OGE ENERGY CORP. - FORM 10-Q - November 7, 2018

Attached files

file	filename
EX-32.01 - EXHIBIT 32.01 - OGE ENERGY CORP.	q32018ogeenergy10-qxex3201.htm
EX-31.01 - EXHIBIT 31.01 - OGE ENERGY CORP.	q32018ogeenergy10-qxex3101.htm

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 September 30, 2018

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 every Interactive Data File required to be submitted 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 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	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 September 30, 2018, there were 199,732,315 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2018

TABLE OF CONTENTS



	Page
GLOSSARY OF TERMS	ii
FORWARD-LOOKING STATEMENTS	1

Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income	2
Condensed Consolidated Statements of Comprehensive Income	3
Condensed Consolidated Statements of Cash Flows	4
Condensed Consolidated Balance Sheets	5
Condensed Consolidated Statements of Changes in Stockholders' Equity	7
Notes to Condensed Consolidated Financial Statements	8

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3. Quantitative and Qualitative Disclosures About Market Risk	49

Item 4. Controls and Procedures	49

Part II - OTHER INFORMATION
Item 1. Legal Proceedings	51

Item 1A. Risk Factors	51

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	53

Item 6. Exhibits	53

Signature	54

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
AES	AES-Shady Point, Inc.
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 Scrubber	Dry flue gas desulfurization unit 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
NO_X	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
QF	Qualified cogeneration facilities
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

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. Risk Factors" of "Part II - Other Information" 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. Risk Factors" of "Part II - Other Information" 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions, except per share data)	2018			2017			2018			2017
OPERATING REVENUES
Revenues from contracts with customers	$	684.5		$	—		$	1,710.1		$	—
Other revenues	14.3			—			48.4			—
Operating revenues	698.8			716.8			1,758.5			1,759.2
COST OF SALES	244.4			255.7			663.6			696.5
OPERATING EXPENSES
Other operation and maintenance	123.3			111.9			353.2			340.9
Depreciation and amortization	81.1			76.9			240.8			207.2
Taxes other than income	22.7			23.2			69.3			68.4
Operating expenses	227.1			212.0			663.3			616.5
OPERATING INCOME	227.3			249.1			431.6			446.2
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	40.1			33.6			103.3			98.6
Allowance for equity funds used during construction	6.7			11.8			20.0			27.2
Other net periodic benefit income (expense)	(0.7		)	(5.8		)	(10.7		)	(15.6		)
Other income	4.1			15.0			14.2			34.1
Other expense	(3.4		)	(2.0		)	(11.1		)	(9.3		)
Net other income	46.8			52.6			115.7			135.0
INTEREST EXPENSE
Interest on long-term debt	40.2			38.7			119.5			113.8
Allowance for borrowed funds used during construction	(3.3		)	(5.2		)	(9.8		)	(12.6		)
Interest on short-term debt and other interest charges	1.8			2.4			8.5			6.8
Interest expense	38.7			35.9			118.2			108.0
INCOME BEFORE TAXES	235.4			265.8			429.1			473.2
INCOME TAX EXPENSE	30.3			82.4			58.3			149.0
NET INCOME	$	205.1		$	183.4		$	370.8		$	324.2
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7			199.7			199.7			199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.6			200.1			200.4			200.0
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	1.03		$	0.92		$	1.86		$	1.62
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	1.02		$	0.92		$	1.85		$	1.62
DIVIDENDS DECLARED PER COMMON SHARE	$	0.36500		$	0.33250		$	1.03000		$	0.93750

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2018			2017			2018			2017
Net income	$	205.1		$	183.4		$	370.8		$	324.2
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, $0.5, $0.8 and $1.3, respectively	0.8			0.6			2.5			2.0
Settlement cost, net of tax of $1.1, $0.0 , $1.1 and $0.0, respectively	3.1			—			3.1			—
Postretirement benefit plans:
Prior service cost arising during the period, net of tax of $0.0, $4.1, $0.0 and $4.1, respectively	—			6.7			—			6.7
Amortization of prior service credit, net of tax of ($0.1), ($0.2), ($0.4) and ($0.2), respectively	(0.5		)	(0.2		)	(1.3		)	(0.2		)
Settlement cost, net of tax of $0.0, $0.2, $0.0 and $0.2, respectively	—			0.5			—			0.5
Other comprehensive income, net of tax	3.4			7.6			4.3			9.0
Comprehensive income	$	208.5		$	191.0		$	375.1		$	333.2

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	370.8		$	324.2
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	240.8			207.2
Deferred income taxes and investment tax credits, net	63.7			152.1
Equity in earnings of unconsolidated affiliates	(103.3		)	(98.6		)
Distributions from unconsolidated affiliates	103.3			98.6
Allowance for equity funds used during construction	(20.0		)	(27.2		)
Stock-based compensation expense	9.7			4.7
Regulatory assets	(4.8		)	10.9
Regulatory liabilities	(3.7		)	(0.6		)
Other assets	2.1			(2.0		)
Other liabilities	(1.4		)	(70.8		)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	(56.4		)	(97.3		)
Fuel, materials and supplies inventories	14.9			4.1
Fuel recoveries	37.5			15.8
Other current assets	19.3			26.8
Accounts payable	(34.1		)	(29.1		)
Other current liabilities	73.3			(55.1		)
Net cash provided from operating activities	711.7			463.7
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(413.8		)	(662.8		)
Investment in unconsolidated affiliates	(1.9		)	(5.2		)
Return of capital - unconsolidated affiliates	2.6			7.3
Proceeds from sale of assets	—			0.4
Net cash used in investing activities	(413.1		)	(660.3		)
CASH FLOWS FROM FINANCING ACTIVITIES
Decrease in short-term debt	(168.4		)	(89.7		)
Proceeds from long-term debt	396.0			592.3
Payment of long-term debt	(250.0		)	(125.1		)
Dividends paid on common stock	(199.4		)	(181.2		)
Issuance (expense) of common stock	(0.1		)	—
Other	(0.4		)	—
Net cash (used in) provided from financing activities	(222.3		)	196.3
NET CHANGE IN CASH AND CASH EQUIVALENTS	76.3			(0.3		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	14.4			0.3
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	90.7		$	—

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30,		December 31,
(In millions)	2018		2017
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	90.7	$	14.4
Accounts receivable, less reserve of $1.6 and $1.5, respectively	245.2		190.6
Accrued unbilled revenues	68.3		66.5
Income taxes receivable	13.5		5.8
Fuel inventories	64.5		84.3
Materials and supplies, at average cost	132.2		80.8
Other	27.6		54.6
Total current assets	642.0		497.0
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,160.6		1,160.4
Other	77.7		76.7
Total other property and investments	1,238.3		1,237.1
PROPERTY, PLANT AND EQUIPMENT
In service	11,604.7		11,041.2
Construction work in progress	632.9		867.5
Total property, plant and equipment	12,237.6		11,908.7
Less accumulated depreciation	3,680.6		3,568.8
Net property, plant and equipment	8,557.0		8,339.9
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	256.2		283.0
Other	9.5		55.7
Total deferred charges and other assets	265.7		338.7
TOTAL ASSETS	$	10,703.0	$	10,412.7

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)



	September 30,			December 31,
(In millions)	2018			2017
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	—		$	168.4
Accounts payable	171.8			230.4
Dividends payable	72.9			66.4
Customer deposits	83.1			80.7
Accrued taxes	62.6			44.5
Accrued interest	39.5			44.0
Accrued compensation	39.6			35.9
Long-term debt due within one year	249.9			249.8
Fuel clause over recoveries	39.2			1.7
Other	82.3			28.7
Total current liabilities	840.9			950.5
LONG-TERM DEBT	2,896.8			2,749.6
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	172.8			192.7
Deferred income taxes	1,291.5			1,227.8
Regulatory liabilities	1,291.0			1,283.4
Other	180.4			157.6
Total deferred credits and other liabilities	2,935.7			2,861.5
Total liabilities	6,673.4			6,561.6
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,124.0			1,114.8
Retained earnings	2,924.5			2,759.5
Accumulated other comprehensive loss, net of tax	(18.9		)	(23.2		)
Total stockholders' equity	4,029.6			3,851.1
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	10,703.0		$	10,412.7

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

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	—	—		—		370.8			—			370.8
Other comprehensive income, net of tax	—	—		—		—			4.3			4.3
Dividends declared on common stock	—	—		—		(205.8		)	—			(205.8		)
Stock-based compensation	—	—		9.2		—			—			9.2
Balance at September 30, 2018	199.7	$	2.0	$	1,122.0	$	2,924.5		$	(18.9	)	$	4,029.6

Balance at December 31, 2016	199.7	$	2.0	$	1,103.8	$	2,367.3		$	(29.3	)	$	3,443.8
Net income	—	—		—		324.2			—			324.2
Cumulative effect of change in accounting principle	—	—		—		22.3			—			22.3
Other comprehensive income, net of tax	—	—		—		—			9.0			9.0
Dividends declared on common stock	—	—		—		(187.2		)	—			(187.2		)
Stock-based compensation	—	—		4.7		—			—			4.7
Balance at September 30, 2017	199.7	$	2.0	$	1,108.5	$	2,526.6		$	(20.3	)	$	3,616.8

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

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 a holding company with investments in energy and energy services providers 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.

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 September 30, 2018 and December 31, 2017, the consolidated results of its operations for the three and nine months ended September 30, 2018 and 2017 and its consolidated cash flows for the nine months ended September 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 September 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 nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 or

for any future 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.



	September 30,		December 31,
(In millions)	2018		2017
REGULATORY ASSETS
Current:
Oklahoma demand program rider under recovery (A)	$	10.7	$	31.6
Production tax credit rider under recovery (A)	6.1		—
SPP cost tracker under recovery (A)	—		7.7
Other (A)	1.6		1.5
Total current regulatory assets	$	18.4	$	40.8
Non-current:
Benefit obligations regulatory asset	$	160.8	$	177.2
Deferred storm expenses	37.4		42.2
Smart Grid	27.5		32.8
Unamortized loss on reacquired debt	11.6		12.3
Other	18.9		18.5
Total non-current regulatory assets	$	256.2	$	283.0
REGULATORY LIABILITIES
Current:
Fuel clause over recoveries	$	39.2	$	1.7
SPP cost tracker over recovery (B)	9.4		—
Other (B)	3.5		2.2
Total current regulatory liabilities	$	52.1	$	3.9
Non-current:
Income taxes refundable to customers, net	$	943.9	$	955.5
Accrued removal obligations, net	308.2		288.4
Pension tracker	32.0		32.3
Other	6.9		7.2
Total non-current regulatory liabilities	$	1,291.0	$	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.

As discussed in Note 14 under "Oklahoma Rate Review Filing - 2018," as a result of the settlement agreement reached in the most recent Oklahoma rate review, OG&E removed production tax credits from base rates and now utilizes a separate rider to credit customers the differential between estimated and actual production tax credits, which can either result in a regulatory asset or regulatory liability based on that differential.

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.

