Document


 

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

FORM 10-Q

(Mark One)
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

o 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: 1-12579
OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)
Oklahoma
 
73-1481638
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)

321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)

405-553-3000
(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.  þ  Yes  o  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).  þ  Yes  o  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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  þ
Accelerated filer  o
Non-accelerated filer    o (Do not check if a smaller reporting company)
Smaller reporting company  o
 
Emerging growth company o

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 standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o  Yes   þ  No

At June 30, 2018, there were 199,731,036 shares of common stock, par value $0.01 per share, outstanding.
 


OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2018

TABLE OF CONTENTS

 
Page
 
 
Part I - FINANCIAL INFORMATION
 
 
 
 
 
 
 
 
 
 
Part II - OTHER INFORMATION
 
 
 
 
 
 
 
 
 


i

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations that are found throughout this Form 10-Q.
Abbreviation
Definition
2017 Form 10-K
Annual Report on Form 10-K for the year ended December 31, 2017
2017 Tax Act
Tax Cuts and Jobs Act of 2017
APSC
Arkansas Public Service Commission
ArcLight group
Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC, collectively
ASC
FASB Accounting Standards Codification
ASU
FASB Accounting Standards Update
CenterPoint
CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO2
Carbon dioxide
Company
OGE Energy Corp., collectively with its subsidiaries
CSAPR
Cross-State Air Pollution Rule
Dry Scrubbers
Dry flue gas desulfurization units with spray dryer absorber
ECP
Environmental Compliance Plan
Enable
Enable Midstream Partners, LP, a partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
Enogex Holdings
Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex LLC
Enogex LLC, collectively with its subsidiaries (effective July 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EPA
U.S. Environmental Protection Agency
FASB
Financial Accounting Standards Board
Federal Clean Water Act
Federal Water Pollution Control Act of 1972, as amended
FERC
Federal Energy Regulatory Commission
FIP
Federal Implementation Plan
GAAP
Accounting principles generally accepted in the U.S.
IRP
Integrated Resource Plan
MATS
Mercury and Air Toxics Standards
MBbl/d
Thousand barrels per day
Mustang Modernization Plan
The construction of seven new, efficient combustion turbines with generating capability of 462 megawatts
MWh
Megawatt-hour
NAAQS
National Ambient Air Quality Standards
NGL
Natural gas liquid
NOX
Nitrogen oxide
OCC
Oklahoma Corporation Commission
OG&E
Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Holdings
OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy, parent company of Enogex Holdings (prior to May 1, 2013) and 25.6 percent owner of Enable Midstream Partners
Pension Plan
Qualified defined benefit retirement plan
Ppb
Parts per billion
Regional Haze Rule
The EPA's Regional Haze Rule
Restoration of Retirement Income Plan
Supplemental retirement plan to the Pension Plan
SIP
State Implementation Plan
SO2
Sulfur dioxide
SPP
Southwest Power Pool
System sales
Sales to OG&E's customers
TBtu/d
Trillion British thermal units per day
U.S.
United States of America

ii

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-Q, including those matters discussed in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "intend," "objective," "plan," "possible," "potential," "project" and similar expressions. Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed in "Item 1A. Risk Factors" in the Company's 2017 Form 10-K and in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Item 1A. of Part II herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
•
general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
•
the ability of the Company and its subsidiaries to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;
•
the ability to obtain timely and sufficient rate relief to allow for recovery of items such as capital expenditures, fuel costs, operating costs, transmission costs and deferred expenditures;
•
prices and availability of electricity, coal, natural gas and NGLs;
•
the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions Enable serves and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable's interstate pipelines;
•
the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering by Enable's gathering and processing business and transporting by Enable's interstate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regions Enable serves;
•
business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;
•
competitive factors, including the extent and timing of the entry of additional competition in the markets served by the Company;
•
the impact on demand for our services resulting from cost-competitive advances in technology, such as distributed electricity generation and customer energy efficiency programs;
•
technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;
•
factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
•
availability and prices of raw materials for current and future construction projects;
•
the effect of retroactive pricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;
•
federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company's markets;
•
environmental laws, safety laws or other regulations that may impact the cost of operations or restrict or change the way the Company operates its facilities;
•
changes in accounting standards, rules or guidelines;
•
the discontinuance of accounting principles for certain types of rate-regulated activities;
•
the cost of protecting assets against, or damage due to, terrorism or cyberattacks and other catastrophic events;
•
creditworthiness of suppliers, customers and other contractual parties;
•
social attitudes regarding the utility, natural gas and power industries;
•
identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions and divestitures;
•
increased pension and healthcare costs;
•
costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including, but not limited to, those described in this Form 10-Q;
•
difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment in Enable that the Company does not control; and
•
other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission, including those listed in "Item 1A. Risk Factors" in the Company's 2017 Form 10-K and Item 1A. of Part II herein.
The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
 
Three Months Ended June 30,
Six Months Ended June 30,
(In millions, except per share data)
2018
2017
2018
2017
OPERATING REVENUES
 
 
 
 
Revenues from contracts with customers
$
547.7

$
—

$
1,025.6

$
—

Other revenues
19.3

—

34.1

—

Operating revenues
567.0

586.4

1,059.7

1,042.4

COST OF SALES
208.7

232.1

419.2

440.8

OPERATING EXPENSES
 
 


Other operation and maintenance
123.2

112.5

242.0

234.6

Depreciation and amortization
80.9

74.7

159.7

130.3

Taxes other than income
22.5

21.3

46.6

45.2

Operating expenses
226.6

208.5

448.3

410.1

OPERATING INCOME
131.7

145.8

192.2

191.5

OTHER INCOME (EXPENSE)
 
 


Equity in earnings of unconsolidated affiliates
29.3

29.4

63.2

65.0

Allowance for equity funds used during construction
6.3

8.5

13.3

15.4

Other net periodic benefit income (expense)
0.8

(2.3
)
2.1

(4.2
)
Other income
4.7

10.3

10.1

19.1

Other expense
(3.3
)
(3.2
)
(7.7
)
(7.3
)
Net other income
37.8

42.7

81.0

88.0

INTEREST EXPENSE
 
 


Interest on long-term debt
39.7

39.2

79.3

75.1

Allowance for borrowed funds used during construction
(2.8
)
(4.1
)
(6.5
)
(7.4
)
Interest on short-term debt and other interest charges
4.0

2.0

6.7

4.4

Interest expense
40.9

37.1

79.5

72.1

INCOME BEFORE TAXES
128.6

151.4

193.7

207.4

INCOME TAX EXPENSE
17.9

46.6

28.0

66.6

NET INCOME
$
110.7

$
104.8

$
165.7

$
140.8

BASIC AVERAGE COMMON SHARES OUTSTANDING
199.7

199.7

199.7

199.7

DILUTED AVERAGE COMMON SHARES OUTSTANDING
200.5

199.9

200.3

200.0

BASIC EARNINGS PER AVERAGE COMMON SHARE
$
0.55

$
0.52

$
0.83

$
0.70

DILUTED EARNINGS PER AVERAGE COMMON SHARE
$
0.55

$
0.52

$
0.83

$
0.70

DIVIDENDS DECLARED PER COMMON SHARE
$
0.33250

$
0.30250

$
0.66500

$
0.60500











The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

2

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended June 30,
Six Months Ended June 30,
(In millions)
2018
2017
2018
2017
Net income
$
110.7

$
104.8

$
165.7

$
140.8

Other comprehensive income (loss), net of tax:
 
 
 
 
Pension Plan and Restoration of Retirement Income Plan:
 
 
 
 
Amortization of deferred net loss, net of tax of $0.3, $0.4, $0.5 and $0.8, respectively
1.0

0.8

1.7

1.4

Postretirement benefit plans:
 
 
 
