UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2019

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File Number: 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)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	OGE	New York Stock Exchange

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.  ☑ Yes  ☐ 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).  ☑ Yes  ☐ 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	☑	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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. ☐

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

At June 30, 2019, there were 200,175,812 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2019

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	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	46
Item 4. Controls and Procedures	46
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	47
Item 1A. Risk Factors	47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 6. Exhibits	47
Signature	48

i

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations that are found throughout this Form 10-Q.

Abbreviation	Definition
2018 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2018
2017 Tax Act	Tax Cuts and Jobs Act of 2017
AES	AES-Shady Point, Inc.
ALJ	Administrative Law Judge
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
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.
MATS	Mercury and Air Toxics Standards
MBbl/d	Thousand barrels per day
MW	Megawatt
MWh	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NGLs	Natural gas liquids
NOX	Nitrogen oxide
OCC	Oklahoma Corporation Commission
OG&E	Oklahoma Gas and Electric Company, wholly owned subsidiary of OGE Energy
OGE Energy	Holding company
OGE Holdings	OGE Enogex Holdings, LLC, wholly owned subsidiary of OGE Energy, parent company of Enogex Holdings (prior to May 1, 2013) and 25.5 percent owner of Enable
Pension Plan	Qualified defined benefit retirement plan
QF	Qualified cogeneration facility
Regional Haze Rule	The EPA's Regional Haze Rule
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SIP	State Implementation Plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day
U.S.	United States of America

ii

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-Q, including those matters discussed within "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 within "Item 1A. Risk Factors" in the Company's 2018 Form 10-K and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" 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 within "Item 1A. Risk Factors" in the Company's 2018 Form 10-K.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2019			2018			2019			2018
OPERATING REVENUES
Revenues from contracts with customers	$	501.1		$	547.7		$	978.5		$	1,025.6
Other revenues	12.6			19.3			25.2			34.1
Operating revenues	513.7			567.0			1,003.7			1,059.7
COST OF SALES	178.7			208.7			391.3			419.2
OPERATING EXPENSES
Other operation and maintenance	119.8			117.2			238.8			229.9
Depreciation and amortization	84.3			80.9			166.7			159.7
Taxes other than income	20.9			22.5			47.2			46.6
Operating expenses	225.0			220.6			452.7			436.2
OPERATING INCOME	110.0			137.7			159.7			204.3
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	35.8			29.3			66.5			63.2
Allowance for equity funds used during construction	1.2			6.3			2.7			13.3
Other net periodic benefit expense	(0.3		)	(5.2		)	(7.3		)	(10.0		)
Other income	5.0			4.7			11.7			10.1
Other expense	(4.4		)	(3.3		)	(10.1		)	(7.7		)
Net other income	37.3			31.8			63.5			68.9
INTEREST EXPENSE
Interest on long-term debt	31.8			39.7			64.4			79.3
Allowance for borrowed funds used during construction	(0.6		)	(2.8		)	(1.6		)	(6.5		)
Interest on short-term debt and other interest charges	4.7			4.0			7.7			6.7
Interest expense	35.9			40.9			70.5			79.5
INCOME BEFORE TAXES	111.4			128.6			152.7			193.7
INCOME TAX EXPENSE	11.2			17.9			5.4			28.0
NET INCOME	$	100.2		$	110.7		$	147.3		$	165.7
BASIC AVERAGE COMMON SHARES OUTSTANDING	200.2			199.7			200.1			199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.6			200.5			200.5			200.3
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	0.50		$	0.55		$	0.74		$	0.83
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	0.50		$	0.55		$	0.73		$	0.83