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 September 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 nine months ended September 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)	2.5			—		—		(1.3		)	1.2
Settlement cost	3.1			—		—		—			3.1
Balance at September 30, 2018	$	(27.1	)	$	—	$	2.5	$	5.7		$	(18.9	)



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net Income (Loss)			Prior Service Cost		Net Income		Prior Service Cost (Credit)			Total
Balance at December 31, 2016	$	(32.1	)	$	0.1	$	2.7	$	—		$	(29.3	)
Other comprehensive income before reclassifications	—			—		—		6.7			6.7
Amounts reclassified from accumulated other comprehensive income (loss)	2.0			—		—		(0.2		)	1.8
Settlement cost	—			—		0.5		—			0.5
Net current period other comprehensive income	2.0			—		0.5		6.5			9.0
Balance at September 30, 2017	$	(30.1	)	$	0.1	$	3.2	$	6.5		$	(20.3	)

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 nine months ended September 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						Nine Months Ended
	September 30,						September 30,
(In millions)	2018			2017			2018			2017
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses (A)	$	(1.1	)	$	(1.1	)	$	(3.3	)	$	(3.3	)	Other Net Periodic Benefit Income (Expense)
Settlement cost (A)	(4.2		)	—			(4.2		)	—			Other Net Periodic Benefit Income (Expense)
	(5.3		)	(1.1		)	(7.5		)	(3.3		)	Income Before Taxes
	(1.4		)	(0.5		)	(1.9		)	(1.3		)	Income Tax Expense
	$	(3.9	)	$	(0.6	)	$	(5.6	)	$	(2.0	)	Net Income

Amortization of postretirement benefit plans items:
Prior service credit (A)	$	0.6		$	0.4		$	1.7		$	0.4		Other Net Periodic Benefit Income (Expense)
Settlement cost (A)	—			(0.7		)	—			(0.7		)	Other Net Periodic Benefit Income (Expense)
	0.6			(0.3		)	1.7			(0.3		)	Income Before Taxes
	0.1			—			0.4			—			Income Tax Expense
	$	0.5		$	(0.3	)	$	1.3		$	(0.3	)	Net Income

Total reclassifications for the period, net of tax	$	(3.4	)	$	(0.9	)	$	(4.3	)	$	(2.3	)	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 nine months ended September 30, 2017 have been adjusted for the reclassification of net periodic benefit cost components and the regulatory Pension tracker mechanism 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." Further discussion can be found in Note 11.


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. 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 for items such as 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 land easements under Topic 842 that exist or expired 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.

Fair Value Measurement Disclosure Framework. In August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement." The new guidance removes, adds or modifies disclosure requirements that impact all levels of the fair value hierarchy, as well as investments measured using the net asset value practical expedient. ASU 2018-13 is effective for fiscal years beginning after December 2019 and is required to be applied both retrospectively and prospectively, depending on the specific disclosure change. Early adoption is permitted. The Company does not believe this ASU will have a significant impact on its financial statement disclosures.

Defined Benefit Plans Disclosure Framework. In August 2018, the FASB issued ASU 2018-14, "Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans." The new guidance removes, adds or clarifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. ASU 2018-14 is effective for fiscal years ending after December 2020 and is required to be applied on a retrospective basis. Early adoption is permitted. The Company does not believe this ASU will have a significant impact on its financial statement disclosures.

Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. In August 2018, the FASB issued ASU 2018-15, "Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract." The new guidance aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. ASU 2018-15 is effective for fiscal years beginning after December 2019 and can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its Condensed Consolidated Financial Statements.


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. Purchases and sales are based on the fixed transaction price determined by the market at the time of the purchase or sale and the MWh quantity purchased or sold. 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.

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."



	September 30, 2018
(In millions)	Three Months Ended		Nine Months Ended
Residential	$	281.0	$	694.6
Commercial	174.7		444.9
Industrial	56.2		145.5
Oilfield	39.5		110.9
Public authorities and street light	58.7		151.5
System sales revenues	610.1		1,547.4
Provision for rate refund	13.5		(6.2		)
Integrated market	16.9		38.7
Transmission	33.2		109.2
Other	10.8		21.0
Revenues from contracts with customers	$	684.5	$	1,710.1

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 September 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 September 30, 2018 and 2017 and $105.9 million during both the nine months ended September 30, 2018 and 2017.

On November 6, 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

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

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 September 30, 2018 and 2017, respectively, and $0.5 million and $2.2 million for the nine months ended September 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 September 30, 2018, 132 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $5.3 million and $6.2 million during the three months ended September 30, 2018 and 2017, respectively, and $22.1 million and $23.5 million for the nine months ended September 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 $12.3 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 $1.7 million as of September 30, 2018 and $2.0 million as of December 31, 2017.

Related Party Transactions - OG&E and Enable

Enable provides gas transportation services to OG&E pursuant to an agreement that expires in April 2019, if either party does not provide notice of termination to the other party at least 180 days prior to the expiration date in April 2019. In October 2018, OG&E and Enable agreed to waive the 180 days written notice and allow a 30 day extension so that the parties can negotiate the terms of a new agreement. 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 nine months ended September 30, 2018 and 2017.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2018		2017		2018		2017
Operating revenues:
Electricity to power electric compression assets	$	4.7	$	4.5	$	12.2	$	10.0
Cost of sales:
Natural gas transportation services	$	8.8	$	8.8	$	26.3	$	26.3
Natural gas purchases (sales)	$	0.1	$	0.4	$	2.6	$	(0.4	)

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at September 30, 2018 and December 31, 2017 and for the three and nine months ended September 30, 2018 and 2017.



	September 30,		December 31,
Balance Sheet	2018		2017
(In millions)
Current assets	$	481	$	416
Non-current assets	$	11,454	$	11,177
Current liabilities	$	1,403	$	1,279
Non-current liabilities	$	2,964	$	2,660



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Income Statement	2018		2017		2018		2017
(In millions)
Total revenues	$	928	$	705	$	2,481	$	1,997
Cost of natural gas and NGLs	$	516	$	349	$	1,335	$	936
Operating income	$	171	$	137	$	436	$	399
Net income	$	129	$	104	$	320	$	301

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 $40.1 million and $33.6 million for the three months ended September 30, 2018 and 2017, respectively, and $103.3 million and $98.6 million for the nine months ended September 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 nine months ended September 30, 2018 and 2017.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2018			2017			2018			2017
Enable net income	$	129.0		$	104.0		$	320.0		$	301.0
OGE Energy's percent ownership at period end	25.6		%	25.7		%	25.6		%	25.7		%
OGE Energy's portion of Enable net income	33.0			26.5			82.0			77.2
Amortization of basis difference	2.8			2.8			8.4			8.5
Elimination of Enable fair value step up	4.3			4.3			12.9			12.9
Equity in earnings of unconsolidated affiliates	$	40.1		$	33.6		$	103.3		$	98.6

The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $689.7 million as of September 30, 2018. The following table reconciles the basis difference in Enable from December 31, 2017 to September 30, 2018.



(In millions)
Basis difference at December 31, 2017	$	714.2
Change in Enable basis difference	(3.2		)
Amortization of basis difference	(8.4		)
Elimination of Enable fair value step up	(12.9		)
Basis difference at September 30, 2018	$	689.7


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 September 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 September 30, 2018 and December 31, 2017.



	September 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	$	3,001.6	$	3,125.9	$	2,854.3	$	3,242.8
OG&E Industrial Authority Bonds	$	135.4	$	135.4	$	135.4	$	135.4
Tinker Debt	$	9.7	$	8.7	$	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 nine months ended September 30, 2018 and 2017 related to the Company's performance units and restricted stock.



	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2018		2017			2018		2017
Performance units:
Total shareholder return	$	2.0	$	1.6		$	6.1	$	4.9
Earnings per share	1.9		(1.4		)	3.6		(0.2		)
Total performance units	3.9		0.2			9.7		4.7
Restricted stock	—		0.1			—		0.1
Total compensation expense	$	3.9	$	0.3		$	9.7	$	4.8
Income tax benefit	$	1.0	$	0.1		$	2.5	$	1.9

During the three and nine months ended September 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.


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 September 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. Further discussion regarding OG&E's response to OCC, APSC and FERC proceedings, including reserves recorded for each jurisdictional revenue, can be found in Note 14 under "Oklahoma Rate Review Filing - 2018," "APSC Order - 2017 Tax Act," "FERC - Request for Waiver" and "FERC - Section 2016 Filing." As of September 30, 2018, the total recorded reserve was $22.8 million, which is included in Other Current Liabilities on the Company's Condensed Consolidated Balance Sheets.

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 2015 or state and local tax examinations by tax authorities for years prior to 2014. 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 nine months ended September 30, 2018.

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 September 30,				Nine Months Ended September 30,
(In millions except per share data)	2018		2017		2018		2017
Net income	$	205.1	$	183.4	$	370.8	$	324.2
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)	0.9		0.4		0.7		0.3
Diluted average common shares outstanding	200.6		200.1		200.4		200.0
Basic earnings per average common share	$	1.03	$	0.92	$	1.86	$	1.62
Diluted earnings per average common share	$	1.02	$	0.92	$	1.85	$	1.62
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—


9.	Long-Term Debt

At September 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)
1.01%	-	2.00%	Garfield Industrial Authority, January 1, 2025	$	47.0
1.01%	-	1.83%	Muskogee Industrial Authority, January 1, 2025	32.4
1.03%	-	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.

Issuance of New Long-Term Debt

In August 2018, OG&E issued $400.0 million of 3.80 percent senior notes due August 15, 2028. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to fund the payment of OG&E's $250.0 million of 6.35 percent senior notes that matured on September 1, 2018, to repay short-term debt and to fund ongoing capital expenditures and working capital.


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 September 30, 2018, the Company had no 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 September 30, 2018.



	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
(In millions)
OGE Energy (B)	$	450.0	$	—	—	%	(D)	March 8, 2023	(E)
OG&E (C)	450.0		0.3		1.05	%	(D)	March 8, 2023	(E)
Total	$	900.0	$	0.3	1.05	%


(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 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. OG&E has requested renewal of this authority for an additional two-year period and expects to receive approval prior to the expiration of its current authority.


11.	Retirement Plans and Postretirement Benefit Plans

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during the plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During the first nine months of 2018, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement. As a result, the Company recorded pension settlement charges of $12.8 million in the third quarter of 2018.The pension settlement charge did not

require a cash outlay by the Company and did not increase the Company's total pension expense over time, as the charge was an acceleration of costs that otherwise would be recognized as pension expense in future periods.

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.