 
Amortization of prior service credit, net of tax of ($0.2), ($0.0), ($0.3) and ($0.0), respectively
(0.3
)
—

(0.8
)
—

Other comprehensive income, net of tax
0.7

0.8

0.9

1.4

Comprehensive income
$
111.4

$
105.6

$
166.6

$
142.2




































The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

3


OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Six Months Ended June 30,
(In millions)
2018
2017
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$
165.7

$
140.8

Adjustments to reconcile net income to net cash provided from operating activities:


Depreciation and amortization
159.7

130.3

Deferred income taxes and investment tax credits, net
19.4

68.0

Equity in earnings of unconsolidated affiliates
(63.2
)
(65.0
)
Distributions from unconsolidated affiliates
63.2

65.0

Allowance for equity funds used during construction
(13.3
)
(15.4
)
Stock-based compensation expense
5.8

4.5

Regulatory assets
(1.6
)
(15.6
)
Regulatory liabilities
1.9

(0.2
)
Other assets
7.3

(3.5
)
Other liabilities
(0.6
)
11.7

Change in certain current assets and liabilities:
 
 
Accounts receivable and accrued unbilled revenues, net
(51.5
)
(38.6
)
Income taxes receivable
(2.0
)
4.6

Fuel, materials and supplies inventories
0.1

1.1

Fuel recoveries
37.0

(56.1
)
Other current assets
22.0

5.7

Accounts payable
(45.7
)
1.3

Other current liabilities
50.0

(41.2
)
Net cash provided from operating activities
354.2

197.4

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures (less allowance for equity funds used during construction)
(273.8
)
(491.1
)
Investment in unconsolidated affiliates
(0.5
)
(5.2
)
Return of capital - unconsolidated affiliates
7.4

5.6

Proceeds from sale of assets
—

0.4

Net cash used in investing activities
(266.9
)
(490.3
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Increase (decrease) in short-term debt
31.7

(43.0
)
Proceeds from long-term debt
—

296.5

Payment of long-term debt
—

(0.1
)
Increase in long-term revolver
—

160.0

Dividends paid on common stock
(133.0
)
(120.8
)
Other
(0.4
)
—

Net cash (used in) provided from financing activities
(101.7
)
292.6

NET CHANGE IN CASH AND CASH EQUIVALENTS
(14.4
)
(0.3
)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
14.4

0.3

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
—

$
—






The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

4

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

June 30,
December 31,
(In millions)
2018
2017
ASSETS
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
$
—

$
14.4

Accounts receivable, less reserve of $1.0 and $1.5, respectively
221.2

188.7

Accounts receivable - unconsolidated affiliates
—

1.9

Accrued unbilled revenues
87.8

66.5

Income taxes receivable
7.8

5.8

Fuel inventories
81.1

84.3

Materials and supplies, at average cost
130.3

80.8

Other
32.6

54.6

Total current assets
560.8

497.0

OTHER PROPERTY AND INVESTMENTS




Investment in unconsolidated affiliates
1,153.6

1,160.4

Other
77.0

76.7

Total other property and investments
1,230.6

1,237.1

PROPERTY, PLANT AND EQUIPMENT
 
 
In service
11,544.6

11,041.2

Construction work in progress
566.0

867.5

Total property, plant and equipment
12,110.6

11,908.7

Less accumulated depreciation
3,637.5

3,568.8

Net property, plant and equipment
8,473.1

8,339.9

DEFERRED CHARGES AND OTHER ASSETS
 
 
Regulatory assets
270.2

283.0

Other
8.9

55.7

Total deferred charges and other assets
279.1

338.7

TOTAL ASSETS
$
10,543.6

$
10,412.7






















The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

5

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
(Unaudited)

June 30,
December 31,
(In millions)
2018
2017
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
CURRENT LIABILITIES
 
 
Short-term debt
$
200.1

$
168.4

Accounts payable
161.4

230.4

Dividends payable
66.4

66.4

Customer deposits
82.5

80.7

Accrued taxes
42.9

44.5

Accrued interest
44.0

44.0

Accrued compensation
37.7

35.9

Long-term debt due within one year
499.9

249.8

Fuel clause over recoveries
38.7

1.7

Other
76.7

28.7

Total current liabilities
1,250.3

950.5

LONG-TERM DEBT
2,500.4

2,749.6

DEFERRED CREDITS AND OTHER LIABILITIES
 
 
Accrued benefit obligations
188.4

192.7

Deferred income taxes
1,255.1

1,227.8

Regulatory liabilities
1,296.1

1,283.4

Other
163.2

157.6

Total deferred credits and other liabilities
2,902.8

2,861.5

Total liabilities
6,653.5

6,561.6

COMMITMENTS AND CONTINGENCIES (NOTE 13)


STOCKHOLDERS' EQUITY
 
 
Common stockholders' equity
1,120.1

1,114.8

Retained earnings
2,792.3

2,759.5

Accumulated other comprehensive loss, net of tax
(22.3
)
(23.2
)
Total stockholders' equity
3,890.1

3,851.1

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
10,543.6

$
10,412.7




















The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

6

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(Unaudited)



(In millions)
Shares Outstanding
Common Stock
Premium on Common Stock
Retained Earnings
Accumulated Other Comprehensive (Loss) Income
Total
Balance at December 31, 2017
199.7

$
2.0

$
1,112.8

$
2,759.5

$
(23.2
)
$
3,851.1

Net income
—

—

—

165.7

—

165.7

Other comprehensive income, net of tax
—

—

—

—

0.9

0.9

Dividends declared on common stock
—

—

—

(132.9
)
—

(132.9
)
Stock-based compensation
—

—

5.3

—

—

5.3

Balance at June 30, 2018
199.7

$
2.0

$
1,118.1

$
2,792.3

$
(22.3
)
$
3,890.1

 
 
 
 
 
 
 
Balance at December 31, 2016
199.7

$
2.0

$
1,103.8

$
2,367.3

$
(29.3
)
$
3,443.8

Net income
—

—

—

140.8

—

140.8

Cumulative effect of change in accounting principle
—

—

—

22.3

—

22.3

Other comprehensive income, net of tax
—

—

—

—

1.4

1.4

Dividends declared on common stock
—

—

—

(120.8
)
—

(120.8
)
Stock-based compensation
—

—

4.5

—

—

4.5

Balance at June 30, 2017
199.7

$
2.0

$
1,108.3

$
2,409.6

$
(27.9
)
$
3,492.0

































The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

7


OGE ENERGY CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.
Summary of Significant Accounting Policies

The Company's significant accounting policies are detailed in "Note 1. Summary of Significant Accounting Policies" in the Company's 2017 Form 10-K. Changes to the Company's accounting policies as a result of adopting ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," are discussed in Note 3 in this Form 10-Q.

Organization

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the Condensed Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries and ultimately OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns an emerging crude oil gathering business in the Bakken Shale formation, principally located in the Williston Basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

Enable was formed effective May 1, 2013 by the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group contributed Enogex LLC to Enable, and the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.
In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at June 30, 2018 and December 31, 2017, the consolidated results of its operations for the three and six months ended June 30, 2018 and 2017 and its consolidated cash flows for the six months ended June 30, 2018 and 2017 have been included and are of a normal, recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring after June 30, 2018 up to the date of issuance of these Condensed Consolidated Financial Statements, and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

Due to seasonal fluctuations and other factors, the Company's operating results for the three and six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 or for any future

8


period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2017 Form 10-K.

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates.

The following table is a summary of OG&E's regulatory assets and liabilities.
 
