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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(Do not check if a smaller reporting company)
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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 25, 2018.
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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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CAA
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Clean Air Act
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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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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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EFSA
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Equity forward sale agreement
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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. Such changes are requested pursuant to a comprehensive general rate case process that includes revenue requirements based on a forecasted test year, debt-to-equity capital structure, return on equity, and overall rate of return. 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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Power Costs
. In addition to price changes resulting from the general rate case process, the OPUC has approved the following mechanisms by which PGE can adjust retail customer prices to cover changes in the Company’s net variable power costs (NVPC). NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts (all 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 condensed consolidated statements of income.
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◦
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Annual Power Cost Update Tariff (AUT). Under this tariff, customer prices are adjusted annually to reflect forecasted NVPC. An initial NVPC forecast, submitted to the OPUC by April 1 each year, is updated during such year and finalized in November. Based upon the final forecast, new prices, as approved by the OPUC, become effective at the beginning of the following calendar year; and
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◦
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Power Cost Adjustment Mechanism (PCAM). Under the PCAM, PGE shares a portion of the business risk or benefit associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year. For additional information, see
“Power Operations”
in the Overview section in Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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Renewable Energy.
The 2007 Oregon Renewable Energy Act (the 2007 Act) established a Renewable Portfolio Standard (RPS), which required that PGE serve at least 15% of its retail load with renewable resources by 2015, with future requirements of 20% by 2020 and 25% by 2025. PGE met the 2015 requirement and expects to meet the requirements going forward.
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Decoupling.
The decoupling mechanism provides a means for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency and conservation efforts undertaken by residential and certain commercial customers. The mechanism, authorized by the OPUC through 2019,
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Years Ended December 31,
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2017
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2016
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2015
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Retail revenues
(1)
(dollars in millions):
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Residential
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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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$
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895
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50
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%
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Commercial
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669
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36
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665
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37
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662
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37
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Industrial
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212
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11
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208
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12
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228
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13
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Subtotal
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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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1,785
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100
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Other accrued (deferred) revenues, net
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10
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1
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3
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—
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(10
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—
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Total retail revenues
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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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$
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1,775
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100
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%
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Retail energy deliveries
(2)
(MWh in thousands):
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Residential
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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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7,325
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38
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%
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Commercial
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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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7,511
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39
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Industrial
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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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4,546
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23
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Total retail energy deliveries
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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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19,382
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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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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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742,467
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88
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%
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Commercial
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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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105,802
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12
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Industrial
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267
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—
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258
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—
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255
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—
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Total
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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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848,524
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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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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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2017
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2016
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2015
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Residential
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Revenue per customer (in dollars):
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$
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1,181
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$
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1,114
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$
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1,139
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Usage per customer (in kilowatt hours):
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10,338
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9,766
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9,866
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Revenue per kilowatt hour (in cents):
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11.42
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¢
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11.40
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¢
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11.55
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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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6,142
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$
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6,166
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$
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6,254
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Usage per customer (in kilowatt hours):
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70,046
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69,839
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70,987
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Revenue per kilowatt hour (in cents):
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8.77
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¢
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8.83
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¢
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8.81
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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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792,466
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$
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804,953
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$
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876,866
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Usage per customer (in kilowatt hours):
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16,041,461
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16,146,371
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17,485,281
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Revenue per kilowatt hour (in cents):
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4.94
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¢
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4.99
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¢
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5.01
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¢
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Heating
Degree-Days
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Cooling
Degree-Days
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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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2015
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3,461
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785
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15-year average
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4,233
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471
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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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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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2015
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2,509
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3,255
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December
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2,390
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3,914
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July
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As of December 31,
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2017
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2016
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2015
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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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1,831
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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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1,371
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30
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%
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Coal
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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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2,645
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56
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2,619
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55
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2,185
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47
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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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16
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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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11
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495
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11
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Total generation
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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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3,397
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74
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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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250
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5
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250
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5
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Hydro
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531
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12
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534
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12
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592
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13
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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
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13
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—
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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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18
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—
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18
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—
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118
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3
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Total long-term contracts
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701
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15
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854
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18
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1,012
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22
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Short-term contracts
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185
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4
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45
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1
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200
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4
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Total purchased power
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886
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19
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899
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19
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1,212
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26
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Total resource capacity
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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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4,609
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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
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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
33%
of PGE’s total retail load requirement in
2017
,
32%
in
2016
, and
25%
in
2015
.
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Wind
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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
9%
of the Company’s total retail load requirement in
2017
,
9%
in
2016
, and
8%
in
2015
, with availability of
95%
in
2017
, and
99%
in both
2016
and in
2015
. 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.
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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 fixed-price purchase agreements that, together with existing inventory, will provide coal sufficient for the anticipated operating needs for Boardman during 2018. The coal is obtained from surface mining operations in Wyoming and is delivered by rail under two separate transportation contracts which extend through 2020.
|
•
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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 three hydroelectric projects on the mid-Columbia River. One contract representing
150
MW of capacity expires in 2018 and a contract representing
163
MW of capacity expires in 2052. Although the projects currently provide a total of
313
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 162 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.
|
•
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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;
|
•
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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.
|
Facility
|
|
Location
|
|
Net
Capacity
(1)
|
|
|
Wholly-owned:
|
|
|
|
|
|
|
Natural Gas/Oil:
|
|
|
|
|
|
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Beaver
|
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Clatskanie, Oregon
|
|
509
|
|
MW
|
Carty
|
|
Boardman, Oregon
|
|
437
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|
|
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
|
|
|
|
3,857
|
|
MW
|
|
|
|
|
|
|
|
|
|
|
|
(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)
|
Reflects PGE’s ownership share.
|
(3)
|
PGE operates Boardman and has a 90% ownership interest.
|
(4)
|
Talen Montana, LLC operates Colstrip and PGE has a 20% ownership interest.
|
(5)
|
PGE operates Pelton and Round Butte and has a 66.67% ownership interest.
|
•
|
Approximately 15% of the Colstrip Project 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 3,490 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.
|
|
|
High
|
|
Low
|
|
Dividends
Declared
Per Share
|
||||||
2017
|
|
|
|
|
|
|
||||||
Fourth Quarter
|
|
$
|
50.11
|
|
|
$
|
44.70
|
|
|
$
|
0.34
|
|
Third Quarter
|
|
48.22
|
|
|
44.20
|
|
|
0.34
|
|
|||
Second Quarter
|
|
48.06
|
|
|
44.04
|
|
|
0.34
|
|
|||
First Quarter
|
|
46.05
|
|
|
42.41
|
|
|
0.32
|
|
|||
2016
|
|
|
|
|
|
|
||||||
Fourth Quarter
|
|
$
|
44.32
|
|
|
$
|
40.28
|
|
|
$
|
0.32
|
|
Third Quarter
|
|
45.21
|
|
|
41.51
|
|
|
0.32
|
|
|||
Second Quarter
|
|
44.12
|
|
|
37.77
|
|
|
0.32
|
|
|||
First Quarter
|
|
40.48
|
|
|
35.27
|
|
|
0.30
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
(In millions, except per share amounts)
|
||||||||||||||||||
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues, net
|
$
|
2,009
|
|
|
$
|
1,923
|
|
|
$
|
1,898
|
|
|
$
|
1,900
|
|
|
$
|
1,810
|
|
Income from operations
|
376
|
|
|
333
|
|
|
309
|
|
|
293
|
|
|
206
|
|
|||||
Net income
|
187
|
|
|
193
|
|
|
172
|
|
|
174
|
|
|
104
|
|
|||||
Net income attributable to Portland General Electric Company
|
187
|
|
|
193
|
|
|
172
|
|
|
175
|
|
|
105
|
|
|||||
Earnings per share—basic
|
2.10
|
|
|
2.17
|
|
|
2.05
|
|
|
2.24
|
|
|
1.36
|
|
|||||
Earnings per share—diluted
|
2.10
|
|
|
2.16
|
|
|
2.04
|
|
|
2.18
|
|
|
1.35
|
|
|||||
Dividends declared per common share
|
1.340
|
|
|
1.260
|
|
|
1.180
|
|
|
1.115
|
|
|
1.095
|
|
|||||
Statement of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
514
|
|
|
584
|
|
|
598
|
|
|
1,007
|
|
|
656
|
|
|
As of December 31,
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
(Dollars in millions)
|
||||||||||||||||||
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
7,838
|
|
|
$
|
7,527
|
|
|
$
|
7,210
|
|
|
$
|
7,030
|
|
|
$
|
6,090
|
|
Total long-term debt
|
2,426
|
|
|
2,350
|
|
|
2,193
|
|
|
2,489
|
|
|
1,905
|
|
|||||
Total capital lease obligations
|
51
|
|
|
54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total Portland General Electric Company shareholders’ equity
|
2,416
|
|
|
2,344
|
|
|
2,258
|
|
|
1,911
|
|
|
1,819
|
|
|||||
Common equity ratio
|
49.4
|
%
|
|
49.4
|
%
|
|
50.7
|
%
|
|
43.4
|
%
|
|
48.9
|
%
|
|
|
|
|
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
•
|
governmental policies 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 17, 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, including the potential impact of the U.S. Tax Cuts and Jobs Act;
|
•
|
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.
|
•
|
Compliance with the RPS through 2050;
|
•
|
Inclusion of cost-effective customer-side options, including energy efficiency, demand response, conservation voltage reduction, and dispatchable standby generation; and
|
•
|
Retention of all existing power plants until 2050, with the exception of Boardman and Colstrip Units 3 & 4.