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, amortization of unrecognized prior service cost and settlement cost are presented within Other Net Periodic Benefit Income (Expense) on the Company's Condensed Consolidated Statements of Income. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table in Note 1 and 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						Nine Months Ended						Three Months Ended				Nine Months Ended
	September 30,						September 30,						September 30,				September 30,
(In millions)	2018 (B)			2017 (B)			2018 (C)			2017 (C)			2018 (B)		2017 (B)		2018 (C)		2017 (C)
Service cost	$	3.6		$	3.9		$	11.1		$	11.6		$	0.1	$	—	$	0.3	$	0.2
Interest cost	6.1			6.5			17.8			19.6			0.1		0.1		0.3		0.2
Expected return on plan assets	(10.7		)	(10.7		)	(33.0		)	(32.0		)	—		—		—		—
Amortization of net loss	3.9			4.4			12.2			13.1			0.1		0.1		0.5		0.3
Amortization of unrecognized prior service cost (A)	—			—			—			—			0.1		0.1		0.1		0.1
Settlement cost	12.2			—			12.2			—			0.6		—		0.6		—
Total net periodic benefit cost	15.1			4.1			20.3			12.3			1.0		0.3		1.8		0.8
Less: Amount paid by unconsolidated affiliates	0.7			1.2			1.9			2.9			0.1		—		0.1		—
Net periodic benefit cost	$	14.4		$	2.9		$	18.4		$	9.4		$	0.9	$	0.3	$	1.7	$	0.8


(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 $15.3 million and $3.2 million of net periodic benefit cost recognized during the three months ended September 30, 2018 and 2017, respectively, the Company recognized the following:


•	a deferral of pension expense during the three months ended September 30, 2018 of $10.5 million related to the pension settlement charge of $12.8 million in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1);


•	a deferral of pension expense during the three months ended September 30, 2018 of $1.0 million related to the Arkansas jurisdictional portion of the pension settlement charge of $12.8 million; and


•	an increase in pension expense during the three months ended September 30, 2017 of $2.7 million to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which is included in the Pension tracker regulatory liability (see Note 1).


(C)	In addition to the $20.1 million and $10.2 million of net periodic benefit cost recognized during the nine months ended September 30, 2018 and 2017, respectively, the Company recognized the following:


•	an increase in pension expense during the nine months ended September 30, 2018 and 2017 of $7.8 million and $8.5 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);


•	a deferral of pension expense during the nine months ended September 30, 2018 of $10.5 million related to the pension settlement charge of $12.8 million in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1);


•	a deferral of pension expense during the nine months ended September 30, 2018 of $1.0 million related to the Arkansas jurisdictional portion of the pension settlement charge of $12.8 million; and


•	a deferral of pension expense during the nine months ended September 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013.



	Postretirement Benefit Plans
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2018 (B)			2017 (B)			2018 (C)			2017 (C)
Service cost	$	—		$	0.1		$	0.2		$	0.5
Interest cost	1.5			1.6			4.1			5.9
Expected return on plan assets	(0.5		)	(0.6		)	(1.5		)	(1.7		)
Amortization of net loss	1.0			0.5			2.9			1.3
Amortization of unrecognized prior service cost (A)	(2.1		)	(1.4		)	(6.3		)	(1.4		)
Settlement cost	—			0.6			—			0.6
Total net periodic benefit cost	(0.1		)	0.8			(0.6		)	5.2
Less: Amount paid by unconsolidated affiliates	(0.2		)	(0.1		)	(0.4		)	0.5
Net periodic benefit cost	$	0.1		$	0.9		$	(0.2	)	$	4.7


(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 $0.1 million and $0.9 million of net periodic benefit cost recognized during the three months ended September 30, 2018 and 2017, respectively, the Company recognized an increase in postretirement medical expense in the three months ended September 30, 2018 and 2017 of $0.1 million and $1.9 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 $0.2 million of net periodic benefit income and $4.7 million of net periodic benefit cost recognized during the nine months ended September 30, 2018 and 2017, respectively, the Company recognized an increase in postretirement medical expense in the nine months ended September 30, 2018 and 2017 of $4.3 million and $3.9 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				Nine Months Ended
	September 30,				September 30,
(In millions)	2018		2017		2018		2017
Capitalized portion of net periodic pension benefit cost	$	0.9	$	1.0	$	2.8	$	3.3
Capitalized portion of net periodic postretirement benefit cost	$	—	$	0.1	$	0.1	$	1.3

Pension Plan Funding

In August 2018, the Company contributed $15.0 million to its Pension Plan. No additional contributions are expected in 2018.


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 nine months ended September 30, 2018 and 2017.



Three Months Ended September 30, 2018	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	698.8	$	—		$	—		$	—		$	698.8
Cost of sales	244.4		—			—			—			244.4
Other operation and maintenance	121.1		0.5			1.7			—			123.3
Depreciation and amortization	81.1		—			—			—			81.1
Taxes other than income	21.9		0.1			0.7			—			22.7
Operating income (loss)	230.3		(0.6		)	(2.4		)	—			227.3
Equity in earnings of unconsolidated affiliates	—		40.1			—			—			40.1
Other income (expense)	10.2		(1.2		)	(0.3		)	(2.0		)	6.7
Interest expense	37.8		—			2.9			(2.0		)	38.7
Income tax expense	18.8		9.9			1.6			—			30.3
Net income (loss)	$	183.9	$	28.4		$	(7.2	)	$	—		$	205.1
Investment in unconsolidated affiliates	$	—	$	1,150.3		$	10.3		$	—		$	1,160.6
Total assets	$	9,652.0	$	1,153.9		$	184.0		$	(286.9	)	$	10,703.0



Three Months Ended September 30, 2017	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	716.8	$	—		$	—		$	—		$	716.8
Cost of sales	255.7		—			—			—			255.7
Other operation and maintenance	115.0		(0.4		)	(2.7		)	—			111.9
Depreciation and amortization	76.2		—			0.7			—			76.9
Taxes other than income	21.7		0.5			1.0			—			23.2
Operating income (loss)	248.2		(0.1		)	1.0			—			249.1
Equity in earnings of unconsolidated affiliates	—		33.6			—			—			33.6
Other income (expense)	19.5		0.4			(0.7		)	(0.2		)	19.0
Interest expense	34.5		—			1.6			(0.2		)	35.9
Income tax expense (benefit)	71.7		12.6			(1.9		)	—			82.4
Net income	$	161.5	$	21.3		$	0.6		$	—		$	183.4
Investment in unconsolidated affiliates	$	—	$	1,152.9		$	5.2		$	—		$	1,158.1
Total assets	$	9,230.9	$	1,503.9		$	87.1		$	(358.2	)	$	10,463.7



Nine Months Ended September 30, 2018	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,758.5	$	—		$	—		$	—		$	1,758.5
Cost of sales	663.6		—			—			—			663.6
Other operation and maintenance	352.2		1.1			(0.1		)	—			353.2
Depreciation and amortization	240.8		—			—			—			240.8
Taxes other than income	66.2		0.5			2.6			—			69.3
Operating income (loss)	435.7		(1.6		)	(2.5		)	—			431.6
Equity in earnings of unconsolidated affiliates	—		103.3			—			—			103.3
Other income (expense)	18.7		(1.2		)	(1.6		)	(3.5		)	12.4
Interest expense	114.3		—			7.4			(3.5		)	118.2
Income tax expense (benefit)	32.9		26.4			(1.0		)	—			58.3
Net income (loss)	$	307.2	$	74.1		$	(10.5	)	$	—		$	370.8
Investment in unconsolidated affiliates	$	—	$	1,150.3		$	10.3		$	—		$	1,160.6
Total assets	$	9,652.0	$	1,153.9		$	184.0		$	(286.9	)	$	10,703.0



Nine Months Ended September 30, 2017	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,759.2	$	—		$	—		$	—		$	1,759.2
Cost of sales	696.5		—			—			—			696.5
Other operation and maintenance	348.8		(0.1		)	(7.8		)	—			340.9
Depreciation and amortization	204.6		—			2.6			—			207.2
Taxes other than income	64.2		1.0			3.2			—			68.4
Operating income (loss)	445.1		(0.9		)	2.0			—			446.2
Equity in earnings of unconsolidated affiliates	—		98.6			—			—			98.6
Other income (expense)	39.2		0.5			(3.0		)	(0.3		)	36.4
Interest expense	103.7		—			4.6			(0.3		)	108.0
Income tax expense (benefit)	116.7		38.6			(6.3		)	—			149.0
Net income	$	263.9	$	59.6		$	0.7		$	—		$	324.2
Investment in unconsolidated affiliates	$	—	$	1,152.9		$	5.2		$	—		$	1,158.1
Total assets	$	9,230.9	$	1,503.9		$	87.1		$	(358.2	)	$	10,463.7


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.

Public Utility Regulatory Policy Act of 1978

As previously disclosed in the Company's 2017 Form 10-K, OG&E has a QF contract with AES whereby OG&E purchases 100 percent of the electricity generated from AES's 320 MW facility. The QF contract expires on January 15, 2023; however, OG&E had the option beginning in July 2017 to provide notice to AES to terminate the contract in January 2018.

On July 17, 2017, OG&E and AES amended the agreement to allow OG&E the option, through July 17, 2018, to provide AES a termination notice that would terminate the agreement on January 15, 2019. On July 17, 2018, OG&E and AES extended the option to provide notice, and on August 24, 2018, OG&E notified AES that OG&E was exercising its option to terminate the contract, effective January 15, 2019. OG&E has issued a request for proposals to fill the capacity need created by the upcoming termination of this QF contract, as further discussed in Note 14.

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.

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 Scrubber system on Sooner Unit 1 completed certain emission testing in October 2018 and was placed into service. The Dry Scrubber system on Sooner Unit 2 is 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 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;


•	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 of $18.9 million was returned to Oklahoma customers during the July billing cycle. As reserved amounts were estimated through June 2018, a true-up mechanism exists for the difference between the estimate and actuals to be calculated after the determination of year-end financial results.

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 $10.7 million as disclosed in Note 1. This dispute was resolved through the June 19, 2018 OCC settlement; as a result, the reserve was reversed at June 30, 2018, and an adjustment was 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. Based on the order received from the FERC, OG&E reserved the excess income taxes collected in current rates

from January 2018 through June 2018, as the new tax rate was reflected in billings beginning with the July 2018 invoice. As 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 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 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. On August 27, 2018, OG&E filed the request for a new Tax Adjustment Rider as well as filed updates to all riders with tax implications, which were then approved by the APSC on September 24, 2018. All rider changes were implemented on October 1, 2018. In October 2018, OG&E refunded the excess income taxes collected from January 1, 2018 through September 30, 2018 and also began refunding the amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act, plus carrying charges, from January 2018 through September 2018, which was approximately $7.7 million. As reserved amounts were estimated through September 2018, a true-up mechanism exists for the difference between the estimate and actuals to be calculated after the determination of year-end financial results.

Integrated Resource Plans

In September 2018, OG&E submitted its final 2018 IRP to the OCC and the APSC. The 2018 IRP identified a need for capacity, and OG&E has issued a request for proposals to identify options to fill that capacity need. OG&E anticipates filing pre-approval cases in the fourth quarter of 2018 in Oklahoma and Arkansas for the outcome of the request for proposal process.

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 $532.0 million, including allowance for funds used during construction and capitalized ad valorem taxes. The Dry Scrubber system on Sooner Unit 1 completed certain emission testing in October 2018 and was placed into service. The Dry Scrubber system on Sooner Unit 2 is expected to be completed in late 2018 to early 2019. As of September 30, 2018, OG&E has invested $483.5 million in the Dry Scrubbers.

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 has reserved an amount within this range. The Company 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. While the Company is unable to predict what final action the FERC will take in response to the Oklahoma Municipal Power Authority's complaint or the timing of such action, 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.

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. Based on an order received from the FERC, OG&E reserved the excess income taxes collected in current rates from January 2018 through June 2018, as the new tax rate was reflected in billings beginning with the July 2018 invoice, 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 hearing on the merits is currently scheduled for December 6, 2018.

Arkansas Formula Rate Plan Filing

Per OG&E's settlement in its last general rate review, OG&E filed an evaluation report under its Formula Rate Plan on October 1, 2018, requesting a $6.4 million revenue increase. A final order is expected from the APSC in March 2019, and the outcome will be reflected in rates that will become effective on April 1, 2019.