June 30,
December 31,
(In millions)
2018
2017
REGULATORY ASSETS
 
 
Current:
 
 
Oklahoma demand program rider under recovery (A)
$
16.7

$
31.6

SPP cost tracker under recovery (A)
0.8

7.7

Other (A)
2.2

1.5

Total current regulatory assets
$
19.7

$
40.8

Non-current:
 

 

Benefit obligations regulatory asset
$
171.9

$
177.2

Deferred storm expenses
39.0

42.2

Smart Grid
29.3

32.8

Unamortized loss on reacquired debt
11.8

12.3

Other
18.2

18.5

Total non-current regulatory assets
$
270.2

$
283.0

REGULATORY LIABILITIES
 

 

Current:
 

 

Fuel clause over recoveries
$
38.7

$
1.7

Other (B)
2.5

2.2

Total current regulatory liabilities
$
41.2

$
3.9

Non-current:
 

 

Income taxes refundable to customers, net
$
944.2

$
955.5

Accrued removal obligations, net
300.2

288.4

Pension tracker
44.4

32.3

Other
7.3

7.2

Total non-current regulatory liabilities
$
1,296.1

$
1,283.4

(A)
Included in Other Current Assets on the Condensed Consolidated Balance Sheets.
(B)
Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.    

Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets or liabilities, which could have significant financial effects.
             

9


Investment in Unconsolidated Affiliates

The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable; therefore, the Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable at June 30, 2018 as presented in Note 12. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

The Company considers distributions received from Enable, which do not exceed cumulative equity in earnings subsequent to the date of investment, to be a return on investment and are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.

Accumulated Other Comprehensive Income (Loss)
The following tables summarize changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the six months ended June 30, 2018 and 2017. All amounts below are presented net of tax.
 
Pension Plan and Restoration of Retirement Income Plan
 
Postretirement Benefit Plans
 
(In millions)
Net income
 (loss)
Prior service cost
 
Net income
Prior service credit
Total
Balance at December 31, 2017
$
(32.7
)
$
—

 
$
2.5

$
7.0

$
(23.2
)
Amounts reclassified from accumulated other comprehensive income (loss)
1.7

—

 
—

(0.8
)
0.9

Balance at June 30, 2018
$
(31.0
)
$
—

 
$
2.5

$
6.2

$
(22.3
)
 
Pension Plan and Restoration of Retirement Income Plan
 
Postretirement Benefit Plans
 
(In millions)
Net income
 (loss)
Prior service cost
 
Net income
Prior service credit
Total
Balance at December 31, 2016
$
(32.1
)
$
0.1

 
$
2.7

$
—

$
(29.3
)
Amounts reclassified from accumulated other comprehensive income
1.4

—

 
—

—

1.4

Balance at June 30, 2017
$
(30.7
)
$
0.1


$
2.7

$
—

$
(27.9
)


10


The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and six months ended June 30, 2018 and 2017.
Details about Accumulated Other Comprehensive Income (Loss) Components
Amount Reclassified from Accumulated Other Comprehensive Income (Loss)
Affected Line Item in the Condensed Consolidated Statements of Income
 
Three Months Ended
Six Months Ended
 
 
June 30,
June 30,
 
(In millions)
2018
2017
2018
2017
 
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
 
 
 
 
 
Actuarial losses (A)
$
(1.3
)
$
(1.2
)
$
(2.2
)
$
(2.2
)
Other Net Periodic Benefit Income (Expense)
 
(0.3
)
(0.4
)
(0.5
)
(0.8
)
Income Tax Expense
 
$
(1.0
)
$
(0.8
)
$
(1.7
)
$
(1.4
)
Net Income
 
 
 
 
 
 
Amortization of postretirement benefit plans items:
 
 
 
 
 
Prior service credit (A)
$
0.5

$
—

$
1.1

$
—

Other Net Periodic Benefit Income (Expense)
 
0.2

—

0.3

—

Income Tax Expense
 
$
0.3

$
—

$
0.8

$
—

Net Income
 
 
 
 
 
 
Total reclassifications for the period, net of tax
$
(0.7
)
$
(0.8
)
$
(0.9
)
$
(1.4
)
Net Income
(A)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).

Reclassifications

Certain prior-year amounts have been reclassified to conform to the current year presentation.

Amounts for the three and six months ended June 30, 2017 have been adjusted for the reclassification of net periodic benefit cost components between Other Operation and Maintenance and Other Net Periodic Benefit Income (Expense) on the Company's Condensed Consolidated Statements of Income to be consistent with the 2018 presentation due to the Company's adoption of ASU 2017-07, "Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost."

2.
Accounting Pronouncements

Recently Adopted Accounting Standards

Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)." The Company adopted this standard in the first quarter of 2018 utilizing the modified retrospective transition method and applied the new standard only to contracts that were not completed at the date of initial application. The Company determined it was not necessary to change the timing or amounts of revenue recognized based on the adoption of Topic 606. Therefore, financial statement amounts in the period of adoption have not changed under Topic 606 as compared with the guidance that was in effect before the adoption of Topic 606. The adoption did change financial statement presentation as Operating Revenues are now separated between Revenues from Contracts with Customers and Other Revenues on the 2018 Condensed Consolidated Statement of Income. In addition, gains and losses associated with OG&E's guaranteed flat bill program that were previously included in Net Other Income on the Condensed Consolidated Statements of Income are now presented as Revenues from Contracts with Customers since the gains and losses are included within the transaction price in the contract under Topic 606. Operating Revenues presented on the 2017 Condensed Consolidated Statement of Income did not change from prior year.

11


Alternative revenue programs are scoped out of Topic 606, as these programs are considered agreements between an entity and a regulator, not contracts between an entity and a customer; therefore, the Company now presents revenues from alternative revenue programs separately from revenues from contracts with customers. Further discussion regarding the Company's revenue recognition as well as additional disclosures resulting from the adoption of Topic 606 can be found in Note 3.

Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. In February 2017, the FASB issued ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets." ASC 610-20 was issued as part of ASU 2014-09 and was added to provide guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with non-customers. The new guidance clarifies the application of the guidance in Topic 606 for the derecognition of nonfinancial assets and unifies guidance related to partial sales of nonfinancial assets. The Company adopted the new guidance beginning in the first quarter of 2018, which did not have a material effect on its Condensed Consolidated Financial Statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In May 2017, the FASB issued ASU 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost." The new guidance is designed to improve the reporting of pension and other postretirement benefit costs by bifurcating the components of net benefit cost between those that are attributed to compensation for service and those that are not. The service cost component of benefit cost continues to be presented within operating income, but entities are now required to present the other components of benefit cost as non-operating within the income statement. Additionally, the new guidance only permits the capitalization of the service cost component of net benefit cost. The accounting change is required to be applied on a retrospective basis for the presentation of components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit costs. The Company adopted the new guidance beginning in the first quarter of 2018. The presentation and recognition impacts of the Company's adoption of ASU 2017-07 are further discussed in Note 11.

Recognition and Measurement of Financial Assets and Financial Liabilities. In January 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The new guidance, among other things, requires entities to measure equity instruments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) at fair value with changes in fair value recognized in net income. Further, an entity has the option to measure equity instruments that do not have readily determinable fair values at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investment of the same issuer. The Company adopted the new guidance beginning in the first quarter of 2018, which did not have a material effect on its Condensed Consolidated Financial Statements.

Issued Accounting Standards Not Yet Adopted

Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between current lease accounting and Topic 842 is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance. Lessees, such as the Company, will need to recognize a right-of-use asset and a lease liability for virtually all of their leases, other than leases that meet the definition of a short-term lease. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to current capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in current lease guidance but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 2018. The new guidance must be adopted using a modified retrospective transition method and provides for certain practical expedients. Transition method options include application of the new guidance at the beginning of the earliest comparative period presented or at the adoption date, with a cumulative-effect adjustment to retained earnings in the period of adoption. The Company is evaluating its current lease contracts and currently intends to take the package of practical expedients allowing entities to not reassess (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases and (iii) initial direct costs for any existing leases. The Company has not quantified the impact on its Condensed Consolidated Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities.

