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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[ ]
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Smaller reporting company
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[ ]
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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 26, 2017.
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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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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. PGE plans to file a general rate case for the 2018 test year (2018 GRC) with the OPUC by the end of February
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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 the Company’s net variable power costs (NVPC), which consist of the cost of purchased power and fuel used in generation (including related transportation costs) less revenues from wholesale power and fuel sales:
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◦
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Annual Power Cost Update Tariff (AUT). Under this tariff, customer prices are adjusted annually to reflect the latest forecast of NVPC. An initial NVPC forecast, submitted to the OPUC by April 1st 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. To the extent actual annual NVPC, subject to certain adjustments, is above or below the deadband, which is a defined range from $30 million above to $15 million below baseline NVPC, the PCAM provides for 90% of the variance beyond the deadband to be collected from or refunded to customers, respectively, subject to a regulated earnings test. A final determination of any customer collection or refund is made by the OPUC through a public filing and review, typically during the second half of the following year. Any estimated collection from customers pursuant to the PCAM is recorded as a reduction in Purchased power and fuel expense in the Company’s consolidated statements of income, while any estimated refund to customers is recorded as a reduction in Revenues, net. 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.” During the past three years, the Company has recorded no refunds or collections as a result of the PCAM.
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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, recently extended by the OPUC through 2019, provides for: i) collections from customers if weather adjusted energy use per customer is lower than levels anticipated in the Company’s most recent general rate case; or ii) refunds to customers if weather adjusted use per customer exceeds levels anticipated in the most recent general rate case. For additional information, see
“Customers and Demand”
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 Act) established a Renewable Portfolio Standard (RPS), which required that PGE initially serve at least 5% of its retail load with renewable resources by 2011, with future requirements of 15% by 2015, 20% by 2020, and 25% by 2025. PGE met the 2011 and 2015 requirements and expects to meet requirements going forward.
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meet RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
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limit the life of RECs generated from facilities that become operational after 2022 to five years, but maintain the unlimited lifespan of all existing RECs and allow for the generation of additional unlimited RECs for a period of five years for projects on line before December 31, 2022;
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include projected production tax credits (PTCs) in prices through any variable power cost forecasting process established by the OPUC, the first of which applied to the AUT filing for 2017; and
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include energy storage costs in its RAC filings.
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Years Ended December 31,
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2016
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2015
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2014
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Retail revenues
(1)
(dollars in millions):
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Residential
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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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$
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893
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51
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%
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Commercial
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665
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37
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662
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37
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657
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36
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Industrial
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208
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12
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228
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13
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221
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13
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Subtotal
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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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1,771
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100
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Other accrued (deferred) revenues, net
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3
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—
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(10
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—
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(8
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—
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Total retail revenues
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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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$
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1,763
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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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7,348
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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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7,462
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39
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%
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Commercial
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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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7,494
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39
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Industrial
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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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4,310
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22
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Total retail energy deliveries
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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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19,266
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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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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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735,502
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87
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%
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Commercial
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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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105,231
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13
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Industrial
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258
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—
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255
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—
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260
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—
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Total
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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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840,993
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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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2016
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2015
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2014
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Residential
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Revenue per customer (in dollars):
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$
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1,114
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$
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1,139
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$
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1,154
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Usage per customer (in kilowatt hours):
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9,766
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9,866
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10,145
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Revenue per kilowatt hour (in cents):
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11.40
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¢
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11.55
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¢
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11.37
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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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6,166
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$
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6,254
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$
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6,187
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Usage per customer (in kilowatt hours):
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69,839
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70,987
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71,216
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Revenue per kilowatt hour (in cents):
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8.83
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¢
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8.81
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¢
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8.69
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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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804,953
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$
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876,866
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$
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851,149
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Usage per customer (in kilowatt hours):
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16,146,371
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17,485,281
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16,576,500
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Revenue per kilowatt hour (in cents):
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4.99
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¢
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5.01
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¢
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5.13
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¢
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Heating
Degree-Days
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Cooling
Degree-Days
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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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2014
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3,794
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653
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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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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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2014
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2,574
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3,866
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February
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2,358
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3,646
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August
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As of December 31,
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2016
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2015
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2014
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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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1,805
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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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1,389
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28
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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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2,619
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55
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2,185
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47
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2,203
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45
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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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16
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717
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15
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Hydro
(2)
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495
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11
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495
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11
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494
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10
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Total generation
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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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3,414
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70
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Purchased power:
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Long-term contracts:
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Capacity/exchange
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250
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5
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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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534
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12
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592
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13
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595
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12
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Wind
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39
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1
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39
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1
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39
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1
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Solar
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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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118
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3
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118
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2
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Total long-term contracts
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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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1,015
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20
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Short-term contracts
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45
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1
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200
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4
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481
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10
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Total purchased power
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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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1,496
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|
30
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Total resource capacity
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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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4,910
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|
100
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%
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(1)
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Capacity represents nameplate and differs from expected energy to be generated, which is expected to range from 215 MWa to 290 MWa, dependent upon wind conditions.
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(2)
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Capacity represents net capacity and differs from expected energy to be generated, which is expected to range from 200 MWa to 250 MWa, dependent upon river flows.
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Thermal
|
The Company has five natural gas-fired generating facilities: PW1, PW2, Beaver, Coyote Springs Unit 1 (Coyote Springs), and Carty. These natural gas-fired generating plants provided approximately
32%
of PGE’s total retail load requirement in
2016
,
25%
in
2015
, and
18%
2014
.
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Wind
|
PGE owns and operates two wind farms, Biglow Canyon Wind Farm (Biglow Canyon) and 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
2016
,
8%
in
2015
, and
9%
in
2014
, with availability of
99%
in both
2016
and
2015
, and
100%
in
2014
. Northwest hydro conditions have a significant impact on the region’s power supply, with water conditions significantly impacting PGE’s cost of power and its ability to economically displace more expensive thermal generation and spot market power purchases.
|
Natural Gas
|
Physical supplies of natural gas are generally purchased up to twelve months in advance of delivery and based on anticipated operation of the plants. PGE attempts to manage the price risk of natural gas supply through the use of financial contracts up to 60 months in advance of expected need of energy.
|
Coal
|
PGE has fixed-price purchase agreements that, together with existing inventory, will provide coal sufficient for the anticipated operating needs for Boardman during 2017. The coal is obtained from surface mining operations in Wyoming and Montana and is delivered by rail under two separate transportation contracts which extend through 2020.
|
•
|
Mid-Columbia hydro
—PGE has long-term power purchase contracts with certain public utility districts in the state of Washington for a portion of the output of 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.
|
•
|
On property owned or leased by PGE;
|
•
|
Under or over streets, alleys, highways and other public places, the public domain and national forests, and federal and state lands primarily under franchises, easements or other rights that are generally subject to termination;
|
•
|
Under or over private property primarily pursuant to easements obtained from the record holder of title at the time of grant; and
|
•
|
Under or over Native American reservations under grant of easement by the Secretary of the Interior or lease or easement by Native American tribes.
|
•
|
Network integration transmission service, a service that integrates generating resources to serve retail loads;
|
•
|
Short- and long-term firm point-to-point transmission service, a service with fixed delivery and receipt points; and
|
•
|
Non-firm point-to-point service, an “as available” service with fixed delivery and receipt points.
|
Facility
|
|
Location
|
|
Net
Capacity
(1)
|
|
|
Wholly-owned:
|
|
|
|
|
|
|
Natural Gas/Oil:
|
|
|
|
|
|
|
Beaver
|
|
Clatskanie, Oregon
|
|
508
|
|
MW
|
Carty
|
|
Boardman, Oregon
|
|
434
|
|
|
Port Westward Unit 1 (PW1)
|
|
Clatskanie, Oregon
|
|
395
|
|
|
Coyote Springs
|
|
Boardman, Oregon
|
|
243
|
|
|
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
|
|
|
|
3,831
|
|
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 capacity on the Colstrip Project Transmission facilities from Colstrip to BPA’s transmission system; and
|
•
|
Approximately 20% of the capacity on the Pacific Northwest Intertie, a 4,800 MW transmission facility between John Day, in northern Oregon, and Malin, in southern 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.
|
1.
|
that, because Abengoa S.A. has alleged that PGE wrongfully terminated the Construction Agreement, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and
|
2.
|
that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond.
|
ITEM 5.
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
|
|
|
High
|
|
Low
|
|
Dividends
Declared
Per Share
|
||||||
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
|
|
|||
2015
|
|
|
|
|
|
|
||||||
Fourth Quarter
|
|
$
|
39.08
|
|
|
$
|
34.97
|
|
|
$
|
0.30
|
|
Third Quarter
|
|
38.00
|
|
|
33.09
|
|
|
0.30
|
|
|||
Second Quarter
|
|
37.69
|
|
|
33.04
|
|
|
0.30
|
|
|||
First Quarter
|
|
41.04
|
|
|
34.72
|
|
|
0.28
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(In millions, except per share amounts)
|
||||||||||||||||||
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues, net
|
$
|
1,923
|
|
|
$
|
1,898
|
|
|
$
|
1,900
|
|
|
$
|
1,810
|
|
|
$
|
1,805
|
|
Gross margin
|
68
|
%
|
|
65
|
%
|
|
62
|
%
|
|
58
|
%
|
|
60
|
%
|
|||||
Income from operations*
|
$
|
333
|
|
|
$
|
309
|
|
|
$
|
293
|
|
|
$
|
206
|
|
|
$
|
302
|
|
Net income*
|
193
|
|
|
172
|
|
|
174
|
|
|
104
|
|
|
140
|
|
|||||
Net income attributable to Portland General Electric Company*
|
193
|
|
|
172
|
|
|
175
|
|
|
105
|
|
|
141
|
|
|||||
Earnings per share—basic*
|
2.17
|
|
|
2.05
|
|
|
2.24
|
|
|
1.36
|
|
|
1.87
|
|
|||||
Earnings per share—diluted*
|
2.16
|
|
|
2.04
|
|
|
2.18
|
|
|
1.35
|
|
|
1.87
|
|
|||||
Dividends declared per common share
|
1.260
|
|
|
1.180
|
|
|
1.115
|
|
|
1.095
|
|
|
1.075
|
|
|||||
Statement of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
584
|
|
|
598
|
|
|
1,007
|
|
|
656
|
|
|
303
|
|
|
|
|
|
|
|
As of December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(Dollars in millions)
|
||||||||||||||||||
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
*
|
$
|
7,527
|
|
|
$
|
7,210
|
|
|
$
|
7,030
|
|
|
$
|
6,090
|
|
|
$
|
5,661
|
|
Total long-term debt
*
|
2,350
|
|
|
2,193
|
|
|
2,489
|
|
|
1,905
|
|
|
1,627
|
|
|||||
Total capital lease obligations
|
54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total Portland General Electric Company shareholders’ equity
|
2,344
|
|
|
2,258
|
|
|
1,911
|
|
|
1,819
|
|
|
1,728
|
|
|||||
Common equity ratio
*
|
49.4
|
%
|
|
50.7
|
%
|
|
43.4
|
%
|
|
48.9
|
%
|
|
51.3
|
%
|
|
|
|
|
|
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, coal, and oil, and the impact of such changes on the Company’s power costs;
|
•
|
capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE’s credit ratings, any of which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, and the repayments of maturing debt;
|
•
|
future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury and other gas emissions;
|
•
|
changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;
|
•
|
the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;
|
•
|
changes in residential, commercial, and industrial customer growth, and in demographic patterns, in PGE’s service territory;
|
•
|
the effectiveness of PGE’s risk management policies and procedures;
|
•
|
declines in the fair value of securities held for the defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such plans;
|
•
|
cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;
|
•
|
employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and a significant number of employees approaching retirement;
|
•
|
new federal, state, and local laws that could have adverse effects on operating results;
|
•
|
political and economic conditions;
|
•
|
natural disasters and other risks, such as earthquake, flood, drought, lightning, wind, and fire;
|
•
|
changes in financial or regulatory accounting principles or policies imposed by governing bodies; and
|
•
|
acts of war or terrorism.
