Document
Table of Contents







 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
 
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2018

or

[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from ____________________ to ____________________

Commission File Number: 001-5532-99

PORTLAND GENERAL ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)

Oregon
     93-0256820          
(State or other jurisdiction of
incorporation or organization)
     (I.R.S. Employer          
     Identification No.)          
121 SW Salmon Street
Portland, Oregon 97204
(503) 464-8000
(Address of principal executive offices, including zip code,
and registrant’s telephone number, including area code) 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [x] Yes [ ] No
  
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
[x] Yes x [ ] No
  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [x]
Accelerated filer [ ]
Non-accelerated filer [ ]
(Do not check if a smaller reporting company)
 
Smaller reporting company [ ]
 
Emerging growth company [ ]


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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standard provided pursuant to Section 13(a) of the Exchange Act. [ ]

 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). [ ] Yes [x] No
 
Number of shares of common stock outstanding as of July 17, 2018 is 89,238,445 shares.
 


Table of Contents


PORTLAND GENERAL ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2018

TABLE OF CONTENTS

 
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 6.
 
 
 


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DEFINITIONS

The following abbreviations and acronyms are used throughout this document:

Abbreviation or Acronym
 
Definition
AFDC
 
Allowance for funds used during construction
AUT
 
Annual Power Cost Update Tariff
Boardman
 
Boardman coal-fired generating plant
Carty
 
Carty natural gas-fired generating plant
Colstrip
 
Colstrip Units 3 and 4 coal-fired generating plant
CWIP
 
Construction work-in-progress
EPA
 
United States Environmental Protection Agency
FERC
 
Federal Energy Regulatory Commission
FMBs
 
First Mortgage Bonds
GAAP
 
Accounting principles generally accepted in the United States of America
GRC
 
General Rate Case
IRP
 
Integrated Resource Plan
Moody’s
 
Moody’s Investors Service
MW
 
Megawatts
MWa
 
Average megawatts
MWh
 
Megawatt hours
NVPC
 
Net Variable Power Costs
OPUC
 
Public Utility Commission of Oregon
PCAM
 
Power Cost Adjustment Mechanism
RPS
 
Renewable Portfolio Standard
S&P
 
S&P Global Ratings
SEC
 
United States Securities and Exchange Commission
TCJA
 
United States Tax Cuts and Jobs Act
Trojan
 
Trojan nuclear power plant


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PART I FINANCIAL INFORMATION

Item 1.
Financial Statements.
 
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
AND COMPREHENSIVE INCOME
(Dollars in millions, except per share amounts)
(Unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 
 
 
 
 
 
Revenues, net
$
449

 
$
449

 
$
944

 
$
979

Alternative revenue programs, net of amortization

 

 
(2
)
 

Total revenues
449

 
449

 
942

 
979

Operating expenses:
 
 
 
 
 
 
 
Purchased power and fuel
104

 
118

 
234

 
259

Generation, transmission and distribution
71

 
81

 
140

 
162

Administrative and other
70

 
64

 
139

 
131

Depreciation and amortization
93

 
86

 
185

 
170

Taxes other than income taxes
31

 
31

 
64

 
64

Total operating expenses
369

 
380

 
762

 
786

Income from operations
80

 
69

 
180

 
193

Interest expense, net
31

 
30

 
62

 
60

Other income:
 
 
 
 
 
 
 
Allowance for equity funds used during construction
2

 
3

 
6

 
5

Miscellaneous income (expense), net
1

 

 

 

Other income, net
3

 
3

 
6

 
5

Income before income tax expense
52

 
42

 
124

 
138

Income tax expense
6

 
10

 
14

 
33

Net income
46

 
32

 
110

 
105

Other comprehensive income

 
1

 

 

Comprehensive income
$
46

 
$
33

 
$
110

 
$
105

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted-average shares outstanding—basic and diluted (in thousands)
89,215

 
89,063

 
89,188

 
89,033

 
 
 
 
 
 
 
 
Earnings per share—basic and diluted
$
0.51

 
$
0.36

 
$
1.23

 
$
1.18

 
 
 
 
 
 
 
 
Dividends declared per common share
$
0.3625

 
$
0.3400

 
$
0.7025

 
$
0.6600

 
 
 
 
 
 
 
 
See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(Unaudited)




 
June 30,
2018
 
December 31,
2017
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
48

 
$
39

Accounts receivable, net
162

 
168

Unbilled revenues
86

 
106

Inventories
85

 
78

Regulatory assets—current
56

 
62

Other current assets
56

 
73

Total current assets
493

 
526

Electric utility plant, net
6,840

 
6,741

Regulatory assets—noncurrent
441

 
438

Nuclear decommissioning trust
42

 
42

Non-qualified benefit plan trust
38

 
37

Other noncurrent assets
55

 
54

Total assets
$
7,909

 
$
7,838

 
 
 
 
See accompanying notes to condensed consolidated financial statements.





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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS, continued
(Dollars in millions)
(Unaudited)



 
June 30,
2018
 
December 31,
2017
LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
103

 
$
132

Liabilities from price risk management activities—current
51

 
59

Current portion of long-term debt
300

 

Accrued expenses and other current liabilities
225

 
241

Total current liabilities
679

 
432

Long-term debt, net of current portion
2,126

 
2,426

Regulatory liabilities—noncurrent
1,348

 
1,288

Deferred income taxes
378

 
376

Unfunded status of pension and postretirement plans
280

 
284

Liabilities from price risk management activities—noncurrent
136

 
151

Asset retirement obligations
192

 
167

Non-qualified benefit plan liabilities
107

 
106

Other noncurrent liabilities
198

 
192

Total liabilities
5,444

 
5,422

Commitments and contingencies (see notes)

 

Equity:
 
 
 
Portland General Electric Company shareholders’ equity:
 
 
 
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of June 30, 2018 and December 31, 2017

 

Common stock, no par value, 160,000,000 shares authorized; 89,238,206 and 89,114,265 shares issued and outstanding as of June 30, 2018 and December 31, 2017, respectively
1,208

 
1,207

Accumulated other comprehensive loss
(8
)
 
(8
)
Retained earnings
1,265

 
1,217

Total equity
2,465

 
2,416

Total liabilities and equity
$
7,909

 
$
7,838

 
See accompanying notes to condensed consolidated financial statements.



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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)

 
Six Months Ended June 30,
 
2018
 
2017
Cash flows from operating activities:
 
 
 
Net income
$
110

 
$
105

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
185

 
170

Deferred income taxes
6

 
20

Pension and other postretirement benefits
13

 
13

Allowance for equity funds used during construction
(6
)
 
(5
)
Decoupling mechanism deferrals, net of amortization
2

 
(15
)
Deferral of net benefits due to Tax Reform
25

 

Other non-cash income and expenses, net
4

 
16

Changes in working capital:
 
 
 
Decrease in accounts receivable and unbilled revenues
26

 
55

(Increase) in inventories
(7
)
 

Decrease in margin deposits, net
4

 
7

(Decrease) in accounts payable and accrued liabilities
(20
)
 
(29
)
Other working capital items, net
13

 
11

Other, net
(17
)
 
(15
)
Net cash provided by operating activities
338

 
333

Cash flows from investing activities:
 
 
 
Capital expenditures
(266
)
 
(245
)
Sales of Nuclear decommissioning trust securities
6

 
11

Purchases of Nuclear decommissioning trust securities
(5
)
 
(9
)
Other, net

 
(2
)
Net cash used in investing activities
(265
)
 
(245
)
Cash flows from financing activities:
 
 
 
Dividends paid
(61
)
 
(57
)
Other
(3
)
 
(4
)
Net cash used in financing activities
(64
)
 
(61
)
Increase in cash and cash equivalents
9

 
27

Cash and cash equivalents, beginning of period
39

 
6

Cash and cash equivalents, end of period
$
48

 
$
33

 
 
 
 
Supplemental cash flow information is as follows:
 
 
 
Cash paid for interest, net of amounts capitalized
$
58

 
$
55

Cash paid for income taxes
10

 
13

Non-cash investing and financing activities:
 
 
 
Assets obtained under leasing arrangements
12

 
55

 
See accompanying notes to condensed consolidated financial statements.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its approximately four thousand square mile, state-approved service area allocation, located entirely within the State of Oregon, encompasses 51 incorporated cities, of which Portland and Salem are the largest. As of June 30, 2018, PGE served approximately 883 thousand retail customers with a service area population of approximately 1.9 million, comprising approximately 46% of the state’s population.

