News Release Details

Portland General Electric Reports 2017 Financial Results and Initiates 2018 Earnings Guidance

February 16, 2018 at 5:00 AM EST

  • Full-year 2017 financial results on target excluding the effects of the Tax Cuts and Jobs Act
  • Initiating 2018 earnings guidance of $2.10 to $2.25 per diluted share
  • Filed 2019 General Rate Case with the Oregon Public Utility Commission

PORTLAND, Ore.--(BUSINESS WIRE)-- Portland General Electric Company (NYSE: POR) today reported net income based on generally accepted accounting principles (GAAP) of $187 million, or $2.10 per diluted share, for the year ended December 31, 2017. This compares with $193 million, or $2.16 per diluted share, for the year ended December 31, 2016. After adjusting for the impacts of the Tax Cuts and Jobs Act (TCJA), non-GAAP net income was $204 million, or $2.29 per diluted share, for the year ended December 31, 2017. GAAP-based net income was $42 million, or 48 cents per diluted share, for the fourth quarter of 2017. This compares with $61 million, or 68 cents per diluted share, for the comparable period of 2016. After adjusting for the impacts of the TCJA, non-GAAP net income was $59 million, or 67 cents per diluted share, for the fourth quarter of 2017. Looking forward, the company is initiating full-year 2018 earnings guidance of $2.10 to $2.25 per diluted share.

"I'm very proud of our employees' accomplishments in delivering outstanding service to our growing customer base and in collaborating with our stakeholders and customers on our Integrated Resource Plan," said Maria Pope, president and CEO. "We are focused on meeting customer expectations for safe, reliable, affordable, clean and secure energy."

2017 earnings compared to 2016 earnings

Before reflecting the impact of the TCJA, annual earnings per diluted share increased year-over-year. Favorable weather had a positive impact on gross margin. This impact was partially offset by adjustments to net deferred taxes as a result of the TCJA, increased service restoration expenses resulting from unusually high storm activity, and depreciation expense and carrying costs related to previously reported incremental construction costs for Carty. Additionally, annual earnings per diluted share decreased due to lower production tax credit generation, higher depreciation and amortization expenses related to additional investments, and higher employee benefits expenses.

2018 earnings guidance

PGE is initiating full-year 2018 earnings guidance of $2.10 to $2.25 per diluted share, which includes the impact of warmer than normal weather in January 2018. Additional assumptions include the following:

  • A decline in retail deliveries between 0 and 1 percent, weather adjusted;
  • Average hydro conditions;
  • Wind generation based on five years of historical levels or forecast studies when historical data is not available;
  • Normal thermal plant operations;
  • Operating and maintenance costs between $575 and $595 million; and
  • Depreciation and amortization expense between $365 and $385 million.

The guidance provided assumes OPUC approval of the Company's intended filing of a deferral application to recover the revenue requirement associated with the customer information system replacement project (Customer Touchpoints), which is expected to be placed in service in the second quarter of 2018.

Company Updates

2019 General Rate Case

On February 15, 2018, PGE filed a general rate case with a 2019 test year (2019 GRC), which would result in an overall customer price increase of 4.8 percent, after adjusting for the effects of the TCJA, effective in January of 2019.

"We are respectful of the impact price increases can have on our customers, and we are committed to protecting affordability," said Pope. "We're making necessary investments in our grid to maintain the safe and reliable service customers expect, and we're upgrading our customer service systems to provide better, more secure service."

PGE's grid investments include:

  • Replacing or upgrading electrical equipment that poses a reliability risk
  • Equipping substations with technology that will shorten outages
  • Strengthening IT systems to protect against cyber and other potential threats
  • Adding infrastructure to accommodate rapid growth in the region while maintaining reliability for all customers

The requested price increase reflects:

  • Return on equity of 9.5 percent
  • Capital structure of 50 percent debt and 50 percent equity
  • Cost of capital of 7.31 percent
  • Rate base of $4.86 billion
  • Annual revenue increase of $86 million, net of customer credits and supplemental tariff updates

PGE expects the Commission to issue a final order in December 2018, with new prices effective in January of 2019. The specific impact on individual customers' bills will vary depending on usage and customer class. If the OPUC approves PGE's request as submitted, typical residential customers using a monthly average of 800 kilowatt-hours of power would see their bill increase by about $6.50 per month.