|
|
2016
|
|
2015
|
|
Increase/
(Decrease)
in Energy
Deliveries
|
|||||||||
|
Average
Number of
Customers
|
|
Energy
Deliveries *
|
|
Average
Number of
Customers
|
|
Energy
Deliveries *
|
|
||||||
Residential
|
752,365
|
|
|
7,348
|
|
|
742,467
|
|
|
7,325
|
|
|
0.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|||||
Commercial (PGE sales only)
|
106,460
|
|
|
6,932
|
|
|
105,472
|
|
|
7,002
|
|
|
(1.0
|
)%
|
Direct Access
|
313
|
|
|
525
|
|
|
330
|
|
|
509
|
|
|
3.1
|
%
|
Total Commercial
|
106,773
|
|
|
7,457
|
|
|
105,802
|
|
|
7,511
|
|
|
(0.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|||||
Industrial (PGE sales only)
|
195
|
|
|
2,968
|
|
|
199
|
|
|
3,369
|
|
|
(11.9
|
)%
|
Direct Access
|
63
|
|
|
1,198
|
|
|
61
|
|
|
1,177
|
|
|
1.8
|
%
|
Total Industrial
|
258
|
|
|
4,166
|
|
|
255
|
|
|
4,546
|
|
|
(8.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|||||
Total (PGE sales only)
|
859,020
|
|
|
17,248
|
|
|
848,138
|
|
|
17,696
|
|
|
(2.5
|
)%
|
Total Direct Access
|
376
|
|
|
1,723
|
|
|
391
|
|
|
1,686
|
|
|
2.2
|
%
|
Total
|
859,396
|
|
|
18,971
|
|
|
848,524
|
|
|
19,382
|
|
|
(2.1
|
)%
|
|
|
|
|
|
*
|
In thousands of MWh.
|
•
|
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 will be made by the OPUC through a public filing and review in
2017
.
|
•
|
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
.
|
•
|
For
2014
, actual NVPC was below baseline NVPC by
$7 million
, which was within the established deadband range. Accordingly,
no
estimated refund to customers was recorded as of December 31, 2014. A final determination regarding the
2014
PCAM results was made by the OPUC through a public filing and review in
2015
, which confirmed no refund to customers pursuant to the PCAM for
2014
.
|
•
|
An investigation of environmental matters regarding Portland Harbor; and
|
•
|
Claims pertaining to the termination of the Construction Agreement for Carty and recovery of incremental costs.
|
•
|
fully depreciate its portion of the Colstrip facility by 2030, with the potential to utilize the output of the facility, in Oregon, until 2035;
|
•
|
meet RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
|
•
|
limit the life of RECs generated from facilities that become operational after 2022 to five years, but maintain the unlimited lifespan of all existing RECs and allow for the generation of additional unlimited RECs for a period of five years for projects on line before December 31, 2022;
|
•
|
include projected PTCs in prices through any variable power cost forecasting process established by the OPUC, the first of which applied to the AUT filing for 2017; and
|
•
|
include energy storage costs in its 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,
|
|||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
|
Amount
|
|
As %
of Rev
|
|
Amount
|
|
As %
of Rev
|
|
Amount
|
|
As %
of Rev
|
|||||||||
Revenues, net
|
$
|
1,923
|
|
|
100
|
%
|
|
$
|
1,898
|
|
|
100
|
%
|
|
$
|
1,900
|
|
|
100
|
%
|
Purchased power and fuel
|
617
|
|
|
32
|
|
|
661
|
|
|
35
|
|
|
713
|
|
|
38
|
|
|||
Gross margin
|
1,306
|
|
|
68
|
|
|
1,237
|
|
|
65
|
|
|
1,187
|
|
|
62
|
|
|||
Other operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Generation, transmission and distribution
|
286
|
|
|
15
|
|
|
266
|
|
|
14
|
|
|
257
|
|
|
13
|
|
|||
Administrative and other
|
247
|
|
|
13
|
|
|
241
|
|
|
13
|
|
|
227
|
|
|
12
|
|
|||
Depreciation and amortization
|
321
|
|
|
16
|
|
|
305
|
|
|
16
|
|
|
301
|
|
|
16
|
|
|||
Taxes other than income taxes
|
119
|
|
|
6
|
|
|
116
|
|
|
6
|
|
|
109
|
|
|
6
|
|
|||
Total other operating expenses
|
973
|
|
|
50
|
|
|
928
|
|
|
49
|
|
|
894
|
|
|
47
|
|
|||
Income from operations
|
333
|
|
|
18
|
|
|
309
|
|
|
16
|
|
|
293
|
|
|
15
|
|
|||
Interest expense, net*
|
112
|
|
|
6
|
|
|
114
|
|
|
6
|
|
|
96
|
|
|
5
|
|
|||
Other income:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Allowance for equity funds used during construction
|
21
|
|
|
1
|
|
|
21
|
|
|
1
|
|
|
37
|
|
|
2
|
|
|||
Miscellaneous income, net
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|||
Other income, net
|
22
|
|
|
1
|
|
|
22
|
|
|
1
|
|
|
38
|
|
|
2
|
|
|||
Income before income taxes
|
243
|
|
|
13
|
|
|
217
|
|
|
11
|
|
|
235
|
|
|
12
|
|
|||
Income tax expense
|
50
|
|
|
3
|
|
|
45
|
|
|
2
|
|
|
61
|
|
|
3
|
|
|||
Net income
|
193
|
|
|
10
|
|
|
172
|
|
|
9
|
|
|
174
|
|
|
9
|
|
|||
Less: net loss attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|||
Net income attributable to Portland General Electric Company
|
$
|
193
|
|
|
10
|
%
|
|
$
|
172
|
|
|
9
|
%
|
|
$
|
175
|
|
|
9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
Revenues
(1)
(dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Residential
|
$
|
907
|
|
|
47
|
%
|
|
$
|
895
|
|
|
47
|
%
|
|
$
|
893
|
|
|
47
|
%
|
Commercial
|
665
|
|
|
35
|
|
|
662
|
|
|
35
|
|
|
657
|
|
|
34
|
|
|||
Industrial
|
208
|
|
|
11
|
|
|
228
|
|
|
12
|
|
|
221
|
|
|
12
|
|
|||
Subtotal
|
1,780
|
|
|
93
|
|
|
1,785
|
|
|
94
|
|
|
1,771
|
|
|
93
|
|
|||
Other accrued (deferred) revenues, net
|
3
|
|
|
—
|
|
|
(10
|
)
|
|
(1
|
)
|
|
(8
|
)
|
|
—
|
|
|||
Total retail revenues
|
1,783
|
|
|
93
|
|
|
1,775
|
|
|
93
|
|
|
1,763
|
|
|
93
|
|
|||
Wholesale revenues
|
103
|
|
|
5
|
|
|
88
|
|
|
5
|
|
|
95
|
|
|
5
|
|
|||
Other operating revenues
|
37
|
|
|
2
|
|
|
35
|
|
|
2
|
|
|
42
|
|
|
2
|
|
|||
Total revenues
|
$
|
1,923
|
|
|
100
|
%
|
|
$
|
1,898
|
|
|
100
|
%
|
|
$
|
1,900
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Energy deliveries
(2)
(MWh in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Retail:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Residential
|
7,348
|
|
|
33
|
%
|
|
7,325
|
|
|
33
|
%
|
|
7,462
|
|
|
34
|
%
|
|||
Commercial
|
7,457
|
|
|
33
|
|
|
7,511
|
|
|
34
|
|
|
7,494
|
|
|
34
|
|
|||
Industrial
|
4,166
|
|
|
19
|
|
|
4,546
|
|
|
21
|
|
|
4,310
|
|
|
20
|
|
|||
Total retail energy deliveries
|
18,971
|
|
|
85
|
|
|
19,382
|
|
|
88
|
|
|
19,266
|
|
|
88
|
|
|||
Wholesale energy deliveries
|
3,352
|
|
|
15
|
|
|
2,560
|
|
|
12
|
|
|
2,520
|
|
|
12
|
|
|||
Total energy deliveries
|
22,323
|
|
|
100
|
%
|
|
21,942
|
|
|
100
|
%
|
|
21,786
|
|
|
100
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Average number of retail customers:
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Residential
|
752,365
|
|
|
88
|
%
|
|
742,467
|
|
|
88
|
%
|
|
735,502
|
|
|
87
|
%
|
|||
Commercial
|
106,773
|
|
|
12
|
|
|
105,802
|
|
|
12
|
|
|
105,231
|
|
|
13
|
|
|||
Industrial
|
258
|
|
|
—
|
|
|
255
|
|
|
—
|
|
|
260
|
|
|
—
|
|
|||
Total
|
859,396
|
|
|
100
|
%
|
|
848,524
|
|
|
100
|
%
|
|
840,993
|
|
|
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 $13 million, $12 million, and $15 million for 2016, 2015, and 2014, respectively. Industrial revenues from ESS customers were $15 million, $16 million, and $18 million for 2016, 2015, and 2014, 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 525, 509, and 563 in 2016, 2015, and 2014, respectively. Industrial deliveries to ESS customers, in thousands of MWhs, were 1,198, 1,177, and 1,099 in 2016, 2015, and 2014, respectively.
|
•
|
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 Normal
*
|
|||||||
Location
|
2017
Forecast
|
|
2016
Actual
|
|
2015
Actual
|
|||
Columbia River at The Dalles, Oregon
|
99
|
%
|
|
89
|
%
|
|
69
|
%
|
Mid-Columbia River at Grand Coulee, Washington
|
95
|
|
|
91
|
|
|
77
|
|
Clackamas River at Estacada, Oregon
|
101
|
|
|
71
|
|
|
53
|
|
Deschutes River at Moody, Oregon
|
98
|
|
|
91
|
|
|
85
|
|
*
|
Volumetric water supply forecasts and historical 30-year averages for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies.