|
•
|
Meet additional capacity needs of 561 MW, of which 240 MW must be dispatchable, in 2021;
|
•
|
Acquire a total of 135 MWa of cost-effective energy efficiency;
|
•
|
Acquire at least 77 MW (winter) and 69 MW (summer) demand response through 2020 and 16 MW of dispatchable standby generation from customers to help manage peak load conditions and other supply contingencies;
|
•
|
Deploy 1 MWa of conservation voltage reduction through 2020;
|
•
|
Submit one or more energy storage proposals in accordance with Oregon House Bill 2193, by January 1, 2018; and
|
•
|
Perform various research and studies related to flexible capacity and curtailment metrics, customer insights, decarbonization, risks associated with Direct Access, treatment of market capacity, access to resources from Montana, and improvements to load forecasting.
|
•
|
200 MW of annual capacity with five-year terms beginning January 1, 2021; and
|
•
|
100 MW of seasonal peak capacity during the summer and winter seasons with a term that would begin July 1, 2019 and continue through February 29, 2024.
|
•
|
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.
|
•
|
A capital structure of 50% debt and 50% equity;
|
•
|
A return on equity of 9.50%
|
•
|
A cost of capital of 7.31%, and
|
•
|
A rate base of $4.86 billion.
|
|
2017
|
|
2016
|
|
Increase/
(Decrease)
in Energy
Deliveries
|
|||||||||
|
Average
Number of
Customers
|
|
Energy
Deliveries *
|
|
Average
Number of
Customers
|
|
Energy
Deliveries *
|
|
||||||
Residential
|
762,211
|
|
|
7,880
|
|
|
752,365
|
|
|
7,348
|
|
|
7.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|||||
Commercial (PGE sales only)
|
107,364
|
|
|
6,932
|
|
|
106,460
|
|
|
6,932
|
|
|
—
|
%
|
Direct Access
|
491
|
|
|
623
|
|
|
313
|
|
|
525
|
|
|
18.7
|
%
|
Total Commercial
|
107,855
|
|
|
7,555
|
|
|
106,773
|
|
|
7,457
|
|
|
1.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|||||
Industrial (PGE sales only)
|
199
|
|
|
2,943
|
|
|
195
|
|
|
2,968
|
|
|
(0.8
|
)%
|
Direct Access
|
68
|
|
|
1,340
|
|
|
63
|
|
|
1,198
|
|
|
11.9
|
%
|
Total Industrial
|
267
|
|
|
4,283
|
|
|
258
|
|
|
4,166
|
|
|
2.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|||||
Total (PGE sales only)
|
869,774
|
|
|
17,755
|
|
|
859,020
|
|
|
17,248
|
|
|
2.9
|
%
|
Total Direct Access
|
559
|
|
|
1,963
|
|
|
376
|
|
|
1,723
|
|
|
13.9
|
%
|
Total
|
870,333
|
|
|
19,718
|
|
|
859,396
|
|
|
18,971
|
|
|
3.9
|
%
|
|
|
|
|
|
*
|
In thousands of MWh.
|
•
|
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 will be made by the OPUC through a public filing and review in
2018
.
|
•
|
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
.
|
•
|
For
2015
, 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, 2015. A final determination regarding the
2015
PCAM results was made by the OPUC through a public filing and review in
2016
, which confirmed no refund to customers pursuant to the PCAM for
2015
.
|
•
|
An ongoing environmental investigation of Portland Harbor; and
|
•
|
The termination of the Construction Agreement for Carty and recovery of related incremental costs.
|
•
|
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 renewable energy certificates (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 in its renewable adjustment clause mechanism (RAC) filings.
|
▪
|
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,
|
|||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|||||||||||||||
|
Amount
|
|
As %
of Rev
|
|
Amount
|
|
As %
of Rev
|
|
Amount
|
|
As %
of Rev
|
|||||||||
Revenues, net
(1)
|
$
|
2,009
|
|
|
100
|
%
|
|
$
|
1,923
|
|
|
100
|
%
|
|
$
|
1,898
|
|
|
100
|
%
|
Purchased power and fuel
(1)
|
592
|
|
|
30
|
|
|
617
|
|
|
32
|
|
|
661
|
|
|
35
|
|
|||
Gross margin
|
1,417
|
|
|
70
|
|
|
1,306
|
|
|
68
|
|
|
1,237
|
|
|
65
|
|
|||
Other operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Generation, transmission and distribution
|
309
|
|
|
16
|
|
|
286
|
|
|
15
|
|
|
266
|
|
|
14
|
|
|||
Administrative and other
|
264
|
|
|
13
|
|
|
247
|
|
|
13
|
|
|
241
|
|
|
13
|
|
|||
Depreciation and amortization
|
345
|
|
|
17
|
|
|
321
|
|
|
16
|
|
|
305
|
|
|
16
|
|
|||
Taxes other than income taxes
|
123
|
|
|
6
|
|
|
119
|
|
|
6
|
|
|
116
|
|
|
6
|
|
|||
Total other operating expenses
|
1,041
|
|
|
52
|
|
|
973
|
|
|
50
|
|
|
928
|
|
|
49
|
|
|||
Income from operations
|
376
|
|
|
18
|
|
|
333
|
|
|
18
|
|
|
309
|
|
|
16
|
|
|||
Interest expense, net
(2)
|
120
|
|
|
6
|
|
|
112
|
|
|
6
|
|
|
114
|
|
|
6
|
|
|||
Other income:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Allowance for equity funds used during construction
|
12
|
|
|
1
|
|
|
21
|
|
|
1
|
|
|
21
|
|
|
1
|
|
|||
Miscellaneous income, net
|
5
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|||
Other income, net
|
17
|
|
|
1
|
|
|
22
|
|
|
1
|
|
|
22
|
|
|
1
|
|
|||
Income before income taxes
|
273
|
|
|
13
|
|
|
243
|
|
|
13
|
|
|
217
|
|
|
11
|
|
|||
Income tax expense
|
86
|
|
|
4
|
|
|
50
|
|
|
3
|
|
|
45
|
|
|
2
|
|
|||
Net income
|
$
|
187
|
|
|
9
|
%
|
|
$
|
193
|
|
|
10
|
%
|
|
$
|
172
|
|
|
9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|||||||||||||||
Revenues
(1)
(dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Residential
|
$
|
969
|
|
|
48
|
%
|
|
$
|
907
|
|
|
47
|
%
|
|
$
|
895
|
|
|
47
|
%
|
Commercial
|
669
|
|
|
33
|
|
|
665
|
|
|
35
|
|
|
662
|
|
|
35
|
|
|||
Industrial
|
212
|
|
|
11
|
|
|
208
|
|
|
11
|
|
|
228
|
|
|
12
|
|
|||
Subtotal
|
1,850
|
|
|
92
|
|
|
1,780
|
|
|
93
|
|
|
1,785
|
|
|
94
|
|
|||
Other accrued (deferred) revenues, net
|
10
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|
(10
|
)
|
|
(1
|
)
|
|||
Total retail revenues
|
1,860
|
|
|
93
|
|
|
1,783
|
|
|
93
|
|
|
1,775
|
|
|
93
|
|
|||
Wholesale revenues
|
105
|
|
|
5
|
|
|
103
|
|
|
5
|
|
|
88
|
|
|
5
|
|
|||
Other operating revenues
|
44
|
|
|
2
|
|
|
37
|
|
|
2
|
|
|
35
|
|
|
2
|
|
|||
Total revenues
|
$
|
2,009
|
|
|
100
|
%
|
|
$
|
1,923
|
|
|
100
|
%
|
|
$
|
1,898
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Energy deliveries
(2)
(MWh in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Residential
|
7,880
|
|
|
34
|
%
|
|
7,348
|
|
|
33
|
%
|
|
7,325
|
|
|
33
|
%
|
|||
Commercial
|
7,555
|
|
|
33
|
|
|
7,457
|
|
|
33
|
|
|
7,511
|
|
|
34
|
|
|||
Industrial
|
4,283
|
|
|
19
|
|
|
4,166
|
|
|
19
|
|
|
4,546
|
|
|
21
|
|
|||
Total retail energy deliveries
|
19,718
|
|
|
86
|
|
|
18,971
|
|
|
85
|
|
|
19,382
|
|
|
88
|
|
|||
Wholesale energy deliveries
|
3,193
|
|
|
14
|
|
|
3,352
|
|
|
15
|
|
|
2,560
|
|
|
12
|
|
|||
Total energy deliveries
|
22,911
|
|
|
100
|
%
|
|
22,323
|
|
|
100
|
%
|
|
21,942
|
|
|
100
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Average number of retail customers:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Residential
|
762,211
|
|
|
88
|
%
|
|
752,365
|
|
|
88
|
%
|
|
742,467
|
|
|
88
|
%
|
|||
Commercial
|
107,855
|
|
|
12
|
|
|
106,773
|
|
|
12
|
|
|
105,802
|
|
|
12
|
|
|||
Industrial
|
267
|
|
|
—
|
|
|
258
|
|
|
—
|
|
|
255
|
|
|
—
|
|
|||
Total
|
870,333
|
|
|
100
|
%
|
|
859,396
|
|
|
100
|
%
|
|
848,524
|
|
|
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 $17 million, $13 million, and $12 million for 2017, 2016, and 2015, respectively. Industrial revenues from ESS customers were $20 million, $15 million, and $16 million for 2017, 2016, and 2015, respectively.
|
|||
(2)
|
Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs. Commercial deliveries to ESS customers, in thousands of MWhs, were: 623 in 2017; 525 in 2016; and 509 in 2015. Industrial deliveries to ESS customers, in thousands of MWhs, were: 1,340
in 2017;
1,198 in 2016; and 1,177 in 2015.