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

2

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Net income	$	100.2		$	110.7		$	147.3		$	165.7
Other comprehensive income, net of tax:
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.3, $0.3, $0.5 and $0.5, respectively	1.0			1.0			1.7			1.7
Settlement cost, net of tax of $0.1, $0.0, $2.3 and $0.0, respectively	0.5			—			7.1			—
Postretirement Benefit Plans:
Amortization of prior service credit, net of tax of ($0.1), ($0.2), ($0.2) and ($0.3), respectively	(0.4		)	(0.3		)	(0.9		)	(0.8		)
Amortization of deferred net gain, net of tax of $0.0, $0.0, $0.0 and $0.0, respectively	(0.1		)	—			(0.1		)	—
Other comprehensive income, net of tax	1.0			0.7			7.8			0.9
Comprehensive income	$	101.2		$	111.4		$	155.1		$	166.6

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

3

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	147.3		$	165.7
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	166.7			159.7
Deferred income taxes and investment tax credits, net	(1.9		)	19.4
Equity in earnings of unconsolidated affiliates	(66.5		)	(63.2		)
Distributions from unconsolidated affiliates	70.6			63.2
Allowance for equity funds used during construction	(2.7		)	(13.3		)
Stock-based compensation expense	5.9			5.8
Regulatory assets	(25.6		)	(1.6		)
Regulatory liabilities	(21.1		)	1.9
Other assets	(3.2		)	7.3
Other liabilities	13.9			(0.6		)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	(12.5		)	(51.5		)
Income taxes receivable	3.6			(2.0		)
Fuel, materials and supplies inventories	7.2			0.1
Fuel recoveries	(28.9		)	37.0
Other current assets	(4.5		)	22.0
Accounts payable	(83.4		)	(45.7		)
Other current liabilities	(36.1		)	50.0
Net cash provided from operating activities	128.8			354.2
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(314.5		)	(273.8		)
Investment in unconsolidated affiliates	(3.2		)	(0.5		)
Return of capital - unconsolidated affiliates	—			7.4
Net cash used in investing activities	(317.7		)	(266.9		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	295.9			—
Increase in short-term debt	207.5			31.7
Payment of long-term debt	(250.0		)	—
Dividends paid on common stock	(148.6		)	(133.0		)
Expense of common stock	(10.2		)	(0.4		)
Net cash provided from (used in) financing activities	94.6			(101.7		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(94.3		)	(14.4		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	94.3			14.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	—

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

4

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,		December 31,
(In millions)	2019		2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	94.3
Accounts receivable, less reserve of $1.3 and $1.7, respectively	163.6		174.7
Accrued unbilled revenues	86.2		62.6
Income taxes receivable	6.3		9.9
Fuel inventories	47.9		57.6
Materials and supplies, at average cost	86.9		126.7
Fuel clause under recoveries	30.7		2.0
Other	34.0		29.5
Total current assets	455.6		557.3
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,171.3		1,177.5
Other	81.4		73.4
Total other property and investments	1,252.7		1,250.9
PROPERTY, PLANT AND EQUIPMENT
In service	12,516.7		11,994.8
Construction work in progress	126.8		376.4
Total property, plant and equipment	12,643.5		12,371.2
Less: accumulated depreciation	3,766.0		3,727.4
Net property, plant and equipment	8,877.5		8,643.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	290.0		285.8
Other	10.4		10.8
Total deferred charges and other assets	300.4		296.6
TOTAL ASSETS	$	10,886.2	$	10,748.6

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

5

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)

	June 30,			December 31,
(In millions)	2019			2018
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	207.5		$	—
Accounts payable	151.6			239.3
Dividends payable	73.0			72.9
Customer deposits	83.4			83.6
Accrued taxes	40.8			44.0
Accrued interest	35.8			44.5
Accrued compensation	33.1			47.8
Long-term debt due within one year	—			250.0
Fuel clause over recoveries	0.1			0.3
Other	77.4			87.0
Total current liabilities	702.7			869.4
LONG-TERM DEBT	3,193.6			2,896.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	224.9			225.7
Deferred income taxes	1,325.0			1,310.9
Deferred investment tax credits	7.2			7.2
Regulatory liabilities	1,243.0			1,270.7
Other	182.6			162.7
Total deferred credits and other liabilities	2,982.7			2,977.2
Total liabilities	6,879.0			6,743.5
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,123.4			1,127.7
Retained earnings	2,904.9			2,906.3
Accumulated other comprehensive loss, net of tax	(21.1		)	(28.9		)
Total stockholders' equity	4,007.2			4,005.1
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	10,886.2		$	10,748.6