In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842," which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that exist or expired

12


before the entity's adoption of Topic 842 and that were not previously accounted for as leases under ASC 840, "Leases." Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. ASU 2018-01 is effective for fiscal years beginning after December 2018. The Company currently intends to elect this practical expedient during its adoption of Topic 842 and does not plan to evaluate existing easement contracts under Topic 842, if these contracts have not previously been accounted for under Topic 840.

In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842): Targeted Improvements," which provides the following additional amendments to ASU 2016-02: (i) entities can elect to initially apply ASU 2016-02 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption and (ii) lessors can elect a practical expedient, by class of underlying asset, to account for nonlease components and the associated lease component as a single component, if the nonlease component otherwise would be accounted for under Topic 606 and certain conditions, as described in ASU 2018-11, are met. If an entity elects the additional (and optional) transition method, the entity will provide the required Topic 840 disclosures for all periods that continue to be reported under Topic 840. ASU 2018-11 is effective for fiscal years beginning after December 2018. The Company is reviewing potential impacts of ASU 2018-11 and currently intends to elect the transition method provided by the guidance allowing for initial application at the adoption date.

3.
Revenue Recognition

Revenue from Contracts with Customers

General

OG&E recognizes revenue from electric sales when power is delivered to customers. The performance obligation to deliver electricity is generally created and satisfied simultaneously, and the provisions of the regulatory-approved tariff determine the charges OG&E may bill the customer, payment due date and other pertinent rights and obligations of both parties. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Condensed Consolidated Balance Sheets and in Revenues from Contracts with Customers on the Condensed Consolidated Statements of Income based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Integrated Market and Transmission

OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority, but not ownership, of OG&E's transmission facilities to the SPP. The SPP has implemented FERC-approved regional day ahead and real-time markets for energy and operating services, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities.

OG&E records the SPP Integrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. Sales are billed based on the fixed transaction price determined by the market at the time of the sale and the MWh quantity purchased. These results are reported as Revenues from Contracts with Customers or Cost of Sales in the Condensed Consolidated Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP.

OG&E's transmission revenues are generated by the use of OG&E's transmission network by the SPP, which operates the network, on behalf of other transmission owners. OG&E recognizes revenue on the sale of transmission service to its customers over time as the service is provided in the amount OG&E has a right to invoice. Transmission service to the SPP is billed monthly based on a fixed transaction price determined by OG&E's FERC-approved formula transmission rates along with other SPP-specific charges and the megawatt quantity reserved.


13


Disaggregated Revenue

The following table disaggregates the Company's revenues from contracts with customers by customer classification. The Company's operating revenues disaggregated by customer classification can be found in "OG&E (Electric Utility) Results of Operations" in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations."
 
June 30, 2018
(In millions)
Three Months Ended
Six Months Ended
Residential
$
217.3

$
413.5

Commercial
152.4

270.2

Industrial
47.7

89.4

Oilfield
37.7

71.5

Public authorities and street light
51.1

92.8

   System sales revenues
506.2

937.4

Provision for rate refund
(16.5
)
(19.7
)
Integrated market
13.1

21.8

Transmission
40.2

76.0

Other
4.7

10.1

Revenues from contracts with customers
$
547.7

$
1,025.6


Other Revenues

Revenues from Alternative Revenue Programs

Other Revenues on the Condensed Consolidated Statements of Income is comprised of certain rider revenue that includes alternative revenue measures as defined in ASC 980, "Regulated Operations," which details two types of alternative revenue programs. The first type adjusts billings for the effects of weather abnormalities or broad external factors or to compensate OG&E for demand-side management initiatives (i.e., no-growth plans and similar conservation efforts). The second type provides for additional billings (i.e., incentive awards) for the achievement of certain objectives, such as reducing costs, reaching specified milestones or demonstratively improving customer service. Once the specific events permitting billing of the additional revenues under either program type have been completed, OG&E recognizes the additional revenues if (i) the program is established by an order from OG&E's regulatory commission that allows for automatic adjustment of future rates; (ii) the amount of additional revenues for the period is objectively determinable and is probable of recovery; and (iii) the additional revenues will be collected within 24 months following the end of the annual period in which they are recognized.

4.
Investment in Unconsolidated Affiliates and Related Party Transactions

On March 14, 2013, the Company entered into a Master Formation Agreement with the ArcLight group and CenterPoint pursuant to which the Company, the ArcLight group and CenterPoint agreed to form Enable to own and operate the midstream businesses of the Company and CenterPoint that was initially structured as a private limited partnership. This transaction closed on May 1, 2013.
Pursuant to the Master Formation Agreement, the Company and the ArcLight group indirectly contributed 100 percent of the equity interests in Enogex LLC to Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost.
Enable completed an initial public offering resulting in Enable becoming a publicly traded Master Limited Partnership in April 2014. At June 30, 2018, the Company owned 111.0 million common units, or 25.6 percent, of Enable's outstanding common units. Distributions received from Enable were $35.3 million during both the three months ended June 30, 2018 and 2017 and $70.6 million during both the six months ended June 30, 2018 and 2017.

On August 1, 2018, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common units, which is unchanged from the previous quarter. If cash distributions to Enable's unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner

14


has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable's cash distributions at the time of the exercise of this reset election.

Related Party Transactions

The Company and Enable are currently parties to several agreements whereby the Company provides specified support services to Enable, such as certain information technology, payroll and benefits administration. Under these agreements, the Company charged operating costs to Enable of $0.2 million and $0.7 million for the three months ended June 30, 2018 and 2017, respectively, and $0.3 million and $1.5 million for the six months ended June 30, 2018 and 2017, respectively. The Company charges operating costs to OG&E and Enable based on several factors, and operating costs directly related to OG&E and/or Enable are assigned as such. Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method, which is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment.

Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of June 30, 2018, 134 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $5.2 million and $7.3 million during the three months ended June 30, 2018 and 2017, respectively, and $16.8 million and $17.3 million for the six months ended June 30, 2018 and 2017, respectively, under the seconding agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by approximately $13.8 million. Settlement and curtailment charges associated with the seconded employees are not reimbursable to the Company by Enable. The seconding agreement can be terminated by mutual agreement of the Company and Enable or solely by the Company upon 120 days' notice.

The Company had accounts receivable from Enable for amounts billed for support services, including the cost of seconded employees, of $1.8 million as of June 30, 2018 and $2.0 million as of December 31, 2017.

Enable provides gas transportation services to OG&E pursuant to an agreement that expires in April 2019. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E's generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable's deliveries exceed OG&E's pipeline receipts. Enable purchases gas from OG&E when OG&E's pipeline receipts exceed Enable's deliveries. The following table summarizes related party transactions between OG&E and Enable during the three and six months ended June 30, 2018 and 2017.
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
(In millions)
2018
2017
2018
2017
Operating revenues:
 
 
 
 
Electricity to power electric compression assets
$
3.6

$
3.3

$
7.6

$
5.5

Cost of sales:
 
 
 
 
Natural gas transportation services
$
8.8

$
8.8

$
17.5

$
17.5

Natural gas purchases (sales)
$
2.2

$
(0.4
)
$
2.5

$
(0.8
)
 
Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2018 and December 31, 2017 and for the three and six months ended June 30, 2018 and 2017.
 
June 30,
December 31,
Balance Sheet
2018
2017
(In millions)
 
Current assets
$
432

$
416

Non-current assets
$
11,360

$
11,177

Current liabilities
$
1,258

$
1,279

Non-current liabilities
$
2,963

$
2,660


15


 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
Income Statement
2018
2017
2018
2017
(In millions)
 
Operating revenues
$
805

$
626

$
1,553

$
1,292

Cost of natural gas and NGLs
$
444

$
279

$
819

$
587

Operating income
$
126

$
122

$
265

$
262

Net income
$
86

$
86

$
191

$
197


The formation of Enable was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value. Enogex Holdings' assets, liabilities and equity have accordingly been adjusted to estimated fair value as of May 1, 2013, resulting in an increase to equity of $2.2 billion. Due to the contribution of Enogex LLC to Enable meeting the requirements of being in substance real estate and thus recording the initial investment at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in the Company's recording of its equity in earnings of Enable.