|
•
|
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, as an estimated $13 million collection was recorded 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
|
|
|
1,867
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2nd quarter
|
686
|
|
|
403
|
|
|
689
|
|
|
129
|
|
|
154
|
|
|
70
|
|
3rd quarter
|
78
|
|
|
78
|
|
|
78
|
|
|
571
|
|
|
394
|
|
|
399
|
|
4th quarter
|
1,623
|
|
|
1,486
|
|
|
1,599
|
|
|
—
|
|
|
—
|
|
|
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
|
|
•
|
A $49 million increase resulting from price changes, as authorized by the OPUC, including Carty going into service and into customer prices in mid-2016, as a result of the Company’s 2016 GRC;
|
•
|
A $10 million increase resulting from the Decoupling mechanism, as an estimated $3 million collection was recorded in 2016 compared to a refund in 2015;
|
•
|
A $5 million increase due to a lower amount of customer credits related to tax credits 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; and
|
•
|
A $5 million overall increase due to various other largely offsetting tariff changes and adjustments; partially offset by
|
•
|
A $38 million decrease in revenues related to a
2.1%
decrease in retail energy deliveries, consisting of
8.4%
and
0.7%
decreases in industrial and commercial deliveries, respectively, partially offset by a
0.3%
increase in residential deliveries. See
“Customers and Demand”
in the Overview section of this Item 7. for further information on customer demand; and
|
•
|
A $23 million decrease related to the collection from customers during 2015 of costs associated with previous capital project deferrals, with no comparable collection in 2016. This decrease in revenues is largely offset by a comparable decrease in depreciation and amortization expense.
|
|
Heating Degree-Days
|
|
Cooling Degree-Days
|
||||||||||||||
|
2016
|
|
2015
|
|
15-Year Average
|
|
2016
|
|
2015
|
|
15-Year Average
|
||||||
1st quarter
|
1,585
|
|
|
1,481
|
|
|
1,866
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2nd quarter
|
403
|
|
|
513
|
|
|
689
|
|
|
154
|
|
|
207
|
|
|
70
|
|
3rd quarter
|
78
|
|
|
76
|
|
|
78
|
|
|
394
|
|
|
573
|
|
|
399
|
|
4th quarter
|
1,486
|
|
|
1,391
|
|
|
1,600
|
|
|
—
|
|
|
5
|
|
|
2
|
|
Total
|
3,552
|
|
|
3,461
|
|
|
4,233
|
|
|
548
|
|
|
785
|
|
|
471
|
|
Increase (decrease) from the 15-year average
|
(16
|
)%
|
|
(18
|
)%
|
|
|
|
|
16
|
%
|
|
67
|
%
|
|
|
|
|
Runoff as a Percent of 30-year Average
|
||||
Location
|
2016
Actual
|
|
2015
Actual
|
||
Columbia River at The Dalles, Oregon
|
89
|
%
|
|
69
|
%
|
Mid-Columbia River at Grand Coulee, Washington
|
91
|
|
|
77
|
|
Clackamas River at Estacada, Oregon
|
71
|
|
|
53
|
|
Deschutes River at Moody, Oregon
|
91
|
|
|
85
|
|
|
Years Ending December 31,
|
||||||||||||||||||||||
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
||||||||||||
Ongoing capital expenditures
(1)
|
$
|
462
|
|
|
$
|
535
|
|
|
$
|
444
|
|
|
$
|
451
|
|
|
$
|
440
|
|
|
$
|
450
|
|
Customer information system
(2)
|
49
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total capital expenditures
|
$
|
511
|
|
(3)
|
$
|
551
|
|
|
$
|
444
|
|
|
$
|
451
|
|
|
$
|
440
|
|
|
$
|
450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Long-term debt maturities
|
$
|
150
|
|
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
—
|
|
|
|
|
|
|
(1)
|
Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connects.
|
(2)
|
Total capital expenditures for the customer information system through December 31, 2017 were $114
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,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Cash and cash equivalents, beginning of year
|
$
|
6
|
|
|
$
|
4
|
|
|
$
|
127
|
|
Net cash provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
597
|
|
|
553
|
|
|
520
|
|
|||
Investing activities
|
(514
|
)
|
|
(585
|
)
|
|
(522
|
)
|
|||
Financing activities
|
(50
|
)
|
|
34
|
|
|
(121
|
)
|
|||
Net change in cash and cash equivalents
|
33
|
|
|
2
|
|
|
(123
|
)
|
|||
Cash and cash equivalents, end of year
|
$
|
39
|
|
|
$
|
6
|
|
|
$
|
4
|
|
|
|
|
|
|
|
Declaration Date
|
|
Record Date
|
|
Payment Date
|
|
Declared Per
Common Share
|
||
February 15, 2017
|
|
March 27, 2017
|
|
April 17, 2017
|
|
$
|
0.32
|
|
April 26, 2017
|
|
June 26, 2017
|
|
July 17, 2017
|
|
0.34
|
|
|
July 26, 2017
|
|
September 25, 2017
|
|
October 16, 2017
|
|
0.34
|
|
|
October 25, 2017
|
|
December 26, 2017
|
|
January 16, 2018
|
|
0.34
|
|
|
Moody’s
|
|
S&P
|
First Mortgage Bonds
|
A1
|
|
A-
|
Senior unsecured debt
|
A3
|
|
BBB
|
Commercial paper
|
P-2
|
|
A-2
|
Outlook
|
Stable
|
|
Positive
|
•
|
$50 million
on August 21, 2017;
|
•
|
$25 million
on October 30, 2017; and
|
•
|
$75 million
on November 27, 2017.
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
There-
after
|
|
Total
|
||||||||||||||
Long-term debt
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
—
|
|
|
$
|
1,976
|
|
|
$
|
2,436
|
|
Interest on long-term debt
(1)
|
123
|
|
|
110
|
|
|
104
|
|
|
100
|
|
|
99
|
|
|
1,574
|
|
|
2,110
|
|
|||||||
Capital and other purchase commitments
|
191
|
|
|
2
|
|
|
10
|
|
|
2
|
|
|
2
|
|
|
58
|
|
|
265
|
|
|||||||
Purchased power and fuel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity purchases
|
156
|
|
|
156
|
|
|
201
|
|
|
200
|
|
|
187
|
|
|
1,733
|
|
|
2,633
|
|
|||||||
Capacity contracts
|
6
|
|
|
5
|
|
|
4
|
|
|
4
|
|
|
4
|
|
|
8
|
|
|
31
|
|
|||||||
Public Utility Districts
|
9
|
|
|
17
|
|
|
16
|
|
|
16
|
|
|
15
|
|
|
85
|
|
|
158
|
|
|||||||
Natural gas
|
51
|
|
|
35
|
|
|
28
|
|
|
25
|
|
|
24
|
|
|
140
|
|
|
303
|
|
|||||||
Coal and transportation
|
15
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|||||||
Pension Plan Contributions
(2)
|
21
|
|
|
17
|
|
|
17
|
|
|
18
|
|
|
24
|
|
|
—
|
|
|
97
|
|
|||||||
Capital leases
|
7
|
|
|
6
|
|
|
6
|
|
|
6
|
|
|
5
|
|
|
72
|
|
|
102
|
|
|||||||
Build-to-suit lease
|
—
|
|
|
15
|
|
|
15
|
|
|
14
|
|
|
14
|
|
|
260
|
|
|
318
|
|
|||||||
Operating leases
|
9
|
|
|
8
|
|
|
6
|
|
|
6
|
|
|
8
|
|
|
165
|
|
|
202
|
|
|||||||
Total
|
$
|
588
|
|
|
$
|
676
|
|
|
$
|
407
|
|
|
$
|
551
|
|
|
$
|
382
|
|
|
$
|
6,071
|
|
|
$
|
8,675
|
|
|
|
|
|
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
||||||||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity
|
$
|
10
|
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
7
|
|
|
$
|
91
|
|
|
$
|
132
|
|
Natural gas
|
43
|
|
|
20
|
|
|
7
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
72
|
|
|||||||
|
$
|
53
|
|
|
$
|
28
|
|
|
$
|
15
|
|
|
$
|
10
|
|
|
$
|
7
|
|
|
$
|
91
|
|
|
$
|
204
|
|
|
Total
Fair
Value
|
|
Carrying Amounts by Maturity Date
|
||||||||||||||||||||||||
|
Total
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
There-
after
|
||||||||||||||||
First Mortgage Bonds
|
$
|
2,698
|
|
|
$
|
2,315
|
|
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
1,855
|
|
Pollution Control Revenue Bonds
|
131
|
|
|
121
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
121
|
|
|||||||
Total
|
$
|
2,829
|
|
|
$
|
2,436
|
|
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
1,976
|
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues, net
|
$
|
2,009
|
|
|
$
|
1,923
|
|
|
$
|
1,898
|
|
Operating expenses:
|
|
|
|
|
|
||||||
Purchased power and fuel
|
592
|
|
|
617
|
|
|
661
|
|
|||
Generation, transmission and distribution
|
309
|
|
|
286
|
|
|
266
|
|
|||
Administrative and other
|
264
|
|
|
247
|
|
|
241
|
|
|||
Depreciation and amortization
|
345
|
|
|
321
|
|
|
305
|
|
|||
Taxes other than income taxes
|
123
|
|
|
119
|
|
|
116
|
|
|||
Total operating expenses
|
1,633
|
|
|
1,590
|
|
|
1,589
|
|
|||
Income from operations
|
376
|
|
|
333
|
|
|
309
|
|
|||
Interest expense, net
|
120
|
|
|
112
|
|
|
114
|
|
|||
Other income:
|
|
|
|
|
|
||||||
Allowance for equity funds used during construction
|
12
|
|
|
21
|
|
|
21
|
|
|||
Miscellaneous income, net
|
5
|
|
|
1
|
|
|
1
|
|
|||
Other income, net
|
17
|
|
|
22
|
|
|
22
|
|
|||
Income before income taxes
|
273
|
|
|
243
|
|
|
217
|
|
|||
Income tax expense
|
86
|
|
|
50
|
|
|
45
|
|
|||
Net income
|
$
|
187
|
|
|
$
|
193
|
|
|
$
|
172
|
|
|
|
|
|
|
|
||||||
Weighted-average shares outstanding (in thousands):
|
|
|
|
|
|
||||||
Basic
|
89,056
|
|
|
88,896
|
|
|
84,180
|
|
|||
Diluted
|
89,176
|
|
|
89,054
|
|
|
84,341
|
|
|||
|
|
|
|
|
|
||||||
Earnings per share:
|
|
|
|
|
|
||||||
Basic
|
$
|
2.10
|
|
|
$
|
2.17
|
|
|
$
|
2.05
|
|
Diluted
|
$
|
2.10
|
|
|
$
|
2.16
|
|
|
$
|
2.04
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Net income
|
$
|
187
|
|
|
$
|
193
|
|
|
$
|
172
|