Demand Program Portfolio Filing

Pursuant to OCC rules, OG&E is required to propose, implement and administer a portfolio of demand programs once every three years. On July 1, 2018, OG&E filed its proposed Demand Program Three Year Portfolio for the 2019-2021 program cycle. A hearing on the merits is currently scheduled for November 15, 2018.

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

Introduction

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 four to six 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 shareholder base, the Company's financial position, the Company's growth targets and the composition of the Company's assets and investment opportunities. The Company also utilizes cash distributions from its investment in Enable to help fund its capital needs and support future dividend growth. The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and having strong regulatory and legislative relationships.

Summary of Operating Results

Three Months Ended September 30, 2018 as compared to Three Months Ended September 30, 2017

Net income was $205.1 million, or $1.02 per diluted share, during the three months ended September 30, 2018 as compared to $183.4 million, or $0.92 per diluted share, during the same period in 2017. The increase in net income of $21.7 million, or $0.10 per diluted share, was primarily due to:

•

an increase in net income at OG&E of $22.4 million, or $0.11 per diluted share of the Company's common stock, primarily due to higher gross margin (excluding impacts from the 2017 Tax Act resulting in lower customer rates which were offset by lower income tax expense), partially offset by lower other income, higher other operation and maintenance expense, higher depreciation and amortization expense and higher interest expense; and


•	an increase in net income at OGE Holdings of $7.1 million, or $0.04 per diluted share of the Company's common stock, primarily due to higher equity in earnings of Enable and lower income tax expense, partially offset by higher other expense and higher other operation and maintenance expense; partially offset by


•	a decrease in net income of other operations of $7.8 million, or $0.05 per diluted share of the Company's common stock, primarily due to higher other operation and maintenance expense, lower income tax benefit and higher interest expense, partially offset by lower depreciation and amortization expense.

Nine Months Ended September 30, 2018 as compared to Nine Months Ended September 30, 2017

Net income was $370.8 million, or $1.85 per diluted share, during the nine months ended September 30, 2018 as compared to $324.2 million, or $1.62 per diluted share, during the same period in 2017. The increase in net income of $46.6 million, or $0.23 per diluted share, was primarily due to:

•

an increase in net income at OG&E of $43.3 million, or $0.22 per diluted share of the Company's common stock, primarily due to higher gross margin (excluding impacts from the 2017 Tax Act resulting in lower customer rates which were offset by lower income tax expense), partially offset by higher depreciation and amortization expense primarily due to a reduction in depreciation expense recorded in March 2017 for the period from July 1, 2016 to December 31, 2016 resulting from the March 2017 OCC rate order, lower other income and higher interest expense; and


•	an increase in net income at OGE Holdings of $14.5 million, or $0.07 per diluted share of the Company's common stock, primarily due to lower income tax expense and higher equity in earnings of Enable, partially offset by higher other expense and higher other operation and maintenance expense; partially offset by


•	a decrease in net income of other operations of $11.2 million, or $0.06 per diluted share of the Company's common stock, primarily due to higher other operation and maintenance expense, lower income tax benefit and higher interest expense, partially offset by lower other expense and lower depreciation and amortization expense.

Recent Developments and Regulatory Matters

For Oklahoma jurisdictional revenues, OG&E reserved the excess income taxes collected in current rates, plus interest, from January 2018 through June 2018, and any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act, which was refunded to Oklahoma customers, as approved by the OCC, during the July 2018 billing cycle. For Arkansas jurisdictional revenues, OG&E reserved the excess income taxes collected in current rates, plus carrying charges, from January 2018 through September 2018, as the Tax Adjustment Rider became effective on October 1, 2018. For FERC jurisdictional revenues, based on an order received from the FERC, OG&E reserved the excess income taxes collected in current rates from January 2018 through June 2018, as the new tax rate was reflected in billings beginning with the July 2018 invoice. Further, for Arkansas and FERC jurisdictional revenues, OG&E is also reserving any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act. Further discussion can be found in Note 14 within "Item 1. Financial Statements."

In January 2018, OG&E filed a general rate review in Oklahoma, seeking recovery of the seven combustion turbines that are part of the Mustang Modernization Plan, requesting an increase in depreciation rates to levels similar with rates in existence

prior to the March 2017 OCC rate order and crediting customers for the impacts of the 2017 Tax Act. In June 2018, the OCC approved a Joint Stipulation and Settlement Agreement. Key terms of the settlement are detailed in Note 14 within "Item 1. Financial Statements." As a result of the settlement, new rates were implemented on July 1, 2018.

2018 Outlook

Key assumptions for 2018 include:

OG&E

The Company projects OG&E to earn approximately $318 million to $322 million, or $1.59 to $1.61 per average diluted share, an increase from the previously issued guidance projected to be at the top end of $286 million to $306 million, or $1.43 to $1.53 per average diluted share, in 2018. The updated projections for 2018 are based on the following:


•	normal weather patterns are experienced for the remainder of the year;


•	gross margin on revenues of approximately $1.376 billion;


•	operating expenses of approximately $892 million to $895 million with operation and maintenance expenses comprising approximately 54 percent of the total;


•	interest expense of approximately $152 million which assumes an $11 million allowance for borrowed funds used during construction reduction to interest expense;


•	other income of approximately $24 million including approximately $23 million of allowance for equity funds used during construction; and


•	an effective tax rate of approximately 9.6 percent.

OGE Holdings

The Company projects the earnings contribution from its ownership interest in Enable for 2018 to be approximately $100 million to $104 million, or $0.50 to $0.52 per average diluted share, an increase from the previously issued guidance of approximately $96 million to $104 million, or $0.48 to $0.52 per average diluted share, and receive approximately $140 million in cash distributions.

Consolidated OGE

The Company's 2018 earnings guidance is between approximately $410 million and $418 million of net income, or $2.05 to $2.09 per average diluted share, an increase from the previously issued guidance of approximately $380 million to $410 million, or $1.90 to $2.05 per average diluted share, and is based on the following assumptions:


•	approximately 200 million average diluted shares outstanding;


•	an effective tax rate of approximately 13 percent; and


•	a $0.04 or an $8 million loss at OGE Energy (holding company).

OG&E's Non-GAAP Financial Measures

Gross margin is defined by OG&E as operating revenues less cost of sales. Cost of sales, as reflected on the income statement, includes fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization and other operation and maintenance expenses. Expenses for fuel and purchased power are recovered through fuel adjustment clauses, and as a result, changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies. Further, gross margin is not intended to replace operating revenues as determined in accordance with GAAP as an indicator of operating performance. For a reconciliation of gross margin to revenue, which is the most directly comparable financial measure calculated and presented in accordance with GAAP, for the three and nine months ended September 30, 2018 and 2017, see "OG&E (Electric Utility) Results of Operations" below.

Detailed below is a reconciliation of gross margin to revenue included in the 2018 Outlook.



(In millions)	Twelve Months Ended December 31, 2018 (A)
Operating revenues	$	2,157
Cost of sales	781
Gross margin	$	1,376


(A)	Based on the midpoint of OG&E earnings guidance for 2018.

Enable's Non-GAAP Financial Measures

Gross margin is defined by Enable as total revenues minus costs of natural gas and NGLs, excluding depreciation and amortization. Total revenues consist of the fees that Enable charges its customers and the sales price of natural gas and NGLs that they sell. The cost of natural gas and NGLs consists of the purchase price of natural gas and NGLs that Enable purchases. Enable deducts the cost of natural gas and NGLs from total revenues to arrive at a measure of the core profitability of their mix of fee-based and commodity-based customer arrangements. Gross margin allows for meaningful comparison of the operating results between Enable's fee-based revenues and Enable's commodity-based contracts which involve the purchase or sale of natural gas, NGLs and/or crude oil. In addition, the Company believes gross margin allows for a meaningful comparison of the results of Enable's commodity-based activities across different commodity price environments because it measures the spread between the product sales price and cost of products sold. Enable's definition of gross margin may be different from similar terms used by other companies. Further, gross margin is not intended to replace operating revenues as determined in accordance with GAAP as an indicator of operating performance. For a reconciliation of gross margin to revenue, which is the most directly comparable financial measure calculated and presented in accordance with GAAP, for the three and nine months ended September 30, 2018 and 2017, see "OGE Holdings (Natural Gas Midstream Operations) Results of Operations" below.

Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the three and nine months ended September 30, 2018 as compared to the same periods in 2017 and the Company's consolidated financial position at September 30, 2018. Due to seasonal fluctuations and other factors, the Company's operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 or for any future period. The following information should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions except per share data)	2018		2017		2018		2017
Net income	$	205.1	$	183.4	$	370.8	$	324.2
Basic average common shares outstanding	199.7		199.7		199.7		199.7
Diluted average common shares outstanding	200.6		200.1		200.4		200.0
Basic earnings per average common share	$	1.03	$	0.92	$	1.86	$	1.62
Diluted earnings per average common share	$	1.02	$	0.92	$	1.85	$	1.62
Dividends declared per common share	$	0.36500	$	0.33250	$	1.03000	$	0.93750

Results by Business Segment



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2018			2017		2018			2017
Net income (loss):
OG&E (Electric Utility)	$	183.9		$	161.5	$	307.2		$	263.9
OGE Holdings (Natural Gas Midstream Operations)	28.4			21.3		74.1			59.6
Other operations (A)	(7.2		)	0.6		(10.5		)	0.7
Consolidated net income	$	205.1		$	183.4	$	370.8		$	324.2


(A)	Other operations primarily includes the operations of the holding company and consolidating eliminations.

The following discussion of results of operations by business segment includes intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements.

OG&E (Electric Utility)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(Dollars in millions)	2018		2017			2018			2017
Operating revenues	$	698.8	$	716.8		$	1,758.5		$	1,759.2
Cost of sales	244.4		255.7			663.6			696.5
Other operation and maintenance	121.1		115.0			352.2			348.8
Depreciation and amortization	81.1		76.2			240.8			204.6
Taxes other than income	21.9		21.7			66.2			64.2
Operating income	230.3		248.2			435.7			445.1
Allowance for equity funds used during construction	6.7		11.8			20.0			27.2
Other net periodic benefit income (expense)	0.5		(5.2		)	(9.5		)	(14.0		)
Other income	3.6		13.4			10.2			27.5
Other expense	0.6		0.5			2.0			1.5
Interest expense	37.8		34.5			114.3			103.7
Income tax expense	18.8		71.7			32.9			116.7
Net income	$	183.9	$	161.5		$	307.2		$	263.9
Operating revenues by classification:
Residential	$	286.4	$	295.1		$	714.7		$	700.0
Commercial	180.0		174.2			460.9			450.6
Industrial	57.5		58.0			149.9			156.3
Oilfield	40.1		43.4			113.3			124.6
Public authorities and street light	60.4		60.6			156.9			159.4
Sales for resale	—		—			0.1			0.1
System sales revenues	624.4		631.3			1,595.8			1,591.0
Provision for rate refund	13.5		29.2			(6.2		)	25.0
Integrated market	16.9		14.0			38.7			16.8
Transmission	33.2		37.7			109.2			113.1
Other	10.8		4.6			21.0			13.3
Total operating revenues	$	698.8	$	716.8		$	1,758.5		$	1,759.2
Reconciliation of gross margin to revenue:
Operating revenues	$	698.8	$	716.8		$	1,758.5		$	1,759.2
Cost of sales	244.4		255.7			663.6			696.5
Gross margin	$	454.4	$	461.1		$	1,094.9		$	1,062.7
MWh sales by classification (In millions)
Residential	2.9		2.9			7.6			6.9
Commercial	2.3		2.1			6.2			5.7
Industrial	1.0		0.9			2.9			2.7
Oilfield	0.9		0.8			2.5			2.4
Public authorities and street light	0.9		0.8			2.4			2.3
System sales	8.0		7.5			21.6			20.0
Integrated market	0.5		0.6			1.1			1.4
Total sales	8.5		8.1			22.7			21.4
Number of customers	846,817		840,519			846,817			840,519
Weighted-average cost of energy per kilowatt-hour (In cents)
Natural gas	2.158		2.747			2.328			2.795
Coal	2.046		2.049			2.035			2.100
Total fuel	2.029		2.253			2.046			2.231
Total fuel and purchased power	2.730		2.966			2.791			3.093
Degree days (A)
Heating - Actual	12		4			2,220			1,574
Heating - Normal	19		19			2,020			2,021
Cooling - Actual	1,265		1,223			2,051			1,847
Cooling - Normal	1,380		1,380			2,018			2,018

(A)

Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.