Condensed Consolidated Financial Statements

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading.

The financial information included herein for the six months ended June 30, 2018 and 2017 is unaudited; however, such information reflects all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary for a fair presentation of the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. The financial information as of December 31, 2017 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2017, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 16, 2018, which should be read in conjunction with such condensed consolidated financial statements.

Comprehensive Income

No material change occurred in Other comprehensive income in the three and six months ended June 30, 2018 and 2017. PGE recorded a net $1 million gain in Other comprehensive income for the three months ended June 30, 2017 due to the combination of changes in compensation retirement benefit liability and amortization, net of taxes of an immaterial amount, and other miscellaneous adjustments.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of gain or loss contingencies, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results experienced by the Company could differ materially from those estimates.

Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas, interim financial results do not necessarily represent those to be expected for the year.

Recent Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-02, Leases (Topic 842), which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Accounting for lessors is substantially unchanged from current accounting principles. Lessees will be required to classify leases as either finance leases or operating leases. Initial balance sheet measurement is similar for both types of leases; however, expense recognition and amortization of right-of-use assets will differ. Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability (as calculated using the effective interest method) and amortization expense of the right-of-use asset.

Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The provisions of this pronouncement are effective for calendar year-end, public entities on January 1, 2019. As issued, ASU 2016-02 requires transition under a modified retrospective basis as of the beginning of the earliest comparative period presented; however the Company is monitoring the FASB’s decisions regarding potential transition practical expedients that would allow companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. Early adoption is permitted, but the Company does not plan to early adopt. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842, which amends ASU 2016-02 to provide entities an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. PGE plans to elect this practical expedient. The Company is monitoring utility industry implementation issues that may change existing and future lease classification in areas such as purchase power agreements, pipeline laterals, utility pole attachments, and other utility industry-related arrangements. In conjunction with monitoring industry issues that may impact lease classification, the Company is in the process of evaluating whether it will elect to adopt certain, optional practical expedients included within the standard. Decisions surrounding the election of practical expedients may impact the Company’s lease population that is ultimately recorded. As a result, PGE has not yet quantified the estimated financial statement impact, but overall, the Company does expect an increase in the recognition of right-of-use assets and lease liabilities on the Company’s consolidated balance sheet.

In February 2018, the FASB issued ASU 2018-02 Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02). ASU 2018-02 allows for a reclassification from accumulated other comprehensive income to retained earnings for the stranded tax effects resulting from the Tax Cuts and Jobs Act (the TCJA). The amendments only relate to the reclassification of the income tax effects of the TCJA, and therefore the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. For calendar year-end entities, the update will be effective for annual periods beginning January 1, 2019, and interim periods within those fiscal years. Early adoption of the amendments is permitted, including adoption in any interim period. PGE has determined that ASU 2018-02 will not have a material impact on its financial position and it may early adopt the standard in 2018.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Recently Adopted Accounting Pronouncements

On January 1, 2018, PGE adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which created Topic 606 and superseded the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The Company applied the modified retrospective transition method to its revenue contracts not yet completed as of January 1, 2018. As a result, amounts previously recorded prior to January 1, 2018 have not been retrospectively restated and are reported in accordance with historical accounting under Topic 605, while revenues for the three and six months ended June 30, 2018 have been presented under Topic 606.

PGE’s transition to the new revenue standard did not result in a material adjustment to opening retained earnings and the Company expects the adoption of the new standard to have an immaterial impact to its results of operations on an ongoing basis. In accordance with the new provisions of Topic 606 PGE has included enhanced quantitative and qualitative disclosures, such as disaggregated revenues by customer class. Adoption of the new standard also resulted in a change to PGE’s presentation and classification of its alternative revenue programs, which are predominately comprised of the decoupling mechanism and renewable adjustment clause (RAC). Pursuant to the new standard, such revenues should be presented separately from revenues from contracts with customers as these amounts represent a contract with the regulator and not with customers. As a result, $2 million, net of amortization, primarily related to PGE’s decoupling mechanism, has been classified as Alternative revenue programs, net of amortization in the condensed consolidated statements of income and comprehensive income for the six months ended June 30, 2018. There was no material alternative revenue programs activity for the three-month period ended June 30, 2018. If PGE had not applied the new provisions of Topic 606, then PGE would have reported Revenues, net of $449 million and $942 million under Topic 605 for the three and six months ended June 30, 2018, respectively, with the difference attributable to the presentation and classification of alternative revenue programs. For further information regarding changes to the Company’s revenue recognition accounting policies, see Note 2, Revenue Recognition.

On January 1, 2018, PGE adopted ASU 2017-07, Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). On a prospective basis, only the service cost component of net periodic pension and postretirement benefit costs is eligible for capitalization to Electric utility plant, net. However, for ratemaking purposes the Company will continue to be allowed to recover its non-service costs related to capital as a component of rate base. Instead of recording such amounts to Electric utility plant, net, the Company will record a Regulatory asset on the condensed consolidated balance sheet that will be amortized in a systematic and rational manner. As of the three and six months ended June 30, 2018, the Company has recorded $1 million and $2 million, respectively, of the non-service costs component of net periodic pension and postretirement benefit costs as a Regulatory asset and estimates this amount will be $3 million for the twelve months ending December 31, 2018. The new pronouncement also requires, on a retrospective basis, that the non-service cost component of net periodic pension and postretirement benefit costs attributable to expense be presented separately from the service cost component and outside the subtotal of income from operations on the condensed consolidated statements of income and comprehensive income. As of the three and six months ended June 30, 2018, the portion of non-service costs attributable to expense is $2 million and $3 million, respectively, classified as Miscellaneous income (expense), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income. To conform to the 2018 presentation, PGE has retrospectively reclassified $1 million and $2 million, respectively, of the non-service costs component for the three and six months ended June 30, 2017 from Administrative and other within Operating expenses to Miscellaneous income (expense), net within Other income. The implementation of ASU 2017-07 has had an immaterial impact on PGE’s consolidated financial position and consolidated results of operations.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

On April 1, 2018, PGE early adopted ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The ASU is intended to simplify the application of hedge accounting and provide increased transparency as to the scope and results of hedging programs. The current impact of this adoption is immaterial to PGE’s consolidated financial statements as the majority of PGE’s price risk management derivatives are related to electric and natural gas commodity price economic hedges. However, PGE periodically enters into interest rate swaps that are designated as cash flow hedges to hedge portions of consolidated interest rate risk associated with anticipated issues of fixed-rate, long-term debt securities. In the event PGE elects to apply hedge accounting to these transactions, PGE will apply the new provisions of this ASU and its related disclosures.

NOTE 2: REVENUE RECOGNITION

Revenue Recognition

Revenue is recognized when obligations under the terms of a contract with customers are satisfied. Generally, this satisfaction of performance obligations and transfer of control occurs and revenues are recognized as electricity is delivered to customers, including any services provided. The prices charged, and amount of consideration PGE receives in exchange for its goods and services provided, are regulated by the Public Utility Commission of Oregon (OPUC) or the Federal Energy Regulatory Commission (FERC). PGE recognizes revenue through the following steps: i) identifying the contract with the customer; ii) identifying the performance obligations in the contract; iii) determining the transaction price; iv) allocating the transaction price to the performance obligations; and v) recognizing revenue when or as each performance obligation is satisfied.
As a rate-regulated utility, PGE, in certain situations, recognizes revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization. For additional information, see “Regulatory Assets and Liabilities” in Note 3, Balance Sheet Components.