|
Other comprehensive (loss) income—Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2017, 2016, and 2015
|
(1
|
)
|
|
1
|
|
|
(1
|
)
|
|||
Comprehensive income
|
$
|
186
|
|
|
$
|
194
|
|
|
$
|
171
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
132
|
|
|
$
|
129
|
|
Liabilities from price risk management activities—current
|
59
|
|
|
44
|
|
||
Current portion of long-term debt
|
—
|
|
|
150
|
|
||
Accrued expenses and other current liabilities
|
241
|
|
|
254
|
|
||
Total current liabilities
|
432
|
|
|
577
|
|
||
Long-term debt, net of current portion
|
2,426
|
|
|
2,200
|
|
||
Regulatory liabilities—noncurrent
|
1,288
|
|
|
958
|
|
||
Deferred income taxes
|
376
|
|
|
669
|
|
||
Unfunded status of pension and postretirement plans
|
284
|
|
|
281
|
|
||
Liabilities from price risk management activities—noncurrent
|
151
|
|
|
125
|
|
||
Asset retirement obligations
|
167
|
|
|
161
|
|
||
Non-qualified benefit plan liabilities
|
106
|
|
|
105
|
|
||
Other noncurrent liabilities
|
192
|
|
|
107
|
|
||
Total liabilities
|
5,422
|
|
|
5,183
|
|
||
Commitments and contingencies (see notes)
|
|
|
|
|
|||
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; 89,114,265 and 88,946,704 shares issued and outstanding as of December 31, 2017 and 2016, respectively
|
1,207
|
|
|
1,201
|
|
||
Accumulated other comprehensive loss
|
(8
|
)
|
|
(7
|
)
|
||
Retained earnings
|
1,217
|
|
|
1,150
|
|
||
Total equity
|
2,416
|
|
|
2,344
|
|
||
Total liabilities and equity
|
$
|
7,838
|
|
|
$
|
7,527
|
|
|
|
|
|
|
Common Stock
|
|
Accumulated
Other
Comprehensive
Loss
|
|
Retained
Earnings
|
|
Total
|
|||||||||||
|
Shares
|
|
Amount
|
|
||||||||||||||
Balance as of December 31, 2014
|
78,228,339
|
|
|
$
|
918
|
|
|
$
|
(7
|
)
|
|
$
|
1,000
|
|
|
$
|
1,911
|
|
Issuances of common stock, net of issuance costs of $12
|
10,400,000
|
|
|
271
|
|
|
—
|
|
|
—
|
|
|
271
|
|
||||
Shares issued pursuant to equity-based plans
|
164,412
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Stock-based compensation
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
6
|
|
||||
Dividends declared ($1.18 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(102
|
)
|
|
(102
|
)
|
||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
172
|
|
|
172
|
|
||||
Other comprehensive (loss)
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
||||
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
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
187
|
|
|
$
|
193
|
|
|
$
|
172
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
345
|
|
|
321
|
|
|
305
|
|
|||
Deferred income taxes
|
70
|
|
|
37
|
|
|
40
|
|
|||
Allowance for equity funds used during construction
|
(12
|
)
|
|
(21
|
)
|
|
(21
|
)
|
|||
Pension and other postretirement benefits
|
24
|
|
|
28
|
|
|
34
|
|
|||
Unrealized losses on non-qualified benefit plan trust assets
|
2
|
|
|
5
|
|
|
6
|
|
|||
Decoupling mechanism deferrals, net of amortization
|
(22
|
)
|
|
(6
|
)
|
|
14
|
|
|||
Other non-cash income and expenses, net
|
29
|
|
|
7
|
|
|
22
|
|
|||
Changes in working capital:
|
|
|
|
|
|
||||||
(Increase) in receivables and unbilled revenues
|
(3
|
)
|
|
(9
|
)
|
|
(11
|
)
|
|||
(Increase) decrease in margin deposits
|
(3
|
)
|
|
25
|
|
|
(22
|
)
|
|||
Increase in payables and accrued liabilities
|
5
|
|
|
15
|
|
|
6
|
|
|||
Other working capital items, net
|
1
|
|
|
(4
|
)
|
|
(4
|
)
|
|||
Contribution to non-qualified employee benefit trust
|
(8
|
)
|
|
(10
|
)
|
|
(9
|
)
|
|||
Other, net
|
(18
|
)
|
|
(28
|
)
|
|
(12
|
)
|
|||
Net cash provided by operating activities
|
597
|
|
|
553
|
|
|
520
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(514
|
)
|
|
(584
|
)
|
|
(598
|
)
|
|||
Purchases of nuclear decommissioning trust securities
|
(18
|
)
|
|
(25
|
)
|
|
(19
|
)
|
|||
Sales of nuclear decommissioning trust securities
|
21
|
|
|
27
|
|
|
22
|
|
|||
Distribution from nuclear decommissioning trust
|
—
|
|
|
—
|
|
|
50
|
|
|||
Sales tax refund received - Tucannon River Wind Farm
|
—
|
|
|
—
|
|
|
23
|
|
|||
Other, net
|
(3
|
)
|
|
(3
|
)
|
|
—
|
|
|||
Net cash used in investing activities
|
(514
|
)
|
|
(585
|
)
|
|
(522
|
)
|
|||
|
|
|
|
|
|
||||||
See accompanying notes to consolidated financial statements.
|
|||||||||||
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from issuance of long-term debt
|
$
|
225
|
|
|
$
|
290
|
|
|
$
|
145
|
|
Payments on long-term debt
|
(150
|
)
|
|
(133
|
)
|
|
(442
|
)
|
|||
Proceeds from issuances of common stock, net of issuance costs
|
—
|
|
|
—
|
|
|
271
|
|
|||
(Maturities) issuances of commercial paper, net
|
—
|
|
|
(6
|
)
|
|
6
|
|
|||
Dividends paid
|
(118
|
)
|
|
(110
|
)
|
|
(97
|
)
|
|||
Other
|
(7
|
)
|
|
(7
|
)
|
|
(4
|
)
|
|||
Net cash (used in) provided by financing activities
|
(50
|
)
|
|
34
|
|
|
(121
|
)
|
|||
Increase (decrease) in cash and cash equivalents
|
33
|
|
|
2
|
|
|
(123
|
)
|
|||
Cash and cash equivalents, beginning of year
|
6
|
|
|
4
|
|
|
127
|
|
|||
Cash and cash equivalents, end of year
|
$
|
39
|
|
|
$
|
6
|
|
|
$
|
4
|
|
|
|
|
|
|
|
||||||
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
||||||
Cash paid for:
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
|
$
|
110
|
|
|
$
|
104
|
|
|
$
|
108
|
|
Income taxes
|
18
|
|
|
16
|
|
|
3
|
|
|||
Non-cash investing and financing activities:
|
|
|
|
|
|
||||||
Accrued capital additions
|
53
|
|
|
50
|
|
|
32
|
|
|||
Accrued dividends payable
|
31
|
|
|
30
|
|
|
28
|
|
|||
Assets obtained under leasing arrangements
|
87
|
|
|
78
|
|
|
—
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Balance as of beginning of year
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
Increase in provision
|
6
|
|
|
5
|
|
|
6
|
|
|||
Amounts written off, less recoveries
|
(6
|
)
|
|
(5
|
)
|
|
(6
|
)
|
|||
Balance as of end of year
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
|
|
|
|
|
|
Nuclear
Decommissioning Trust
|
|
Non-Qualified Benefit
Plan Trust
|
||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Cash equivalents
|
$
|
25
|
|
|
$
|
21
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Marketable securities, at fair value:
|
|
|
|
|
|
|
|
||||||||
Equity securities
|
—
|
|
|
—
|
|
|
7
|
|
|
6
|
|
||||
Debt securities
|
17
|
|
|
20
|
|
|
1
|
|
|
1
|
|
||||
Insurance contracts, at cash surrender value
|
—
|
|
|
—
|
|
|
28
|
|
|
26
|
|
||||
|
$
|
42
|
|
|
$
|
41
|
|
|
$
|
37
|
|
|
$
|
34
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
Other current assets:
|
|
|
|
||||
Prepaid expenses
|
$
|
50
|
|
|
$
|
48
|
|
Margin deposits
|
11
|
|
|
8
|
|
||
Assets from price risk management activities
|
6
|
|
|
18
|
|
||
Other
|
6
|
|
|
3
|
|
||
|
$
|
73
|
|
|
$
|
77
|
|
Accrued expenses and other current liabilities:
|
|
|
|
||||
Regulatory liabilities—current
|
$
|
31
|
|
|
$
|
51
|
|
Accrued employee compensation and benefits
|
60
|
|
|
52
|
|
||
Accrued dividends payable
|
31
|
|
|
30
|
|
||
Accrued interest payable
|
27
|
|
|
25
|
|
||
Accrued taxes payable
|
31
|
|
|
25
|
|
||
Other
|
61
|
|
|
71
|
|
||
|
$
|
241
|
|
|
$
|
254
|
|
|
|
|
|
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, 2017
|
||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other
(2)
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear decommissioning trust:
(1)
|
|
|
|
|
|
|
|
|
|
||||||||||
Debt securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic government
|
$
|
4
|
|
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11
|
|
Corporate credit
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|||||
Money market funds measured at NAV
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
25
|
|
|||||
Non-qualified benefit plan trust:
(3)
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Equity securities—domestic
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|||||
Debt securities—domestic government
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Investments measured at NAV:
(2)
|
|
|
|
|
|
|
|
|
|
||||||||||
Collective trust—domestic equity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Assets from price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
Natural gas
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
|
$
|
13
|
|
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
25
|
|
|
$
|
57
|
|
Liabilities - Liabilities from price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
130
|
|
|
$
|
—
|
|
|
$
|
135
|
|
Natural gas
|
—
|
|
|
66
|
|
|
9
|
|
|
—
|
|
|
75
|
|
|||||
|
$
|
—
|
|
|
$
|
71
|
|
|
$
|
139
|
|
|
$
|
—
|
|
|
$
|
210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.