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

6

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(Unaudited)

(In millions)	Shares Outstanding	Common Stock		Premium on Common Stock			Retained Earnings			Accumulated Other Comprehensive (Loss) Income			Total
Balance at December 31, 2018	199.7	$	2.0	$	1,125.7		$	2,906.3		$	(28.9	)	$	4,005.1
Net income	—	—		—			47.1			—			47.1
Other comprehensive income net of tax	—	—		—			—			6.8			6.8
Dividends declared on common stock ($0.3650 per share)	—	—		—			(75.6		)	—			(75.6		)
Stock-based compensation	0.5	—		(7.2		)	—			—			(7.2		)
Balance at March 31, 2019	200.2	$	2.0	$	1,118.5		$	2,877.8		$	(22.1	)	$	3,976.2
Net income	—	—		—			100.2			—			100.2
Other comprehensive income net of tax	—	—		—			—			1.0			1.0
Dividends declared on common stock ($0.3650 per share)	—	—		—			(73.1		)	—			(73.1		)
Stock-based compensation	—	—		2.9			—			—			2.9
Balance at June 30, 2019	200.2	$	2.0	$	1,121.4		$	2,904.9		$	(21.1	)	$	4,007.2
Balance at December 31, 2017	199.7	$	2.0	$	1,112.8		$	2,759.5		$	(23.2	)	$	3,851.1
Net income	—	—		—			55.0			—			55.0
Other comprehensive income net of tax	—	—		—			—			0.2			0.2
Dividends declared on common stock ($0.3325 per share)	—	—		—			(66.5		)	—			(66.5		)
Stock-based compensation	—	—		2.3			—			—			2.3
Balance at March 31, 2018	199.7	$	2.0	$	1,115.1		$	2,748.0		$	(23.0	)	$	3,842.1
Net income	—	—		—			110.7			—			110.7
Other comprehensive income, net of tax	—	—		—			—			0.7			0.7
Dividends declared on common stock ($0.3325 per share)	—	—		—			(66.4		)	—			(66.4		)
Stock-based compensation	—	—		3.0			—			—			3.0
Balance at June 30, 2018	199.7	$	2.0	$	1,118.1		$	2,792.3		$	(22.3	)	$	3,890.1

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

7

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

The Company's significant accounting policies are detailed in "Note 1. Summary of Significant Accounting Policies" in the Company's 2018 Form 10-K. Changes to the Company's accounting policies as a result of adopting ASU 2016-02, "Leases (Topic 842)," and the related ASU 2018-01 and ASU 2018-11 are discussed in Notes 2 and 4 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.

The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries and ultimately OGE Holdings. Enable was formed in 2013, and its general partner 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 accounts for its interest in Enable using the equity method of accounting. Enable is primarily 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 in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at June 30, 2019 and December 31, 2018, the consolidated results of its operations for the three and six months ended June 30, 2019 and 2018 and its consolidated cash flows for the six months ended June 30, 2019 and 2018 have been included and are of a normal, recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring after June 30, 2019 up to the date of issuance of these Condensed Consolidated Financial Statements, and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

Due to seasonal fluctuations and other factors, the Company's operating results for the three and six months ended June 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 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 2018 Form 10-K.

8

Accounting Records

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

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

The following table is a summary of OG&E's regulatory assets and liabilities.