The Company recorded equity in earnings of unconsolidated affiliates of $29.3 million and $29.4 million for the three months ended June 30, 2018 and 2017, respectively, and $63.2 million and $65.0 million for the six months ended June 30, 2018 and 2017, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex LLC and its underlying equity in the net assets of Enable. The basis difference is being amortized over approximately 30 years, which is the average life of the assets to which the basis difference is attributed, beginning in May 2013. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described below.

The following table reconciles the Company's equity in earnings of unconsolidated affiliates for the three and six months ended June 30, 2018 and 2017.

Three Months Ended
Six Months Ended
 
June 30,
June 30,
(In millions)
2018
2017
2018
2017
Enable net income
$
86.4

$
86.2

$
191.0

$
197.4

OGE Energy's percent ownership at period end
25.6
%
25.7
%
25.6
%
25.7
%
OGE Energy's portion of Enable net income
22.2

22.2

49.0

50.7

Amortization of basis difference
2.8

2.9

5.6

5.7

Elimination of Enable fair value step up
4.3

4.3

8.6

8.6

Equity in earnings of unconsolidated affiliates
$
29.3

$
29.4

$
63.2

$
65.0


The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $696.9 million as of June 30, 2018. The following table reconciles the basis difference in Enable from December 31, 2017 to June 30, 2018.
(In millions)
 
 
Basis difference at December 31, 2017
 
$
714.2

Change in Enable basis difference
 
(3.1
)
Amortization of basis difference
 
(5.6
)
Elimination of Enable fair value step up
 
(8.6
)
Basis difference at June 30, 2018
 
$
696.9



16


5.
Fair Value Measurements
 
The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1), and the lowest priority given to unobservable inputs (Level 3). 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 three levels defined in the fair value hierarchy are as follows:
 
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.
 
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.  

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). 
 
The Company had no financial instruments measured at fair value on a recurring basis at June 30, 2018 and December 31, 2017. The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy, with the exception of the Tinker Debt which is classified as Level 3 in the fair value hierarchy as its fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate. The following table summarizes the fair value and carrying amount of the Company's financial instruments at June 30, 2018 and December 31, 2017.
 
June 30,
December 31,
 
2018
2017
(In millions)
Carrying Amount 
Fair
Value
Carrying Amount 
 Fair
Value
Long-term Debt (including Long-term Debt due within one year):
 
 
 
 
Senior Notes
$
2,855.2

$
3,101.4

$
2,854.3

$
3,242.8

OG&E Industrial Authority Bonds
$
135.4

$
135.4

$
135.4

$
135.4

Tinker Debt
$
9.7

$
9.1

$
9.7

$
9.8


6.
Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three and six months ended June 30, 2018 and 2017 related to the Company's performance units and restricted stock.
 
Three Months Ended June 30,
Six Months Ended June 30,
(In millions)
2018
2017
2018
2017
Performance units:
 
 
 
 
Total shareholder return
$
2.1

$
1.8

$
4.1

$
3.3

Earnings per share
1.0

0.6

1.7

1.2

Total performance units
3.1

2.4

5.8

4.5

Restricted stock
—

—

—

—

Total compensation expense
$
3.1

$
2.4

$
5.8

$
4.5

Income tax benefit
$
0.8

$
1.0

$
1.5

$
1.8


During the three and six months ended June 30, 2018, the Company issued an immaterial number of shares of new common stock pursuant to the Company's Stock Incentive Plan to satisfy restricted stock grants and payouts of earned performance units.

17



7.
Income Taxes

As previously discussed in the Company's 2017 Form 10-K, the 2017 Tax Act was signed into law in December 2017, reducing the corporate federal tax rate from 35 percent to 21 percent for tax years beginning in 2018. ASC 740, "Income Taxes," requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized and settled. Entities subject to ASC 980, "Accounting for Regulated Entities," such as OG&E, are required to recognize a regulatory liability for the decrease in taxes payable for the change in tax rates that are expected to be returned to customers through future rates and to recognize a regulatory asset for the increase in taxes receivable for the change in tax rates that are expected to be recovered from customers through future rates. At December 31, 2017, as a result of remeasuring existing deferred taxes at the lower 21 percent tax rate, the Company reduced net deferred income tax liabilities and increased regulatory liabilities. As of June 30, 2018, the Company's regulatory liability for income taxes refundable to customers, net was $1.028 billion, as a result of the change in the corporate federal tax rate.

Staff Accounting Bulletin No. 118 addresses the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the 2017 Tax Act. The Company recognized the provisional tax impacts related to the revaluation of deferred tax assets and liabilities as of December 31, 2017. The ultimate impact may differ from those provisional amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations and assumptions the Company has made, additional regulatory guidance that may be issued and the actions the Company may take as a result of the 2017 Tax Act. The Company continues to evaluate its computations, and any subsequent adjustments to the amounts recognized as of December 31, 2017 will be recorded in the quarter when the analysis is complete.

As a result of the 2017 Tax Act, in early January 2018: (i) the OCC ordered OG&E to record a reserve, including accrued interest, to reflect the reduced federal corporate tax rate, among other tax implications, on an interim basis, subject to refund until utility rates were adjusted to reflect the federal tax savings; (ii) the APSC ordered OG&E to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act until the resulting benefits, including carrying charges, are returned to customers; and (iii) through a Section 206 filing with the FERC, modifications were requested to be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act. For Oklahoma jurisdictional revenues, OG&E has reserved the excess income taxes collected in current rates, plus interest, from January 2018 to June 2018, which was refunded to Oklahoma customers, as approved by the OCC, during the July 2018 billing cycle. For Arkansas jurisdictional revenues, OG&E is reserving the excess income taxes collected in current rates, plus carrying charges, from January 2018 to the effective date of the rider based on an order received from the APSC. For FERC jurisdictional revenues, OG&E is reserving the excess income taxes collected in current rates, plus interest, from January 2018 to the date the new tax rate is reflected in billings based on an order received from the FERC. Further, for Oklahoma, Arkansas and FERC jurisdictional revenues, OG&E is also reserving any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act. As of June 30, 2018, the total recorded reserve was $32.8 million, which is included in Other Current Liabilities on the Company's Condensed Consolidated Balance Sheets. Further discussion can be found in Note 14.

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal tax examinations by tax authorities for years prior to 2014 or state and local tax examinations by tax authorities for years prior to 2013. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.

8.
Common Equity
 
Automatic Dividend Reinvestment and Stock Purchase Plan
 
The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and six months ended June 30, 2018.  


18


Earnings Per Share
 
Basic earnings per share is calculated by dividing net income attributable to the Company by the weighted-average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted-average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units and restricted stock units. The following table calculates basic and diluted earnings per share for the Company.
 
Three Months Ended June 30,
Six Months Ended June 30,
(In millions except per share data)
2018
2017
2018
2017
Net income
$
110.7

$
104.8

$
165.7

$
140.8

Average common shares outstanding:
 
 
 
 
Basic average common shares outstanding
199.7

199.7

199.7

199.7

Effect of dilutive securities:
 
 
 
 
Contingently issuable shares (performance and restricted stock units)
0.8

0.2

0.6

0.3

Diluted average common shares outstanding
200.5

199.9

200.3

200.0

Basic earnings per average common share
$
0.55

$
0.52

$
0.83

$
0.70

Diluted earnings per average common share
$
0.55

$
0.52

$
0.83

$
0.70

Anti-dilutive shares excluded from earnings per share calculation
—

—

—

—


9.
Long-Term Debt
 
At June 30, 2018, the Company was in compliance with all of its debt agreements.
 