|
•
|
An $11 million increase in revenues related to a
0.6%
increase in retail energy deliveries, consisting of
5.5%
and
0.2%
increases in industrial and commercial deliveries, respectively, partially offset by a
1.8%
decrease in residential deliveries; and
|
•
|
A $4 million net increase that related to higher average retail prices resulting from the January 1, 2015 price increase authorized by the OPUC in the Company’s 2015 GRC, which was net of a $28 million decrease due to various supplemental tariff changes, including $20 million in customer credits in 2015 related to proceeds received in connection with the settlement of a legal matter regarding the operation of the ISFSI at the former Trojan nuclear power plant site and tax credits, all of which are offset in Depreciation and Amortization expense.
|
|
Heating Degree-Days
|
|
Cooling Degree-Days
|
||||||||||||||
|
2015
|
|
2014
|
|
15-Year Average
|
|
2015
|
|
2014
|
|
15-Year Average
|
||||||
1st quarter
|
1,481
|
|
|
1,891
|
|
|
1,864
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2nd quarter
|
513
|
|
|
530
|
|
|
713
|
|
|
207
|
|
|
57
|
|
|
70
|
|
3rd quarter
|
76
|
|
|
18
|
|
|
85
|
|
|
573
|
|
|
579
|
|
|
382
|
|
4th quarter
|
1,391
|
|
|
1,355
|
|
|
1,602
|
|
|
5
|
|
|
17
|
|
|
1
|
|
Total
|
3,461
|
|
|
3,794
|
|
|
4,264
|
|
|
785
|
|
|
653
|
|
|
453
|
|
Increase (decrease) from the 15-year average
|
(19
|
)%
|
|
(11
|
)%
|
|
|
|
|
73
|
%
|
|
44
|
%
|
|
|
|
|
Runoff as a Percent of Normal
*
|
||||
Location
|
2015
Actual
|
|
2014
Actual
|
||
Columbia River at The Dalles, Oregon
|
69
|
%
|
|
108
|
%
|
Mid-Columbia River at Grand Coulee, Washington
|
77
|
|
|
110
|
|
Clackamas River at Estacada, Oregon
|
53
|
|
|
97
|
|
Deschutes River at Moody, Oregon
|
85
|
|
|
98
|
|
*
|
Actual volumetric water supply amounts and historical 30-year averages for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies.
|
|
Years Ending December 31,
|
||||||||||||||||||||||
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
||||||||||||
Ongoing capital expenditures
|
$
|
406
|
|
|
$
|
604
|
|
|
$
|
427
|
|
|
$
|
294
|
|
|
$
|
300
|
|
|
$
|
290
|
|
Carty
|
190
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total capital expenditures
|
$
|
596
|
|
*
|
$
|
610
|
|
|
$
|
427
|
|
|
$
|
294
|
|
|
$
|
300
|
|
|
$
|
290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Long-term debt maturities
|
$
|
—
|
|
|
$
|
150
|
|
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Cash and cash equivalents, beginning of year
|
$
|
4
|
|
|
$
|
127
|
|
|
$
|
107
|
|
Net cash provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
553
|
|
|
520
|
|
|
520
|
|
|||
Investing activities
|
(585
|
)
|
|
(522
|
)
|
|
(994
|
)
|
|||
Financing activities
|
34
|
|
|
(121
|
)
|
|
494
|
|
|||
Net change in cash and cash equivalents
|
2
|
|
|
(123
|
)
|
|
20
|
|
|||
Cash and cash equivalents, end of year
|
$
|
6
|
|
|
$
|
4
|
|
|
$
|
127
|
|
|
|
|
|
|
|
Declaration Date
|
|
Record Date
|
|
Payment Date
|
|
Declared Per
Common Share
|
||
February 17, 2016
|
|
March 25, 2016
|
|
April 15, 2016
|
|
$
|
0.30
|
|
April 27, 2016
|
|
June 27, 2016
|
|
July 15, 2016
|
|
0.32
|
|
|
July 27, 2016
|
|
September 26, 2016
|
|
October 17, 2016
|
|
0.32
|
|
|
October 26, 2016
|
|
December 27, 2016
|
|
January 17, 2017
|
|
0.32
|
|
|
Moody’s
|
|
S&P
|
First Mortgage Bonds
|
A1
|
|
A-
|
Senior unsecured debt
|
A3
|
|
BBB
|
Commercial paper
|
Prime-2
|
|
A-2
|
Outlook
|
Stable
|
|
Stable
|
•
|
$50 million on May 4, 2016;
|
•
|
$75 million on June 15, 2016; and
|
•
|
$25 million on October 31, 2016.
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
There-
after
|
|
Total
|
||||||||||||||
Long-term debt
|
$
|
150
|
|
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
1,751
|
|
|
$
|
2,361
|
|
Interest on long-term debt
(1)
|
116
|
|
|
114
|
|
|
101
|
|
|
95
|
|
|
91
|
|
|
1,530
|
|
|
2,047
|
|
|||||||
Capital and other purchase commitments
|
176
|
|
|
8
|
|
|
2
|
|
|
9
|
|
|
1
|
|
|
60
|
|
|
256
|
|
|||||||
Purchased power and fuel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity purchases
|
221
|
|
|
157
|
|
|
181
|
|
|
256
|
|
|
239
|
|
|
1,750
|
|
|
2,804
|
|
|||||||
Capacity contracts
|
7
|
|
|
6
|
|
|
5
|
|
|
4
|
|
|
4
|
|
|
12
|
|
|
38
|
|
|||||||
Public Utility Districts
|
4
|
|
|
4
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
11
|
|
|
21
|
|
|||||||
Natural gas
|
53
|
|
|
39
|
|
|
32
|
|
|
27
|
|
|
24
|
|
|
158
|
|
|
333
|
|
|||||||
Coal and transportation
|
17
|
|
|
9
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|||||||
Pension Plan Contributions
(2)
|
3
|
|
|
21
|
|
|
21
|
|
|
21
|
|
|
20
|
|
|
—
|
|
|
86
|
|
|||||||
Capital leases
|
7
|
|
|
7
|
|
|
6
|
|
|
6
|
|
|
6
|
|
|
77
|
|
|
109
|
|
|||||||
Build-to-suit lease
|
—
|
|
|
4
|
|
|
14
|
|
|
13
|
|
|
13
|
|
|
237
|
|
|
281
|
|
|||||||
Operating leases
|
10
|
|
|
9
|
|
|
6
|
|
|
6
|
|
|
7
|
|
|
177
|
|
|
215
|
|
|||||||
Total
|
$
|
764
|
|
|
$
|
378
|
|
|
$
|
674
|
|
|
$
|
437
|
|
|
$
|
566
|
|
|
$
|
5,763
|
|
|
$
|
8,582
|
|
|
|
|
|
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity
|
$
|
6
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
77
|
|
|
$
|
111
|
|
Natural gas
|
20
|
|
|
7
|
|
|
6
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
35
|
|
|||||||
|
$
|
26
|
|
|
$
|
14
|
|
|
$
|
13
|
|
|
$
|
9
|
|
|
$
|
7
|
|
|
$
|
77
|
|
|
$
|
146
|
|
|
Total
Fair
Value
|
|
Carrying Amounts by Maturity Date
|
||||||||||||||||||||||||
|
Total
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
There-
after
|
||||||||||||||||
First Mortgage Bonds
|
$
|
2,411
|
|
|
$
|
2,090
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
1,790
|
|
Unsecured Term Bank Loans
|
150
|
|
|
150
|
|
|
150
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Pollution Control Revenue Bonds
|
132
|
|
|
121
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
121
|
|
|||||||
Total
|
$
|
2,693
|
|
|
$
|
2,361
|
|
|
$
|
150
|
|
|
$
|
—
|
|
|
$
|
300
|
|
|
$
|
—
|
|
|
$
|
1,911
|
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues, net
|
$
|
1,923
|
|
|
$
|
1,898
|
|
|
$
|
1,900
|
|
Operating expenses:
|
|
|
|
|
|
||||||
Purchased power and fuel
|
617
|
|
|
661
|
|
|
713
|
|
|||
Generation, transmission and distribution
|
286
|
|
|
266
|
|
|
257
|
|
|||
Administrative and other
|
247
|
|
|
241
|
|
|
227
|
|
|||
Depreciation and amortization
|
321
|
|
|
305
|
|
|
301
|
|
|||
Taxes other than income taxes
|
119
|
|
|
116
|
|
|
109
|
|
|||
Total operating expenses
|
1,590
|
|
|
1,589
|
|
|
1,607
|
|
|||
Income from operations
|
333
|
|
|
309
|
|
|
293
|
|
|||
Interest expense, net
|
112
|
|
|
114
|
|
|
96
|
|
|||
Other income:
|
|
|
|
|
|
||||||
Allowance for equity funds used during construction
|
21
|
|
|
21
|
|
|
37
|
|
|||
Miscellaneous income, net
|
1
|
|
|
1
|
|
|
1
|
|
|||
Other income, net
|
22
|
|
|
22
|
|
|
38
|
|
|||
Income before income taxes
|
243
|
|
|
217
|
|
|
235
|
|
|||
Income tax expense
|
50
|
|
|
45
|
|
|
61
|
|
|||
Net income
|
193
|
|
|
172
|
|
|
174
|
|
|||
Less: net loss attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||
Net income attributable to Portland General Electric Company
|
$
|
193
|
|
|
$
|
172
|
|
|
$
|
175
|
|
|
|
|
|
|
|
||||||
Weighted-average shares outstanding (in thousands):
|
|
|
|
|
|
||||||
Basic
|
88,896
|
|
|
84,180
|
|
|
78,180
|
|
|||
Diluted
|
89,054
|
|
|
84,341
|
|
|
80,494
|
|
|||
|
|
|
|
|
|
||||||
Earnings per share:
|
|
|
|
|
|
||||||
Basic
|
$
|
2.17
|
|
|
$
|
2.05
|
|
|
$
|
2.24
|
|
Diluted
|
$
|
2.16
|
|
|
$
|
2.04
|
|
|
$
|
2.18
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Net income
|
$
|
193
|
|
|
$
|
172
|
|
|
$
|
174
|
|
Other comprehensive income (loss)—Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2016 and 2015, and $2 in 2014
|
1
|
|
|
(1
|
)
|
|
(2
|
)
|
|||
Comprehensive income
|
194
|
|
|
171
|
|
|
172
|
|
|||
Less: comprehensive loss attributable to the noncontrolling interests
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||
Comprehensive income attributable to Portland General Electric Company
|
$
|
194
|
|
|
$
|
171
|
|
|
$
|
173
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
129
|
|
|
$
|
98
|
|
Liabilities from price risk management activities—current
|
44
|
|
|
130
|
|
||
Short-term debt
|
—
|
|
|
6
|
|
||
Current portion of long-term debt
|
150
|
|
|
133
|
|
||
Accrued expenses and other current liabilities
|
254
|
|
|
259
|
|
||
Total current liabilities
|
577
|
|
|
626
|
|
||
Long-term debt, net of current portion
|
2,200
|
|
|
2,060
|
|
||
Regulatory liabilities—noncurrent
|
958
|
|
|
928
|
|
||
Deferred income taxes
|
669
|
|
|
632
|
|
||
Unfunded status of pension and postretirement plans
|
281
|
|
|
259
|
|
||
Liabilities from price risk management activities—noncurrent
|
125
|
|
|
161
|
|
||
Asset retirement obligations
|
161
|
|
|
151
|
|
||
Non-qualified benefit plan liabilities
|
105
|
|
|
106
|
|
||
Other noncurrent liabilities
|
107
|
|
|
29
|
|
||
Total liabilities
|
5,183
|
|
|
4,952
|
|
||
Commitments and contingencies (see notes)
|
|
|
|
|
|||
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; 88,946,704 and 88,792,751 shares issued and outstanding as of December 31, 2016 and 2015, respectively
|
1,201
|
|
|
1,196
|
|
||
Accumulated other comprehensive loss
|
(7
|
)
|
|
(8
|
)
|
||
Retained earnings
|
1,150
|
|
|
1,070
|
|
||
Total equity
|
2,344
|
|
|
2,258
|
|
||
Total liabilities and equity
|
$
|
7,527
|
|
|
$
|
7,210
|
|
|
|
|
|
|
Portland General Electric Company
Shareholders’ Equity
|
|
|
|
|||||||||||||||
|
Common Stock
|
|
Accumulated
Other
Comprehensive
Loss
|
|
Retained
Earnings
|
|
|
Noncontrolling
Interests’
Equity
|
|||||||||||
|
Shares
|
|
Amount
|
|
|||||||||||||||
Balance as of December 31, 2013
|
78,085,559
|
|
|
$
|
911
|
|
|
$
|
(5
|
)
|
|
$
|
913
|
|
|
|
$
|
1
|
|
Shares issued pursuant to equity-based plans
|
142,780