Alternative Revenue Programs

Revenues related to PGE’s decoupling mechanism and RAC are considered to be earned under alternative revenue programs, in accordance with the new revenue standard. Such revenues are presented separately from revenues from contracts with customers and classified as Alternative revenue programs, net of amortization on the condensed consolidated statement of income and comprehensive income, as these amounts represent a contract with the regulator and not with customers. The activity within this line item is comprised of current period deferral adjustments, which can either be a collection from or a refund to customers, and is net of any related amortization. When amounts related to alternative revenue programs are ultimately included in prices and customer bills, the amounts are included within Revenues, net, with an equal and offsetting amount of amortization recorded on the Alternative revenue programs, net of amortization line item.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Disaggregated Revenue

The following table presents PGE’s revenue, disaggregated by customer type (in millions):

 
Three Months Ended June 30, 2018
 
Six Months Ended
June 30, 2018
Retail:
 
 
 
Residential
$
207

 
$
475

Commercial
162

 
313

Industrial
39

 
83

Direct access customers
13

 
23

Subtotal
421

 
894

Alternative revenue programs, net of amortization

 
(2
)
Other accrued (deferred) revenues, net(1)
(10
)
 
(27
)
Total retail revenues
411

 
865

Wholesale revenues(2)
24

 
52

Other operating revenues
14

 
25

Total revenues
$
449

 
$
942


(1) Includes a regulatory liability deferral of $10 million and $25 million for the three and six months ended June 30, 2018, respectively, related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. For further information, see Note 10, Income Taxes.
(2) Wholesale revenues includes $4 million and $6 million related to electricity commodity contract derivative settlements for the three and six months ended June 30, 2018, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers pursuant to Topic 606. For further information, see Note 5, Risk Management.

Retail Revenues

The Company’s primary revenue source is generated through the sale of electricity to customers based on regulated tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single family housing, multiple family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating season and summer cooling season. Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers. Customers include most businesses, small industrial companies, and public street and highway lighting accounts. Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers. Demand from industrial customers is primarily driven by economic conditions, with weather having little impact on this customer class.
In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and are determined through general rate case proceedings and various tariff filings with the OPUC. Additionally, the Company offers different pricing options including a daily market price option, various time-of-use options, and several renewable energy options for residential and small commercial customers.
Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that has not yet been billed to customers. This amount, which is classified as Unbilled revenues in the Company’s condensed consolidated balance

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

sheets, is calculated based on each month’s actual net retail system load, the number of days from the last meter read date through the last day of the month, and current customer prices.
PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct goods that are substantially the same and have the same pattern of transfer to the customer that is satisfied over time as customers simultaneously receive and consume the benefits provided. PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations to transfer each distinct delivery of electricity in the series to the customer.
Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers associated with activities for the benefit of the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and are not reflected in Revenues, net within the condensed consolidated statements of income and comprehensive income.
Wholesale Revenues
PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power, hydro and wind conditions, and daily and seasonal retail demand.
The majority of PGE’s wholesale electricity sales is to utilities and power marketers, is predominantly short-term, and consists of a single performance obligation satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale Revenues.
Other Operating Revenues
Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, excess fuel sales, utility pole attachment revenues, and other electric services provided to customers.

Arrangements with Multiple Performance Obligations

Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. PGE generally determines standalone selling prices based on the prices charged to customers.

Practical Expedients and Exemptions

PGE does not disclose the value of unsatisfied performance obligations for: i) contracts with an original expected length of one year or less; and ii) contracts for which the Company recognizes revenue at the amount to which it has the right to invoice for goods delivered or services performed.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

NOTE 3: BALANCE SHEET COMPONENTS

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that inventories are recorded at the lower of average cost or net realizable value.

Other Current Assets

Other current assets consist of the following (in millions):
 
June 30, 2018
 
December 31, 2017
Prepaid expenses
$
38

 
$
50

Assets from price risk management activities
3

 
6

Margin deposits
7

 
11

Other
8

 
6

Other current assets
$
56

 
$
73


Electric Utility Plant, Net

Electric utility plant, net consists of the following (in millions):
 
June 30, 2018
 
December 31, 2017
Electric utility plant
$
10,257

 
$
9,914

Construction work-in-progress
290

 
391

Total cost
10,547

 
10,305

Less: accumulated depreciation and amortization
(3,707
)
 
(3,564
)
Electric utility plant, net
$
6,840

 
$
6,741


Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $317 million and $296 million as of June 30, 2018 and December 31, 2017, respectively. Amortization expense related to intangible assets was $14 million and $27 million for the three and six months ended June 30, 2018, respectively, and $12 million and $23 million for the three and six months ended June 30, 2017, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.
 

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Regulatory Assets and Liabilities

Regulatory assets and liabilities consist of the following (in millions):
 
June 30, 2018
 
December 31, 2017
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Regulatory assets:
 
 
 
 
 
 
 
Price risk management
$
48

 
$
135

 
$
53

 
$
151

Pension and other postretirement plans

 
209

 

 
218

Debt issuance costs

 
17

 

 
19

Trojan decommissioning activities

 
26

 

 

Other
8

 
54

 
9

 
50

Total regulatory assets
$
56

 
$
441

 
$
62

 
$
438

Regulatory liabilities:
 
 
 
 
 
 
 
Asset retirement removal costs
$

 
$
955

 
$

 
$
933

Deferred income taxes

 
272

 

 
277

Trojan decommissioning activities
2

 

 
3

 

Asset retirement obligations

 
53

 

 
52

Tax Reform Deferral(1)

 
25

 

 

Other
20

 
43

 
28

 
26

Total regulatory liabilities
$
22

(2) 
$
1,348

 
$
31

(2) 
$
1,288


(1) Related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA.
(2) Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consist of the following (in millions):
 
June 30, 2018
 
December 31, 2017
Accrued employee compensation and benefits
$
54

 
$
60

Accrued taxes payable
25

 
31

Accrued interest payable
27

 
27

Accrued dividends payable
33

 
31

Regulatory liabilities—current
22

 
31

Other
64

 
61

Total accrued expenses and other current liabilities
$
225

 
$
241



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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Asset Retirement Obligations

Asset retirement obligations (AROs) consist of the following (in millions):
 
June 30, 2018
 
December 31, 2017
Trojan decommissioning activities
$
69

 
$
45

Utility plant
110

 
109

Non-utility property
13

 
13

Asset retirement obligations
$
192

 
$
167


Trojan decommissioning activities represents the present value of future decommissioning costs for the plant, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the Independent Spent Fuel Storage Installation (ISFSI), an interim dry storage facility that is licensed by the Nuclear Regulatory Commission (NRC). The ISFSI is to house the spent nuclear fuel at the former plant site until an off-site storage facility is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a U.S. Department of Energy facility is complete, which is not expected prior to 2034. The NRC mandated an increase in staffing for the next 16 years that increased the Trojan ARO in the first quarter of 2018 by $23 million.

Credit Facilities

As of June 30, 2018, PGE had a $500 million revolving credit facility scheduled to expire in November 2021.

Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, as backup for commercial paper borrowings, and to permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the credit facility. The facility contains a provision that requires annual fees based on PGEs unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of June 30, 2018, PGE was in compliance with this covenant with a 51.3% debt-to-total capital ratio.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility.

PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.

Under the revolving credit facility, as of June 30, 2018, PGE had no borrowings outstanding and there were no commercial paper or letters of credit issued. As a result, as of June 30, 2018, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

In addition, PGE has four letter of credit facilities that provide a total capacity of $220 million under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $64 million were outstanding as of June 30, 2018. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2020.

Long-term Debt

During the six months ended June 30, 2018, PGE did not enter into any long-term debt transactions. Due to an anticipated repayment of $300 million of long-term debt in 2019, this amount was classified as current on the Company’s condensed consolidated balance sheets as of June 30, 2018.