2018 General Rate Case

On January 1, 2018, new customer prices went into effect pursuant to the OPUC order issued in PGE's 2018 GRC. The OPUC authorized a $16 million increase in annual revenues, representing an approximate 1 percent overall increase in customer prices. In addition, the order approved a capital structure of 50 percent debt and 50 percent equity, a return on equity of 9.5 percent, a cost of capital of 7.35 percent, and a rate base of $4.5 billion.

The general rate case filings, as well as copies of the orders, direct testimony, exhibits, and stipulations are available on the OPUC website at

Integrated Resource Planning

In November 2016, PGE filed an IRP (2016 IRP) with the Oregon Public Utility Commission (OPUC). The 2016 IRP addressed acquisition of additional resources to meet Renewable Portfolio Standard (RPS) requirements and replace energy and capacity from Boardman, which will cease coal-fired operations at the end of 2020. Further actions identified through 2021 are expected to offset expiring power purchase agreements and integrate variable energy resources, such as wind or solar generation facilities.

In August 2017, the OPUC acknowledged PGE's 2016 IRP and the following primary action plan items:

  • Meet additional capacity needs of 561 MW, of which 240 MW must be dispatchable, in 2021;
  • Acquire a total of 135 MWa of cost-effective energy efficiency;
  • Acquire at least 77 MW (winter) and 69 MW (summer) demand response through 2020 and 16 MW of dispatchable standby generation from customers to help manage peak load conditions and other supply contingencies;
  • Submit one or more energy storage proposals, and;
  • Perform voltage reduction and various research and studies related to flexible capacity and curtailment metrics, customer insights, decarbonization, risks associated with Direct Access, treatment of market capacity, accessing resources from Montana, and load forecasting improvements.

In December 2017, PGE received acknowledgement from the OPUC of the filed addendum to the 2016 IRP for the procurement of 100 MWa of RPS compliant renewable resources.

Since issuing the 2016 IRP, PGE has identified a potential benchmark wind resource that could have a nameplate capacity of up to 300 MW that would meet the acknowledged need for renewable resources and qualify for the federal Production Tax Credit. The Company continues to explore this option and should due diligence be completed and agreements reached, the potential benchmark resource would be submitted into the RFP and considered along with other renewable resource proposals. The RFP process will include oversight by an independent evaluator and review by the OPUC.

In December 2017, the OPUC approved PGE's application for waiver of the competitive bidding guidelines for the procurement of capacity. PGE has now finalized bilateral power purchase agreements for a total capacity of 300 MW.

Tax Reform

On December 22, 2017, the TCJA was enacted and signed into law with an effective date of January 1, 2018. The reduction of the federal corporate tax rate from 35% to 21% required the Company to remeasure its existing deferred income tax balances as of December 31, 2017. As a result of the Company's remeasurement, net deferred tax liabilities on the Company's consolidated balance sheets were reduced by $340 million.

Of the remeasurement amount, $357 million has been deferred as a regulatory liability and is expected to be refunded to customers over time. The remaining remeasurement amount of $17 million represents a reduction to net deferred tax assets related to other business items, primarily comprised of deferred tax assets related to the Company's non-qualified employee benefit plans. The Company has recorded a $17 million charge to the results of operations, reflected as an increase in income tax expense in the Company's consolidated statements of income for the period ended December 31, 2017.