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Stock-based compensation
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Dividends declared ($1.115 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(88
|
)
|
|
|
—
|
|
||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
175
|
|
|
|
(1
|
)
|
||||
Other comprehensive (loss)
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
|
—
|
|
||||
Balance as of December 31, 2014
|
78,228,339
|
|
|
918
|
|
|
(7
|
)
|
|
1,000
|
|
|
|
—
|
|
||||
Issuances of common stock, net of issuance costs of $12
|
10,400,000
|
|
|
271
|
|
|
|
|
|
|
|
|
|||||||
Shares issued pursuant to equity-based plans
|
164,412
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Stock-based compensation
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Dividends declared ($1.18 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(102
|
)
|
|
|
—
|
|
||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
172
|
|
|
|
—
|
|
||||
Other comprehensive (loss)
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
|
—
|
|
||||
Balance as of December 31, 2015
|
88,792,751
|
|
|
1,196
|
|
|
(8
|
)
|
|
1,070
|
|
|
|
—
|
|
||||
Shares issued pursuant to equity-based plans
|
153,953
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Stock-based compensation
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Dividends declared ($1.26 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
(113
|
)
|
|
|
—
|
|
||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
193
|
|
|
|
—
|
|
||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
|
—
|
|
||||
Balance as of December 31, 2016
|
88,946,704
|
|
|
$
|
1,201
|
|
|
$
|
(7
|
)
|
|
$
|
1,150
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
193
|
|
|
$
|
172
|
|
|
$
|
174
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
321
|
|
|
305
|
|
|
301
|
|
|||
Deferred income taxes
|
37
|
|
|
40
|
|
|
39
|
|
|||
Allowance for equity funds used during construction
|
(21
|
)
|
|
(21
|
)
|
|
(37
|
)
|
|||
Pension and other postretirement benefits
|
28
|
|
|
34
|
|
|
33
|
|
|||
Regulatory deferral of settled derivative instruments
|
2
|
|
|
2
|
|
|
10
|
|
|||
Unrealized losses on non-qualified benefit plan trust assets
|
5
|
|
|
6
|
|
|
7
|
|
|||
Decoupling mechanism deferrals, net of amortization
|
(6
|
)
|
|
14
|
|
|
6
|
|
|||
Other non-cash income and expenses, net
|
5
|
|
|
20
|
|
|
14
|
|
|||
Changes in working capital:
|
|
|
|
|
|
||||||
(Increase) decrease in receivables and unbilled revenues
|
(9
|
)
|
|
(11
|
)
|
|
8
|
|
|||
Decrease (increase) in margin deposits
|
25
|
|
|
(22
|
)
|
|
(2
|
)
|
|||
Increase (decrease) in payables and accrued liabilities
|
15
|
|
|
6
|
|
|
(13
|
)
|
|||
Other working capital items, net
|
(4
|
)
|
|
(4
|
)
|
|
(12
|
)
|
|||
Cash received to be returned to customers pursuant to the Residential Exchange Program, net of amortization
|
(6
|
)
|
|
(1
|
)
|
|
13
|
|
|||
Contribution to non-qualified employee benefit trust
|
(10
|
)
|
|
(9
|
)
|
|
(8
|
)
|
|||
Contribution to voluntary employees’ benefit association trust
|
(2
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|||
Other, net
|
(20
|
)
|
|
(7
|
)
|
|
(10
|
)
|
|||
Net cash provided by operating activities
|
553
|
|
|
520
|
|
|
520
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(584
|
)
|
|
(598
|
)
|
|
(1,007
|
)
|
|||
Purchases of nuclear decommissioning trust securities
|
(25
|
)
|
|
(19
|
)
|
|
(19
|
)
|
|||
Sales of nuclear decommissioning trust securities
|
27
|
|
|
22
|
|
|
17
|
|
|||
Distribution from (contribution to) nuclear decommissioning trust
|
—
|
|
|
50
|
|
|
(6
|
)
|
|||
Sales tax refund received - Tucannon River Wind Farm
|
—
|
|
|
23
|
|
|
—
|
|
|||
Cash received in connection with purchase of 10% interest in Boardman, net of cash paid
|
—
|
|
|
—
|
|
|
8
|
|
|||
Other, net
|
(3
|
)
|
|
—
|
|
|
13
|
|
|||
Net cash used in investing activities
|
(585
|
)
|
|
(522
|
)
|
|
(994
|
)
|
|||
See accompanying notes to consolidated financial statements.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from issuance of long-term debt
|
$
|
290
|
|
|
$
|
145
|
|
|
$
|
585
|
|
Payments on long-term debt
|
(133
|
)
|
|
(442
|
)
|
|
—
|
|
|||
Proceeds from issuances of common stock, net of issuance costs
|
—
|
|
|
271
|
|
|
—
|
|
|||
(Maturities) issuances of commercial paper, net
|
(6
|
)
|
|
6
|
|
|
—
|
|
|||
Dividends paid
|
(110
|
)
|
|
(97
|
)
|
|
(87
|
)
|
|||
Other
|
(7
|
)
|
|
(4
|
)
|
|
(4
|
)
|
|||
Net cash provided by (used in) financing activities
|
34
|
|
|
(121
|
)
|
|
494
|
|
|||
Increase (decrease) in cash and cash equivalents
|
2
|
|
|
(123
|
)
|
|
20
|
|
|||
Cash and cash equivalents, beginning of year
|
4
|
|
|
127
|
|
|
107
|
|
|||
Cash and cash equivalents, end of year
|
$
|
6
|
|
|
$
|
4
|
|
|
$
|
127
|
|
|
|
|
|
|
|
||||||
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
||||||
Cash paid for:
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
|
$
|
104
|
|
|
$
|
108
|
|
|
$
|
86
|
|
Income taxes
|
16
|
|
|
3
|
|
|
22
|
|
|||
Non-cash investing and financing activities:
|
|
|
|
|
|
||||||
Accrued capital additions
|
50
|
|
|
32
|
|
|
70
|
|
|||
Accrued dividends payable
|
30
|
|
|
28
|
|
|
23
|
|
|||
Accrued sales tax refund related to Tucannon River Wind Farm
|
—
|
|
|
—
|
|
|
23
|
|
|||
Assets obtained under leasing arrangements
|
78
|
|
|
—
|
|
|
—
|
|
•
|
On a prospective basis, all excess tax benefits and deficiencies are recognized within the consolidated statements of income in the year incurred, as opposed to equity, and shall be classified as operating activities in the consolidated statements of cash flows. As a result of adoption, PGE recognized less than
$1 million
of excess tax benefits related to its share-based payment awards, which was recorded as a reduction of Income tax expense in the consolidated statements of income for the period ended December 31, 2016.
|
•
|
Reporting entities are now allowed to make a policy election regarding its accounting for forfeitures either by estimating the number of awards that are expected to vest or account for forfeitures when they occur. PGE’s stock compensation expense will continue to reflect estimated forfeitures.
|
•
|
On a retrospective basis, cash paid on behalf of employees related to restricted shares withheld for tax purposes shall now be classified as a financing activity in the statement of cash flows. In the consolidated statements of cash flows for the twelve months ended December 31, 2015 and 2014, PGE has retrospectively reclassified
$3 million
and
$2 million
, respectively, from Other non-cash income and expenses, net within operating activities to Other financing outflow activities. For the twelve months ended December 31, 2016,
$3 million
is reflected as an outflow within the financing activities section.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Balance as of beginning of year
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
Increase in provision
|
5
|
|
|
6
|
|
|
6
|
|
|||
Amounts written off, less recoveries
|
(5
|
)
|
|
(6
|
)
|
|
(6
|
)
|
|||
Balance as of end of year
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
|
|
|
|
|
|
Nuclear
Decommissioning Trust
|
|
Non-Qualified Benefit
Plan Trust
|
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Cash equivalents
|
$
|
21
|
|
|
$
|
18
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Marketable securities, at fair value:
|
|
|
|
|
|
|
|
||||||||
Equity securities
|
—
|
|
|
—
|
|
|
6
|
|
|
5
|
|
||||
Debt securities
|
20
|
|
|
22
|
|
|
1
|
|
|
1
|
|
||||
Insurance contracts, at cash surrender value
|
—
|
|
|
—
|
|
|
26
|
|
|
26
|
|
||||
|
$
|
41
|
|
|
$
|
40
|
|
|
$
|
34
|
|
|
$
|
33
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
Other current assets:
|
|
|
|
||||
Prepaid expenses
|
$
|
48
|
|
|
$
|
43
|
|
Margin deposits
|
8
|
|
|
33
|
|
||
Assets from price risk management activities
|
18
|
|
|
10
|
|
||
Other
|
3
|
|
|
2
|
|
||
|
$
|
77
|
|
|
$
|
88
|
|
Accrued expenses and other current liabilities:
|
|
|
|
||||
Regulatory liabilities—current
|
$
|
51
|
|
|
$
|
55
|
|
Accrued employee compensation and benefits
|
52
|
|
|
51
|
|
||
Accrued interest payable
|
25
|
|
|
25
|
|
||
Accrued dividends payable
|
30
|
|
|
28
|
|
||
Accrued taxes payable
|
25
|
|
|
25
|
|
||
Other
|
71
|
|
|
75
|
|
||
|
$
|
254
|
|
|
$
|
259
|
|
|
|
|
|
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, 2016
|
||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other
(2)
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear decommissioning trust:
(1)
|
|
|
|
|
|
|
|
|
|
||||||||||
Debt securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic government
|
$
|
2
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
12
|
|
Corporate credit
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Money market funds measured at NAV
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
21
|
|
|||||
Non-qualified benefit plan trust:
(3)
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Equity securities—domestic
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|||||
Debt securities—domestic government
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Investments measured at NAV:
(2)
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Collective trust—domestic equity
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|||||
Assets from price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
—
|
|
|
6
|
|
|
1
|
|
|
—
|
|
|
7
|
|
|||||
Natural gas
|
—
|
|
|
15
|
|
|
1
|
|
|
—
|
|
|
16
|
|
|||||
|
$
|
8
|
|
|
$
|
39
|
|
|
$
|
2
|
|
|
$
|
23
|
|
|
$
|
72
|
|
Liabilities - Liabilities from price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
$
|
—
|
|
|
$
|
6
|
|
|
$
|
112
|
|
|
$
|
—
|
|
|
$
|
118
|
|
Natural gas
|
—
|
|
|
42
|
|
|
9
|
|
|
—
|
|
|
51
|
|
|||||
|
$
|
—
|
|
|
$
|
48
|
|
|
$
|
121
|
|
|
$
|
—
|
|
|
$
|
169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.