Defined Benefit Pension Plan Costs

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):
 
Three Months Ended June 30,
 
Six Months Ended
June 30,
 
2018
 
2017
 
2018
 
2017
Service cost
$
5

 
$
4

 
$
10

 
$
8

Interest cost*
8

 
9

 
16

 
17

Expected return on plan assets*
(11
)
 
(10
)
 
(21
)
 
(20
)
Amortization of net actuarial loss*
4

 
3

 
8

 
6

Net periodic benefit cost
$
6

 
$
6

 
$
13

 
$
11


* The expense portion of non-service cost components are included in Miscellaneous income (expense), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income pursuant to ASU 2017-07. See Note 1, Basis of Presentation for additional information.

NOTE 4: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of June 30, 2018 and December 31, 2017. PGE then classifies these financial assets and liabilities based on a fair value hierarchy that is applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are:

Level 1
Quoted prices are available in active markets for identical assets or liabilities as of the measurement date;

Level 2
Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date; and

Level 3
Pricing inputs include significant inputs that are unobservable for the asset or liability.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels during the three and six months ended June 30, 2018 and 2017, except those presented in this note.

The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions):
 
As of June 30, 2018
 
Level 1
 
Level 2
 
Level 3
 
Other(2)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Cash equivalents
$
31

 
$

 
$

 
$

 
$
31

Nuclear decommissioning trust: (1)
 
 
 
 
 
 
 
 
 
Debt securities:
 
 
 
 
 
 
 
 
 
Domestic government
3

 
7

 

 

 
10

Corporate credit

 
5

 

 

 
5

Money market funds measured at NAV (2)

 

 

 
27

 
27

Non-qualified benefit plan trust: (3)
 
 
 
 
 
 
 
 
 
Money market funds
2

 

 

 

 
2

Equity securities—domestic
7

 

 

 

 
7

Debt securities—domestic government
1

 

 

 

 
1

Assets from price risk management activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity

 
1

 
2

 

 
3

Natural gas

 
1

 

 

 
1

 
$
44

 
$
14

 
$
2

 
$
27

 
$
87

Liabilities from price risk management
activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity
$

 
$
4

 
$
116

 
$

 
$
120

Natural gas

 
52

 
15

 

 
67

 
$

 
$
56

 
$
131

 
$

 
$
187

 
(1)
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.
(2)
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)
Excludes insurance policies of $28 million, which are recorded at cash surrender value.
(4)
For further information, see Note 5, Risk Management.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

 
As of December 31, 2017
 
Level 1
 
Level 2
 
Level 3
 
Other (2)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Cash equivalents
$
30

 
$

 
$

 
$

 
$
30

Nuclear decommissioning trust: (1)
 
 
 
 
 
 
 
 
 
Debt securities:
 
 
 
 
 
 
 
 
 
Domestic government
4

 
7

 

 

 
11

Corporate credit

 
6

 

 

 
6

Money market funds measured at NAV (2)

 

 

 
25

 
25

Non-qualified benefit plan trust: (3)
 
 
 
 
 
 
 
 
 
Money market funds
1

 

 

 

 
1

Equity securities—domestic
7

 

 

 

 
7

Debt securities—domestic government
1

 

 

 

 
1

Assets from price risk management activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity

 
3

 

 

 
3

Natural gas

 
3

 

 

 
3

 
$
43

 
$
19

 
$

 
$
25

 
$
87

Liabilities from price risk management
activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity
$

 
$
5

 
$
130

 
$

 
$
135

Natural gas

 
66

 
9

 

 
75

 
$

 
$
71

 
$
139

 
$

 
$
210

 
(1)
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.
(2)
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)
Excludes insurance policies of $28 million, which are recorded at cash surrender value.
(4)
For further information, see Note 5, Risk Management.

Cash equivalents are highly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted average maturity of the fund’s securities holdings do not exceed 90 days and investors have the ability to redeem the fund’s shares daily at its respective net asset value. These cash equivalents are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for money market fund prices include published exchanges such as NASDAQ and the New York Stock Exchange.

Assets held in the Nuclear decommissioning trust and Non-qualified benefit plan (NQBP) trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:
 
Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date.
 

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yields and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

Equity securities—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange.

Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.

Assets and liabilities from price risk management activities are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Risk Management.

For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps.

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term commodity forwards, futures, and swaps.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:
 
 
Fair Value
 
Valuation Technique
 
Significant Unobservable Input
 
Price per Unit
Commodity Contracts
 
Assets
 
Liabilities
 
 
 
Low
 
High
 
Weighted Average
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
As of June 30, 2018:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electricity physical forwards
 
$
2

 
$
116

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
$
11.29

 
$
50.00

 
$
33.35

Natural gas financial swaps
 

 
15

 
Discounted cash flow
 
Natural gas forward price (per Decatherm)
 
1.11

 
3.00

 
1.62

Electricity financial futures
 

 

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
15.33

 
33.32

 
24.59

 
 
$
2

 
$
131

 
 
 
 
 
 
 
 
 
 
As of December 31, 2017:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electricity physical forwards
 
$

 
$
130

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
$
7.79

 
$
41.23

 
$
30.95

Natural gas financial swaps
 

 
9

 
Discounted cash flow
 
Natural gas forward price (per Decatherm)
 
1.26

 
2.92

 
1.90

Electricity financial futures
 

 

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
7.79

 
29.74

 
21.74

 
 
$

 
$
139

 
 
 
 
 
 
 
 
 
 

The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter term contracts, PGE employs the mid-point of the bid-ask spread of the market and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data from multiple sources. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed price curves, which derive longer term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a quarterly basis by the Company.

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and PGE’s position as either the buyer or seller under the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Significant Unobservable Input
 
Position
 
Change to Input
 
Impact on Fair Value Measurement
Market price
 
Buy
 
Increase (decrease)
 
Gain (loss)
Market price
 
Sell
 
Increase (decrease)
 
Loss (gain)
 
 
 
 
 
 
 


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2018

2017
 
2018
 
2017
Balance as of the beginning of the period
134

 
144

 
$
139

 
$
119

Net realized and unrealized (gains)/losses*
(4
)
 
9

 
(8
)
 
35

Transfers out of Level 3 to Level 2
(1
)
 

 
(2
)
 
(1
)
Balance as of the end of the period
$
129

 
$
153

 
$
129

 
$
153

 

* Both realized and unrealized (gains)/losses, of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income and comprehensive income.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the three and six months ended June 30, 2018 and 2017, there were no transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and out of Level 3 at the end of the reporting period for all of its derivative instruments.

Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur, as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement. As of June 30, 2018, the carrying amount of PGE’s long-term debt was $2,426 million, net of $10 million of unamortized debt expense, and its estimated aggregate fair value was $2,639 million. As of December 31, 2017, the carrying amount of PGE’s long-term debt was $2,426 million, net of $10 million of unamortized debt expense, and its estimated aggregate fair value was $2,829 million.

NOTE 5: RISK MANAGEMENT

Price Risk Management

PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generation combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existing long-term wholesale contracts. Wholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions for Company-owned generation resources. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flows.

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk in order to reduce volatility in NVPC for its retail customers. Such derivative instruments may include forward, futures, swaps, and option contracts, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

statements of income. In accordance with the ratemaking and cost recovery processes authorized by the OPUC, the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. The Company does not engage in trading activities for non-retail purposes.

PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions):
 
June 30, 2018
 
December 31, 2017
Current assets:
 
 
 
Commodity contracts:
 
 
 
Electricity
$
3

 
$
3

Natural gas
1

 
3

Total current derivative assets*
4

 
6

Total derivative assets not designated as hedging instruments
$
4

 
$
6

Total derivative assets
$
4

 
$
6

Current liabilities:
 
 
 
Commodity contracts:
 
 
 
Electricity
$
12

 
$
13

Natural gas
39

 
46

Total current derivative liabilities
51

 
59

Noncurrent liabilities:
 
 
 
Commodity contracts:
 
 
 
Electricity
108

 
122

Natural gas
28

 
29

Total noncurrent derivative liabilities
136

 
151

Total derivative liabilities not designated as hedging instruments
$
187

 
$
210

Total derivative liabilities
$
187

 
$
210


* Included in Other current assets on the condensed consolidated balance sheets.