As a result of the TCJA, PGE expects to incur lower income tax expense in 2018 than what was estimated in setting customer prices in the Company's 2018 GRC. In addition to the effects of the 2017 remeasurement of deferred income taxes, PGE has proposed to defer and refund the 2018 expected net benefits of the TCJA under a deferral application filed with the OPUC on December 29, 2017. If approved as requested, any refund to customers of the net benefits associated with the TCJA in 2018 would be subject to an earnings test and limited by the Company's previously authorized regulated return on equity.

The impact of the TCJA may differ from these amounts due to, among other things, changes in interpretations and assumptions the Company has made; federal tax regulations, guidance or orders that may be issued by the U.S. Department of the Treasury, Internal Revenue Service, and OPUC; and actions the Company may take as a result of the TCJA.

2017 Annual Operating Results

Earnings Reconciliation of 2016 to 2017
($ in millions, except EPS)   Pre-Tax Income     Net Income*   Diluted EPS***
Reported 2016   $243     $193   $2.16
Electric retail price change (5) (3) (0.04)
Electric retail volume change 71 43 0.48
Change in decoupling deferral 10 6 0.07
Electric wholesale price and volume change 2 1 0.02
Other Items 8     5   0.06
Change in Revenue   86     52   0.59
Power Cost              
Change in average power cost 38 23 0.25
Change purchased power and generation (13)     (8)   (0.09)
Change in Power Costs   25     15   0.16
Generation, transmission, distribution (23) (14) (0.15)
Administrative and general (17)     (10)   (0.11)
Change in O&M   (40)     (24)   (0.26)
Other Items              
Depreciation & amortization (24) (15) (0.16)
AFDC Equity** (9) (9) (0.10)
Other Items (8) (5) (0.06)
Production Tax Credits (7) (0.08)
Tax Reform: Net Deferred Tax Asset Remeasurement (17) (0.19)
Adjustment for effective vs statutory tax rate       3   0.04
Change in Other Items   (41)     (50)   (0.55)
Reported 2017   $273     $187   $2.10
Non-GAAP Earnings Reconciliation for the three and twelve months ended December 31, 2017
($ in millions, except EPS)
GAAP-based as reported for the twelve months ended December 31, 2017 $187 $2.10
Exclusion of Tax Reform Remeasurement 17   0.19
Non-GAAP adjusted earnings for the twelve months ended December 31, 2017 $204 $2.29
GAAP-based as reported for the three months ended December 31, 2017 $42 $0.48
Exclusion of Tax Reform Remeasurement 17   0.19
Non-GAAP adjusted earnings for the three months ended December 31, 2017     $59   $0.67
* After tax adjustments based on PGE's statutory tax rate of 39.5%
** Statutory tax rate does not apply to AFDC equity
*** Some values may not foot due to rounding

Revenues increased $86 million, or 4.5%, in 2017 compared with 2016 as a result of the items discussed below.

Total retail revenues increased $77 million, or 4.3%, in 2017 compared with 2016, primarily due to the net effect of:

  • A $71 million increase due to a 3.9% increase in retail energy deliveries consisting of a 7.2% increase in residential deliveries, a 2.8% increase in industrial deliveries, and a 1.3% increase in commercial deliveries. Considerably cooler temperatures in the first half of 2017 than experienced in 2016 combined with warmer temperatures in the summer cooling season in 2017, both drove deliveries higher in 2017 than in 2016.
  • A $10 million increase resulting from the Decoupling mechanism, as an estimated $13 million collection was recorded in 2017; and
  • A $5 million increase, directly offset in Depreciation and amortization expense, related to the accelerated cost recovery of Colstrip, partially offset by
  • A $5 million reduction as a result of overall price changes, which includes a $55 million reduction in revenues attributable to lower NVPC, as filed in the 2017 AUT; and
  • A $3 million decrease due to higher customer credits related to the USDOE settlement in connection with operation of the ISFSI at the former Trojan nuclear power plant site. Such credits are directly offset in Depreciation and amortization expense.