	June 30,		December 31,
(In millions)	2019		2018
REGULATORY ASSETS
Current:
Fuel clause under recoveries	$	30.7	$	2.0
Cogeneration credit rider over credit (A)	8.2		—
Production tax credit rider over credit (A)	4.1		6.9
Oklahoma demand program rider under recovery (A)	—		6.4
Other (A)	5.1		3.2
Total current regulatory assets	$	48.1	$	18.5
Non-current:
Benefit obligations regulatory asset	$	172.3	$	188.2
Deferred storm expenses	43.6		36.5
Smart Grid	22.1		25.6
Sooner Dry Scrubbers	21.0		4.5
Unamortized loss on reacquired debt	11.0		11.4
Arkansas deferred pension expenses	7.7		6.8
Other	12.3		12.8
Total non-current regulatory assets	$	290.0	$	285.8
REGULATORY LIABILITIES
Current:
Reserve for tax refund and interim surcharge (B)	$	17.7	$	15.4
SPP cost tracker over recovery (B)	8.0		16.8
Oklahoma demand program rider over recovery (B)	6.2		—
Transmission cost recovery rider over recovery (B)	1.1		2.7
Fuel clause over recoveries	0.1		0.3
Other (B)	3.2		1.4
Total current regulatory liabilities	$	36.3	$	36.6
Non-current:
Income taxes refundable to customers, net	$	921.6	$	937.1
Accrued removal obligations, net	312.9		308.1
Pension tracker	2.2		18.7
Other	6.3		6.8
Total non-current regulatory liabilities	$	1,243.0	$	1,270.7

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

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

9

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 June 30, 2019 as presented in Note 13. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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

Accumulated Other Comprehensive Income (Loss)

The following tables summarize changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the six months ended June 30, 2019 and 2018. 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 (Credit)		Net Income (Loss)			Prior Service Cost (Credit)			Total
Balance at December 31, 2018	$	(38.8	)	$	—	$	4.6		$	5.3		$	(28.9	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.7			—		(0.1		)	(0.9		)	0.7
Settlement cost	7.1			—		—			—			7.1
Balance at June 30, 2019	$	(30.0	)	$	—	$	4.5		$	4.4		$	(21.1	)

	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net Income  (Loss)			Prior Service Cost (Credit)		Net Income		Prior Service Cost (Credit)			Total
Balance at December 31, 2017	$	(32.7	)	$	—	$	2.5	$	7.0		$	(23.2	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.7			—		—		(0.8		)	0.9
Balance at June 30, 2018	$	(31.0	)	$	—	$	2.5	$	6.2		$	(22.3	)

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The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and six months ended June 30, 2019 and 2018.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)												Affected Line Item in the Condensed Consolidated Statements of Income
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2019			2018			2019			2018
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses (A)	$	(1.3	)	$	(1.3	)	$	(2.2	)	$	(2.2	)	Other Net Periodic Benefit Expense
Settlement cost (A)	(0.6		)	—			(9.4		)	—			Other Net Periodic Benefit Expense
	(1.9		)	(1.3		)	(11.6		)	(2.2		)	Income Before Taxes
	(0.4		)	(0.3		)	(2.8		)	(0.5		)	Income Tax Expense
	$	(1.5	)	$	(1.0	)	$	(8.8	)	$	(1.7	)	Net Income
Amortization of postretirement benefit plans items:
Prior service credit (A)	$	0.5		$	0.5		$	1.1		$	1.1		Other Net Periodic Benefit Expense
Actuarial gains (A)	0.1			—			0.1			—			Other Net Periodic Benefit Expense
	0.6			0.5			1.2			1.1			Income Before Taxes
	0.1			0.2			0.2			0.3			Income Tax Expense
	$	0.5		$	0.3		$	1.0		$	0.8		Net Income
Total reclassifications for the period, net of tax	$	(1.0	)	$	(0.7	)	$	(7.8	)	$	(0.9	)	Net Income

(A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 12 for additional information).

Reclassifications

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

2. Accounting Pronouncements

Recently Adopted Accounting Standards

Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between prior 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, 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 is equal to the present value of lease payments. The asset is 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 result in straight-line expense, while finance leases result in a front-loaded expense pattern, similar to prior capital leases. Classification of operating and finance leases is based on criteria that are largely similar to those applied in prior lease guidance but without the explicit thresholds. The Company adopted this standard in the first quarter of 2019 utilizing the modified retrospective transition method.