PGE’s net purchase volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle through 2035, were as follows (in millions):
 
June 30, 2018
 
December 31, 2017
Commodity contracts:
 
 
 
 
 
Electricity
5

MWh
 
7

MWh
Natural gas
112

Decatherms
 
114

Decatherms
Foreign currency
$
22

Canadian
 
$
21

Canadian

PGE has elected to report gross on the condensed consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of June 30, 2018 and December 31, 2017, gross amounts included as Price risk management liabilities subject to master netting agreements were $122 million and $136 million, respectively, for which PGE posted collateral of $11 million, which consisted entirely of letters of credit. As of June 30, 2018, of the gross amounts recognized, $116 million was for electricity and $6 million was for natural gas compared to $130 million for electricity and $6 million for natural gas recognized as of December 31, 2017.

Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the condensed consolidated statements of income and were as follows (in millions):
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2018
 
2017
 
2018
 
2017
Commodity contracts:
 
 
 
 
 
 
 
Electricity
$
(3
)
 
$
16

 
$
(2
)
 
$
49

Natural Gas

 
7

 
14

 
41

Foreign currency exchange
1

 
(1
)
 
1

 
(1
)

Net unrealized and certain net realized losses (gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended June 30, 2018 and 2017, net gains of $9 million and net losses of $4 million, respectively, have been offset. Net losses of $6 million and $65 million have been offset for the six-month periods ended June 30, 2018 and 2017, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of June 30, 2018 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
Total
Commodity contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
Electricity
$
4

 
$
9

 
$
8

 
$
7

 
$
7

 
$
82

 
$
117

Natural gas
25

 
25

 
11

 
5

 

 

 
66

Net unrealized loss
$
29

 
$
34

 
$
19

 
$
12

 
$
7

 
$
82

 
$
183


PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.

The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of June 30, 2018 was $183 million, for which PGE has posted $28 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at June 30, 2018, the cash requirement to either post as collateral or settle the instruments immediately would have been $182 million. As of June 30, 2018, PGE had no cash collateral posted for derivative instruments with no credit-risk-related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheet.

24

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:
 
June 30, 2018
 
December 31, 2017
Assets from price risk management activities:
 
 
 
Counterparty A
39
%
 
%
Counterparty B
23

 
39

Counterparty C
18

 
7

Counterparty D
1

 
12

 
81
%
 
58
%
Liabilities from price risk management activities:
 
 
 
Counterparty E
62
%
 
62
%
 
62
%
 
62
%

See Note 4, Fair Value of Financial Instruments, for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities.

Interest Rate Risk

PGE has used a forward starting interest rate swap lock agreement to hedge a portion of its interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. This derivative was designated as a cash flow hedge, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance.
The notional amount of the interest rate swap is $85 million with a mandatory cash settlement date in January 2019. Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. Such amounts are also included as a component of cost of debt for ratemaking purposes.
PGE is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, PGE receives cash to settle its interest rate swap derivatives when prevailing market rates at the time of settlement exceed the fixed swap rates. Until settlement, the interest rate swap is carried at fair value as a derivative asset or liability with the corresponding offset recorded as either a regulatory liability or regulatory asset, respectively. The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. As of June 30, 2018, the fair value of the interest rate swap was immaterial.

NOTE 6: EARNINGS PER SHARE

Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.


25

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

For the three and six months ended June 30, 2018, unvested performance-based restricted stock units and related dividend equivalent rights in the total amount of 231 thousand were excluded from the dilutive calculation because the performance goals had not been met, with 273 thousand excluded for the three and six months ended June 30, 2017.

Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2018
 
2017
 
2018
 
2017
Weighted-average common shares outstanding—basic and diluted
89,215

 
89,063

 
89,188

 
89,033


NOTE 7: EQUITY

The activity in equity during the six-month periods ended June 30, 2018 and 2017 is as follows (dollars in millions):
 
Common Stock
 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
 
 
 
 
 
 
 
 
Shares
 
Amount
 
 
 
Total
Balances as of December 31, 2017
89,114,265

 
$
1,207

 
$
(8
)
 
$
1,217

 
$
2,416

Issuances of shares pursuant to equity-based plans
123,941

 

 

 

 

Stock-based compensation

 
1

 

 

 
1

Dividends declared

 

 

 
(62
)
 
(62
)
Net income

 

 

 
110

 
110

Balances as of June 30, 2018
89,238,206

 
$
1,208

 
$
(8
)
 
$
1,265

 
$
2,465

 
 
 
 
 
 
 
 
 
 
Balances as of December 31, 2016
88,946,704

 
$
1,201

 
$
(7
)
 
$
1,150

 
$
2,344

Issuances of shares pursuant to equity-based plans
115,856

 
1

 

 

 
1

Stock-based compensation

 
1

 

 

 
1

Dividends declared

 

 

 
(59
)
 
(59
)
Net income

 

 

 
105

 
105

Balances as of June 30, 2017
89,062,560

 
$
1,203

 
$
(7
)
 
$
1,196

 
$
2,392


NOTE 8: CONTINGENCIES

PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the condensed consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate.

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be determined, then PGE: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons.

If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period.

PGE evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, will be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

Carty

In 2013, PGE entered into a turnkey engineering, procurement, and construction agreement (Construction Agreement) with Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership (collectively, the Contractor), affiliates of Abengoa S.A., for the construction of the Carty natural gas-fired generating plant (Carty) located in Eastern Oregon. Liberty Mutual Insurance Company and Zurich American Insurance Company (together, the Sureties) provided a performance bond of $145.6 million (Performance Bond) in connection with the Construction Agreement. PGE, the Contractor, Abengoa S.A., and the Sureties are hereinafter collectively referred to as the Parties.

In December 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. Following termination of the Construction Agreement, PGE brought on new contractors and completed construction.

Carty was placed into service on July 29, 2016 and the Company began collecting its revenue requirement in customer prices on August 1, 2016, as authorized by the OPUC, based on the approved capital cost of $514 million. Actual costs for the construction of Carty exceeded the approved amount and, as of June 30, 2018, PGE has capitalized $640 million to Electric utility plant.

The excess costs resulted from various matters relating to the resumption of construction activities following the termination of the Construction Agreement, including, among other things, completing the remaining construction work, correcting deficiencies and defects in work performed by the Contractor, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, resolving claims and removing certain liens filed on the property for goods and services provided under contracts with the Contractor, and procuring additional materials.


27

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

The Company sought recovery of excess construction costs and other damages pursuant to breach of contract claims against the Contractor and claims against the Sureties pursuant to the Performance Bond. The Sureties denied liability in whole under the Performance Bond, and the Contractor filed claims against the Company alleging wrongful termination of contract and related damages.

Various actions relating to this matter were filed in the U.S. District Court for the District of Oregon, in the Ninth Circuit Court of Appeals, and in the International Chamber of Commerce’s Court of Arbitration.

As a result of the foregoing events, PGE has incurred a higher cost of service than what is reflected in the current authorized revenue requirement amount, primarily due to higher depreciation, interest, and legal expenses. These incremental expenses are recognized in the Company’s current results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP. Such incremental expenses were $4 million and $7 million for the three and six months ended June 30, 2018, respectively, and $3 million and $7 million for the three and six months ended June 30, 2017, respectively.

The excess costs recorded to date exclude liens and claims filed for goods and services provided under contracts with the Contractor that remain in dispute of up to $5 million. The Company believes these claims by subcontractors are not owed by the Company and is contesting the liens and claims in the courts.