Total heating degree-days in 2017 were above the 15-year average and considerably greater than total heating degree-days in 2016. Total cooling degree-days in 2017 exceeded the 15-year average by 49% and were considerably higher than 2016. The following table presents the number of heating and cooling degree-days in 2017 and 2016, along with the 15-year averages, reflecting that weather had a considerable influence on comparative energy deliveries:

  Heating Degree-Days   Cooling Degree-Days
  2017       2016      


  2017       2016      


1st quarter 2,171   1,585   1,867    
2nd quarter 686 403 689 129 154 70
3rd quarter 78 78 78 571 394 399
4th quarter   1,623     1,486     1,599             2  
Total   4,558     3,552     4,233     700     548     471  
Increase (decrease) from the 15-year average   8 %   (16 )%   49 %   16 %

On a weather-adjusted basis, total retail energy deliveries in 2017 were 0.6% below 2016 levels. PGE projects that retail energy deliveries for 2018 will be nearly comparable to slightly lower than 2017 weather-adjusted levels, reflecting the closure of a large paper customer in late 2017 as well as continued energy efficiency and conservation efforts.

Wholesale revenues result from sales of electricity to utilities and power marketers made in the Company's efforts to secure reasonably priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand.

In 2017, the $2 million, or 2%, increase in wholesale revenues from 2016 consisted of a $7 million increase that resulted as a 7% increase in average prices was received when the Company sold power into the wholesale market, partially offset by a $5 million decrease related to 5% less wholesale sales volume.

Other operating revenues increased $7 million, or 19%, in 2017 from 2016, as the sale of excess natural gas not used to fuel the Company's generating facilities accounted for the majority of the increase.

Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale revenues, decreased $27 million in 2017 compared with 2016. The decrease attributable to changes in Purchased power and fuel expense was the result of a 6% decline in the average variable power cost per MWh, offset slightly by a 2% increase in total system load. The decrease in actual NVPC was also driven by a 7% increase in the average price per MWh of wholesale power sales, offset slightly by a 5% decrease in the volume of wholesale energy deliveries as a greater portion of its system load was used to meet retail load requirements, largely due to the effects of weather.

For 2017, actual NVPC, as calculated for regulatory purposes under the PCAM, was $15 million above the 2017 baseline NVPC. In 2016, NVPC was $10 million below the anticipated baseline.

Generation, transmission, and distribution expense increased $23 million, or 8%, in 2017 compared with 2016. The increase was driven by the combination of $10 million in higher costs due to the addition of Carty, $8 million higher service restoration and storm costs, $3 million higher plant maintenance expenses, and $2 million higher information technology expenses.

Administrative and other expense increased $17 million, or 7%, in 2017 compared with 2016, primarily due to $12 million higher overall labor and employee benefit expenses and $3 million higher legal costs attributable to Carty.

Depreciation and amortization expense in 2017 increased $24 million, or 7%, compared with 2016. The increase was primarily driven by $26 million higher expense resulting from capital additions, offset by a $3 million reduction in expense due to higher amortization credits in 2017 of the regulatory liability for the ISFSI spent fuel settlement. The overall impact resulting from the amortization of the regulatory assets and liabilities is directly offset by corresponding reductions in retail revenues.

Taxes other than income taxes expense increased $4 million, or 3%, in 2017 compared with 2016, driven by $2 million higher Oregon property taxes and $2 million higher payroll taxes.

Interest expense increased $8 million, or 7%, in 2017 compared with 2016 due to a $4 million decrease in the credits for the allowance for borrowed funds used during construction (primarily due to the Carty plant being placed in service in 2016) and increased expense of $3 million resulting from a 5% increase in the average balance of debt outstanding.

Other income, net was $17 million in 2017 compared to $22 million in 2016, with the decrease primarily due to lower allowance for equity funds used during construction, which resulted from Carty being placed in service during 2016.