OG&E's net income increased $22.4 million, or 13.9 percent, and $43.3 million, or 16.4 percent, during the three and nine months ended September 30, 2018, respectively, as compared to the same periods in 2017. The increase for the three months ended September 30, 2018 was primarily due to higher gross margin (excluding impacts from the 2017 Tax Act resulting in lower customer rates which were offset by lower income tax expense), partially offset by lower other income, higher other operation and maintenance expense, higher depreciation and amortization expense and higher interest expense. The increase for the nine months ended September 30, 2018 was primarily due to higher gross margin (excluding impacts from the 2017 Tax Act resulting in lower customer rates which were offset by lower income tax expense), partially offset by higher depreciation and amortization expense, lower other income and higher interest expense.

Gross margin decreased $6.7 million, or 1.5 percent, and increased $32.2 million, or 3.0 percent, during the three and nine months ended September 30, 2018, respectively, as compared to the same periods in 2017. The below factors contributed to the changes in gross margin.



	Change for
	September 30, 2018
(In millions)	Three Months Ended			Nine Months Ended
Price variance (A)	$	(33.9	)	$	(13.2	)
Wholesale transmission revenue (B)	(2.8		)	0.9
Reserve for tax refund (C)	10.0			(22.8		)
Other	6.6			8.8
Weather (price and quantity) (D)	4.6			40.4
Non-residential demand and related revenue	3.5			6.8
New customer growth	3.3			6.3
Industrial and oilfield sales	2.0			5.0
Change in gross margin	$	(6.7	)	$	32.2


(A)	Decreased during the three and nine months ended September 30, 2018 primarily due to the Oklahoma tax refund to customers during the July 2018 billing cycle and new Oklahoma rates being implemented on July 1, 2018, which reflected the lower corporate federal tax rate as a result of the 2017 Tax Act.


(B)	The three and nine months ended September 30, 2018 include the lower corporate federal tax rate, as a result of the 2017 Tax Act, which was reflected in billings beginning with the July 2018 invoice, as discussed in Note 14 in "Item 1. Financial Statements."


(C)	The three and nine months ended September 30, 2018 include the $18.9 million refunded to Oklahoma customers during the July 2018 billing cycle that was previously reserved. Further discussion of OG&E's reserve for tax refund in response to OCC, APSC and FERC proceedings can be found in Notes 7 and 14 in "Item 1. Financial Statements."


(D)	Cooling degree days increased three percent and 11 percent during the three and nine months ended September 30, 2018, respectively, and heating degree days increased 41 percent during the nine months ended September 30, 2018, as compared to the same periods in 2017.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC. OG&E's cost of sales decreased $11.3 million, or 4.4 percent, and $32.9 million, or 4.7 percent, during the three and nine months ended September 30, 2018, respectively, as compared to the same periods in 2017. The below factors contributed to the changes in cost of sales.



	Change for
	September 30, 2018
(In millions)	Three Months Ended			Nine Months Ended
Fuel expense (A)	$	(14.2	)	$	(24.7	)
Purchased power costs:
Purchases from SPP (B)	2.3			(11.4		)
Wind	0.5			2.2
Cogeneration	(1.3		)	(3.4		)
Other	0.6			0.7
Transmission expense (C)	0.8			3.7
Change in cost of sales	$	(11.3	)	$	(32.9	)


(A)	Decrease in fuel expense during the three and nine months ended September 30, 2018 was primarily due to decreased utilization of company-owned generation.

(B)

Increase in the cost of purchases from the SPP for the three months ended September 30, 2018 was due to a 21.2 percent increase in MWhs purchased offset by a 22.0 percent decrease in cost per MWh purchased. The decrease in cost per MWh purchased was due to a decrease in fuel prices. Decrease in the cost of purchases from the SPP for the nine months ended September 30, 2018 was due to a 20.4 percent increase in MWhs purchased offset by a 30.2 percent decrease in cost per MWh purchased. The decrease in cost per MWh purchased was due to a decrease in fuel prices.


(C)	Increase in transmission-related charges was primarily due to higher SPP charges for the base plan projects of other utilities.

Other operation and maintenance expense increased $6.1 million, or 5.3 percent, and $3.4 million, or 1.0 percent, during the three and nine months ended September 30, 2018, respectively, as compared to the same periods in 2017. The below factors contributed to the changes in other operation and maintenance expense.



	Change for
	September 30, 2018
(In millions)	Three Months Ended			Nine Months Ended
Payroll and benefits (A)	$	6.3		$	10.4
Other	1.9			(1.5		)
Contract technical and construction services (B)	1.2			(7.2		)
Vegetation management	(3.3		)	1.7
Change in other operation and maintenance expense	$	6.1		$	3.4


(A)	Increased primarily due to annual salary increases and an increase in incentive compensation.


(B)	Changes are primarily due to the timing of normal plant maintenance.

Depreciation and amortization expense increased $36.2 million, or 17.7 percent, during the nine months ended September 30, 2018, as compared to the same period in 2017, primarily due to a reduction in depreciation expense of approximately $20.0 million recorded in March 2017 for the period from July 1, 2016 to December 31, 2016 resulting from the March 2017 OCC rate order, and additional assets being placed into service.

Allowance for equity funds used during construction decreased $5.1 million, or 43.2 percent, and $7.2 million, or 26.5 percent, during the three and nine months ended September 30, 2018, respectively, as compared to the same periods in 2017, primarily due to lower construction work in progress balances resulting from certain environmental projects being completed and placed into service.

Other net periodic benefit expense decreased $5.7 million during the three months ended September 30, 2018 and $4.5 million, or 32.1 percent, during the nine months ended September 30, 2018, as compared to the same periods in 2017, primarily due to amortization of unrecognized prior service cost.

Other income decreased $9.8 million, or 73.1 percent, and $17.3 million, or 62.9 percent, during the three and nine months ended September 30, 2018, respectively, as compared to the same periods in 2017, primarily due to a decrease in the tax gross-up related to lower allowance for funds used during construction and a decrease in guaranteed flat bill margins, which are now included in gross margin.

Allowance for borrowed funds used during construction decreased $1.9 million, or 36.5 percent, and $2.8 million, or 22.2 percent, during the three and nine months ended September 30, 2018, as compared to the same periods in 2017, primarily due to lower construction work in progress balances resulting from certain environmental projects being completed and placed into service.

Income tax expense decreased $52.9 million, or 73.8 percent, and $83.8 million, or 71.8 percent, during the three and nine months ended September 30, 2018, respectively, as compared to the same periods in 2017, primarily due to a reduction in the corporate federal tax rate, an increase in the amortization of net unfunded deferred taxes, an increase in state tax credit generation and lower pre-tax income.

OGE Holdings (Natural Gas Midstream Operations)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2018			2017			2018			2017
Operating revenues	$	—		$	—		$	—		$	—
Cost of sales	—			—			—			—
Other operation and maintenance	0.5			(0.4		)	1.1			(0.1		)
Depreciation and amortization	—			—			—			—
Taxes other than income	0.1			0.5			0.5			1.0
Operating loss	(0.6		)	(0.1		)	(1.6		)	(0.9		)
Equity in earnings of unconsolidated affiliates	40.1			33.6			103.3			98.6
Other income (expense)	(1.2		)	0.4			(1.2		)	0.5
Income before taxes	38.3			33.9			100.5			98.2
Income tax expense	9.9			12.6			26.4			38.6
Net income attributable to OGE Holdings	$	28.4		$	21.3		$	74.1		$	59.6

Reconciliation of Equity in Earnings of Unconsolidated Affiliates

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2018			2017			2018			2017
Enable net income	$	129.0		$	104.0		$	320.0		$	301.0
OGE Energy's percent ownership at period end	25.6		%	25.7		%	25.6		%	25.7		%
OGE Energy's portion of Enable net income	33.0			26.5			82.0			77.2
Amortization of basis difference	2.8			2.8			8.4			8.5
Elimination of Enable fair value step up	4.3			4.3			12.9			12.9
Equity in earnings of unconsolidated affiliates	$	40.1		$	33.6		$	103.3		$	98.6

Equity in earnings of unconsolidated affiliates includes the Company's share of Enable earnings adjusted for the amortization of the basis difference of the Company's investment in Enogex LLC and its underlying equity in the net assets of Enable and is also adjusted for the elimination of the Enogex Holdings fair value adjustments.

The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $689.7 million as of September 30, 2018. The basis difference is being amortized over approximately 30 years, beginning in May 2013. The following table reconciles the basis difference in Enable from December 31, 2017 to September 30, 2018.



(In millions)
Basis difference at December 31, 2017	$	714.2
Change in Enable basis difference	(3.2		)
Amortization of basis difference	(8.4		)
Elimination of Enable fair value step up	(12.9		)
Basis difference at September 30, 2018	$	689.7

Enable Results of Operations

The following table presents summarized financial information of Enable for the three and nine months ended September 30, 2018 and 2017.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2018		2017		2018		2017
Reconciliation of gross margin to revenue:
Total revenues	$	928	$	705	$	2,481	$	1,997
Cost of natural gas and NGLs	516		349		1,335		936
Gross margin	$	412	$	356	$	1,146	$	1,061
Operating income	$	171	$	137	$	436	$	399
Net income	$	129	$	104	$	320	$	301

Enable Operating Data

The following table presents Enable's operating data for the three and nine months ended September 30, 2018 and 2017.



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2018	2017	2018	2017
Gathered volumes - TBtu/d	4.61	3.52	4.44	3.38
Transported volumes - TBtu/d	5.22	4.83	5.35	5.05
Natural gas processed volumes - TBtu/d	2.50	1.90	2.35	1.89
NGLs sold - MBbl/d (A)(B)	146.29	86.83	130.18	84.10


(A)	Excludes condensate.