|
(2)
|
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
|
(3)
|
Excludes insurance policies of
$26 million
, which are recorded at cash surrender value.
|
(4)
|
For further information, see Note 5, Price Risk Management.
|
|
As of December 31, 2015
|
||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other
(2)
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear decommissioning trust:
(1)
|
|
|
|
|
|
|
|
|
|
||||||||||
Debt securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic government
|
$
|
6
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
14
|
|
Corporate credit
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Money market funds measured at NAV
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
18
|
|
|||||
Non-qualified benefit plan trust:
(3)
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Equity securities—domestic
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
Debt securities—domestic government
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Investments measured at NAV:
(2)
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|||||
Collective trust—domestic equity
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|||||
Assets from price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
—
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|||||
Natural gas
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
|
$
|
10
|
|
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
21
|
|
|
$
|
57
|
|
Liabilities - Liabilities from price risk management activities:
(1) (4)
|
|
|
|
|
|
|
|
|
|
||||||||||
Electricity
|
$
|
—
|
|
|
$
|
28
|
|
|
$
|
105
|
|
|
$
|
—
|
|
|
$
|
133
|
|
Natural gas
|
—
|
|
|
144
|
|
|
14
|
|
|
—
|
|
|
158
|
|
|||||
|
$
|
—
|
|
|
$
|
172
|
|
|
$
|
119
|
|
|
$
|
—
|
|
|
$
|
291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in regulatory assets or regulatory liabilities as appropriate.
|
(2)
|
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 2, Summary of Significant Accounting Policies.
|
(3)
|
Excludes insurance policies of
$26 million
, which are recorded at cash surrender value.
|
(4)
|
For further information, see Note 5, Price Risk Management.
|
|
|
|
|
|
|
|
|
Significant
|
|
Price per Unit
|
||||||||||||||
|
|
Fair Value
|
|
Valuation
|
|
Unobservable
|
|
|
|
|
|
Weighted
|
||||||||||||
Commodity Contracts
|
|
Assets
|
|
Liabilities
|
|
Technique
|
|
Input
|
|
Low
|
|
High
|
|
Average
|
||||||||||
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Electricity physical forward
|
|
$
|
—
|
|
|
$
|
112
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
$
|
14.25
|
|
|
$
|
54.73
|
|
|
$
|
38.18
|
|
Natural gas financial swaps
|
|
1
|
|
|
9
|
|
|
Discounted cash flow
|
|
Natural gas forward price (per Dth)
|
|
1.85
|
|
|
4.92
|
|
|
2.64
|
|
|||||
Electricity financial futures
|
|
1
|
|
|
—
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
8.57
|
|
|
33.60
|
|
|
25.10
|
|
|||||
|
|
$
|
2
|
|
|
$
|
121
|
|
|
|
|
|
|
|
|
|
|
|
||||||
As of December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Electricity physical forward
|
|
$
|
—
|
|
|
$
|
105
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
$
|
8.50
|
|
|
$
|
84.47
|
|
|
$
|
30.69
|
|
Natural gas financial swaps
|
|
—
|
|
|
14
|
|
|
Discounted cash flow
|
|
Natural gas forward price (per Dth)
|
|
2.06
|
|
|
3.70
|
|
|
2.54
|
|
|||||
Electricity financial futures
|
|
—
|
|
|
—
|
|
|
Discounted cash flow
|
|
Electricity forward price (per MWh)
|
|
9.98
|
|
|
27.36
|
|
|
19.26
|
|
|||||
|
|
$
|
—
|
|
|
$
|
119
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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,
|
||||||
|
2016
|
|
2015
|
||||
Net liabilities from price risk management activities as of beginning of year
|
$
|
119
|
|
|
$
|
100
|
|
Net realized and unrealized losses
*
|
11
|
|
|
80
|
|
||
Net transfers in to Level 3 from Level 2
|
(1
|
)
|
|
—
|
|
||
Net transfers out of Level 3 to Level 2
|
(10
|
)
|
|
(61
|
)
|
||
Net liabilities from price risk management activities as of end of year
|
$
|
119
|
|
|
$
|
119
|
|
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting
|
$
|
11
|
|
|
$
|
80
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
||||||
|
2016
|
|
2015
|
|
||||
Current assets:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
$
|
6
|
|
|
$
|
7
|
|
|
Natural gas
|
12
|
|
|
3
|
|
|
||
Total current derivative assets
|
18
|
|
(1)
|
10
|
|
(1)
|
||
Noncurrent assets:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
1
|
|
|
—
|
|
|
||
Natural gas
|
4
|
|
|
—
|
|
|
||
Total noncurrent derivative assets
|
5
|
|
(2)
|
—
|
|
(2)
|
||
Total derivative assets not designated as hedging instruments
|
$
|
23
|
|
|
$
|
10
|
|
|
Total derivative assets
|
$
|
23
|
|
|
$
|
10
|
|
|
Current liabilities:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
$
|
12
|
|
|
$
|
36
|
|
|
Natural gas
|
32
|
|
|
94
|
|
|
||
Total current derivative liabilities
|
44
|
|
|
130
|
|
|
||
Noncurrent liabilities:
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
||||
Electricity
|
106
|
|
|
97
|
|
|
||
Natural gas
|
19
|
|
|
64
|
|
|
||
Total noncurrent derivative liabilities
|
125
|
|
|
161
|
|
|
||
Total derivative liabilities not designated as hedging instruments
|
$
|
169
|
|
|
$
|
291
|
|
|
Total derivative liabilities
|
$
|
169
|
|
|
$
|
291
|
|
|
|
|
|
|
|
(1)
|
Included in Other current assets on the consolidated balance sheets.
|
(2)
|
Included in Other noncurrent assets on the consolidated balance sheets.
|
|
As of December 31,
|
||||||||||
|
2016
|
|
2015
|
||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
||||
Electricity
|
8
|
|
|
MWh
|
|
12
|
|
|
MWh
|
||
Natural gas
|
107
|
|
|
Dth
|
|
124
|
|
|
Dth
|
||
Foreign currency exchange
|
$
|
22
|
|
|
Canadian
|
|
$
|
7
|
|
|
Canadian
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Commodity contracts:
|
|
|
|
|
|
||||||
Electricity
|
$
|
34
|
|
|
$
|
72
|
|
|
$
|
13
|
|
Natural Gas
|
(56
|
)
|
|
103
|
|
|
72
|
|
|||
Foreign currency exchange
|
—
|
|
|
1
|
|
|
—
|
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
Commodity contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity
|
$
|
6
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
77
|
|
|
$
|
111
|
|
Natural gas
|
20
|
|
|
7
|
|
|
6
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
35
|
|
|||||||
Net unrealized loss
|
$
|
26
|
|
|
$
|
14
|
|
|
$
|
13
|
|
|
$
|
9
|
|
|
$
|
7
|
|
|
$
|
77
|
|
|
$
|
146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||
|
2016
|
|
2015
|
||
Assets from price risk management activities:
|
|
|
|
||
Counterparty A
|
22
|
%
|
|
5
|
%
|
Counterparty B
|
17
|
|
|
8
|
|
Counterparty C
|
12
|
|
|
8
|
|
Counterparty D
|
8
|
|
|
10
|
|
Counterparty E
|
1
|
|
|
59
|
|
|
60
|
%
|
|
90
|
%
|
Liabilities from price risk management activities:
|
|
|
|
||
Counterparty F
|
66
|
%
|
|
36
|
%
|
Counterparty C
|
7
|
%
|
|
10
|
%
|
Counterparty B
|
5
|
%
|
|
10
|
%
|
|
78
|
%
|
|
56
|
%
|
|
Weighted Average Remaining
Life
(1)
|
|
As of December 31,
|
||||||||||||||
|
2016
|
|
2015
|
||||||||||||||
|
Current
|
|
Noncurrent
|
|
Current
|
|
Noncurrent
|
||||||||||
Regulatory assets:
|
|
|
|
|
|
|
|
|
|
||||||||
Price risk management
(2)
|
6 years
|
|
$
|
26
|
|
|
$
|
120
|
|
|
$
|
120
|
|
|
$
|
161
|
|
Pension and other postretirement plans
(2)
|
(3)
|
|
—
|
|
|
235
|
|
|
—
|
|
|
239
|
|
||||
Deferred income taxes
(2)
|
(4)
|
|
—
|
|
|
86
|
|
|
—
|
|
|
86
|
|
||||
Debt issuance costs
(2)
|
6 years
|
|
—
|
|
|
22
|
|
|
—
|
|
|
16
|
|
||||
Other
(5)
|
Various
|
|
10
|
|
|
35
|
|
|
9
|
|
|
22
|
|
||||
Total regulatory assets
|
|
|
$
|
36
|
|
|
$
|
498
|
|
|
$
|
129
|
|
|
$
|
524
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||
Asset retirement removal costs
(6)
|
(4)
|
|
$
|
—
|
|
|
$
|
887
|
|
|
$
|
—
|
|
|
$
|
837
|
|
Trojan decommissioning activities
|
3 years
|
|
18
|
|
|
—
|
|
|
17
|
|
|
15
|
|
||||
Asset retirement obligations
(6)
|
(4)
|
|
—
|
|
|
49
|
|
|
—
|
|
|
45
|
|
||||
Other
|
Various
|
|
33
|
|
|
22
|
|
|
38
|
|
|
31
|
|
||||
Total regulatory liabilities
|
|
|
$
|
51
|
|
(7)
|
$
|
958
|
|
|
$
|
55
|
|
(7)
|
$
|
928
|
|
|
|
|
|
|
(1)
|
As of
December 31, 2016
.
|
(2)
|
Does not include a return on investment.
|
(3)
|
Recovery expected over the average service life of employees.
|
(4)
|
Recovery expected over the estimated lives of the assets.
|
(5)
|
Of the total other unamortized regulatory asset balances, a return is recorded on
$44 million
and
$29 million
as of
December 31, 2016
and
2015
, respectively.
|
(6)
|
Included in rate base for ratemaking purposes.
|
(7)
|
Included in Accrued expenses and other current liabilities on the consolidated balance sheets.