|
(2)
|
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
|
(3)
|
Excludes insurance policies of
$28 million
, which are recorded at cash surrender value.
|
(4)
|
For further information, see Note 5, Price Risk Management.
|
|
As of December 31, 2016
|
||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other
(2)
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear decommissioning trust:
(1)
|
|
|
|
|
|
|
|
|
|
||||||||||
Debt securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic government
|
$
|
2
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
12
|
|
Corporate credit
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Money market funds measured at NAV
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
21
|
|
|||||
Non-qualified benefit plan trust:
(3)
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Equity securities—domestic
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|||||
Debt securities—domestic government
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Investments measured at NAV:
(2)
|
|
|
|
|
|
|
|
|
|
||||||||||
Collective trust—domestic equity
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|||||
Assets from price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
—
|
|
|
6
|
|
|
1
|
|
|
—
|
|
|
7
|
|
|||||
Natural gas
|
—
|
|
|
15
|
|
|
1
|
|
|
—
|
|
|
16
|
|
|||||
|
$
|
8
|
|
|
$
|
39
|
|
|
$
|
2
|
|
|
$
|
23
|
|
|
$
|
72
|
|
Liabilities - Liabilities from price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
$
|
—
|
|
|
$
|
6
|
|
|
$
|
112
|
|
|
$
|
—
|
|
|
$
|
118
|
|
Natural gas
|
—
|
|
|
42
|
|
|
9
|
|
|
—
|
|
|
51
|
|
|||||
|
$
|
—
|
|
|
$
|
48
|
|
|
$
|
121
|
|
|
$
|
—
|
|
|
$
|
169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.
|
(2)
|
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
|
(3)
|
Excludes insurance policies of
$26 million
, which are recorded at cash surrender value.
|
(4)
|
For further information, see Note 5, Price Risk Management.
|
|
|
|
|
|
|
|
|
Significant
|
|
Price per Unit
|
||||||||||||||
|
|
Fair Value
|
|
Valuation
|
|
Unobservable
|
|
|
|
|
|
Weighted
|
||||||||||||
Commodity Contracts
|
|
Assets
|
|
Liabilities
|
|
Technique
|
|
Input
|
|
Low
|
|
High
|
|
Average
|
||||||||||
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Electricity physical forward
|
|
$
|
—
|
|
|
$
|
130
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
$
|
7.79
|
|
|
$
|
41.23
|
|
|
$
|
30.95
|
|
Natural gas financial swaps
|
|
—
|
|
|
9
|
|
|
Discounted cash flow
|
|
Natural gas forward price (per Dth)
|
|
1.26
|
|
|
2.92
|
|
|
1.90
|
|
|||||
Electricity financial futures
|
|
—
|
|
|
—
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
7.79
|
|
|
29.74
|
|
|
21.74
|
|
|||||
|
|
$
|
—
|
|
|
$
|
139
|
|
|
|
|
|
|
|
|
|
|
|
||||||
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Electricity physical forward
|
|
$
|
—
|
|
|
$
|
112
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
$
|
14.25
|
|
|
$
|
54.73
|
|
|
$
|
38.18
|
|
Natural gas financial swaps
|
|
1
|
|
|
9
|
|
|
Discounted cash flow
|
|
Natural gas forward price (per Dth)
|
|
1.85
|
|
|
4.92
|
|
|
2.64
|
|
|||||
Electricity financial futures
|
|
1
|
|
|
—
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
8.57
|
|
|
33.60
|
|
|
25.10
|
|
|||||
|
|
$
|
2
|
|
|
$
|
121
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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,
|
||||||
|
2017
|
|
2016
|
||||
Net liabilities from price risk management activities as of beginning of year
|
$
|
119
|
|
|
$
|
119
|
|
Net realized and unrealized losses
*
|
35
|
|
|
11
|
|
||
Net transfers in to Level 3 from Level 2
|
—
|
|
|
(1
|
)
|
||
Net transfers out of Level 3 to Level 2
|
(15
|
)
|
|
(10
|
)
|
||
Net liabilities from price risk management activities as of end of year
|
$
|
139
|
|
|
$
|
119
|
|
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting
|
$
|
41
|
|
|
$
|
11
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
||||||
|
2017
|
|
2016
|
|
||||
Current assets:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
$
|
3
|
|
|
$
|
6
|
|
|
Natural gas
|
3
|
|
|
12
|
|
|
||
Total current derivative assets
|
6
|
|
(1)
|
18
|
|
(1)
|
||
Noncurrent assets:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
—
|
|
|
1
|
|
|
||
Natural gas
|
—
|
|
|
4
|
|
|
||
Total noncurrent derivative assets
|
—
|
|
(2)
|
5
|
|
(2)
|
||
Total derivative assets not designated as hedging instruments
|
$
|
6
|
|
|
$
|
23
|
|
|
Total derivative assets
|
$
|
6
|
|
|
$
|
23
|
|
|
Current liabilities:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
$
|
13
|
|
|
$
|
12
|
|
|
Natural gas
|
46
|
|
|
32
|
|
|
||
Total current derivative liabilities
|
59
|
|
|
44
|
|
|
||
Noncurrent liabilities:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
122
|
|
|
106
|
|
|
||
Natural gas
|
29
|
|
|
19
|
|
|
||
Total noncurrent derivative liabilities
|
151
|
|
|
125
|
|
|
||
Total derivative liabilities not designated as hedging instruments
|
$
|
210
|
|
|
$
|
169
|
|
|
Total derivative liabilities
|
$
|
210
|
|
|
$
|
169
|
|
|
|
|
|
|
|
(1)
|
Included in Other current assets on the consolidated balance sheets.
|
(2)
|
Included in Other noncurrent assets on the consolidated balance sheets.
|
|
As of December 31,
|
||||||||||
|
2017
|
|
2016
|
||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
||||
Electricity
|
7
|
|
|
MWh
|
|
8
|
|
|
MWh
|
||
Natural gas
|
114
|
|
|
Dth
|
|
107
|
|
|
Dth
|
||
Foreign currency exchange
|
$
|
21
|
|
|
Canadian
|
|
$
|
22
|
|
|
Canadian
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Commodity contracts:
|
|
|
|
|
|
||||||
Electricity
|
$
|
41
|
|
|
$
|
34
|
|
|
$
|
72
|
|
Natural Gas
|
85
|
|
|
(56
|
)
|
|
103
|
|
|||
Foreign currency exchange
|
(1
|
)
|
|
—
|
|
|
1
|
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
||||||||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity
|
$
|
10
|
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
7
|
|
|
$
|
91
|
|
|
$
|
132
|
|
Natural gas
|
43
|
|
|
20
|
|
|
7
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
72
|
|
|||||||
Net unrealized loss
|
$
|
53
|
|
|
$
|
28
|
|
|
$
|
15
|
|
|
$
|
10
|
|
|
$
|
7
|
|
|
$
|
91
|
|
|
$
|
204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||
|
2017
|
|
2016
|
||
Assets from price risk management activities:
|
|
|
|
||
Counterparty A
|
39
|
%
|
|
22
|
%
|
Counterparty B
|
12
|
|
|
17
|
|
Counterparty C
|
3
|
|
|
12
|
|
|
54
|
%
|
|
51
|
%
|
Liabilities from price risk management activities:
|
|
|
|
||
Counterparty D
|
62
|
%
|
|
66
|
%
|
|
62
|
%
|
|
66
|
%
|
|
Weighted Average Remaining
Life
(1)
|
|
As of December 31,
|
||||||||||||||
|
2017
|
|
2016
|
||||||||||||||
|
Current
|
|
Noncurrent
|
|
Current
|
|
Noncurrent
|
||||||||||
Regulatory assets:
|
|
|
|
|
|
|
|
|
|
||||||||
Price risk management
(2)
|
6 years
|
|
$
|
53
|
|
|
$
|
151
|
|
|
$
|
26
|
|
|
$
|
120
|
|
Pension and other postretirement plans
(2)
|
(3)
|
|
—
|
|
|
218
|
|
|
—
|
|
|
235
|
|
||||
Deferred income taxes
(6)
|
(4)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
86
|
|
||||
Debt issuance costs
(2)
|
6 years
|
|
—
|
|
|
19
|
|
|
—
|
|
|
22
|
|
||||
Other
(5)
|
Various
|
|
9
|
|
|
50
|
|
|
10
|
|
|
35
|
|
||||
Total regulatory assets
|
|
|
$
|
62
|
|
|
$
|
438
|
|
|
$
|
36
|
|
|
$
|
498
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||
Asset retirement removal costs
(6)
|
(4)
|
|
$
|
—
|
|
|
$
|
933
|
|
|
$
|
—
|
|
|
$
|
887
|
|
Deferred income taxes
(6)
|
(4)
|
|
—
|
|
|
277
|
|
|
—
|
|
|
—
|
|
||||
Trojan decommissioning activities
|
5 years
|
|
3
|
|
|
—
|
|
|
18
|
|
|
—
|
|
||||
Asset retirement obligations
(6)
|
(4)
|
|
—
|
|
|
52
|
|
|
—
|
|
|
49
|
|
||||
Other
|
Various
|
|
28
|
|
|
26
|
|
|
33
|
|
|
22
|
|
||||
Total regulatory liabilities
|
|
|
$
|
31
|
|
(7)
|
$
|
1,288
|
|
|
$
|
51
|
|
(7)
|
$
|
958
|
|
|
|
|
|
|
(1)
|
As of
December 31, 2017
.