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Various practical expedients for the application of Topic 842 were approved, and the Company elected to apply the below:

• a 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;

• an option that permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that exist or expired before the entity's adoption of Topic 842 and that were not previously accounted for as leases under ASC 840, "Leases"; and

• an option that permits an entity to 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, provided that if an entity elects this 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.

The Company evaluated its current lease contracts and, at January 1, 2019, recognized $34.5 million and $39.1 million of operating lease right-of-use assets and liabilities, respectively, for railcar, wind farm land and office space leases in the Condensed Consolidated Balance Sheet. The new standard did not have a material impact on the Company's 2019 periods within the Condensed Consolidated Statements of Income. Further, the Company evaluated its existing processes and controls regarding lease identification, accounting and presentation and implemented changes as necessary in order to adequately address the requirements of Topic 842. Additional information regarding the Company's adoption of Topic 842 can be found in the Company's 2018 Form 10-K.

Issued Accounting Standards Not Yet Adopted

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Residential	$	182.3		$	217.3		$	373.5		$	413.5
Commercial	115.4			135.1			210.8			235.9
Industrial	52.9			57.0			105.2			107.4
Oilfield	48.9			45.7			98.3			87.8
Public authorities and street light	44.4			51.1			84.5			92.8
System sales revenues	443.9			506.2			872.3			937.4
Provision for rate refund	(0.5		)	(16.5		)	(0.6		)	(19.7		)
Integrated market	10.3			13.1			17.0			21.8
Transmission	39.8			40.2			75.9			76.0
Other	7.6			4.7			13.9			10.1
Revenues from contracts with customers	$	501.1		$	547.7		$	978.5		$	1,025.6

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4. Leases

The Company evaluates all contracts under Topic 842 to determine if the contract is or contains a lease and to determine classification as an operating or finance lease. If a lease is identified, the Company recognizes a right-of-use asset and a lease liability in its Consolidated Balance Sheets. The Company recognizes and measures a lease liability when it concludes the contract contains an identified asset that the Company controls through having the right to obtain substantially all of the economic benefits and the right to direct the use of the identified asset. The liability is equal to the present value of lease payments, and the asset is based on the liability, subject to adjustment, such as for initial direct costs. Further, the Company utilizes an incremental borrowing rate for purposes of measuring lease liabilities, if the discount rate is not implicit in the lease. To calculate the incremental borrowing rate, the Company starts with a current pricing report for the Company's senior unsecured notes, which indicates rates for periods reflective of the lease term, and adjusts for the effects of collateral to arrive at the secured incremental borrowing rate. As permitted by Topic 842, the Company made an accounting policy election to not apply the balance sheet recognition requirements to short-term leases and to not separate lease components from nonlease components when recognizing and measuring lease liabilities. For income statement purposes, the Company records operating lease expense on a straight-line basis.

Based on its evaluation of all contracts under Topic 842, as described above, the Company concluded it has operating lease obligations for OG&E railcar leases, OG&E wind farm land leases and the Company's office space lease.

Operating Leases

OG&E Railcar Lease Agreement

Effective February 1, 2019, OG&E renewed a railcar lease agreement for 780 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to fuel expense and are recovered through OG&E's fuel adjustment clauses. On February 1, 2024, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $6.8 million.

OG&E Wind Farm Land Lease Agreements

The Company has operating leases related to land for OG&E's Centennial, OU Spirit and Crossroads wind farms with terms of 25 to 30 years. The Centennial lease has rent escalations which increase annually based on the Consumer Price Index. While lease liabilities are not remeasured as a result of changes to the Consumer Price Index, changes to the Consumer Price Index are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. The OU Spirit and Crossroads leases have rent escalations which increase after five and 10 years. Although the leases are cancellable, OG&E is required to make annual lease payments as long as the wind turbines are located on the land. OG&E does not expect to terminate the leases until the wind turbines reach the end of their useful life.