OG&E Industrial Authority Bonds

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are included in the following table.
SERIES
DATE DUE
AMOUNT
 
 
 
 
(In millions)
1.06%
-
2.00%
Garfield Industrial Authority, January 1, 2025
$
47.0

1.05%
-
1.83%
Muskogee Industrial Authority, January 1, 2025
32.4

1.06%
-
1.86%
Muskogee Industrial Authority, June 1, 2027
56.0

Total (redeemable during next 12 months)
$
135.4


All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third-party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as Long-term Debt in the Company's Condensed Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.


19


10.
Short-Term Debt and Credit Facilities
 
The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. As of June 30, 2018, the Company had $200.1 million of short-term debt as compared to $168.4 million at December 31, 2017. The following table provides information regarding the Company's revolving credit agreements at June 30, 2018.
 
Aggregate
Amount
Weighted-Average
 
 
 
Entity
Commitment 
Outstanding (A)
Interest Rate
 
Expiration
 
(In millions)
 
 
 
 
 
OGE Energy (B)
$
450.0

$
200.1

2.31
%
(D)
March 8, 2023
(E)
OG&E (C)
450.0

0.3

0.95
%
(D)
March 8, 2023
(E)
Total
$
900.0

$
200.4

2.31
%
 
 
 
(A)
Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2018.
(B)
This bank facility is available to back up the Company's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.  
(C)
This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.   
(D)
Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.
(E)
In March 2017, the Company and OG&E entered into unsecured five-year revolving credit agreements totaling $900.0 million ($450.0 million for the Company and $450.0 million for OG&E). Each of the facilities contained an option, which could be exercised up to two times, to extend the term of the respective facility for an additional year. Effective March 9, 2018, the Company and OG&E utilized one of those extensions to extend the maturity of their respective credit facility from March 8, 2022 to March 8, 2023.

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit.
 
OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2017 and ending December 31, 2018.

11.
Retirement Plans and Postretirement Benefit Plans

Net Periodic Benefit Cost

The Company adopted ASU 2017-07 in the first quarter of 2018 and, as a result, presents the service cost component of net benefit cost in operating income and the other components of net benefit cost as non-operating within its Condensed Consolidated Statements of Income. Further, as required by ASU 2017-07, the Company adjusted prior year income statement presentation of the net benefit cost components, which were previously presented in total within Other Operation and Maintenance on the Company's Condensed Consolidated Statements of Income. The Company elected the practical expedient allowed by ASU 2017-07 to utilize amounts disclosed in the Company's retirement plans and postretirement benefit plans note for the prior comparative period as the estimation basis for applying the retrospective presentation requirements.

20



The following tables present the net periodic benefit cost components, before consideration of capitalized amounts, of the Company's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the Condensed Consolidated Financial Statements. Service cost is presented within Other Operation and Maintenance, and interest cost, expected return on plan assets, amortization of net loss and amortization of unrecognized prior service cost are presented within Other Net Periodic Benefit Income (Expense) on the Company's Condensed Consolidated Statements of Income.

 
Pension Plan
 
Restoration of Retirement
Income Plan
 
Three Months Ended
Six Months Ended
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
 
June 30,
June 30,
(In millions)
2018
(A)
2017
(A)
2018
(B)
2017
(B)
 
2018
(A)
2017
(A)
2018
(B)
2017
(B)
Service cost
$
3.4

$
3.5

$
7.5

$
7.7

 
$
0.1

$
0.1

$
0.2

$
0.2

Interest cost
5.8

6.6

11.7

13.1

 
0.1

—

0.2

0.1

Expected return on plan assets
(11.0
)
(10.6
)
(22.3
)
(21.3
)
 
—

—

—

—

Amortization of net loss
4.4

4.7

8.3

8.7

 
0.3

0.1

0.4

0.2

Total net periodic benefit cost
2.6

4.2

5.2

8.2


0.5

0.2

0.8

0.5

Less: Amount paid by unconsolidated affiliates
0.7

0.9

1.2

1.7

 
—

—

—

—

Net periodic benefit cost
$
1.9

$
3.3

$
4.0

$
6.5

 
$
0.5

$
0.2

$
0.8

$
0.5

(A)
In addition to the $2.4 million and $3.5 million of net periodic benefit cost recognized during the three months ended June 30, 2018 and 2017, respectively, the Company recognized the following:
•
an increase in pension expense during the three months ended June 30, 2018 and 2017 of $3.8 million and $2.9 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1); and
•
a deferral of pension expense during the three months ended June 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013.
(B)
In addition to the $4.8 million and $7.0 million of net periodic benefit cost recognized during the six months ended June 30, 2018 and 2017, respectively, the Company recognized the following:
•
an increase in pension expense during the six months ended June 30, 2018 and 2017 of $7.8 million and $5.8 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1); and
•
a deferral of pension expense during the six months ended June 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013.

21



 
Postretirement Benefit Plans
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
(In millions)
2018 (B)
2017 (B)
2018 (C)
2017 (C)
Service cost
$
0.1

$
0.2

$
0.2

$
0.4

Interest cost
1.3

2.1

2.6

4.3

Expected return on plan assets
(0.5
)
(0.5
)
(1.0
)
(1.1
)
Amortization of net loss
0.9

0.2

1.9

0.8

Amortization of unrecognized prior service cost (A)
(2.1
)
—

(4.2
)
—

Total net periodic benefit cost
(0.3
)
2.0

(0.5
)
4.4

Less: Amount paid by unconsolidated affiliates
(0.1
)
0.2

(0.2
)
0.6

Net periodic benefit cost
$
(0.2
)
$
1.8

$
(0.3
)
$
3.8

(A)
Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.
(B)
In addition to the $0.2 million of net periodic benefit income and $1.8 million of net periodic benefit cost recognized during the three months ended June 30, 2018 and 2017, respectively, the Company recognized an increase in postretirement medical expense in the three months ended June 30, 2018 and 2017 of $2.2 million and $1.0 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).
(C)
In addition to the $0.3 million of net periodic benefit income and $3.8 million of net periodic benefit cost recognized during the six months ended June 30, 2018 and 2017, respectively, the Company recognized an increase in postretirement medical expense in the six months ended June 30, 2018 and 2017 of $4.3 million and $2.1 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

As required by ASU 2017-07, the Company only capitalizes the service cost component of net benefit cost, beginning in the first quarter of 2018. Prior year capitalized amounts were not adjusted, as this change was implemented on a prospective basis.
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
(In millions)
2018
2017
2018
2017
Capitalized portion of net periodic pension benefit cost
$
0.9

$
1.2

$
1.9

$
2.3

Capitalized portion of net periodic postretirement benefit cost
$
0.1

$
0.5

$
0.1

$
1.2



22

12.
Report of Business Segments

The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy and (ii) the natural gas midstream operations segment. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. The following tables summarize the results of the Company's business segments during the three and six months ended June 30, 2018 and 2017.
Three Months Ended June 30, 2018
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
567.0

$
—

$
—

$
—

$
567.0

Cost of sales
208.7

—

—

—

208.7

Other operation and maintenance
123.5

0.3

(0.6
)
—

123.2

Depreciation and amortization
80.9

—

—

—

80.9

Taxes other than income
21.6

0.2

0.7

—

22.5

Operating income (loss)
132.3

(0.5
)
(0.1
)
—

131.7

Equity in earnings of unconsolidated affiliates
—

29.3

—

—

29.3

Other income (expense)
10.0

—

(0.6
)
(0.9
)
8.5

Interest expense
39.2

—

2.6

(0.9
)
40.9

Income tax expense
11.1

6.7

0.1

—

17.9

Net income (loss)
$
92.0

$
22.1

$
(3.4
)
$
—

$
110.7

Investment in unconsolidated affiliates
$
—

$
1,144.6

$
9.0

$
—

$
1,153.6

Total assets
$
9,447.8

$
1,147.9

$
95.6

$
(147.7
)
$
10,543.6

Three Months Ended June 30, 2017
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
586.4

