 1, 1945 (Form 8, Amendment No. 1 dated June 14, 1965) (File No. 001-05532-99).
|
4.2*
|
Fortieth Supplemental Indenture dated October 1, 1990 (Form 10-K for the year ended December 31, 1990, Exhibit 4) (File No. 001-05532-99).
|
4.3*
|
|
4.4*
|
|
(10)
|
Material Contracts
|
10.1*
|
|
10.2*
|
|
10.3
|
|
10.4*
|
|
10.5*
|
|
10.6*
|
|
10.7*
|
|
10.8*
|
|
10.9*
|
|
10.10*
|
|
10.11*
|
Exhibit
Number
|
Description
|
10.12*
|
|
10.13*
|
|
10.14*
|
|
10.15*
|
|
10.16*
|
|
10.17*
|
|
10.18*
|
|
10.19*
|
|
(23)
|
Consents of Experts and Counsel
|
23.1
|
|
(31)
|
Rule 13a-14(a)/15d-14(a) Certifications
|
31.1
|
|
31.2
|
|
(32)
|
Section 1350 Certifications
|
32.1
|
|
(101)
|
Interactive Data File
|
101.INS
|
XBRL Instance Document.
|
101.SCH
|
XBRL Taxonomy Extension Schema Document.
|
101.CAL
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
101.DEF
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
101.LAB
|
XBRL Taxonomy Extension Label Linkbase Document.
|
101.PRE
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
|
|
|
|
|
*
|
Incorporated by reference as indicated.
|
+
|
Indicates a management contract or compensatory plan or arrangement.
|
|
PORTLAND GENERAL ELECTRIC COMPANY
|
|
|
|
|
|
By:
|
/s/ MARIA M. POPE
|
|
|
Maria M. Pope
|
|
|
President and Chief Executive Officer
|
Signature
|
Title
|
|
|
/s/ MARIA M. POPE
|
President, Chief Executive Officer, and Director
(principal executive officer)
|
Maria M. Pope
|
|
|
|
/s/ JAMES F. LOBDELL
|
Senior Vice President of Finance, Chief Financial Officer, and Treasurer
(principal financial and accounting officer)
|
James F. Lobdell
|
|
|
|
/s/ JOHN W. BALLANTINE
|
Director
|
John W. Ballantine
|
|
|
|
/s/ RODNEY L. BROWN, JR.
|
Director
|
Rodney L. Brown, Jr.
|
|
|
|
/s/ JACK E. DAVIS
|
Director
|
Jack E. Davis
|
|
|
|
/s/ DAVID A. DIETZLER
|
Director
|
David A. Dietzler
|
|
|
|
/s/ KIRBY A. DYESS
|
Director
|
Kirby A. Dyess
|
|
|
|
/s/ MARK B. GANZ
|
Director
|
Mark B. Ganz
|
|
|
|
/s/ KATHRYN J. JACKSON
|
Director
|
Kathryn J. Jackson
|
|
|
|
/s/ NEIL J. NELSON
|
Director
|
Neil J. Nelson
|
|
|
|
/s/ M. LEE PELTON
|
Director
|
M. Lee Pelton
|
|
|
|
/s/ CHARLES W. SHIVERY
|
Director
|
Charles W. Shivery
|
|
ADMINISTRATIVE AGENT:
|
WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent
|
1.
|
I have reviewed this Annual Report on Form 10-K of Portland General Electric Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
February 14, 2019
|
|
/s/ MARIA M. POPE
|
|
|
Maria M. Pope
|
|
|
President and
Chief Executive Officer
|
1.
|
I have reviewed this Annual Report on Form 10-K of Portland General Electric Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
February 14, 2019
|
|
/s/ JAMES F. LOBDELL
|
|
|
James F. Lobdell
|
|
|
Senior Vice President of Finance, Chief Financial Officer, and Treasurer
|
/s/ MARIA M. POPE
|
|
/s/ JAMES F. LOBDELL
|
Maria M. Pope
|
|
James F. Lobdell
|
President and
Chief Executive Officer
|
|
Senior Vice President of Finance, Chief Financial Officer and Treasurer
|
|
|
|
Date:
February 14, 2019
|
|
Date:
February 14, 2019
|