Subsequent to June 30, 2018, on July 16, 2018, the Parties reached a settlement to resolve all claims relating to Carty construction between the Company and each of the Contractor, Abengoa S.A., and the Sureties. Under the terms of the settlement, i) the Sureties will pay $130 million to PGE, and ii) the Contractor, Abengoa S.A., and the Sureties will release all claims against the Company arising out of the Carty construction, and in return, PGE will release all such claims against the Contractor, Abengoa S.A., and the Sureties.

The settlement will be treated as a subsequent event that will be recorded in PGE’s financial statements for the third quarter ending September 30, 2018. PGE is in the process of assessing the impact of the settlement to its financial position, results of operations, and cash flows. The Company anticipates that the proceeds will fully offset the incremental construction costs, thus eliminating ongoing excess depreciation and amortization, interest expense, and partially offsetting the Company’s other accumulated damages.

In July 2016, PGE requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the excess capital costs for Carty, starting from its in-service date to the date that such amounts are approved in a subsequent regulatory proceeding. The Company requested that the OPUC delay its review of this deferral request until all legal actions with respect to this matter, including PGE’s actions against the Sureties, have been resolved. As a result of the settlement described above, the Company plans to withdraw the deferral application.

EPA Investigation of Portland Harbor

An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site and listed 69 Potentially Responsible Parties (PRPs). PGE was included among the original PRPs as it historically owned or operated property near the river.


28

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

In 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation as well as several miles beyond. The EPA then listed additional PRPs, which now number over one hundred.

The Portland Harbor site remedial investigation had been completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the remedial investigation and feasibility study and stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy.

The EPA finalized the feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued on January 6, 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion, comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs, for a combined discounted present value of $1.1 billion. Remediation construction costs were estimated to be incurred over a 13-year period, with long-term operation and maintenance costs estimated to be incurred over a 30-year period from the start of construction. The EPA acknowledged the estimated costs were based on data that was outdated and that pre-remedial design sampling was necessary to gather updated baseline data to better refine the remedial design and estimated cost. In December 2017, the EPA announced that four PRPs have entered into an administrative order on consent to conduct this additional sampling, which was estimated to be completed in two years. PGE is not among the four PRPs performing this sampling.

PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including results of the pre-remedial design sampling, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor. Based on the above facts and remaining uncertainties, PGE cannot reasonably estimate its potential liability or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor.

In cases in which injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state trustees may seek to recover for such damages, which are referred to as Natural Resource Damages (NRD). As it relates to Portland Harbor, PGE continues to participate in the NRD assessment process. The EPA does not manage NRD assessment activities but provides claims information and coordination support to the NRD trustees. NRD assessment activities are typically conducted by a Council made up of the trustee entities for the site. The Portland Harbor NRD trustees consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, and certain tribal entities.

The NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate the trustees for costs incurred in assessing the damages. The NRD trustees are in the process of negotiating NRD liability with several PRPs, including PGE. The Company believes that PGE’s portion of NRD liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows.

Significant uncertainties remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, the amount of NRD, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. However, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor, although such costs could be material. The Company

29

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

plans to seek recovery of any costs resulting from the Portland Harbor proceeding through claims under insurance policies and regulatory recovery in customer prices.

In 2016, the Company filed an application with the OPUC seeking the deferral of future environmental remediation costs as well as seeking authorization to establish a regulatory cost recovery mechanism for such environmental costs. In the first quarter of 2017, the OPUC approved the deferral request and a mechanism that will allow the Company to defer and recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and customer prices, as necessary. The mechanism establishes annual prudency reviews of environmental expenditures and is subject to an annual earnings test.

Trojan Investment Recovery Class Actions

In 1993, PGE closed the Trojan nuclear power plant (Trojan) and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan.

Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the matter to the OPUC for reconsideration.

In 2003, in two separate legal proceedings, lawsuits were filed against PGE on behalf of two classes of electric service customers: i) Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court; and ii) Morgan v. Portland General Electric Company, Marion County Circuit Court. The class action lawsuits seek damages totaling $260 million, plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan.

In August 2006, the Oregon Supreme Court (OSC) issued a ruling ordering the abatement of the class action proceedings. The OSC concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could be offered to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment that the Company collected in prices.

In 2008, the OPUC issued an order (2008 Order) that required PGE to provide refunds of $33 million, including interest, which refunds were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in 2013 and by the OSC in 2014.

In June 2015, based on a motion filed by PGE, the Marion County Circuit Court (Circuit Court) lifted the abatement and in July 2015, heard oral argument on the Company’s motion for Summary Judgment. In March 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. In April 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon. A Court of Appeals decision remains pending.

PGE believes that the 2014 OSC decision and the Circuit Court decisions that followed have reduced the risk of any loss to the Company beyond the amounts previously recorded and discussed above. However, because the class actions remain subject to a decision in the appeal, management believes that it is reasonably possible that such a loss to the Company could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss.
 

30

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Deschutes River Alliance Clean Water Act Claims

On August 12, 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company (Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon) that seeks injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claims PGE has violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleges the violations are related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project.

The SWW, located above Round Butte Dam on the Deschutes River in central Oregon, is, among other things, designed to blend water from the surface of the reservoir with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements, for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA has alleged that PGE’s operation of the SWW has caused the above-referenced violations of the CWA, which in turn have degraded the Deschutes River’s fish and wildlife habitat below the Project and harmed the economic and personal interests of DRA’s members and supporters.

In September 2016, PGE filed a motion to dismiss, which asserted that the CWA does not allow citizen suits of this nature, and that the FERC has jurisdiction over all licensing issues, including the alleged CWA violations. On March 27, 2017, the court denied PGE’s motion to dismiss. On April 7, 2017, the U.S. District Court granted an unopposed motion filed by the Confederated Tribes of Warm Springs (CTWS) to appear in the case as a friend of the court. The CTWS shares ownership of the Project with PGE, but was not initially named as a defendant.

Following conferences and negotiations involving various parties, the District Court Judge (Judge), on January 17, 2018, established a briefing schedule for summary judgment motions and scheduled a bench trial to start December 3, 2018. In March and April 2018, DRA and PGE filed cross-motions for summary judgment and PGE and the CTWS filed separate motions to dismiss. At a hearing on May 9, 2018, the Judge requested that PGE file an alternative motion to dismiss, which the Company and the CTWS filed on May 16, 2018. On June 11, 2018, the court denied the motions to dismiss filed in March 2018 and held that the CTWS was a necessary party to the lawsuit. DRA thereafter joined the CTWS as a defendant. At a hearing on July 17, 2018, the Judge heard and took under advisement the cross-motions for summary judgment and the motions to dismiss filed by PGE and the CTWS on May 16, 2018. The Judge also struck all future calendar dates, including the trial date.

The Company cannot predict the outcome of this matter, but believes that it has strong defenses to DRA’s claims and intends to defend against them. Because: i) this matter involves novel issues of law; and ii) the mechanism and costs for achieving the relief sought in DRA’s claims have not yet been determined, the Company cannot, at this time, determine the likelihood of whether the outcome of this matter will result in a material loss.

Other Matters

PGE is subject to other regulatory, environmental, and legal proceedings, investigations, and claims that arise from time to time in the ordinary course of business that may result in judgments against the Company. Although management currently believes that resolution of such matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future.

NOTE 9: GUARANTEES

PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be

31


reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of June 30, 2018, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

NOTE 10: INCOME TAXES

Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes regulatory flow-through adjustments, tax credits, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the U.S. Federal statutory rate and PGE’s effective tax rate for financial reporting purposes are as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Federal statutory tax rate
21.0
 %
 
35.0
 %
 
21.0
 %
 
35.0
 %
Federal tax credits*
(17.0
)
 
(12.4
)
 
(17.5
)
 
(15.0
)
State and local taxes, net of federal tax benefit
6.5

 
5.2

 
6.5

 
5.1

Flow through depreciation and cost basis differences
(2.2
)
 
(1.7
)
 
(3.4
)
 
0.1

Other
3.2

 
(2.3
)
 
4.7

 
(1.3
)
Effective tax rate
11.5
 %
 
23.8
 %
 
11.3
 %
 
23.9
 %
 
 
 
 
 
 
 
 
* Federal tax credits consists of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in-service dates. PGE’s PTC generation ends at various dates through 2024.