$
—

$
—

$
—

$
586.4

Cost of sales
232.1

—

—

—

232.1

Other operation and maintenance
114.7

0.2

(2.4
)
—

112.5

Depreciation and amortization
73.7

—

1.0

—

74.7

Taxes other than income
20.2

0.3

0.8

—

21.3

Operating income (loss)
145.7

(0.5
)
0.6

—

145.8

Equity in earnings of unconsolidated affiliates
—

29.4

—

—

29.4

Other income (expense)
13.8

—

(0.5
)
—

13.3

Interest expense
35.6

—

1.5

—

37.1

Income tax expense (benefit)
37.7

10.6

(1.7
)
—

46.6

Net income
$
86.2

$
18.3

$
0.3

$
—

$
104.8

Investment in unconsolidated affiliates
$
—

$
1,153.9

$
5.2

$
—

$
1,159.1

Total assets
$
9,199.0

$
1,513.9

$
89.2

$
(381.6
)
$
10,420.5


23

Six Months Ended June 30, 2018
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
1,059.7

$
—

$
—

$
—

$
1,059.7

Cost of sales
419.2

—

—

—

419.2

Other operation and maintenance
243.2

0.6

(1.8
)
—

242.0

Depreciation and amortization
159.7

—

—

—

159.7

Taxes other than income
44.3

0.4

1.9

—

46.6

Operating income (loss)
193.3

(1.0
)
(0.1
)
—

192.2

Equity in earnings of unconsolidated affiliates
—

63.2

—

—

63.2

Other income (expense)
20.6

—

(1.3
)
(1.5
)
17.8

Interest expense
76.5

—

4.5

(1.5
)
79.5

Income tax expense (benefit)
14.1

16.5

(2.6
)
—

28.0

Net income (loss)
$
123.3

$
45.7

$
(3.3
)
$
—

$
165.7

Investment in unconsolidated affiliates
$
—

$
1,144.6

$
9.0

$
—

$
1,153.6

Total assets
$
9,447.8

$
1,147.9

$
95.6

$
(147.7
)
$
10,543.6

Six Months Ended June 30, 2017
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
1,042.4

$
—

$
—

$
—

$
1,042.4

Cost of sales
440.8

—

—

—

440.8

Other operation and maintenance
239.4

0.3

(5.1
)
—

234.6

Depreciation and amortization
128.4

—

1.9

—

130.3

Taxes other than income
42.5

0.5

2.2

—

45.2

Operating income (loss)
191.3

(0.8
)
1.0

—

191.5

Equity in earnings of unconsolidated affiliates
—

65.0

—

—

65.0

Other income (expense)
25.3

0.1

(2.3
)
(0.1
)
23.0

Interest expense
69.2

—

3.0

(0.1
)
72.1

Income tax expense (benefit)
45.0

26.0

(4.4
)
—

66.6

Net income
$
102.4

$
38.3

$
0.1

$
—

$
140.8

Investment in unconsolidated affiliates
$
—

$
1,153.9

$
5.2

$
—

$
1,159.1

Total assets
$
9,199.0

$
1,513.9

$
89.2

$
(381.6
)
$
10,420.5


13.
Commitments and Contingencies
 
Except as set forth below, in Note 14 and under "Environmental Laws and Regulations" in Item 2 of Part I and in Item 1 of Part II of this Form 10-Q, the circumstances set forth in Notes 13 and 14 to the Company's Consolidated Financial Statements included in the Company's 2017 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

Environmental Laws and Regulations
The activities of OG&E are subject to numerous stringent and complex federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways, including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of its operations are in substantial compliance with current federal, state and local environmental standards.


24


Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. OG&E is managing several potentially material uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.

Air Quality Control System

On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating Dry Scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015 to install the Dry Scrubber systems. The Dry Scrubbers are expected to be completed in late 2018 to early 2019. More detail regarding the ECP can be found in Note 14 under "Pending Regulatory Matters."

Other
 
In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, the Company has incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in the Company's Condensed Consolidated Financial Statements. At the present time, based on currently available information, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

14.
Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 14 to the Company's Consolidated Financial Statements included in the Company's 2017 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters. References to "March 2017 OCC rate order" below and in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" indicate the general rate review order OG&E received from the OCC on March 20, 2017, as detailed further in "Note 14. Rate Matters and Regulation" in the Company's 2017 Form 10-K.

Completed Regulatory Matters

Oklahoma Rate Review Filing - 2018

On January 16, 2018, OG&E filed a general rate review in Oklahoma, requesting a rate increase of $1.9 million per year, assuming a 9.9 percent return on equity. The filing sought recovery of the seven combustion turbines that are part of the Mustang Modernization Plan, an increase in depreciation rates to levels similar with rates in existence prior to the March 2017 OCC rate order and credit to customers for the impacts of the 2017 Tax Act, which was enacted on December 22, 2017.

On December 22, 2017, the Attorney General of Oklahoma requested that the OCC reduce the rates and charges for electric service and provide for an immediate refund due to the customers of OG&E resulting from the 2017 Tax Act. In response, on January 4, 2018, the OCC ordered OG&E to record a reserve, beginning on January 4, 2018, to reflect the reduced federal corporate tax rate of 21 percent and the amortization of excess accumulated deferred income tax and any other tax implications of the 2017 Tax Act on an interim basis, subject to refund until utility rates are adjusted to reflect the federal tax savings and a final order is issued in the rate review. Further, the OCC ordered the amounts of any refunds of such reserves owed to customers should accrue interest at a rate equivalent to OG&E's cost of capital as previously recognized in the March 2017 OCC rate order. OG&E has reserved the excess income taxes collected in current rates and any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act, plus interest, from January 2018 through June 2018.

On June 19, 2018, the OCC approved a Joint Stipulation and Settlement Agreement. Key terms of the settlement include the following:

•
an annual net decrease of $64.0 million in OG&E's rates to its Oklahoma retail customers, which reflects recovery of the Mustang Modernization Plan, offset by reductions for the impact of the lower corporate income taxes resulting from the 2017 Tax Act;

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•
for purposes of calculating the Allowance for Funds Used During Construction and OG&E's various recovery riders that include a full return component, use of the most-recently approved return on equity of 9.5 percent and a capital structure of 47 percent debt/53 percent equity;
•
depreciation rates remain unchanged from the current depreciation rates approved in the March 2017 OCC rate order;
•
regulatory asset treatment for the Dry Scrubbers at Sooner Units 1 and 2 that will defer the non-fuel operation and maintenance expenses, depreciation, debt cost associated with the capital investment and related ad valorem taxes, subject to a prudence review in a future general rate review and a determination as to whether the project is used and useful;
•
production tax credits will be removed from base rates and placed into a separate rider;
•
a federal tax credit rider will be established to refund to customers the amount of excess taxes received from January to June 2018, as discussed above, and the ongoing annual true up of excess accumulated deferred income taxes resulting from the reduction in corporate income tax rates as part of the 2017 Tax Act (further discussed in Note 7); and
•
the demand program rider tariff will be revised to allow for concurrent recovery of lost revenues from foregone sales due to certain achieved energy efficiency and demand savings.

As a result of the settlement, new rates were implemented on July 1, 2018, reflecting the impacts of the order, and the tax reserve balance estimated for January 2018 through June 2018 was returned to Oklahoma customers during the July billing cycle.