Income tax expense increased $36 million, or 72%, in 2017 compared to 2016. The change relates to a $13 million increase due to higher pre-tax income and $7 million due to lower production tax credits. Additionally, income tax expense increased $17 million due to the remeasurement of deferred taxes pursuant to the change in corporate tax rates in the TCJA.

Fourth Quarter 2017 earnings call and web cast — Feb. 16, 2018

PGE will host a conference call with financial analysts and investors on Friday, Feb. 16, 2018, at 11 a.m. ET. The conference call will be web cast live on the PGE website at A replay of the call will be available beginning at 2 p.m. ET on Friday, Feb. 16, 2018 through Friday, Feb. 23, 2018.

Maria Pope, president and CEO; Jim Lobdell, senior vice president of finance, CFO, and treasurer; and Chris Liddle, manager, investor relations and treasury, will participate in the call. Management will respond to questions following formal comments.

The attached unaudited consolidated statements of income, condensed consolidated balance sheets, and condensed consolidated statements of cash flows, as well as the supplemental operating statistics, are an integral part of this earnings release.

About Portland General Electric Company

Portland General Electric Company is a vertically integrated electric utility that serves approximately 875,000 residential, commercial and industrial customers in the Portland/Salem metropolitan area of Oregon. The company's headquarters are located at 121 S.W. Salmon Street, Portland, Oregon 97204. Visit PGE's website at

Safe Harbor Statement

Statements in this news release that relate to future plans, objectives, expectations, performance, events and the like may constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include statements regarding earnings guidance; statements regarding future load, hydro conditions, wind conditions and operating and maintenance costs; statements concerning implementation of the company's integrated resource plan; statements concerning future compliance with regulations limiting emissions from generation facilities and the costs to achieve such compliance; as well as other statements containing words such as "anticipates," "believes," "intends," "estimates," "promises," "expects," "should," "conditioned upon," and similar expressions. Investors are cautioned that any such forward-looking statements are subject to risks and uncertainties, including reductions in demand for electricity and the sale of excess energy during periods of low wholesale market prices; operational risks relating to the company's generation facilities, including hydro conditions, wind conditions, disruption of fuel supply, and unscheduled plant outages, which may result in unanticipated operating, maintenance and repair costs, as well as replacement power costs; the costs of compliance with environmental laws and regulations, including those that govern emissions from thermal power plants; changes in weather, hydroelectric and energy markets conditions, which could affect the availability and cost of purchased power and fuel; changes in capital market conditions, which could affect the availability and cost of capital and result in delay or cancellation of capital projects; failure to complete capital projects on schedule or within budget, or the abandonment of capital projects which could result in the company's inability to recover project costs; the outcome of various legal and regulatory proceedings; and general economic and financial market conditions. As a result, actual results may differ materially from those projected in the forward-looking statements. All forward-looking statements included in this news release are based on information available to the company on the date hereof and such statements speak only as of the date hereof. The company assumes no obligation to update any such forward-looking statement. Prospective investors should also review the risks and uncertainties listed in the company's most recent annual report on form 10-K and the company's reports on forms 8-K and 10-Q filed with the United States Securities and Exchange Commission, including management's discussion and analysis of financial condition and results of operations and the risks described therein from time to time.


Source: Portland General Electric Company




(In millions, except per share amounts)




Three Months Ended Years Ended
December 31, December 31,
2017     2016 2017     2016
Revenues, net $ 515 $ 524 $ 2,009 $ 1,923
Operating expenses:
Purchased power and fuel 149 162 592 617
Generation, transmission and distribution 74 87 309 286
Administrative and other 67 62 264 247
Depreciation and amortization 88 77 345 321
Taxes other than income taxes 29   30   123   119
Total operating expenses 407   418   1,633   1,590
Income from operations 108 106 376 333
Interest expense, net 30 30 120 112
Other income:
Allowance for equity funds used during construction 3 2 12 21
Miscellaneous income, net 1   1   5   1
Other income, net 4   3   17   22
Income before income taxes 82 79 273 243
Income taxes 40   18   86   50
Net income 42   61   187   193
Weighted-average shares outstanding (in thousands):
Basic 89,056   88,927   89,056   88,896
Diluted 89,176   89,085   89,176   89,054
Earnings per share:
Basic $ 0.48   $ 0.68   $ 2.10   $ 2.17
Diluted $ 0.48   $ 0.68   $ 2.10   $ 2.16