|
(2)
|
Does not include a return on investment.
|
(3)
|
Recovery expected over the average service life of employees.
|
(4)
|
Recovery or refund expected over the estimated lives of the net balance.
|
(5)
|
Of the total other unamortized regulatory asset balances, a return is recorded on
$51 million
and
$44 million
as of
December 31, 2017
and
2016
, respectively.
|
(6)
|
Included in rate base for ratemaking purposes.
|
(7)
|
Included in Accrued expenses and other current liabilities on the consolidated balance sheets.
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
Trojan decommissioning activities
|
$
|
45
|
|
|
$
|
44
|
|
Utility plant
|
109
|
|
|
105
|
|
||
Non-utility property
|
13
|
|
|
12
|
|
||
Asset retirement obligations
|
$
|
167
|
|
|
$
|
161
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Balance as of beginning of year
|
$
|
161
|
|
|
$
|
151
|
|
|
$
|
116
|
|
Liabilities incurred
|
2
|
|
|
1
|
|
|
2
|
|
|||
Liabilities settled
|
(3
|
)
|
|
(3
|
)
|
|
(4
|
)
|
|||
Accretion expense
|
7
|
|
|
7
|
|
|
7
|
|
|||
Revisions in estimated cash flows
|
—
|
|
|
5
|
|
|
30
|
|
|||
Balance as of end of year
|
$
|
167
|
|
|
$
|
161
|
|
|
$
|
151
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Average daily amount of short-term debt outstanding
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
Weighted daily average interest rate *
|
—
|
%
|
|
0.7
|
%
|
|
0.6
|
%
|
|||
Maximum amount outstanding during the year
|
$
|
—
|
|
|
$
|
23
|
|
|
$
|
11
|
|
|
|
|
|
|
*
|
Excludes the effect of commitment fees, facility fees and other financing fees.
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
First Mortgage Bonds
, rates range from 2.51% to 9.31%, with a weighted average rate of 5.03% in 2017 and 4.86% in 2016, due at various dates through 2048
|
$
|
2,315
|
|
|
$
|
2,090
|
|
Unsecured term bank loans
, variable rates of approximately 1.87%
at 11/27/2017 and 1.37% at 12/31/2016
|
—
|
|
|
150
|
|
||
Pollution Control Revenue Bonds
, 5% rate, due 2033
|
142
|
|
|
142
|
|
||
Pollution Control Revenue Bonds owned by PGE
|
(21
|
)
|
|
(21
|
)
|
||
Total long-term debt
|
2,436
|
|
|
2,361
|
|
||
Less: Unamortized debt expense
|
(10
|
)
|
|
(11
|
)
|
||
Less: Current portion of long-term debt
|
—
|
|
|
(150
|
)
|
||
Long-term debt, net of current portion
|
$
|
2,426
|
|
|
$
|
2,200
|
|
|
|
|
|
•
|
$50 million
on August 21, 2017;
|
•
|
$25 million
on October 30, 2017; and
|
•
|
$75 million
on November 27, 2017.
|
Years ending December 31:
|
|
|
||
2018
|
|
$
|
—
|
|
2019
|
|
300
|
|
|
2020
|
|
—
|
|
|
2021
|
|
160
|
|
|
2022
|
|
—
|
|
|
Thereafter
|
|
1,976
|
|
|
|
|
$
|
2,436
|
|
|
|
|
|
2017
|
|
2016
|
||||||||||||||||||||
|
NQBP
|
|
Other NQBP
|
|
Total
|
|
NQBP
|
|
Other NQBP
|
|
Total
|
||||||||||||
Non-qualified benefit plan trust
|
$
|
17
|
|
|
$
|
20
|
|
|
$
|
37
|
|
|
$
|
16
|
|
|
$
|
18
|
|
|
$
|
34
|
|
Non-qualified benefit plan liabilities *
|
25
|
|
|
81
|
|
|
106
|
|
|
25
|
|
|
80
|
|
|
105
|
|
|
|
|
|
|
*
|
For the NQBP, excludes the current portion of
$2 million
in
2017
and
2016
, respectively, which are classified in Other current liabilities in the consolidated balance sheets.
|
|
As of December 31,
|
||||||||||
|
2017
|
|
2016
|
||||||||
|
Actual
|
|
Target *
|
|
Actual
|
|
Target *
|
||||
Defined Benefit Pension Plan:
|
|
|
|
|
|
|
|
||||
Equity securities
|
68
|
%
|
|
67
|
%
|
|
68
|
%
|
|
67
|
%
|
Debt securities
|
32
|
|
|
33
|
|
|
32
|
|
|
33
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
Other Postretirement Benefit Plans:
|
|
|
|
|
|
|
|
||||
Equity securities
|
63
|
%
|
|
62
|
%
|
|
60
|
%
|
|
62
|
%
|
Debt securities
|
37
|
|
|
38
|
|
|
40
|
|
|
38
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
Non-Qualified Benefits Plans:
|
|
|
|
|
|
|
|
||||
Equity securities
|
18
|
%
|
|
12
|
%
|
|
15
|
%
|
|
11
|
%
|
Debt securities
|
6
|
|
|
12
|
|
|
7
|
|
|
11
|
|
Insurance contracts
|
76
|
|
|
76
|
|
|
78
|
|
|
78
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
|
|
|
|
*
|
The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the NQBP, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and NQBP, reported percentages are affected by the fair market values of the investments within the pools.