Demand Program Rider - Energy Efficiency Lost Net Revenues

During the May 2017 implementation of new rates from the March 2017 OCC rate order, OG&E reserved $5.6 million, pending resolution of a dispute with the OCC's Public Utility Division staff regarding recovery of certain lost revenues associated with energy efficiency programs incurred prior to the March 2017 OCC rate order. These lost revenues are included within the total Demand Program Rider regulatory asset balance of $16.7 million as disclosed in Note 1. This dispute was resolved through the June 19, 2018 OCC settlement; as a result, the reserve has been reversed, and an adjustment has been recorded to the Demand Program Rider regulatory asset balance.

Fuel Adjustment Clause Review for Calendar Year 2016

On August 3, 2017, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2016, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On February 7, 2018, an intervenor filed a recommendation to disallow the Oklahoma jurisdictional portion of $3.3 million related to wind sales in the SPP. On April 4, 2018, a Joint Stipulation and Settlement Agreement was filed with the OCC. As part of the agreement, the stipulating parties settled all claims regarding the issue of wind energy settlement costs for the period September 2016 through May 2017, and OG&E agreed to refund $2.4 million to customers related to wind sales in the SPP. On April 25, 2018, the OCC approved the Joint Stipulation and Settlement Agreement, and in May 2018, OG&E refunded this settlement amount to customers.

FERC - Request for Waiver

On May 22, 2018, OG&E submitted a request for waiver of applicable formula rate provisions in OG&E's Open Access Transmission Tariff and SPP, Inc.'s Open Access Transmission Tariff. OG&E requested a waiver, effective January 1, 2018, to revise its 2018 projected net revenue requirement to reflect the federal corporate income tax rate reduction from 35 percent to 21 percent as a result of the 2017 Tax Act. On June 29, 2018, the FERC granted OG&E's request for waiver, effective January 1, 2018, which will allow OG&E to lower its current year projected net revenue requirement and provide benefits to customers through lower rates more promptly than if OG&E were to wait until the current year true-up adjustment to recognize the reduced federal corporate income tax rate. OG&E is reserving the excess income taxes collected in current rates, plus interest, from January 2018 to the date the new tax rate is reflected in billings based on the order received from the FERC. Once the SPP adjusts the rates billed to OG&E's customers, OG&E will begin reversing the reserve as the previous months in 2018 are resettled based on the lower tax rate.

APSC Order - 2017 Tax Act

On January 12, 2018, as a result of the 2017 Tax Act, the APSC ordered OG&E to prepare and file an analysis, within 30 days of this order, of the ratemaking effects of the 2017 Tax Act on OG&E's revenue requirement and begin, effective January 1, 2018, to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act. On July 26, 2018, the APSC ordered OG&E to file, within 30 days of this order, a separate rider that includes the reduction in tax expense due to the 2017 Tax Act and amortization of the applicable excess accumulated deferred income taxes as a reduction in revenue requirement effective from January 1, 2018 to the date that OG&E's first year Formula Rate Plan filing goes into effect in April 2019. OG&E is reserving the excess income taxes collected in current rates and any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act, plus carrying charges, from January 2018 to the effective date of the rider.

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Pending Regulatory Matters

Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates.

Environmental Compliance Plan

On August 6, 2014, OG&E filed an application under Oklahoma Statute Title 17, Section 286 (B) with the OCC for approval of its plan to comply with the EPA's MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asked the OCC to predetermine the prudence of its Mustang Modernization Plan and approval for a recovery mechanism for the associated costs.

On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.

On December 11, 2015, OG&E filed a motion requesting modification of the OCC order for the purposes of approving only the ECP under Oklahoma Statute Title 17, Section 286 (B), and on December 23, 2015, the OCC rejected OG&E's motion.

On February 12, 2016, OG&E filed an application under Oklahoma Statute Title 17, Section 151, et seq. requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed, and OG&E seeks recovery in a general rate review. On April 28, 2016, the OCC approved the Dry Scrubber project.

Two parties appealed the OCC's decision to the Oklahoma Supreme Court. On April 24, 2018, the Oklahoma Supreme Court ruled that the OCC did not have the authority to grant pre-approval of OG&E's Dry Scrubber project outside the authority of Oklahoma Statute Title 17, Section 286 (B). OG&E intends to seek recovery of the Dry Scrubber total cost in a general rate review after the project is completed.

OG&E anticipates the total cost of Dry Scrubbers will be $542.4 million, including allowance for funds used during construction and capitalized ad valorem taxes and expects the project to be completed in late 2018 to early 2019. As of June 30, 2018, OG&E has invested $451.6 million in the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $385.0 million, including allowance for funds used during construction and capitalized ad valorem taxes. As of June 30, 2018, OG&E has invested $376.3 million in the Mustang Modernization Plan. All seven combustion turbines have been placed into service, and a majority of the project is complete, with only minor items remaining for completion in the second half of 2018.

Integrated Resource Plans

In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014 but did not make any material changes to the ECP and other parts of the plan. Currently, OG&E is scheduled to update its IRP in Oklahoma by October 1, 2018 and in Arkansas by October 31, 2018.

FERC - Section 206 Filing

In January 2018, the Oklahoma Municipal Power Authority filed a complaint at the FERC stating that the base return on common equity used by OG&E in calculating formula transmission rates under the SPP Open Access Transmission Tariff is unjust and unreasonable and should be reduced from 10.60 percent to 7.85 percent, effective upon the date of the complaint. The Company is analyzing the potential impact of the complaint but estimates that if the FERC ultimately orders a reduction, each 25 basis point reduction in the requested return on equity would reduce the Company's SPP Open Access Transmission Tariff transmission revenues by approximately $1.5 million annually. OG&E contested the reduction of its base return on equity. The Company is unable to predict what action the FERC will take in response to the Oklahoma Municipal Power Authority's complaint or the timing of such action. However, if the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could have a material adverse effect on the Company's consolidated financial position, results of operations and cash flows.

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In addition to the request to reduce the return on equity, the Oklahoma Municipal Power Authority's complaint also requests that modifications be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act, including the 2017 Tax Act's impact on accumulated deferred income tax balances. OG&E is reserving the excess income taxes collected in current rates, plus interest, from January 2018 to the date the new tax rate is reflected in billings based on the order received from the FERC, as discussed under "FERC - Request for Waiver" above. Further, OG&E is also reserving any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act.

Fuel Adjustment Clause Review for Calendar Year 2017

On July 9, 2018, the OCC staff filed an application to review OG&E's fuel adjustment clause for the calendar year 2017, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. A preliminary hearing on procedural issues was held on July 19, 2018. OG&E expects to file its Minimum Filing Requirements and Supporting Testimony on September 7, 2018.

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Introduction
 
The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the Condensed Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries and ultimately OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns an emerging crude oil gathering business in the Bakken Shale formation, principally located in the Williston Basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois. As disclosed in the Company's 2017 Form 10-K and herein, Enable is subject to a number of risks, including contract renewal risk, the reliance on the drilling and production decisions of others and the volatility of natural gas, NGL and crude oil prices. If any of those risks were to occur, the Company's business, financial condition, results of operations or cash flows could be materially adversely affected.
 
Overview
 
Company Strategy
 
The Company's mission, through OG&E and its equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customer's needs for energy and related services, focusing on safety, efficiency, reliability, customer service and risk management. The Company's corporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and interest in a publicly traded midstream company, while providing competitive energy products and services to customers as well as seeking growth opportunities in both businesses. 

Additionally, the Company wants to achieve a premium valuation of its businesses relative to its peers, grow earnings per share with a stable earnings pattern, create a high performance culture and achieve desired outcomes with target stakeholders. The Company's financial objectives include a long-term annual earnings growth rate for OG&E of three to five percent on a weather-normalized basis, maintaining a strong credit rating as well as targeting dividend increases of approximately 10 percent annually through 2019. The targeted annual dividend increase has been determined after consideration of numerous factors, including the largely retail composition of the Company's shareh