On December 22, 2017, the TCJA was enacted and, among other provisions, reduced the federal corporate tax rate from 35% to 21%. The change in federal statutory tax rate is the primary driver of the change in effective tax rate from 2017 to 2018. As a result of the change in corporate tax rate, PGE is incurring lower income tax expense in 2018 than was estimated in setting customer prices in the Company’s 2018 General Rate Case (2018 GRC). In a deferral filing with the OPUC on December 29, 2017, PGE has proposed to defer and refund the 2018 expected net benefits of the TCJA. 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 currently authorized regulated return on equity. Under the proposed deferral filing, PGE has recorded a net refund to customers of $25 million as of June 30, 2018, which was recorded as a reduction to Revenues, net on the condensed consolidated statements of income and comprehensive income and an increase to Regulatory liabilities on the condensed consolidated balance sheets.

In accordance with tax normalization rules, the benefits of the 2017 deferred tax remeasurement of plant-related deferred taxes will be passed on to customers through future prices over the remaining useful life of the underlying assets for which the deferred income taxes relate. PGE has commenced amortization using the average rate assumption method to account for the refund to customers; however, as customer prices are not anticipated to be adjusted until 2019, such amortization has been deferred in Income tax expense and recorded as a Regulatory liability. As of June 30, 2018, PGE has deferred $4 million in tax normalization refunds.

Carryforwards


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Federal tax credit carryforwards as of June 30, 2018 and December 31, 2017 were $55 million and $50 million, respectively. These credits consist of PTCs, which will expire at various dates through 2038. PGE has analyzed the provisions of the TCJA and its effects on the Company’s deferred income tax assets, and PGE believes that it is more likely than not that its deferred income tax assets as of June 30, 2018 will be realized; accordingly, no valuation allowance has been recorded. As of June 30, 2018 and December 31, 2017, PGE had no unrecognized tax benefits.

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions, and objectives concerning future results of operations, business prospects, future loads, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance, and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s forward-looking statements are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that the expectations, beliefs, or projections contained in such forward-looking statements will be achieved or accomplished.

In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

governmental policies and regulatory audits, investigations and actions, including those of the FERC and the 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 8, Contingencies, in the Notes to the Condensed Consolidated Financial Statements;

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;


33

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operational factors affecting PGE’s power generating facilities, including forced outages, hydro and wind conditions, and disruption of fuel supply, any of which may cause the Company to incur repair costs or purchase replacement power at increased costs;

the failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;

volatility in wholesale power and natural gas prices, which could require PGE to issue additional letters of credit or post additional cash as collateral with counterparties pursuant to power and natural gas purchase agreements;

changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes on the Company’s power costs;

capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE’s credit ratings, any of which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, and the repayments of maturing debt;

future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury, and other gas emissions;

changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;

the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;

changes in residential, commercial, and industrial customer growth, and in demographic patterns, in PGE’s service territory;

the effectiveness of PGE’s risk management policies and procedures;

declines in the fair value of securities held for the defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such plans;

cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation, transmission, and distribution facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;

employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and a significant number of employees approaching retirement;

new federal, state, and local laws that could have adverse effects on operating results, including the potential impact of the U.S. Tax Cuts and Jobs Act (TCJA);
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.

Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors or assess the impact of

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any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. This MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended December 31, 2017, and other periodic and current reports filed with the SEC.

PGE is a vertically integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity, as well as the wholesale purchase and sale of electricity and natural gas in order to meet the needs of its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.

PGE is responding proactively to an evolving landscape of customer expectations, technology changes, and regulatory frameworks by focusing efforts on four strategic initiatives: i) deliver exceptional customer service; ii) invest in a reliable and clean energy future; iii) build a smarter, more resilient grid; and iv) pursue excellence in its work. The Company is participating in the development of a report from the OPUC to the Oregon legislature that was required under Senate Bill 978, which deals with the existing regulatory system, incentives and obligations currently employed by the OPUC. For further information, see “SB 978” in this Overview section of Item 2.

To deliver exceptional customer service, PGE must respond to the changing expectations of its customer base. The Company’s Integrated Resource Plan (IRP), new customer information system, and planned infrastructure investments are part of a strategy focused on providing power supply, distribution reliability, and customer service that meet those expectations.

PGE’s investments in a reliable and clean energy future are a key element of the IRP, which will require compliance with statutory renewable standards and consideration of state and local government initiatives to decarbonize the statewide economy.

Building a smarter, more resilient grid is essential to delivering the affordable, clean energy future that customers want. This requires embracing new technologies, modernizing the Company’s existing infrastructure, and implementation of a new customer information system to create a foundation to integrate emerging technologies. PGE’s capital requirements contemplate the impact of making these improvements to its transmission, distribution, and information technology infrastructure.

PGE’s 2016 IRP addressed the Company’s proposal to meet future customer demand and described PGE’s future energy supply strategy and anticipated resource needs over the next 20 years. The areas of focus for the plan included, among other topics, additional resources needed to meet Oregon’s Renewable Portfolio Standard (RPS) requirements and to replace energy from Boardman, the Company’s coal-fired generating plant located in Eastern Oregon that will cease coal-fired operations at the end of 2020. For further information regarding the 2016 IRP, the update to it, and the resulting Request for Proposal for the addition of RPS-compliant renewable resources (Renewable RFP), see “Integrated Resource Plan” in this Overview section of Item 2.

In February 2018, PGE filed a general rate case for a 2019 test year (2019 GRC). The Company expects the OPUC to authorize new customer prices effective January 1, 2019. For further information, see “General Rate Case” in this Overview section of Item 2.

As a market participant in the California Independent System Operator’s (CAISO) Energy Imbalance Market (western EIM), PGE has designated certain of its generating plants to receive automated dispatch signals from the CAISO that allows for load balancing with other EIM participants. The Company expects its western EIM

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participation will help integrate more renewable energy into the grid and provide access to the least-cost energy available in the region to meet changes in real-time energy demand and short-term variations in customer demand. The Company continues to work with the CAISO and regional partners on targeted market enhancements to the western EIM design, and also continues to participate in dialogue related to the development of a regional day-ahead market that could deliver additional benefits.

The discussion that follows in this MD&A provides additional information related to the Company’s operating activities, legal, regulatory, and environmental matters, results of operations, and liquidity and financing activities.

Integrated Resource Plan—In August 2017, the OPUC acknowledged PGE’s 2016 IRP and action plan items to, among other things:
meet additional capacity needs;
acquire cost-effective energy efficiency;
acquire demand response and dispatchable standby generation; and
submit one or more energy storage proposals in accordance with Oregon House Bill 2193.

Capacity—As part of the 2016 IRP, the Company put forth a variety of scenarios to meet future capacity needs, driven by the need to replace the output of Boardman, which will cease coal-fired generation by the end of 2020. As a result of the public review process, the Company pursued and has finalized bilateral power purchase agreements with capacity providers in the region, summarized as follows:
200 MW of annual capacity with five-year terms beginning January 1, 2021; and
100 MW of seasonal peak capacity during the summer and winter seasons with a term that begins July 1, 2019 and continues through February 29, 2024.

Renewables—In November 2017, PGE submitted to the OPUC an addendum to the 2016 IRP that included a request for the issuance of a Renewable RFP. In December 2017, the OPUC acknowledged the addendum and, as a result, in May 2018, PGE issued the Renewable RFP seeking a 100 MWa procurement target. The Company is in the process of evaluating the proposals received, which were due in June 2018, with the oversight of an independent evaluator and review by the OPUC.