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other *
|
|
Total
|
||||||||||
As of December 31, 2017:
|
|
|
|
|
|
|
|
|
|
||||||||||
Defined Benefit Pension Plan assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity securities—Domestic
|
$
|
83
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
83
|
|
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
528
|
|
|
528
|
|
|||||
Private equity funds
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
|||||
|
$
|
83
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
546
|
|
|
$
|
629
|
|
Other Postretirement Benefit Plans assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
International
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|||||
Debt securities—Domestic government
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|||||
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
8
|
|
|||||
|
$
|
13
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
12
|
|
|
$
|
33
|
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
||||||||||
Defined Benefit Pension Plan assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity securities—Domestic
|
$
|
52
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
52
|
|
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
483
|
|
|
483
|
|
|||||
Private equity funds
|
—
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
18
|
|
|||||
|
$
|
52
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
507
|
|
|
$
|
559
|
|
Other Postretirement Benefit Plans assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
International
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Debt securities—Domestic government
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|||||
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|||||
Collective trust funds
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
12
|
|
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
11
|
|
|
$
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
|
|
Defined Benefit Pension Plan
|
|
Other Postretirement
Benefits
|
|
|
Non-Qualified
Benefit Plans
|
|||||||||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
2016
|
||||||||||||
Benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of January 1
|
$
|
797
|
|
|
$
|
758
|
|
|
$
|
73
|
|
|
|
$
|
81
|
|
|
|
$
|
27
|
|
|
$
|
27
|
|
Service cost
|
17
|
|
|
16
|
|
|
2
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||||
Interest cost
|
33
|
|
|
33
|
|
|
3
|
|
|
|
4
|
|
|
|
1
|
|
|
1
|
|
||||||
Participants’ contributions
|
—
|
|
|
—
|
|
|
2
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||||
Actuarial loss (gain)
|
60
|
|
|
26
|
|
|
3
|
|
|
|
(11
|
)
|
|
|
1
|
|
|
1
|
|
||||||
Contractual termination benefits
|
—
|
|
|
—
|
|
|
1
|
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||||
Benefit payments
|
(36
|
)
|
|
(34
|
)
|
|
(6
|
)
|
|
|
(5
|
)
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||
Administrative expenses
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||||
As of December 31
|
$
|
869
|
|
|
$
|
797
|
|
|
$
|
78
|
|
|
|
$
|
73
|
|
|
|
$
|
27
|
|
|
$
|
27
|
|
Fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of January 1
|
$
|
559
|
|
|
$
|
550
|
|
|
$
|
30
|
|
|
|
$
|
30
|
|
|
|
$
|
16
|
|
|
$
|
15
|
|
Actual return on plan assets
|
106
|
|
|
45
|
|
|
4
|
|
|
|
1
|
|
|
|
1
|
|
|
1
|
|
||||||
Company contributions
|
2
|
|
|
—
|
|
|
3
|
|
|
|
2
|
|
|
|
2
|
|
|
2
|
|
||||||
Participants’ contributions
|
—
|
|
|
—
|
|
|
2
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||||
Benefit payments
|
(36
|
)
|
|
(34
|
)
|
|
(6
|
)
|
|
|
(5
|
)
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||
Administrative expenses
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||||
As of December 31
|
$
|
629
|
|
|
$
|
559
|
|
|
$
|
33
|
|
|
|
$
|
30
|
|
|
|
$
|
17
|
|
|
$
|
16
|
|
Unfunded position as of December 31
|
$
|
(240
|
)
|
|
$
|
(238
|
)
|
|
$
|
(45
|
)
|
|
|
$
|
(43
|
)
|
|
|
$
|
(10
|
)
|
|
$
|
(11
|
)
|
Accumulated benefit plan obligation as of December 31
|
$
|
778
|
|
|
$
|
714
|
|
|
N/A
|
|
|
N/A
|
|
|
$
|
27
|
|
|
$
|
27
|
|
||||
Classification in consolidated balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Noncurrent asset
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
17
|
|
|
$
|
16
|
|
Current liability
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||
Noncurrent liability
|
(240
|
)
|
|
(238
|
)
|
|
(45
|
)
|
|
|
(43
|
)
|
|
|
(25
|
)
|
|
(25
|
)
|
||||||
Net liability
|
$
|
(240
|
)
|
|
$
|
(238
|
)
|
|
$
|
(45
|
)
|
|
|
$
|
(43
|
)
|
|
|
$
|
(10
|
)
|
|
$
|
(11
|
)
|
Amounts included in comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial loss (gain)
|
$
|
(4
|
)
|
|
$
|
21
|
|
|
$
|
—
|
|
|
|
$
|
(10
|
)
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Amortization of net actuarial loss
|
(13
|
)
|
|
(14
|
)
|
|
—
|
|
|
|
—
|
|
|
|
(1
|
)
|
|
(1
|
)
|
||||||
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(1
|
)
|
|
|
—
|
|
|
—
|
|
||||||
|
$
|
(17
|
)
|
|
$
|
7
|
|
|
$
|
—
|
|
|
|
$
|
(11
|
)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Amounts included in AOCL*:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial loss (gain)
|
$
|
218
|
|
|
$
|
236
|
|
|
$
|
(1
|
)
|
|
|
$
|
(2
|
)
|
|
|
$
|
13
|
|
|
$
|
13
|
|
Prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
|
1
|
|
|
|
—
|
|
|
—
|
|
||||||
|
$
|
218
|
|
|
$
|
236
|
|
|
$
|
(1
|
)
|
|
|
$
|
(1
|
)
|
|
|
$
|
13
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit Pension Plan
|
|
Other Postretirement
Benefits
|
|
|
Non-Qualified
Benefit Plans
|
|||||||||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
2016
|
||||||||||||
Assumptions used:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Discount rate for benefit obligation
|
3.65
|
%
|
|
4.17
|
%
|
|
3.42
|
%
|
-
|
|
3.75
|
%
|
-
|
|
3.65
|
%
|
|
4.17
|
%
|
||||||
|
|
|
|
|
3.70
|
%
|
|
|
4.23
|
%
|
|
|
|
|
|
||||||||||
Discount rate for benefit cost
|
4.17
|
%
|
|
4.36
|
%
|
|
3.75
|
%
|
-
|
|
3.90
|
%
|
-
|
|
4.17
|
%
|
|
4.36
|
%
|
||||||
|
|
|
|
|
4.23
|
%
|
|
|
4.45
|
%
|
|
|
|
|
|
||||||||||
Weighted average rate of compensation increase for benefit obligation
|
4.58
|
%
|
|
3.65
|
%
|
|
4.58
|
%
|
|
|
4.58
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
Weighted average rate of compensation increase for benefit cost
|
3.65
|
%
|
|
3.65
|
%
|
|
4.58
|
%
|
|
|
4.58
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
Long-term rate of return on plan assets for benefit obligation
|
7.50
|
%
|
|
7.50
|
%
|
|
6.26
|
%
|
|
|
6.26
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
Long-term rate of return on plan assets for benefit cost
|
7.50
|
%
|
|
7.50
|
%
|
|
6.26
|
%
|
|
|
6.29
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit
Pension Plan
|
|
Other Postretirement
Benefits
|
|
Non-Qualified
Benefit Plans
|
||||||||||||||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||||||||
Service cost
|
$
|
17
|
|
|
$
|
16
|
|
|
$
|
18
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest cost on benefit obligation
|
33
|
|
|
33
|
|
|
31
|
|
|
3
|
|
|
4
|
|
|
3
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|||||||||
Expected return on plan assets
|
(42
|
)
|
|
(40
|
)
|
|
(40
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Amortization of net actuarial loss
|
13
|
|
|
14
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|||||||||
Net periodic benefit cost
|
$
|
21
|
|
|
$
|
23
|
|
|
$
|
29
|
|
|
$
|
3
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due
|
||||||||||||||||||||||
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023 - 2026
|
||||||||||||
Defined benefit pension plan
|
$
|
39
|
|
|
$
|
41
|
|
|
$
|
42
|
|
|
$
|
43
|
|
|
$
|
44
|
|
|
$
|
234
|
|
Other postretirement benefits
|
5
|
|
|
5
|
|
|
5
|
|
|
4
|
|
|
5
|
|
|
22
|
|
||||||
Non-qualified benefit plans
|
2
|
|
|
3
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
10
|
|
||||||
Total
|
$
|
46
|
|
|
$
|
49
|
|
|
$
|
49
|
|
|
$
|
49
|
|
|
$
|
51
|
|
|
$
|
266
|
|
•
|
For
2017
,
6.5%
annual rate of increase in the per capita cost of covered health care benefits was assumed for
2018
, decreasing to
6.0%
in 2019, then decreasing
0.25%
per year thereafter, reaching
5.0%
in 2023;
|
•
|
For
2016
,
7%
annual rate of increase in the per capita cost of covered health care benefits was assumed for
2017
, decreasing to
6.5%
in 2018, then decreasing
0.25%
per year thereafter, reaching
5.0%
in 2023; and
|
•
|
For
2015
,
6.5%
annual rate of increase in the per capita cost of covered health care benefits was assumed for
2016
, decreasing to
6.0%
in 2017, then decreasing
0.25%
per year thereafter, reaching
5.0%
in 2021.
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
4
|
|
|
$
|
10
|
|
|
$
|
4
|
|
State and local
|
12
|
|
|
3
|
|
|
1
|
|
|||
|
16
|
|
|
13
|
|
|
5
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
61
|
|
|
23
|
|
|
26
|
|
|||
State and local
|
9
|
|
|
14
|
|
|
14
|
|
|||
|
70
|
|
|
37
|
|
|
40
|
|
|||
Income tax expense
|
$
|
86
|
|
|
$
|
50
|
|
|
$
|
45
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
Federal statutory tax rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
Federal tax credits
(1)
|
(14.0
|
)
|
|
(18.2
|
)
|
|
(19.0
|
)
|
Change in federal tax law
(2)
|
6.1
|
|
|
—
|
|
|
—
|
|
State and local taxes, net of federal tax benefit
|
5.0
|
|
|
4.8
|
|
|
4.2
|
|
Flow through depreciation and cost basis differences
|
1.5
|
|
|
0.2
|
|
|
—
|
|
Other
|
(2.1
|
)
|
|
(1.2
|
)
|
|
0.5
|
|
Effective tax rate
|
31.5
|
%
|
|
20.6
|
%
|
|
20.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in service dates. PGE’s PTC generation ends
at various dates between 2017 and 2024.