(In millions)


As of December 31,
2017     2016
Current assets:
Cash and cash equivalents $ 39 6
Accounts receivable, net 168 155
Unbilled revenues 106 107
Inventories, at average cost:
Materials and supplies 52 50
Fuel 26 32
Regulatory assets—current 62 36
Other current assets 73   77  
Total current assets 526 463
Electric utility plant:
Generation 4,667 4,597
Transmission 547 521
Distribution 3,543 3,343
General 550 501
Intangible 607 572
Construction work-in-progress 391   213  
Total electric utility plant 10,305 9,747
Accumulated depreciation and amortization (3,564 ) (3,313 )
Electric utility plant, net 6,741 6,434
Regulatory assets - noncurrent 438 498
Nuclear decommissioning trust 42 41
Non-qualified benefit plan trust 37 34
Other noncurrent assets 54   57  
Total assets 7,838   7,527  



(In millions)


As of December 31,
2017       2016
Current liabilities:
Accounts payable $ 132 $ 129
Liabilities from price risk management activities—current 59 44
Current portion of long-term debt 150
Accrued expenses and other current liabilities 241         254  
Total current liabilities 432         577  
Long-term debt, net of current portion 2,426 2,200
Regulatory liabilities—noncurrent 1,288 958
Deferred income taxes 376 669
Unfunded status of pension and postretirement plans 284 281
Liabilities from price risk management activities—noncurrent 151 125
Asset retirement obligations 167 161
Non-qualified benefit plan liabilities 106 105
Other noncurrent liabilities 192         107  
Total liabilities 5,422         5,183  
Commitments and contingencies
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding
Common stock, no par value, 160,000,000 shares authorized; 89,114,265 and 88,946,704 shares issued and outstanding as of December 31, 2017 and 2016, respectively 1,207 1,201
Accumulated other comprehensive loss (8 ) (7 )
Retained earnings 1,217         1,150  
Total equity 2,416         2,344  
Total liabilities and equity $ 7,838         $ 7,527  



(In millions)


Years Ended December 31,
2017     2016     2015
Cash flows from operating activities:
Net income $ 187 $ 193 $ 172
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 345 321 305
Deferred income taxes 70 37 40
Allowance for equity funds used during construction (12 ) (21 ) (21 )
Pension and other postretirement benefits 24 28 34
Unrealized losses on non-qualified benefit plan trust assets 2 5 6
Decoupling mechanism deferrals, net of amortization (22 ) (6 ) 14
Other non-cash income and expenses, net 29 7 22
Changes in working capital:
(Increase) in receivables and unbilled revenues (3 ) (9 ) (11 )
(Increase) decrease in margin deposits (3 ) 25 (22 )
Increase in payables and accrued liabilities 5 15 6
Other working capital items, net 1 (4 ) (4 )
Contribution to non-qualified employee benefit trust (8 ) (10 ) (9 )
Other, net (18 ) (28 ) (12 )
Net cash provided by operating activities 597   553   520  
Cash flows from investing activities:
Capital expenditures (514 ) (584 ) (598 )
Purchases of nuclear decommissioning trust securities (18 ) (25 ) (19 )
Sales of nuclear decommissioning trust securities 21 27 22
Distribution from nuclear decommissioning trust 50
Sales tax refund received - Tucannon River Wind Farm 23
Other, net (3 ) (3 )  
Net cash used in investing activities (514 ) (585 ) (522 )
Cash flows from financing activities:
Proceeds from issuance of long-term debt $ 225 $ 290 $ 145
Payments on long-term debt (150 ) (133 ) (442 )
Proceeds from issuances of common stock, net of issuance costs 271
(Maturities) issuances of commercial paper, net (6 ) 6
Dividends paid (118 ) (110 ) (97 )
Other (7 ) (7 ) (4 )
Net cash (used in) provided by financing activities (50 ) 34   (121 )
Increase (decrease) in cash and cash equivalents 33 2 (123 )
Cash and cash equivalents, beginning of year 6   4   127  
Cash and cash equivalents, end of year $ 39   $ 6   $ 4  
Supplemental disclosures of cash flow information:
Cash paid for:
Interest, net of amounts capitalized $ 110 $ 104 $ 108
Income taxes 18 16 3
Non-cash investing and financing activities:
Accrued capital additions 53 50 32
Accrued dividends payable 31 30 28
Assets obtained under leasing arrangements 87 78