(B)	NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

Three Months Ended September 30, 2018 as compared to Three Months Ended September 30, 2017

OGE Holdings' earnings before taxes increased $4.4 million for the three months ended September 30, 2018 as compared to the same period in 2017, primarily due to an increase in equity in earnings of Enable of $6.5 million, partially offset by an increase in other expense. The following table presents summarized information regarding Enable's income statement changes for the three months ended September 30, 2018, compared to the same period in 2017, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

The increase in the Company's equity in earnings of Enable was primarily due to the following:



(In millions)	Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	56.0	$	14.3
Operation and maintenance, General and administrative	$	12.0	$	(3.1	)
Depreciation and amortization	$	10.0	$	(2.6	)
Interest expense	$	9.0	$	(2.3	)

Enable's gathering and processing business segment reported an increase in operating income of $33.0 million. The following table presents summarized information regarding Enable's gathering and processing business segment income statement changes for the three months ended September 30, 2018, compared to the same period in 2017, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

The increase in Enable's gathering and processing business segment operating income was primarily due to the following:



(In millions)	Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	51.0	$	13.1
Operation and maintenance, General and administrative	$	8.0	$	(2.0	)
Depreciation and amortization	$	10.0	$	(2.6	)

Gathering and processing gross margin increased primarily due to: (i) an increase in processing service fees from higher processed volumes in the Anadarko and Ark-La-Tex Basins; (ii) an increase in natural gas gathering fees due to higher fees and gathered volumes in the Anadarko and Ark-La-Tex Basins; and (iii) an increase in crude oil and water gathering fees due to an increase in gathered volumes, partially offset by a reduction in average rates. These increases were partially offset by: (i) a decrease in changes in the fair value of natural gas, condensate and NGL derivatives; (ii) a decrease in revenues from natural gas sales less the cost of natural gas primarily due to a change in imbalance volumes owed customers, an increase in fuel costs and an increase in third party processing fees, partially offset by an increase due to higher sales volumes; and (iii) a decrease in revenues from NGL sales less the cost of NGLs, partially offset by higher average NGL prices and higher processed volumes in the Anadarko and Ark-La-Tex Basins.

Enable's transportation and storage business segment reported an increase in operating income of $3.0 million. The following table presents summarized information regarding Enable's transportation and storage business segment income statement changes for the three months ended September 30, 2018, compared to the same period in 2017, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

The increase in transportation and storage business segment operating income was primarily due to the following:



(In millions)	Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	6.0	$	1.5
Operation and maintenance, General and administrative	$	3.0	$	(0.8	)

Transportation and storage gross margin increased primarily due to: (i) an increase in volume-dependent transportation primarily due to an increase in commodity fees from new contracts and an increase in off-system transportation due to increases in volumes at higher rates; (ii) an increase in system management activities; and (iii) an increase in other firm transportation and storage services due to new intrastate transportation contracts. These increases were partially offset by a decrease in the fair value of natural gas derivatives.

Income tax expense decreased $2.7 million, or 21.4 percent, during the three months ended September 30, 2018, as compared to the same period in 2017, primarily due to a reduction in the corporate federal tax rate.

Nine Months Ended September 30, 2018 as compared to Nine Months Ended September 30, 2017

OGE Holdings' earnings before taxes increased $2.3 million for the nine months ended September 30, 2018 as compared to the same period in 2017, primarily due to an increase in equity in earnings of Enable of $4.7 million, partially offset by an increase in other expense. The following table presents summarized information regarding Enable's income statement changes for the nine months ended September 30, 2018, compared to the same period in 2017, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

The increase in the Company's equity in earnings of Enable was primarily due to the following:



(In millions)	Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	85.0	$	21.8
Operation and maintenance, General and administrative	$	22.0	$	(5.6	)
Depreciation and amortization	$	25.0	$	(6.4	)
Interest expense	$	20.0	$	(5.1	)

Enable's gathering and processing business segment reported an increase in operating income of $57.0 million. The following table presents summarized information regarding Enable's gathering and processing business segment income statement changes for the nine months ended September 30, 2018, compared to the same period in 2017, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

The increase in Enable's gathering and processing business segment operating income was primarily due to the following:



(In millions)	Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	98.0	$	25.1
Operation and maintenance, General and administrative	$	15.0	$	(3.8	)
Depreciation and amortization	$	24.0	$	(6.1	)

Gathering and processing gross margin increased primarily due to: (i) an increase in processing service fees due to higher processed volumes in the Anadarko and Ark-La-Tex Basins; (ii) an increase in natural gas gathering fees due to higher fees and gathered volumes in the Anadarko and Ark-La-Tex Basins; and (iii) an increase in crude oil and water gathering fees due to an increase in gathered volumes, partially offset by a reduction in average rates. These increases were partially offset by a decrease in the fair value of natural gas, condensate and NGL derivatives and a decrease in revenues from NGL sales less the cost of NGLs, partially offset by higher average NGL prices and higher processed volumes in the Anadarko and Ark-La-Tex Basins.

Enable's transportation and storage business segment reported a decrease in operating income of $20.0 million. The following table presents summarized information regarding Enable's transportation and storage business segment income statement changes for the nine months ended September 30, 2018, compared to the same period in 2017, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

The decrease in transportation and storage business segment operating income was primarily due to the following:



(In millions)	Income Statement Change at Enable			Impact to Company's Equity in Earnings
Gross margin	$	(14.0	)	$	(3.6	)
Operation and maintenance, General and administrative	$	6.0		$	(1.5	)

Transportation and storage gross margin decreased primarily due to a decrease in the fair value of natural gas derivatives and a decrease in firm transportation services between Carthage, Texas and Perryville, Louisiana due to contract expirations during the second quarter of 2017. These decreases were partially offset by: (i) an increase in volume-dependent transportation primarily due to an increase in commodity fees from new contracts and an increase in off-system transportation due to increases in volumes at higher rates; (ii) an increase in system management activities; and (iii) an increase in other firm transportation and storage services due to new intrastate transportation contracts.

Income tax expense decreased $12.2 million, or 31.6 percent, during the nine months ended September 30, 2018 as compared to the same period in 2017, primarily due to a reduction in the corporate federal tax rate.

Off-Balance Sheet Arrangements

There have been no significant changes in the Company's off-balance sheet arrangements from those discussed in the Company's 2017 Form 10-K. The Company has no off-balance sheet arrangements with equity method investments that would affect its liquidity.

Liquidity and Capital Resources

Working Capital

Working capital is defined as the difference in current assets and current liabilities. The Company's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to and the timing of collections from customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries.

Cash and Cash Equivalents. The balance in Cash and Cash Equivalents was $90.7 million and $14.4 million at September 30, 2018 and December 31, 2017, respectively, an increase of $76.3 million, primarily due to an increase in cash received from customers reflecting normal, seasonal business operations and a decrease in expenditures related to environmental projects.

Accounts Receivable and Accrued Unbilled Revenues. The balance of Accounts Receivable and Accrued Unbilled Revenues was $313.5 million and $257.1 million at September 30, 2018 and December 31, 2017, respectively, an increase of $56.4 million, or 21.9 percent, primarily due to an increase in billings to OG&E's retail customers reflecting higher seasonal usage in September 2018 as compared to December 2017.

Fuel Inventories. The balance in Fuel Inventories was $64.5 million and $84.3 million at September 30, 2018 and December 31, 2017, respectively, a decrease of $19.8 million, or 23.5 percent, primarily due to decreased coal and gas inventory.

Materials and Supplies, at Average Cost. The balance of Materials and Supplies, at Average Cost was $132.2 million and $80.8 million at September 30, 2018 and December 31, 2017, respectively, an increase of $51.4 million, or 63.6 percent, primarily due to increased inventory related to long-term service agreements.

Other Current Assets. The balance of Other Current Assets was $27.6 million and $54.6 million at September 30, 2018 and December 31, 2017, respectively, a decrease of $27.0 million, or 49.5 percent, primarily due to increased collections from customers associated with various rate riders.

Short-Term Debt. There was no balance in Short-term Debt at September 30, 2018 compared to a balance of $168.4 million at December 31, 2017, respectively, a decrease of $168.4 million, or 100.0 percent. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. The decrease during the nine months ended September 30, 2018 was primarily due to the proceeds of the senior notes issuance in August 2018 being utilized for general corporate purposes instead of borrowings under the Company's revolving credit agreement.

Accounts Payable. The balance of Accounts Payable was $171.8 million and $230.4 million at September 30, 2018 and December 31, 2017, respectively, a decrease of $58.6 million, or 25.4 percent, primarily due to the timing of vendor payments.

Accrued Taxes. The balance of Accrued Taxes was $62.6 million and $44.5 million at September 30, 2018 and December 31, 2017, respectively, an increase of $18.1 million, or 40.7 percent, primarily resulting from the timing of tax accruals offset by ad valorem payments.

Fuel Clause Recoveries. The balance of Fuel Clause Over Recoveries was $39.2 million and $1.7 million at September 30, 2018 and December 31, 2017, respectively, an increase of $37.5 million, primarily due to higher recoveries from OG&E retail customers as compared to the actual cost of fuel and purchased power.

Other Current Liabilities. The balance of Other Current Liabilities was $82.3 million and $28.7 million at September 30, 2018 and December 31, 2017, respectively, an increase of $53.6 million, primarily due to amounts owed to customers, including the reserve for tax refund of $22.8 million resulting from the 2017 Tax Act and SPP credits of $23.1 million.

Cash Flows



	Nine Months Ended
	September 30,						2018 vs. 2017
(Dollars in millions)	2018			2017			$ Change			% Change
Net cash provided from operating activities	$	711.7		$	463.7		$	248.0		53.5	%
Net cash used in investing activities	$	(413.1	)	$	(660.3	)	$	247.2		(37.4	)%
Net cash (used in) provided from financing activities	$	(222.3	)	$	196.3		$	(418.6	)	*

* Change is greater than 100 percent variance.

Operating Activities

The increase of $248.0 million, or 53.5 percent, in net cash provided from operating activities during the nine months ended September 30, 2018 as compared to the same period in 2017 was primarily due to increased amounts received from customers at OG&E and a decrease in vendor payments.

Investing Activities

The decrease of $247.2 million, or 37.4 percent, in net cash used in investing activities during the nine months ended September 30, 2018 as compared to the same period in 2017 was primarily due to a decrease in capital expenditures related to environmental projects at OG&E.

Financing Activities

The decrease of $418.6 million in net cash provided from financing activities during the nine months ended September 30, 2018 as compared to the same period in 2017 was primarily due to the issuance of less long-term debt by OG&E in 2018, additional long-term debt paid off in 2018 and a decrease in short-term debt.

Future Capital Requirements

The Company's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.

Capital Expenditures

The Company's consolidated estimates of capital expenditures, which represent base maintenance capital expenditures plus capital expenditures for known and committed projects, for the years 2018 through 2022 are discussed in detail in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's 2017 Form 10-K. Additional capital expenditures beyond those identified in the Company's 2017 Form 10-K, including additional incremental growth opportunities in electric transmission assets, will be evaluated based upon their impact upon achieving the Company's financial objectives.

Financing Activities and Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long- and short-term debt, proceeds from the sales of common stock to the public through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings and distributions from Enable will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. The Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

Short-Term Debt and Credit Facilities

Short-term borrowings generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by issuance of commercial paper and by borrowings under its revolving credit agreement. The Company has revolving credit facilities totaling $900.0 million. These bank facilities can also be used as letter of credit facilities. As of September 30, 2018, the Company had no short-term debt as compared to $168.4 million at December 31, 2017. The following tables highlight the Company's short-term debt activity as of and for the nine month period ended September 30, 2018.