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
Trojan decommissioning activities
|
$
|
44
|
|
|
$
|
43
|
|
Utility plant
|
105
|
|
|
97
|
|
||
Non-utility property
|
12
|
|
|
11
|
|
||
Asset retirement obligations
|
$
|
161
|
|
|
$
|
151
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Balance as of beginning of year
|
$
|
151
|
|
|
$
|
116
|
|
|
$
|
100
|
|
Liabilities incurred
|
1
|
|
|
2
|
|
|
15
|
|
|||
Liabilities settled
|
(3
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|||
Accretion expense
|
7
|
|
|
7
|
|
|
6
|
|
|||
Revisions in estimated cash flows
|
5
|
|
|
30
|
|
|
(2
|
)
|
|||
Balance as of end of year
|
$
|
161
|
|
|
$
|
151
|
|
|
$
|
116
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Average daily amount of short-term debt outstanding
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Weighted daily average interest rate *
|
0.7
|
%
|
|
0.6
|
%
|
|
—
|
%
|
|||
Maximum amount outstanding during the year
|
$
|
23
|
|
|
$
|
11
|
|
|
$
|
—
|
|
|
|
|
|
|
*
|
Excludes the effect of commitment fees, facility fees and other financing fees.
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
First Mortgage Bonds
, rates range from 2.51% to 9.31%, with a weighted average rate of 4.86% in 2016 and 5.29% in 2015, due at various dates through 2048
|
$
|
2,090
|
|
|
$
|
2,083
|
|
Unsecured term bank loans
, variable rates of approximately 1.37%
due 2017
|
150
|
|
|
—
|
|
||
Pollution Control Revenue Bonds
, 5% rate, due 2033
|
142
|
|
|
142
|
|
||
Pollution Control Revenue Bonds owned by PGE
|
(21
|
)
|
|
(21
|
)
|
||
Total long-term debt
|
2,361
|
|
|
2,204
|
|
||
Less: Unamortized debt expense
|
(11
|
)
|
|
(11
|
)
|
||
Less: Current portion of long-term debt
|
(150
|
)
|
|
(133
|
)
|
||
Long-term debt, net of current portion
|
$
|
2,200
|
|
|
$
|
2,060
|
|
|
|
|
|
•
|
$50 million
on May 4, 2016;
|
•
|
$75 million
on June 15, 2016; and
|
•
|
$25 million
on October 31, 2016.
|
|
2016
|
|
2015
|
||||||||||||||||||||
|
NQBP
|
|
Other NQBP
|
|
Total
|
|
NQBP
|
|
Other NQBP
|
|
Total
|
||||||||||||
Non-qualified benefit plan trust
|
$
|
16
|
|
|
$
|
18
|
|
|
$
|
34
|
|
|
$
|
15
|
|
|
$
|
18
|
|
|
$
|
33
|
|
Non-qualified benefit plan liabilities *
|
25
|
|
|
80
|
|
|
105
|
|
|
25
|
|
|
81
|
|
|
106
|
|
|
|
|
|
|
*
|
For the NQBP, excludes the current portion of
$2 million
in
2016
and
2015
, which are classified in Other current liabilities in the consolidated balance sheets.
|
|
As of December 31,
|
||||||||||
|
2016
|
|
2015
|
||||||||
|
Actual
|
|
Target *
|
|
Actual
|
|
Target *
|
||||
Defined Benefit Pension Plan:
|
|
|
|
|
|
|
|
||||
Equity securities
|
68
|
%
|
|
67
|
%
|
|
67
|
%
|
|
67
|
%
|
Debt securities
|
32
|
|
|
33
|
|
|
33
|
|
|
33
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
Other Postretirement Benefit Plans:
|
|
|
|
|
|
|
|
||||
Equity securities
|
60
|
%
|
|
62
|
%
|
|
60
|
%
|
|
64
|
%
|
Debt securities
|
40
|
|
|
38
|
|
|
40
|
|
|
36
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
Non-Qualified Benefits Plans:
|
|
|
|
|
|
|
|
||||
Equity securities
|
15
|
%
|
|
11
|
%
|
|
15
|
%
|
|
14
|
%
|
Debt securities
|
7
|
|
|
11
|
|
|
7
|
|
|
8
|
|
Insurance contracts
|
78
|
|
|
78
|
|
|
78
|
|
|
78
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
|
|
|
|
*
|
The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the Non-Qualified Benefit Plans, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and Non-Qualified Benefit Plans, reported percentages are affected by the fair market values of the investments within the pools.
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other *
|
|
Total
|
||||||||||
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
||||||||||
Defined Benefit Pension Plan assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity securities—Domestic
|
$
|
52
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
52
|
|
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
483
|
|
|
483
|
|
|||||
Private equity funds
|
—
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
18
|
|
|||||
|
$
|
52
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
507
|
|
|
$
|
559
|
|
Other Postretirement Benefit Plans assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
International
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Debt securities—Domestic government
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|||||
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|||||
|
$
|
12
|
|
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
11
|
|
|
$
|
30
|
|
As of December 31, 2015:
|
|
|
|
|
|
|
|
|
|
||||||||||
Defined Benefit Pension Plan assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity securities—Domestic
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
44
|
|
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
479
|
|
|
479
|
|
|||||
Private equity funds
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
22
|
|
|||||
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
506
|
|
|
$
|
550
|
|
Other Postretirement Benefit Plans assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Domestic
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
International
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Debt securities—Domestic government
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|||||
Investments measured at NAV:
|
|
|
|
|
|
|
|
|
|
||||||||||
Money market funds
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|||||
Collective trust funds
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|||||
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
14
|
|
|
$
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 2, Summary of Significant Accounting Policies.
|
|
Defined Benefit Pension Plan
|
|
Other Postretirement
Benefits
|
|
|
Non-Qualified
Benefit Plans
|
|||||||||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
2015
|
||||||||||||
Benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of January 1
|
$
|
758
|
|
|
$
|
777
|
|
|
$
|
81
|
|
|
|
$
|
83
|
|
|
|
$
|
27
|
|
|
$
|
27
|
|
Service cost
|
16
|
|
|
18
|
|
|
2
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||||
Interest cost
|
33
|
|
|
31
|
|
|
4
|
|
|
|
3
|
|
|
|
1
|
|
|
1
|
|
||||||
Participants’ contributions
|
—
|
|
|
—
|
|
|
2
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||||
Actuarial (gain) loss
|
26
|
|
|
(31
|
)
|
|
(11
|
)
|
|
|
(4
|
)
|
|
|
1
|
|
|
1
|
|
||||||
Contractual termination benefits
|
—
|
|
|
—
|
|
|
—
|
|
|
|
1
|
|
|
|
—
|
|
|
—
|
|
||||||
Benefit payments
|
(34
|
)
|
|
(35
|
)
|
|
(5
|
)
|
|
|
(6
|
)
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||
Administrative expenses
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||||
As of December 31
|
$
|
797
|
|
|
$
|
758
|
|
|
$
|
73
|
|
|
|
$
|
81
|
|
|
|
$
|
27
|
|
|
$
|
27
|
|
Fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
As of January 1
|
$
|
550
|
|
|
$
|
591
|
|
|
$
|
30
|
|
|
|
$
|
32
|
|
|
|
$
|
15
|
|
|
$
|
15
|
|
Actual return on plan assets
|
45
|
|
|
(4
|
)
|
|
1
|
|
|
|
(2
|
)
|
|
|
1
|
|
|
—
|
|
||||||
Company contributions
|
—
|
|
|
—
|
|
|
2
|
|
|
|
4
|
|
|
|
2
|
|
|
2
|
|
||||||
Participants’ contributions
|
—
|
|
|
—
|
|
|
2
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
||||||
Benefit payments
|
(34
|
)
|
|
(35
|
)
|
|
(5
|
)
|
|
|
(6
|
)
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||
Administrative expenses
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||||
As of December 31
|
$
|
559
|
|
|
$
|
550
|
|
|
$
|
30
|
|
|
|
$
|
30
|
|
|
|
$
|
16
|
|
|
$
|
15
|
|
Unfunded position as of December 31
|
$
|
(238
|
)
|
|
$
|
(208
|
)
|
|
$
|
(43
|
)
|
|
|
$
|
(51
|
)
|
|
|
$
|
(11
|
)
|
|
$
|
(12
|
)
|
Accumulated benefit plan obligation as of December 31
|
$
|
714
|
|
|
$
|
681
|
|
|
N/A
|
|
|
N/A
|
|
|
$
|
27
|
|
|
$
|
27
|
|
||||
Classification in consolidated balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Noncurrent asset
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
16
|
|
|
$
|
15
|
|
Current liability
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||
Noncurrent liability
|
(238
|
)
|
|
(208
|
)
|
|
(43
|
)
|
|
|
(51
|
)
|
|
|
(25
|
)
|
|
(25
|
)
|
||||||
Net liability
|
$
|
(238
|
)
|
|
$
|
(208
|
)
|
|
$
|
(43
|
)
|
|
|
$
|
(51
|
)
|
|
|
$
|
(11
|
)
|
|
$
|
(12
|
)
|
Amounts included in comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial loss (gain)
|
$
|
21
|
|
|
$
|
13
|
|
|
$
|
(10
|
)
|
|
|
$
|
—
|
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Amortization of net actuarial loss
|
(14
|
)
|
|
(20
|
)
|
|
—
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
(1
|
)
|
||||||
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
—
|
|
|
—
|
|
||||||
|
$
|
7
|
|
|
$
|
(7
|
)
|
|
$
|
(11
|
)
|
|
|
$
|
(2
|
)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Amounts included in AOCL*:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial loss (gain)
|
$
|
236
|