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
Deferred income tax assets:
|
|
|
|
||||
Employee benefits
|
$
|
128
|
|
|
$
|
181
|
|
Price risk management
|
56
|
|
|
59
|
|
||
Regulatory liabilities
|
14
|
|
|
29
|
|
||
Tax credits
|
50
|
|
|
56
|
|
||
Other
|
4
|
|
|
5
|
|
||
Total deferred income tax assets
|
252
|
|
|
330
|
|
||
Deferred income tax liabilities:
|
|
|
|
||||
Depreciation and amortization
|
496
|
|
|
829
|
|
||
Regulatory assets
|
132
|
|
|
170
|
|
||
Other
|
—
|
|
|
—
|
|
||
Total deferred income tax liabilities
|
628
|
|
|
999
|
|
||
Deferred income tax liability, net
|
$
|
(376
|
)
|
|
$
|
(669
|
)
|
|
Units
|
|
Weighted Average
Grant Date
Fair Value
|
|||
Outstanding as of December 31, 2014
|
463,893
|
|
|
$
|
28.96
|
|
Granted
|
181,797
|
|
|
34.77
|
|
|
Forfeited
|
(14,988
|
)
|
|
34.10
|
|
|
Vested
|
(187,709
|
)
|
|
25.82
|
|
|
Outstanding as of December 31, 2015
|
442,993
|
|
|
32.84
|
|
|
Granted
|
193,734
|
|
|
35.89
|
|
|
Forfeited
|
(3,044
|
)
|
|
28.62
|
|
|
Vested
|
(174,891
|
)
|
|
31.47
|
|
|
Outstanding as of December 31, 2016
|
458,792
|
|
|
34.68
|
|
|
Granted
|
202,145
|
|
|
41.96
|
|
|
Forfeited
|
(64,840
|
)
|
|
39.57
|
|
|
Vested
|
(196,721
|
)
|
|
31.78
|
|
|
Outstanding as of December 31, 2017
|
399,376
|
|
|
37.98
|
|
|
Years Ended December 31,
|
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
Weighted average common shares outstanding—basic
|
89,056
|
|
|
88,896
|
|
|
84,180
|
|
Dilutive effect of potential common shares
|
120
|
|
|
158
|
|
|
161
|
|
Weighted average common shares outstanding—diluted
|
89,176
|
|
|
89,054
|
|
|
84,341
|
|
|
Payments Due
|
||||||||||||||||||||||||||
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
||||||||||||||
Capital and other purchase commitments
|
$
|
191
|
|
|
$
|
2
|
|
|
$
|
10
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
58
|
|
|
$
|
265
|
|
Purchased power and fuel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity purchases
|
156
|
|
|
156
|
|
|
201
|
|
|
200
|
|
|
187
|
|
|
1,733
|
|
|
2,633
|
|
|||||||
Capacity contracts
|
6
|
|
|
5
|
|
|
4
|
|
|
4
|
|
|
4
|
|
|
8
|
|
|
31
|
|
|||||||
Public utility districts
|
9
|
|
|
17
|
|
|
16
|
|
|
16
|
|
|
15
|
|
|
85
|
|
|
158
|
|
|||||||
Natural gas
|
51
|
|
|
35
|
|
|
28
|
|
|
25
|
|
|
24
|
|
|
140
|
|
|
303
|
|
|||||||
Coal and transportation
|
15
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|||||||
Total
|
$
|
428
|
|
|
$
|
220
|
|
|
$
|
259
|
|
|
$
|
247
|
|
|
$
|
232
|
|
|
$
|
2,024
|
|
|
$
|
3,410
|
|
|
Revenue Bonds as of December 31, 2017
|
|
PGE’s Share as of December 31, 2017
|
|
Contract
Expiration
|
|
PGE Cost,
including Debt Service
|
||||||||||||||||
|
Output
|
|
Capacity
|
|
|
2017
|
|
2016
|
|
2015
|
|||||||||||||
|
|
|
|
|
(in MW)
|
|
|
|
|
|
|
|
|
||||||||||
Priest Rapids and Wanapum
|
$
|
1,269
|
|
|
8.6
|
%
|
|
163
|
|
|
2052
|
|
$
|
16
|
|
|
$
|
16
|
|
|
$
|
18
|
|
Wells
|
160
|
|
|
19.4
|
|
|
150
|
|
|
2018
|
|
11
|
|
|
10
|
|
|
10
|
|
||||
Portland Hydro
|
—
|
|
|
—
|
|
|
—
|
|
|
2017
|
|
1
|
|
|
1
|
|
|
2
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Minimum Lease Payments
|
||||||||||
|
Capital Leases
|
|
Build-to-Suit
|
|
Operating Leases
|
||||||
2018
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
9
|
|
2019
|
6
|
|
|
15
|
|
|
8
|
|
|||
2020
|
6
|
|
|
15
|
|
|
6
|
|
|||
2021
|
6
|
|
|
14
|
|
|
6
|
|
|||
2022
|
5
|
|
|
14
|
|
|
8
|
|
|||
Thereafter
|
72
|
|
|
260
|
|
|
165
|
|
|||
Total minimum lease payments
|
$
|
102
|
|
|
$
|
318
|
|
|
$
|
202
|
|
Less imputed interest
|
51
|
|
|
|
|
|
|||||
Present value of net minimum lease payments
|
$
|
51
|
|
|
|
|
|
||||
Less current portion
|
2
|
|
|
|
|
|
|||||
Non-current portion
|
$
|
49
|
|
|
|
|
|
|
PGE
Share
|
|
In-service Date
|
|
Plant
In-service
|
|
Accumulated
Depreciation*
|
|
Construction
Work In
Progress
|
|||||||||
Boardman
|
90.00
|
%
|
|
1980
|
|
$
|
515
|
|
|
$
|
426
|
|
|
$
|
—
|
|
||
Colstrip
|
20.00
|
|
|
1986
|
|
546
|
|
|
351
|
|
|
5
|
|
|||||
Pelton/Round Butte
|
66.67
|
|
|
1958
|
/
|
1964
|
|
251
|
|
|
68
|
|
|
7
|
|
|||
Total
|
|
|
|
|
|
|
$
|
1,312
|
|
|
$
|
845
|
|
|
$
|
12
|
|
|
|
|
|
|
*
|
Excludes AROs and accumulated asset retirement removal costs.
|
•
|
A breach of contract claim dated March 23, 2016, Portland General Electric Company v. Liberty Mutual Insurance Company and Zurich American Insurance Company, U.S. District Court of the District of Oregon, brought by PGE against the Sureties in U.S. District Court asserting that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Contractor’s breach of contract. The Company’s complaint disputes the Sureties’ assertion that the Company wrongfully terminated the Construction Agreement and asserts that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Sureties’ breach of contract, including damages in excess of the
$145.6 million
stated amount of the Performance Bond. Such damages include additional costs incurred by PGE to complete Carty.
|
•
|
A claim dated October 21, 2016, Portland General Electric Company v. Abeinsa EPC LLC, Abener Construction Services, LLC (formerly known as Abener Engineering and Construction Services, LLC), Teyma Construction USA LLC, and Abeinsa Abener Teyma General Partnership, U.S. District Court of the District of Oregon, brought by PGE in U.S. District Court against the Contractor for failure to satisfy its obligations under the Construction Agreement. PGE is seeking damages from the Contractor in excess of
$200 million
for: i) costs incurred to complete construction of Carty, settle claims with unpaid contractors and vendors, and remove liens; and ii) damages in excess of the construction costs, including a project management fee, liquidated damages under the Construction Agreement, legal fees and costs, damages due to delay of the project, warranty costs, and interest.
|
•
|
A claim dated December 31, 2015, In the Matter of an Arbitration Under the Rules of the International Chamber of Commerce’s Court of Arbitration, International Chamber of Commerce’s Court of Arbitration, by Abengoa S.A. in the ICC arbitration proceeding alleging that the Company’s termination of the Construction Agreement was wrongful and in breach of the terms of the agreement and did not give rise to any liability of Abengoa S.A.; and
|
•
|
A claim by the Contractor against PGE in the ICC arbitration proceeding seeking damages of
$117 million
based on a claim that PGE wrongfully terminated the Construction Agreement and
$44 million
based on a claim that PGE failed to disclose certain information to the Contractor, in connection with the Contractor’s bid submitted pursuant to the Company’s request for proposals.
|
|
Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
(In millions, except per share amounts)
|
||||||||||||||
2017
|
|
|
|
|
|
|
|
||||||||
Revenues, net
|
$
|
530
|
|
|
$
|
449
|
|
|
$
|
515
|
|
|
$
|
515
|
|
Income from operations
|
123
|
|
|
68
|
|
|
77
|
|
|
108
|
|
||||
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
|
|
||||
2016
|
|
|
|
|
|
|
|
||||||||
Revenues, net
|
$
|
487
|
|
|
$
|
428
|
|
|
$
|
484
|
|
|
$
|
524
|
|
Income from operations
|
99
|
|
|
64
|
|
|
64
|
|
|
106
|
|
||||
Net income
|
61
|
|
|
37
|
|
|
34
|
|
|
61
|
|
||||
Earnings per share:
*
|
|
|
|
|
|
|
|
||||||||
Basic
|
0.68
|
|
|
0.42
|
|
|
0.38
|
|
|
0.68
|
|
||||
Diluted
|
0.68
|
|
|
0.42
|
|
|
0.38
|
|
|
0.68
|
|
|
|
|
|
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
|
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*
|
|
|
|
Exhibit
Number
|
Description
|
10.11*
|
|
10.12*
|
|
10.13*
|
|
10.14*
|
|
10.15*
|
|
10.16*
|
|
10.17*
|
|
10.18*
|
|
(12)
|
Statements Re Computation of Ratios
|
12.1
|
|
(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
|
ADMINISTRATIVE AGENT:
|
WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent
|
PORTLAND GENERAL ELECTRIC COMPANY
|
|||||||||||||||||||
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
|
|||||||||||||||||||
(Dollars in thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Years Ended December 31,
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from continuing operations before income taxes
|
$
|
273,085
|
|
|
$
|
243,108
|
|
|
$
|
216,818
|
|
|
$
|
236,679
|
|
|
$
|
125,758
|
|
Total fixed charges
|
137,124
|
|
|
132,654
|
|
|
135,956
|
|
|
128,515
|
|
|
118,189
|
|
|||||
Total earnings
|
$
|
410,209
|
|
|
$
|
375,762
|
|
|
$
|
352,774
|
|
|
$
|
365,194
|
|
|
$
|
243,947
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
$
|
119,636
|
|
|
$
|
111,539
|
|
|
$
|
113,861
|
|
|
$
|
96,068
|
|
|
$
|
100,818
|
|
Capitalized interest
|
6,001
|
|
|
10,820
|
|
|
12,520
|
|
|
22,441
|
|
|
6,892
|
|
|||||
Interest on certain long-term power contracts
|
5,311
|
|
|
4,946
|
|
|
5,140
|
|
|
5,137
|
|
|
5,996
|
|
|||||
Estimated interest factor in rental expense
|
6,176
|
|
|
5,349
|
|
|
4,435
|
|
|
4,869
|
|
|
4,483
|
|
|||||
Total fixed charges
|
$
|
137,124
|
|
|
$
|
132,654
|
|
|
$
|
135,956
|
|
|
$
|
128,515
|
|
|
$
|
118,189
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
2.99
|
|
|
2.83
|
|
|
2.59
|
|
|
2.84
|
|
|
2.06
|
|
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 15, 2018
|
|
/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 15, 2018
|
|
/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 15, 2018
|
|
Date:
February 15, 2018
|