(Dollars in millions)	September 30, 2018
Balance of outstanding supporting letters of credit	$	0.3
Weighted-average interest rate of outstanding supporting letters of credit	1.05		%
Net available liquidity under revolving credit agreements	$	899.7
Balance of cash and cash equivalents	$	90.7

(Dollars in millions)	Nine Months Ended September 30, 2018
Average balance of short-term debt	$	172.3
Weighted-average interest rate of average balance of short-term debt	2.10		%
Maximum month-end balance of short-term debt	$	289.0

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. OG&E has requested renewal of this authority for an additional two-year period and expects to receive approval prior to the expiration of its current authority. See Note 10 in "Item 1. Financial Statements" for further discussion of the Company's short-term debt activity.

Issuance of New Long-Term Debt

Security Ratings

Access to reasonably priced capital is dependent in part on credit and security ratings. Generally, lower ratings lead to higher financing costs. 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.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency, and each rating should be evaluated independently of any other rating.

On March 5, 2018, S&P Global Ratings revised the rating outlooks on the Company and OG&E from stable to negative. S&P Global Ratings indicated that the revised outlooks reflect the limited cushion in company financial measures, which incorporate higher capital spending plans and the effects of the 2017 Tax Act, and uncertainty regarding regulatory risk. The revised outlooks did not trigger any collateral requirements or change fees under the revolving credit agreements.

On June 18, 2018, S&P Global Ratings lowered its issuer credit ratings for the Company and OG&E from A- to BBB+ and revised their rating outlooks from negative to stable. S&P Global Ratings also lowered its rating on OG&E's senior unsecured notes from A- to BBB+. S&P Global Ratings indicated that the changes in ratings are a result of the $64.0 million rate decrease in the June 19, 2018 OCC settlement, the existing level of depreciation expense and continued capital spending, which places the Company and OG&E at a higher level of financial risk in S&P Global Rating's risk profile. Furthermore, S&P Global Ratings indicated that the Company's change in credit rating was impacted by Enable's business risk, due to the volatility of the oil and gas industry. However, S&P Global Ratings indicated that the stable outlook reflects its expectation that the Company and OG&E will be able to manage future regulatory risk in Oklahoma.

On July 11, 2018, Moody's Investors Service lowered its rating from A3 to Baa1 for the Company and from A1 to A2 for OG&E with both companies having negative outlooks. The Oklahoma regulatory environment and the 2017 Tax Act were both cited by Moody's Investors Service as contributing factors to the credit downgrade. Moody's Investors Service indicated that the negative outlook for OG&E is a reflection of current capital expenditures relating to environmental projects, upcoming debt maturities over the next year and decreased cash flow as a result of the 2017 Tax Act. In addition to the OG&E impacts, Moody's Investors Service indicated that the negative outlook for the Company is a reflection of Enable's business risk, due to the volatility of the oil and gas industry, which Moody's Investors Service indicated could lead to decreased distributions.

On August 1, 2018, Fitch Ratings lowered its senior unsecured debt rating from A- to BBB+ for the Company and from A+ to A for OG&E with both companies having stable outlooks. Fitch Ratings cited the regulatory environment in Oklahoma, underscored by the unfavorable rate review outcomes in 2017 and 2018 and uncertainty surrounding regulatory treatment for OG&E's investment in the Dry Scrubbers at Sooner Units 1 and 2, as a key contributing factor to the credit downgrade. Fitch Ratings also indicated that the Company's credit profile reflects Enable's higher operating risks.

The Company's and OG&E's borrowing costs under the credit agreements will increase immaterially as a result of these recent credit downgrades.

Quarterly Distributions by Enable

Pursuant to the Enable Limited Partnership Agreement, during the three and nine months ended September 30, 2018, Enable made distributions of $35.3 million and $105.9 million to the Company, respectively.

Critical Accounting Policies and Estimates

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements contain information that is pertinent to Management's Discussion and Analysis. In preparing the Condensed Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company's Condensed Consolidated Financial Statements. However, the Company believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates.

In management's opinion, the areas of the Company where the most significant judgment is exercised for all Company segments include the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations and depreciable lives of property, plant and equipment. For the electric utility segment, significant judgment is also exercised in the determination of regulatory assets and liabilities and unbilled revenues. The selection, application and disclosure of the Company's critical accounting estimates have been discussed with the Company's Audit Committee and are discussed in detail in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's 2017 Form 10-K.

Commitments and Contingencies

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 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. See Notes 13 and 14 in "Item 1. Financial Statements" for a discussion of the Company's commitments and contingencies.

Environmental Laws and Regulations

The activities of the Company 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 the Company's business activities in many ways, including the handling or disposal of waste material, planning for future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions 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. These environmental laws and regulations are also discussed in detail in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's 2017 Form 10-K.

Air

Federal Clean Air Act Overview

OG&E's operations are subject to the Federal Clean Air Act as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. OG&E likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.

Regional Haze Control Measures

The EPA's 2005 Regional Haze Rule is intended to protect visibility in certain national parks and wilderness areas throughout the U.S. that may be impacted by air pollutant emissions. On December 28, 2011, the EPA issued a final Regional Haze Rule for Oklahoma which adopted a FIP for SO₂ emissions at Sooner Units 1 and 2 and Muskogee Units 4 and 5. The FIP compliance date is January 4, 2019 as a result of an appeal filed by OG&E and others.

OG&E's strategy for satisfying the FIP includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. As of September 30, 2018, OG&E has invested $483.5 million in the Dry Scrubbers and $28.4 million in the Muskogee gas conversion.

Cross-State Air Pollution Rule

In August 2011, the EPA finalized its CSAPR that required 27 states in the eastern half of the U.S. (including Oklahoma) to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. Litigation challenging the rule prevented it from entering into effect until 2014. Several parties to that litigation, including OG&E, have petitions for review that remain pending although the rule is now effective. Compliance with the CSAPR began in 2015 using the amount of allowances originally scheduled to be available in 2012. As of September 30, 2018, OG&E has installed seven low NO_X burner systems on two Muskogee units, two Sooner units and three Seminole units and is in compliance.

On September 7, 2016, the EPA finalized an update to the 2011 CSAPR. The new rule applies to ozone-season NO_X in 22 eastern states (including Oklahoma), utilizes a cap and trade program for NO_X emissions and took effect on May 1, 2017. The rule reduces the 2016 CSAPR emissions cap for all seven of OG&E's coal and gas facilities by 47 percent combined. OG&E and numerous other parties filed petitions for judicial and administrative review of the 2016 rule. Oral argument before the D.C. Circuit U.S. Court of Appeals was held on October 3, 2018.

Due to the pending litigation and administrative proceedings, the ultimate timing and impact of the 2016 CSAPR update rule on our operations cannot be determined with certainty at this time. However, the Company does not anticipate additional capital expenditures beyond what has already been disclosed and does not expect that the reduced emissions cap, if upheld, will have a material impact on the Company's consolidated financial position, results of operations or cash flows.

Hazardous Air Pollutants Emission Standards

On February 16, 2012, the EPA published the final MATS rule regulating the emissions of certain hazardous air pollutants from electric generating units, which became effective April 16, 2012. The Company complied with the MATS rule by the April 16, 2016 deadline that applied to OG&E by installing activated carbon injection for all five coal units. Nonetheless, there is continuing litigation, to which the Company is not a party, challenging whether the EPA had statutory authority to issue the MATS rule. On October 5, 2018, the EPA submitted to the Office of Management and Budget a revision to the 2012 rule in response to lengthy litigation in the DC Circuit Court. It is unknown what the rule requires at this point; however, the rule will be released for public comment after the Office of Management and Budget process. The Company cannot predict the outcome of the litigation or regulatory proposal or how it will affect the Company.

National Ambient Air Quality Standards

The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, the Company could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of September 30, 2018, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect the Company's operations. Several processes are under way to designate areas in Oklahoma as attaining or not attaining revised NAAQS.

The EPA proposed to designate part of Muskogee County, in which OG&E's Muskogee Power Plant is located, as non-attainment for the 2010 SO₂ NAAQS on March 1, 2016, even though nearby monitors indicate compliance with the NAAQS. The proposed designation is based on modeling that does not reflect the planned conversion of two of the coal units at Muskogee to natural gas. OG&E commented that the EPA should defer a designation of the area to allow time for additional monitoring. The State of Oklahoma's revised monitoring plan was approved by the EPA, and the required monitoring commenced at the beginning of 2017 and will continue through the end of 2019. Nonetheless, the EPA has a deadline for making a decision on the designation pursuant to a consent decree entered by the U.S. District Court for the Northern District of California to resolve a citizen suit. The deadline has been extended several times, with the current deadline being August 26, 2017, but a decision has yet to be reached. It is unclear what impact, if any, the consent decree deadline will have on the monitoring plan. At this time, OG&E cannot determine with any certainty whether the proposed designation of Muskogee County will cause a material impact to OG&E's financial results. The EPA has published final decisions on all other areas of Oklahoma. In this decision, Noble County, in which the Sooner plant is located, was deemed to be in attainment with the 2010 standard.

On September 30, 2015, the EPA finalized a NAAQS for ozone at 70 ppb, which is more stringent than the previous standard of 75 ppb set in 2008. In September 2016, Governor Mary Fallin submitted to the EPA the recommendation of "attainment/unclassifiable" for all 77 counties in Oklahoma. On June 4, 2018, the EPA published its final determination that there are no nonattainment areas in Oklahoma. Based on this assessment, no material impacts are anticipated at this time.

The Company is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to the Company's financial results.

Climate Change and Greenhouse Gas Emissions

There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including CO₂, sulfur hexafluoride and methane and whether these emissions are contributing to the warming of the earth's atmosphere. On June 1, 2017, President Trump announced that the U.S. will withdraw from the Paris Climate Accord and begin negotiations to re-enter the agreement with different terms. A new agreement may result in future additional emissions reductions in the U.S.; however, it is not possible to determine what the international legal standards for greenhouse gas emissions will be in the future and the extent to which these commitments will be implemented through the Clean Air Act, or any other existing statutes and new legislation.

If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of CO₂ and other greenhouse gases on the Company's facilities, this could result in significant additional compliance costs that would affect the Company's future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Several states outside the area where the Company operates have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.