|
|
$
|
228
|
|
|
$
|
(2
|
)
|
|
|
$
|
9
|
|
|
|
$
|
13
|
|
|
$
|
13
|
|
Prior service cost
|
—
|
|
|
—
|
|
|
1
|
|
|
|
1
|
|
|
|
—
|
|
|
—
|
|
||||||
|
$
|
236
|
|
|
$
|
228
|
|
|
$
|
(1
|
)
|
|
|
$
|
10
|
|
|
|
$
|
13
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit Pension Plan
|
|
Other Postretirement
Benefits
|
|
|
Non-Qualified
Benefit Plans
|
|||||||||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
2015
|
||||||||||||
Assumptions used:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Discount rate for benefit obligation
|
4.17
|
%
|
|
4.36
|
%
|
|
3.75
|
%
|
-
|
|
3.90
|
%
|
-
|
|
4.17
|
%
|
|
4.36
|
%
|
||||||
|
|
|
|
|
4.23
|
%
|
|
|
4.45
|
%
|
|
|
|
|
|
||||||||||
Discount rate for benefit cost
|
4.36
|
%
|
|
4.02
|
%
|
|
3.90
|
%
|
-
|
|
3.07
|
%
|
-
|
|
4.36
|
%
|
|
4.02
|
%
|
||||||
|
|
|
|
|
4.45
|
%
|
|
|
4.10
|
%
|
|
|
|
|
|
||||||||||
Weighted average rate of compensation increase for benefit obligation
|
3.65
|
%
|
|
3.65
|
%
|
|
4.58
|
%
|
|
|
4.58
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
Weighted average rate of compensation increase for benefit cost
|
3.65
|
%
|
|
3.65
|
%
|
|
4.58
|
%
|
|
|
4.58
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
Long-term rate of return on plan assets for benefit obligation
|
7.50
|
%
|
|
7.50
|
%
|
|
6.26
|
%
|
|
|
6.29
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
Long-term rate of return on plan assets for benefit cost
|
7.50
|
%
|
|
7.50
|
%
|
|
6.29
|
%
|
|
|
6.37
|
%
|
|
|
N/A
|
|
|
N/A
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit
Pension Plan
|
|
Other Postretirement
Benefits
|
|
Non-Qualified
Benefit Plans
|
||||||||||||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||||||||
Service cost
|
$
|
16
|
|
|
$
|
18
|
|
|
$
|
15
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest cost on benefit obligation
|
33
|
|
|
31
|
|
|
34
|
|
|
4
|
|
|
3
|
|
|
4
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|||||||||
Expected return on plan assets
|
(40
|
)
|
|
(40
|
)
|
|
(39
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Amortization of net actuarial loss
|
14
|
|
|
20
|
|
|
17
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|||||||||
Net periodic benefit cost
|
$
|
23
|
|
|
$
|
29
|
|
|
$
|
27
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
6
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due
|
||||||||||||||||||||||
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022 - 2026
|
||||||||||||
Defined benefit pension plan
|
$
|
37
|
|
|
$
|
39
|
|
|
$
|
40
|
|
|
$
|
42
|
|
|
$
|
43
|
|
|
$
|
229
|
|
Other postretirement benefits
|
5
|
|
|
5
|
|
|
5
|
|
|
4
|
|
|
5
|
|
|
22
|
|
||||||
Non-qualified benefit plans
|
3
|
|
|
2
|
|
|
3
|
|
|
2
|
|
|
2
|
|
|
10
|
|
||||||
Total
|
$
|
45
|
|
|
$
|
46
|
|
|
$
|
48
|
|
|
$
|
48
|
|
|
$
|
50
|
|
|
$
|
261
|
|
•
|
For
2016
,
7%
annual rate of increase in the per capita cost of covered health care benefits was assumed for
2017
, decreasing to
6.5%
in 2018, then decreasing
0.25%
per year thereafter, reaching
5%
in 2023;
|
•
|
For
2015
,
6.5%
annual rate of increase in the per capita cost of covered health care benefits was assumed for
2016
, decreasing to
6.0%
in 2017, then decreasing
0.25%
per year thereafter, reaching
5%
in 2021; and
|
•
|
For
2014
,
7%
annual rate of increase in the per capita cost of covered health care benefits was assumed for
2015
, and assumed to decrease
0.5%
per year thereafter, reaching
5%
in 2019.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
10
|
|
|
$
|
4
|
|
|
$
|
20
|
|
State and local
|
3
|
|
|
1
|
|
|
2
|
|
|||
|
13
|
|
|
5
|
|
|
22
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
23
|
|
|
26
|
|
|
26
|
|
|||
State and local
|
14
|
|
|
14
|
|
|
13
|
|
|||
|
37
|
|
|
40
|
|
|
39
|
|
|||
Income tax expense
|
$
|
50
|
|
|
$
|
45
|
|
|
$
|
61
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Federal statutory tax rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
Federal tax credits *
|
(18.2
|
)
|
|
(19.0
|
)
|
|
(11.4
|
)
|
State and local taxes, net of federal tax benefit
|
4.8
|
|
|
4.2
|
|
|
3.9
|
|
Flow through depreciation and cost basis differences
|
0.2
|
|
|
—
|
|
|
(2.3
|
)
|
Other
|
(1.2
|
)
|
|
0.5
|
|
|
0.8
|
|
Effective tax rate
|
20.6
|
%
|
|
20.7
|
%
|
|
26.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
*
|
Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions. The PTCs are generated for 10 years from the corresponding facility’s in service date. PGE’s PTCs end at various dates between 2017 and 2024.
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
Deferred income tax assets:
|
|
|
|
||||
Employee benefits
|
$
|
181
|
|
|
$
|
170
|
|
Price risk management
|
59
|
|
|
112
|
|
||
Regulatory liabilities
|
29
|
|
|
42
|
|
||
Tax credits
|
56
|
|
|
46
|
|
||
Other
|
5
|
|
|
—
|
|
||
Total deferred income tax assets
|
330
|
|
|
370
|
|
||
Deferred income tax liabilities:
|
|
|
|
||||
Depreciation and amortization
|
829
|
|
|
781
|
|
||
Regulatory assets
|
170
|
|
|
220
|
|
||
Other
|
—
|
|
|
1
|
|
||
Total deferred income tax liabilities
|
999
|
|
|
1,002
|
|
||
Deferred income tax liability, net
|
$
|
(669
|
)
|
|
$
|
(632
|
)
|
|
Units
|
|
Weighted Average
Grant Date
Fair Value
|
|||
Outstanding as of December 31, 2013
|
431,090
|
|
|
$
|
26.31
|
|
Granted
|
203,410
|
|
|
31.49
|
|
|
Forfeited
|
(12,278
|
)
|
|
29.90
|
|
|
Vested
|
(158,329
|
)
|
|
24.95
|
|
|
Outstanding as of December 31, 2014
|
463,893
|
|
|
28.96
|
|
|
Granted
|
181,797
|
|
|
34.77
|
|
|
Forfeited
|
(14,988
|
)
|
|
34.10
|
|
|
Vested
|
(187,709
|
)
|
|
25.82
|
|
|
Outstanding as of December 31, 2015
|
442,993
|
|
|
32.84
|
|
|
Granted
|
193,734
|
|
|
35.89
|
|
|
Forfeited
|
(3,044
|
)
|
|
28.62
|
|
|
Vested
|
(174,891
|
)
|
|
31.47
|
|
|
Outstanding as of December 31, 2016
|
458,792
|
|
|
34.68
|
|
|
Years Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Weighted average common shares outstanding—basic
|
88,896
|
|
|
84,180
|
|
|
78,180
|
|
Dilutive effect of potential common shares
|
158
|
|
|
161
|
|
|
2,314
|
|
Weighted average common shares outstanding—diluted
|
89,054
|
|
|
84,341
|
|
|
80,494
|
|
|
Payments Due
|
||||||||||||||||||||||||||
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
Capital and other purchase commitments
|
$
|
176
|
|
|
$
|
8
|
|
|
$
|
2
|
|
|
$
|
9
|
|
|
$
|
1
|
|
|
$
|
60
|
|
|
$
|
256
|
|
Purchased power and fuel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electricity purchases
|
221
|
|
|
157
|
|
|
181
|
|
|
256
|
|
|
239
|
|
|
1,750
|
|
|
2,804
|
|
|||||||
Capacity contracts
|
7
|
|
|
6
|
|
|
5
|
|
|
4
|
|
|
4
|
|
|
12
|
|
|
38
|
|
|||||||
Public utility districts
|
4
|
|
|
4
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
11
|
|
|
21
|
|
|||||||
Natural gas
|
53
|
|
|
39
|
|
|
32
|
|
|
27
|
|
|
24
|
|
|
158
|
|
|
333
|
|
|||||||
Coal and transportation
|
17
|
|
|
9
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|||||||
Total
|
$
|
478
|
|
|
$
|
223
|
|
|
$
|
226
|
|
|
$
|
296
|
|
|
$
|
269
|
|
|
$
|
1,991
|
|
|
$
|
3,483
|
|
|
Revenue Bonds as of December 31, 2016
|
|
PGE’s Share as of December 31, 2016
|
|
Contract
Expiration
|
|
PGE Cost,
including Debt Service
|
||||||||||||||||
|
Output
|
|
Capacity
|
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||
|
|
|
|
|
(in MW)
|
|
|
|
|
|
|
|
|
||||||||||
Priest Rapids and Wanapum
|
$
|
1,190
|
|
|
8.6
|
%
|
|
163
|
|
|
2052
|
|
$
|
16
|
|
|
$
|
18
|
|
|
$
|
14
|
|
Wells
|
177
|
|
|
19.4
|
|
|
150
|
|
|
2018
|
|
10
|
|
|
10
|
|
|
10
|
|
||||
Portland Hydro
|
—
|
|
|
100.0
|
|
|
36
|
|
|
2017
|
|
1
|
|
|
2
|
|
|
4
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Minimum Lease Payments
|
||||||||||
|
Capital Leases
|
|
Build-to-Suit
|
|
Operating Leases
|
||||||
2017
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
10
|
|
2018
|
7
|
|
|
4
|
|
|
9
|
|
|||
2019
|
6
|
|
|
14
|
|
|
6
|
|
|||
2020
|
6
|
|
|
13
|
|
|
6
|
|
|||
2021
|
6
|
|
|
13
|
|
|
7
|
|
|||
Thereafter
|
77
|
|
|
237
|
|
|
177
|
|
|||
Total minimum lease payments
|
$
|
109
|
|
|
$
|
281
|
|
|
$
|
215
|
|
Less imputed interest
|
55
|
|
|
|
|
|
|||||
Present value of net minimum lease payments
|
$
|
54
|
|
|
|
|
|
||||
Less current portion
|
3
|
|
|
|
|
|
|||||
Non-current portion
|
$
|
51
|
|
|
|
|
|
|
PGE
Share
|
|
In-service Date
|
|
Plant
In-service
|
|
Accumulated
Depreciation*
|
|
Construction
Work In
Progress
|
|||||||||
Boardman
|
90.00
|
%
|
|
1980
|
|
$
|
514
|
|
|
$
|
400
|
|
|
$
|
—
|
|
||
Colstrip
|
20.00
|
|
|
1986
|
|
528
|
|
|
342
|
|
|
9
|
|
|||||
Pelton/Round Butte
|
66.67
|
|
|
1958
|
/
|
1964
|
|
255
|
|
|
63
|
|
|
5
|
|
|||
Total
|
|
|
|
|
|
|
$
|
1,297
|
|
|
$
|
805
|
|
|
$
|
14
|
|
|
|
|
|
|
*
|
Excludes AROs and accumulated asset retirement removal costs.
|
1.
|
that, because Abengoa S.A. has alleged that PGE wrongfully terminated the Construction Agreement, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and
|
2.