Three Months Ended Years Ended
December 31, December 31,
2017     2016 2017     2016
Revenues (dollars in millions):
Residential $ 254 $ 259 $ 969 $ 907
Commercial 168 173 669 665
Industrial 54   55   212   208
Subtotal 476 487 1,850 1,780
Other accrued (deferred) revenues, net 3   (2 ) 10   3
Total retail revenues 479 485 1,860 1,783
Wholesale revenues 26 29 105 103
Other operating revenues 10   10   44   37
Total revenues $ 515   $ 524   $ 2,009   $ 1,923
Energy sold and delivered (MWh in thousands):
Retail energy sales:
Residential 2,053 2,070 7,880 7,348
Commercial 1,739 1,784 6,932 6,932
Industrial 756 800 2,943 2,968
Total retail energy sales 4,548 4,654 17,755 17,248
Direct access retail deliveries:
Commercial 151 122 623 525
Industrial 295 290 1,340 1,198
Total direct access retail deliveries 446 412 1,963 1,723
Total retail energy sales and direct access deliveries 4,994 5,066 19,718 18,971
Wholesale energy deliveries 857 731 3,193 3,352
Total energy sold and delivered 5,851 5,797 22,911 22,323
Average number of retail customers:
Residential 762,211 752,365
Commercial 107,364 106,460
Industrial 199 195
Direct access 559 376
Total retail customers 870,333 859,396
Heating Degree-days   Cooling Degree-days  
2017   2016   Average   2017   2016   Average  
First quarter 2,171   1,585   1,867    
Second quarter 686 403 689 129 154 70
Third quarter 78 78 78 571 394 399
Fourth Quarter 1,623   1,486   1,599       2  


4,558 3,552 4,233 700 548 471

Note: "Average" amounts represent the 15-year rolling averages provided by the National Weather Service (Portland Airport).





Three Months Ended Years Ended
December 31, December 31,
2017     2016 2017     2016
Sources of energy (MWh in thousands):
Natural gas 2,246 1,794 6,228 5,811
Coal 773   957   3,344   3,492  
Total thermal 3,019 2,751 9,572 9,303
Hydro 421 415 1,774 1,629
Wind 358   353   1,641   1,912  
Total generation 3,798   3,519   12,987   12,844  
Purchased power:
Term 1,487 1,606 7,192 6,961
Hydro 316 381 1,648 1,541
Wind 57 60 264 301
Total purchased power 1,860   2,047   9,104   8,803  
Total system load 5,658 5,566 22,091 21,647
Less: wholesale sales (857 ) (731 ) (3,193 ) (3,352 )
Retail load requirement 4,801   4,835   18,898   18,295  

Portland General Electric
Media Contact:

Steve Corson
Corporate Communications
Investor Contact:
Chris Liddle
Investor Relations

Source: Portland General Electric Company

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