PGE submitted a benchmark proposal into the Renewable RFP process that includes a wind resource that could have a nameplate capacity of up to 300 MW and would qualify for the federal production tax credit. The benchmark proposal will be considered along with other renewable resource proposals. A final shortlist of proposals is expected to be submitted to the OPUC in October 2018.

Energy Storage—Pursuant to OPUC acknowledgment of the 2016 IRP, and in accordance with Oregon House Bill 2193 (HB 2193), PGE filed an energy storage proposal in November 2017. The proposal called for 39 MW of storage to be developed over the next several years at various locations across the grid, at a cost of $50 to $100 million. Partial stipulations have been filed regarding most issues raised in this proposal and, as a result, the Company has revised its cost estimates and now expects capital spending on projects under the proposal would be approximately $45 million. The OPUC is to review the proposed projects and provide approval or modifications with a target decision date of August 15, 2018.

IRP Update—In March 2018, PGE filed an update to its 2016 IRP with the OPUC. The OPUC acknowledged the IRP Update at its April 24, 2018 meeting, and, as a result, PGE included the resource and financial parameters in its May 1, 2018 annual avoided cost update filing.

Since 2016, the Company has experienced significant growth in contract requests from Qualifying Facilities (QFs) under the Public Utilities Regulatory Policies Act. PGE continues to see a trend in which QF

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contracts are executed and subsequently packaged and sold to large, sophisticated multi-national developers in an attempt to take advantage of contract rates that are significantly higher than current market rates. PGE will attempt to work with the OPUC and stakeholders to restructure the QF implementation process to align with RPS targets to ensure customers receive affordable and reliable renewable energy, while continuing to comply with legal requirements.

As part of the IRP Update filing, PGE’s capacity need has been updated to reflect the recently executed bilateral capacity contracts, changes to load forecast, and additional executed QF contracts. PGE expects that the anticipated procurement of resources through the Renewable RFP and energy storage associated with the HB 2193 will contribute to meeting the remaining forecasted need identified in the 2016 IRP.

General Rate Case—On February 15, 2018, the Company filed with the OPUC a GRC based on a 2019 test year (2019 GRC). After adjusting for the effects of the TCJA, the Company’s filing requested an approximate 4.8% overall increase relative to currently approved prices and would have resulted in an $86 million increase in the annual revenue requirement. The filing sought recovery of costs related to better serving customers and building a smarter, more resilient system and included the expectation of higher net variable power costs in 2019.

Primary elements included:

Installation of a new customer information system to provide better, more secure service;
Replacement and upgrades to equipment to ensure system safety and reliability;
Equip substations with technology to address potential outages and shorten those that do occur;
Strengthen safeguards that protect against cyber attacks and other potential threats; and
Add infrastructure to support rapid growth in the region.

The net increase in annual revenue requirement, as requested, was based upon:
A capital structure of 50% debt and 50% equity;
A return on equity of 9.50%;
A cost of capital of 7.31%; and
A rate base of $4.86 billion.

PGE, interveners, and the OPUC Staff are currently in the settlement discussion phase of the public proceeding. The Company filed reply testimony on July 13, 2018. Regulatory review of the 2019 GRC will continue throughout 2018, with a final order targeted to be issued by the OPUC by mid-December 2018. New customer prices are expected to become effective January 1, 2019.

The 2019 GRC filing (OPUC Docket UE 335), as well as copies of direct and reply testimony and exhibits, are available on the OPUC website at www.oregon.gov/puc.

Tax Reform—On December 22, 2017, the TCJA was enacted and signed into law with substantially all of the provisions of the TCJA having an effective date of January 1, 2018. Among other provisions, the TCJA reduced the federal corporate tax rate from 35% to 21%. As a result of the change in corporate tax rate, PGE expects to incur lower income tax expense throughout 2018 than what was estimated in setting customer prices in the Company’s 2018 GRC. PGE has proposed in a filing with the OPUC on December 29, 2017, to track and defer tax savings as a result of the TCJA and work with the OPUC to determine strategies to provide customers the appropriate benefit. This work is ongoing. 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 currently authorized regulated return on equity. As of June 30, 2018, PGE has recorded a year-to-date net refund to customers of $25 million for net benefits expected in 2018. This deferral excludes the effects of applying an earnings test at the Company’s

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authorized regulated return on equity, as well as other regulatory adjustments. The anticipated refund amount was recorded as a reduction to Revenues, net in the condensed consolidated statements of income and comprehensive income. The net impact to earnings of the reduction in revenue is largely offset by reduced income tax expense.

For additional information regarding income taxes, see Note 10, Income Taxes, in the Notes to Condensed Consolidated Financial Statements.

Capital Requirements and Financing—The Company expects 2018 capital expenditures to total $648 million, excluding AFDC. For additional information regarding estimated capital expenditures, see “Capital Requirements” in the Liquidity and Capital Resources section of this Item 2.


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PGE plans to fund capital requirements with cash from operations during 2018, which is expected to range from $575 million to $625 million, the $130 million proceeds from the settlement of the Carty matter, and the issuance of debt securities of up to $75 million. For additional information, see “Liquidity” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 2.

Operating Activities—The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues and income from operations to fluctuate from period to period. PGE typically experiences its highest average MWh deliveries and retail energy sales during the winter heating season, although deliveries also increase during the summer months, generally resulting from air conditioning demand. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues while wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.

Customers and Demand—Retail energy deliveries for the six months ended June 30, 2018, decreased 3.9% compared with the six months ended June 30, 2017, as illustrated in the table below. This decrease was primarily driven by mild temperatures impacting usage in the residential and commercial classes.

During the first quarter of the calendar year, customer demand was influenced by mild temperatures during the heating season. During the first quarter of 2018, heating degree-days, an indication of the extent to which customers are likely to have used electricity for heating, were 19% below the first quarter of 2017.

During the second quarter of 2018, heating degree-days, were 31% below the second quarter of 2017. Also during the second quarter, cooling degree-days, an indication of the extent to which customers are likely to have used electricity for cooling, were 10% below prior year, indicating that temperature variations had a lesser effect on customer demand in the second quarter of 2018 when compared with 2017. See “Revenues” in the Results of Operations section of this Item 2 for further information on heating and cooling degree-days.

Residential energy deliveries decreased 0.9% in the second quarter of 2018 compared with the second quarter of 2017 reflecting decreased average usage per customer due to milder weather, partially offset by increased customer counts. Energy deliveries to commercial customers were comparable with the prior year quarter, while industrial deliveries were down 4.4% for the quarter largely due to a paper manufacturing closure in late 2017.

On a weather-adjusted basis, total energy deliveries increased 0.5% for the six months ended June 30, 2018. Growth in customer count and increased deliveries to high tech manufacturing customers continues to be partially offset by decreased average usage per customer driven by energy efficiency and conservation efforts. The financial effects of such efforts by residential and certain commercial customers are mitigated by the decoupling mechanism. See “Legal, Regulatory and Environmental” in this Overview section of Item 2 for further information on the decoupling mechanism.

The following table, which includes deliveries to the Company’s Direct Access customers who purchase their energy from Electricity Service Suppliers, presents the average number of retail customers by customer type, and

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the corresponding energy deliveries, for the periods indicated:
 
Six Months Ended June 30,
 
 
 
2018
 
2017
 
% Increase (Decrease) in Energy
Deliveries
 
Average
Number of
Customers
 
Retail Energy
Deliveries*
 
Average
Number of
Customers
 
Retail Energy
Deliveries*
 
Residential
770,247

 
3,745

 
759,765

 
4,009

 
(6.6
)%
 
 
 
 
 
 
 
 
 
 
Commercial (PGE sales only)
107,834

 
3,251

 
106,593

 
3,342

 
(2.7
)%
     Direct Access
531

 
311

 
458

 
303

 
2.6
 %
Total Commercial
108,365

 
3,562

 
107,051

 
3,645