|
that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond.
|
|
Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
(In millions, except per share amounts)
|
||||||||||||||
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
|
|
||||
2015
|
|
|
|
|
|
|
|
||||||||
Revenues, net
|
$
|
473
|
|
|
$
|
450
|
|
|
$
|
476
|
|
|
$
|
499
|
|
Income from operations
|
85
|
|
|
72
|
|
|
68
|
|
|
84
|
|
||||
Net income
|
50
|
|
|
35
|
|
|
36
|
|
|
51
|
|
||||
Earnings per share:
*
|
|
|
|
|
|
|
|
||||||||
Basic
|
0.64
|
|
|
0.44
|
|
|
0.40
|
|
|
0.57
|
|
||||
Diluted
|
0.62
|
|
|
0.44
|
|
|
0.40
|
|
|
0.57
|
|
|
|
|
|
|
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*
|
Third Amended and Restated Articles of Incorporation of Portland General Electric Company (Form 8-K filed May 9, 2014, Exhibit 3.1).
|
3.2*
|
Tenth Amended and Restated Bylaws of Portland General Electric Company (Form 8-K filed May 9, 2014, Exhibit 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*
|
Sixty-second Supplemental Indenture dated April 1, 2009 (Form 8-K filed April 16, 2009, Exhibit 4.1) (File No. 001-05532-99).
|
(10)
|
Material Contracts
|
10.1*
|
Amended and Restated Credit Agreement dated March 6, 2015 between Portland General Electric Company and Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A., Barclays Bank PLC, JPMorgan Chase Bank, N.A. and U.S. Bank National Association (Form 10-Q filed April 27, 2015, Exhibit 10.1).
|
10.2
|
Portland General Electric Company Severance Pay Plan for Executive Employees, as amended and restated effective February 14, 2017. +
|
10.3*
|
Portland General Electric Company Outplacement Assistance Plan dated June 15, 2005 (Form 8-K filed June 20, 2005, Exhibit 10.2) (File No. 001-05532-99). +
|
10.4*
|
Portland General Electric Company 2005 Management Deferred Compensation Plan dated January 1, 2005 (Form 10-K filed March 11, 2005, Exhibit 10.18) (File No. 001-05532-99). +
|
10.5*
|
Portland General Electric Company Management Deferred Compensation Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.1) (File No. 001-05532-99). +
|
10.6*
|
Portland General Electric Company Supplemental Executive Retirement Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.2) (File No. 001-05532-99). +
|
10.7*
|
Portland General Electric Company Senior Officers’ Life Insurance Benefit Plan dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.3) (File No. 001-05532-99). +
|
10.8*
|
Portland General Electric Company Umbrella Trust for Management dated March 12, 2003 (Form 10-Q filed May 15, 2003, Exhibit 10.4) (File No. 001-05532-99). +
|
10.9*
|
Portland General Electric Company 2006 Stock Incentive Plan, as amended (Form 10-K filed February 27, 2008, Exhibit 10.23) (File No. 001-05532-99). +
|
10.10*
|
Portland General Electric Company 2006 Annual Cash Incentive Master Plan (Form 8-K filed March 17, 2006, Exhibit 10.1) (File No. 001-05532-99). +
|
10.11*
|
Portland General Electric Company 2006 Outside Directors’ Deferred Compensation Plan (Form 8-K filed May 17, 2006, Exhibit 10.1) (File No. 001-05532-99). +
|
10.12*
|
Portland General Electric Company 2008 Annual Cash Incentive Master Plan for Executive Officers (Form 8-K filed February 26, 2008, Exhibit 10.1) (File No. 001-05532-99). +
|
10.13*
|
Form of Portland General Electric Company Agreement Concerning Indemnification and Related Matters (Form 8-K filed December 24, 2009, Exhibit 10.1) (File No. 001-05532-99). +
|
Exhibit
Number
|
Description
|
10.14*
|
Form of Portland General Electric Company Agreement Concerning Indemnification and Related Matters for Officers and Key Employees (Form 8-K filed February 19, 2010, Exhibit 10.1). +
|
10.15*
|
Form of Directors’ Restricted Stock Unit Agreement (Form 8-K filed July 14, 2006, Exhibit 10.1) (File No. 001-05532-99). +
|
10.16*
|
Form of Officers’ and Key Employees’ Performance Stock Unit Agreement (Form 10-Q filed May 3, 2012, Exhibit 10.1) (File No. 001-05532-99). +
|
(12)
|
Statements Re Computation of Ratios
|
12.1
|
Computation of Ratio of Earnings to Fixed Charges.
|
(23)
|
Consents of Experts and Counsel
|
23.1
|
Consent of Independent Registered Public Accounting Firm Deloitte & Touche LLP.
|
(31)
|
Rule 13a-14(a)/15d-14(a) Certifications
|
31.1
|
Certification of Chief Executive Officer.
|
31.2
|
Certification of Chief Financial Officer.
|
(32)
|
Section 1350 Certifications
|
32.1
|
Certifications of Chief Executive Officer and Chief Financial Officer.
|
(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/ JAMES J. PIRO
|
|
|
James J. Piro
|
|
|
President and Chief Executive Officer
|
Signature
|
Title
|
|
|
/s/ JAMES J. PIRO
|
President, Chief Executive Officer, and Director
(principal executive officer)
|
James J. Piro
|
|
|
|
/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
|
|
(a)
|
Termination for Cause
. The Employee’s employment is terminated for Cause;
|
(b)
|
Short Term Layoff with Potential of Recall
. The Employee is laid off for a period of short duration and subject to recall within a reasonable time, as determined by the Company;
|
(c)
|
Offer of Position
. In connection with an Employee’s removal from a position, the Employee (i) receives an offer of employment from the Company or a Divested Employer or any of their respective affiliates, provided that the conditions of such offer would not have constituted Good Reason, or (ii) accepts an offer of employment at any salary or location from the Company or a Divested Employer or any of their respective affiliates, regardless of whether the requirements of (i) above are satisfied;
|
(d)
|
Other Severance or Termination Benefits
. The Employee receives extra or additional consideration outside of the Plan in connection with the Employee’s termination of, or retirement from, employment (including by way of example, but not limited to, enhanced retirement benefits or incentive remuneration), and the Committee makes a determination that a severance benefit under the Plan should not be paid; or
|
(e)
|
Other Special Circumstances
. Special circumstances exist for which the Chief Executive Officer of the Company makes a written determination that a severance benefit will not be paid.
|
2.
|
PGE will provide you final distribution of all amounts payable to you under the Severance Pay Plan (totaling approximately $
[X]
) during the period provided for under the plan (expected to be approximately
[X]
following your termination date). The following taxes will be withheld: State of Oregon and federal withholding.
|
3.
|
As a management employee, you are eligible to participate in the Outplacement Assistance Plan. Each management employee will be offered the services of a professional outplacement firm selected by PGE for not less than three months, with the option to extend the services for an additional three months or such additional period as permitted by the Benefits Administration Committee. PGE will pay 100 percent of the cost of your outplacement services.
[NAME]
, PGE Plan Administrator, 121 SW Salmon Street, Portland, Oregon 97204, 503-464-2023, will coordinate your start date with the outplacement consultant. You are responsible for initiating the services of an outplacement consultant within 30 days of termination of employment. Please notify
[NAME]
of your intentions as soon as possible.
|
4.
|
If you are rehired within one year of the date of termination, you will be required to repay that portion of your severance benefit which is in excess of the amount of base pay you would have received if you had remained employed at your rate of base pay at termination until the date of your reemployment.
|
5.
|
PGE will provide employment references stating your term of employment and job title. Any information beyond this must be authorized by you in writing.
|
6.
|
Eligibility factor(s) to qualify for the Severance Pay Plan and Outplacement Assistance Plan are as set forth in the plan documents.
|
7.
|
Please write below on the lines provided: “I am agreeing to the release, representations and covenants forth in section 1 voluntarily with full understanding of their effect.”
|
8.
|
This agreement was first presented to you for consideration on
[DATE]
.
|
9.
|
WE ADVISE THAT YOU SEEK THE ADVICE OF A LAWYER BEFORE SIGNING THIS AGREEMENT. YOU HAVE FORTY-FIVE (45) DAYS TO CONSIDER THIS AGREEMENT BEFORE SIGNING.
|
10.
|
You have seven (7) days to revoke following execution of this agreement. The agreement will not be effective or enforceable until seven (7) days have expired from the day you sign it.
|
PORTLAND GENERAL ELECTRIC COMPANY
|
|||||||||||||||||||
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
|
|||||||||||||||||||
(Dollars in thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Years Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from continuing operations before income taxes
|
$
|
243,108
|
|
|
$
|
216,818
|
|
|
$
|
236,679
|
|
|
$
|
125,758
|
|
|
$
|
205,406
|
|
Total fixed charges
|
132,654
|
|
|
135,956
|
|
|
128,515
|
|
|
118,189
|
|
|
122,851
|
|
|||||
Total earnings
|
$
|
375,762
|
|
|
$
|
352,774
|
|
|
$
|
365,194
|
|
|
$
|
243,947
|
|
|
$
|
328,257
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
$
|
111,539
|
|
|
$
|
113,861
|
|
|
$
|
96,068
|
|
|
$
|
100,818
|
|
|
$
|
107,992
|
|
Capitalized interest
|
10,820
|
|
|
12,520
|
|
|
22,441
|
|
|
6,892
|
|
|
3,699
|
|
|||||
Interest on certain long-term power contracts
|
4,946
|
|
|
5,140
|
|
|
5,137
|
|
|
5,996
|
|
|
6,643
|
|
|||||
Estimated interest factor in rental expense
|
5,349
|
|
|
4,435
|
|
|
4,869
|
|
|
4,483
|
|
|
4,517
|
|
|||||
Total fixed charges
|
$
|
132,654
|
|
|
$
|
135,956
|
|
|
$
|
128,515
|
|
|
$
|
118,189
|
|
|
$
|
122,851
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
2.83
|
|
|
2.59
|
|
|
2.84
|
|
|
2.06
|
|
|
2.67
|
|
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;
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4.
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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:
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(a)
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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;
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(b)
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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;
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(c)
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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
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(d)
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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
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5.
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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):
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(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
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(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.
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Date:
February 16, 2017
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/s/ JAMES J. PIRO
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|
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James J. Piro
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|
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President and
Chief Executive Officer
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1.
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I have reviewed this Annual Report on Form 10-K of Portland General Electric Company;
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2.
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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;
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3.
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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 16, 2017
|
|
/s/ JAMES F. LOBDELL
|
|
|
James F. Lobdell
|
|
|
Senior Vice President of Finance, Chief Financial Officer, and Treasurer
|
/s/ JAMES J. PIRO
|
|
/s/ JAMES F. LOBDELL
|
James J. Piro
|
|
James F. Lobdell
|
President and
Chief Executive Officer
|
|
Senior Vice President of Finance, Chief Financial Officer and Treasurer
|
|
|
|
Date:
February 16, 2017
|
|
Date:
February 16, 2017
|