On October 23, 2015, the EPA published the final Clean Power Plan that established standards of performance for CO₂ emissions from existing fossil-fuel-fired power plants along with state-specific CO₂ reduction standards expressed as both rate-based (lbs./MWh) and mass-based (tons/yr.) goals. However, the rule was challenged in court when it was issued, and the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan on February 9, 2016 pending resolution of the court challenges. The EPA published a proposal on October 16, 2017 to repeal the Clean Power Plan. On August 31, 2018, the EPA published a proposed rule to replace the Clean Power Plan. The ultimate timing and impact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO₂ emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect the Company's future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

Nonetheless, OG&E's current business strategy will result in a reduced carbon emissions rate compared to current levels. As discussed in Note 14 in "Item 1. Financial Statements" under "Pending Regulatory Matters," OG&E's plan to comply with the EPA's MATS rule and Regional Haze Rule FIP includes converting two coal-fired generating units at the Muskogee Station to natural gas, among other measures. OG&E's deployment of Smart Grid technology helps to reduce the peak load demand. OG&E is also deploying more renewable energy sources that do not emit greenhouse gases. OG&E's service territory borders one of the nation's best wind resource areas, and OG&E has leveraged its geographic position to develop renewable energy resources and completed transmission investments to deliver the renewable energy. The SPP has begun to authorize the construction of transmission lines capable of bringing renewable energy out of the wind resource areas in western Oklahoma, the Texas Panhandle and western Kansas to load centers by planning for more transmission to be built in the area. In addition to increasing overall system reliability, these new transmission resources should provide greater access to additional wind resources that are currently constrained due to existing transmission delivery limitations.

EPA Startup, Shutdown and Malfunction Policy

On May 22, 2015, the EPA issued a final rule to address the provisions in the SIPs of 36 states (including Oklahoma) regarding the treatment of emissions that occur during startup, shutdown and malfunction operations. The final rule clarifies the EPA's Startup, Shutdown and Malfunction Policy. Although judicial challenges to the rule are ongoing, the Oklahoma Department of Environmental Quality submitted a SIP revision for the EPA's approval on November 7, 2016 to comply with this rule. This rule has resulted in permit modifications for certain OG&E units. The Company does not anticipate capital expenditures or a material impact to its consolidated financial position, results of operations or cash flows, as a result of adoption of this rule.

Air Quality Control System

Endangered Species

Certain federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. If such species are located in an area in which the Company conducts operations, or if additional species in those areas become subject to protection, the Company's operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or the Company could be required to implement expensive mitigation measures.

Waste

OG&E's operations generate wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of waste.

In 2015, the EPA finalized a rule under the Federal Resource Conservation and Recovery Act for the handling and disposal of coal combustion residuals or coal ash. The rule regulates coal ash as a solid waste rather than a hazardous waste, which would have made the management of coal ash more costly. The rule is currently being appealed at the D.C. Circuit Court of Appeals. On June 28, 2018, the EPA approved the State of Oklahoma's application for a state coal ash permitting program that will operate in lieu of the federal coal ash program promulgated under the Federal Resource Conservation and Recovery Act. The Company is

monitoring other regulatory developments relating to this rule, none of which appear to be material to OG&E at this time. OG&E is in compliance with this rule at this time.

The Company has sought and will continue to seek pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. The Company obtains refunds from the recycling of scrap metal, salvaged transformers and used transformer oil. Additional savings are expected to be gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years.

Water

OG&E's operations are subject to the Federal Clean Water Act and comparable state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters.

The EPA issued a final rule on May 19, 2014 to implement Section 316(b) of the Federal Clean Water Act, which requires that power plant cooling water intake structure location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. OG&E submitted compliance plans to the State of Oklahoma in April 2015. The Oklahoma Department of Environmental Quality issued final permits on December 22, 2017 and August 22, 2018 for Muskogee Power Plant and Seminole Power Plant, respectively, in compliance with the final 316(b) rule, and OG&E did not incur any material costs associated with the rule's implementation at either location. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation at other facilities following the future issuance of permits from the State of Oklahoma.

On September 30, 2015, the EPA issued a final rule addressing the effluent limitation guidelines for power plants under the Federal Clean Water Act. The final rule establishes technology- and performance-based standards that may apply to discharges of six waste streams including bottom ash transport water. Compliance with this rule will occur by 2023; however, on April 12, 2017, the EPA granted a Petition for Reconsideration of the 2015 Rule. OG&E is evaluating what, if any, compliance actions are needed but is not able to quantify with any certainty what costs may be incurred. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation following issuance of the permits from the State of Oklahoma.

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generates wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E.

For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 13 in "Item 1. Financial Statements."

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

There have been no significant changes in the market risks affecting the Company from those discussed in the Company's 2017 Form 10-K.

Item 4. Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Company's management, including the chief executive officer and chief financial officer, of the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities

Exchange Act of 1934), the chief executive officer and chief financial officer have concluded that the Company's disclosure controls and procedures are effective.

No change in the Company's internal control over financial reporting has occurred during the Company's most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Reference is made to Item 3 of Part I of the Company's 2017 Form 10-K for a description of certain legal proceedings presently pending. Except as described above under "Environmental Laws and Regulations" in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," there are no new significant cases to report against the Company or its subsidiaries, and there have been no material changes in the previously reported proceedings.

Item 1A. Risk Factors.

Except as detailed below, there have been no significant changes in the Company's risk factors from those discussed in the Company's 2017 Form 10-K, which are incorporated herein by reference. The following risk is associated with the Company's investment in Enable.

Enable's operations are subject to extensive regulation by federal regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us.

The rates charged by several of Enable's pipeline systems, including for interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. The FERC and state regulatory agencies also regulate other terms and conditions of the services Enable may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower Enable's tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service Enable might propose or offer, the profitability of Enable's pipeline businesses could suffer. If Enable were permitted to raise its tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit Enable's profitability. Furthermore, competition from other pipeline systems may prevent Enable from raising its tariff rates even if regulatory agencies permit it to do so. The regulatory agencies that regulate Enable's systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for Enable's services or otherwise adversely affect Enable's financial position, results of operations and ability to make cash distributions to its unitholders, including us.

Enable's natural gas interstate pipelines are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. Generally, the FERC's authority over interstate natural gas transportation extends to:

•rates, operating terms, conditions of service and service contracts;

•certification and construction of new facilities;

•extension or abandonment of services and facilities or expansion of existing facilities;

•maintenance of accounts and records;

•acquisition and disposition of facilities;

•initiation and discontinuation of services;

•depreciation and amortization policies;

•conduct and relationship with certain affiliates;

•market manipulation in connection with interstate sales, purchases or natural gas transportation; and

•various other matters.

Should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 to impose penalties for current violations of up to $1.0 million per day for each violation and possible criminal penalties of up to approximately $1.2 million per violation.

The FERC's jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to expansions, lateral and other facilities and abandonment of facilities and services. Prior to commencing construction of significant new interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or an order amending its existing certificate, from the FERC. Certain minor expansions are authorized by blanket certificates that the FERC has issued by rule. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any failure by an agency to issue sufficient authorizations or permits in a timely manner for one or more of these projects may mean that Enable will not be able to pursue these projects or that they will be constructed in a manner or with capital

requirements that Enable did not anticipate. Enable's inability to obtain sufficient permits and authorizations in a timely manner could materially and negatively impact the additional revenues expected from these projects.

The FERC conducts audits to verify compliance with the FERC's regulations and the terms of its orders, including whether the websites of interstate pipelines accurately provide information on the operations and availability of services. The FERC's regulations require uniform terms and conditions for service, as set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the standard form of service agreements set forth in the pipeline's FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require Enable to seek modification, or alternatively require Enable to modify its tariff so that the non-conforming provisions are generally available to all customers.

The rates, terms and conditions for transporting natural gas in interstate commerce on certain of Enable intrastate pipelines and for services offered at certain of Enable's storage facilities are subject to the jurisdiction of the FERC under Section 311 of the Natural Gas Policy Act of 1978. Rates to provide such interstate transportation service must be "fair and equitable" under the Natural Gas Policy Act of 1978 and are subject to review, refund with interest if found not to be fair and equitable, and approval by the FERC at least once every five years.

Enable's crude oil gathering pipelines are subject to common carrier regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that Enable maintain tariffs on file with the FERC setting forth the rates Enable charges for providing transportation services, as well as the rules and regulations governing such services. The Interstate Commerce Act requires, among other things, that Enable's rates must be "just and reasonable" and that Enable provides service in a manner that is nondiscriminatory. Shippers on Enable crude oil gathering pipelines may protest its tariff filings, file complaints against Enable's existing rates, or the FERC can investigate Enable's rates on its own initiative. In the event that the FERC finds that Enable's existing or proposed rates are unjust and unreasonable, it could deny requested rate increases or could order Enable to reduce its rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint.

On December 22, 2017, the 2017 Tax Act was enacted, which reduced the highest marginal U.S. federal corporate income tax rate from 35 percent to 21 percent for tax years beginning after December 31, 2017. In a series of related issuances on March 15, 2018, the FERC revised its policy so that it will no longer permit pipelines organized as master limited partnerships to recover an income tax allowance in their cost-of-service rates, and proposed rules for implementing this revised policy and the corporate income tax rate reduction pursuant to the 2017 Tax Act with respect to natural gas pipeline rates. In July 2018, the FERC denied requests for rehearing of the policy statement relating to recovery of an income tax allowance (although it indicated that a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors' income tax costs). Also in July 2018, the FERC adopted proposed rules that require all FERC-regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information that will allow the FERC and other stakeholders to evaluate the impacts of the revised policy and the corporate income tax rate reduction on each individual pipeline's rates, and to select one of four options: file a limited Natural Gas Act of 1938 Section 4 filing reducing its rates only as required related to the revised policy and the 2017 Tax Act, commit to filing a general Natural Gas Act of 1938 Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. Enable Gas Transmission, LLC, filed its Form No. 501-G on October 11, 2018 and explained why a reduction to rates is not warranted.

The FERC's Revised Policy Statement requires the reduced maximum corporate tax rate to be reflected in initial oil cost-of-service rates and cost-of-service rate changes going forward and in future filings of Page 700 of FERC Form No. 6. The FERC will consider the information provided by pipelines in Page 700 of FERC Form No. in its 2020 five-year review of the oil pipeline index level.

Although Enable cannot predict the ultimate impact of the policy statement and final rules, the cost-of-service rates Enable is permitted to charge their customers for transportation and storage services could be impacted when Enable Mississippi River Transmission, LLC, or if Enable Gas Transmission, LLC, files a limited or general Natural Gas Act of 1938 Section 4 rate filing or if the FERC or customers challenge the cost-of-service rates that Enable Gas Transmission, LLC, is authorized to charge. Enable also cannot predict the outcome of the 2020 oil pipeline index five-year review, but the rates Enable is permitted to charge its customers for cost-of-service based crude oil transportation services could be impacted. If the FERC requires Enable to establish new tariff rates for either Enable's natural gas or crude oil pipelines that reflect a lower federal corporate income tax rate and the Revised Policy Statement, it is possible the rates would be reduced, which could adversely affect Enable's financial position, results of operations and ability to make cash distributions to Enable's unitholders, including us.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 6. Exhibits.



Exhibit No.	Description
4.01	Supplemental Indenture No. 19 dated as of August 15, 2018 between OG&E and BOKF, NA, as trustee. (Filed as Exhibit 4.01 to the Company's Form 8-K filed August 17, 2018 (File No. 1-12579) and incorporated by reference herein).
31.01	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Schema Document.
101.PRE	XBRL Taxonomy Presentation Linkbase Document.
101.LAB	XBRL Taxonomy Label Linkbase Document.
101.CAL	XBRL Taxonomy Calculation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	OGE ENERGY CORP.
	(Registrant)

By:	/s/ Sarah R. Stafford
	Sarah R. Stafford
	Controller and Chief Accounting Officer
	(On behalf of the Registrant and in her capacity as Chief Accounting Officer)

November 7, 2018

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