Office Space Lease

The Company has a noncancellable office space lease agreement, with a term from September 1, 2018 to August 31, 2021, that allows for leasehold improvements.

13

Financial Statement Information and Maturity Analysis of Lease Liabilities

Operating lease cost was $1.4 million and $3.0 million for the three and six months ended June 30, 2019, respectively. Payments for operating lease obligations were $4.9 million for the year ended December 31, 2018.

The following table presents amounts recognized for operating leases in the Company's 2019 Condensed Consolidated Cash Flow Statement and Balance Sheet and supplemental information related to those amounts recognized, as well as a maturity analysis of the Company's operating lease liabilities.

	Six Months Ended
(In millions)	June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	4.1
Right-of-use assets obtained in exchange for new operating lease liabilities	$	10.7
(Dollars in millions)	June 30, 2019
Right-of-use assets at period end (A)	$	43.1
Operating lease liabilities at period end (B)	$	47.8
Operating lease weighted-average remaining lease term (in years)	13.3
Operating lease weighted-average discount rate	3.9		%

Future minimum operating lease payments as of: (In millions)	June 30, 2019		December 31, 2018 (C)(D)
2019	$	1.7	$	22.1
2020	6.2		3.9
2021	5.9		3.5
2022	5.2		2.9
2023	5.1		2.9
Thereafter	37.8		37.6
Total future minimum lease payments	61.9		$	72.9
Less: Imputed interest	14.1
Present value of net minimum lease payments	$	47.8

(A) Included in Property, Plant and Equipment in the 2019 Condensed Consolidated Balance Sheet.

(B) Included in Other Deferred Credits and Other Liabilities in the 2019 Condensed Consolidated Balance Sheet.

(C) Amounts included for comparability and accounted for in accordance with ASC 840, "Leases."

(D) At the end of the railcar lease term, which was February 1, 2019, OG&E had the option to either purchase the railcars at a stipulated fair market value or renew the lease. OG&E renewed the lease effective February 1, 2019. If OG&E chose not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars was less than the stipulated fair market value, OG&E would have been responsible for the difference in those values up to a maximum of $16.2 million.

5. Investment in Unconsolidated Affiliates and Related Party Transactions

In 2013, the Company, CenterPoint and the ArcLight group formed Enable as a private limited partnership, and 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 recorded the contribution at historical cost. 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 was allocated to the assets acquired and liabilities assumed based on their fair value. Enogex Holdings' assets, liabilities and equity were accordingly adjusted to estimated fair value, resulting in an increase to Enable's equity of $2.2 billion. Since the contribution of Enogex LLC to Enable was recorded 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. As prior real estate sales accounting guidance was superseded by ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets," the Company recognizes

14

gains or losses on sales or dilution events in the Company's investment in Enable within the Company's earnings, net of proportional basis difference recognition.

At June 30, 2019, the Company owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units. On June 28, 2019, Enable's common unit price closed at $13.71. The Company recorded equity in earnings of unconsolidated affiliates of $35.8 million and $29.3 million for the three months ended June 30, 2019 and 2018, respectively, and $66.5 million and $63.2 million for the six months ended June 30, 2019 and 2018, 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, beginning in 2013, over the average life of the assets to which the basis difference is attributed, which is approximately 30 years. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above. These amortizations may also include gain or loss on dilution, net of proportional basis difference recognition.

Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2019 and December 31, 2018 and for the three and six months ended June 30, 2019 and 2018.

	June 30,		December 31,
Balance Sheet	2019		2018
(In millions)
Current assets	$	376	$	449
Non-current assets	$	12,033	$	11,995
Current liabilities	$	1,270	$	1,615
Non-current liabilities	$	3,580	$	3,211

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Income Statement	2019		2018		2019		2018
(In millions)
Total revenues	$	735	$	805	$	1,530	$	1,553
Cost of natural gas and NGLs	$	317	$	444	$	695	$	819
Operating income	$	167	$	126	$	332	$	265
Net income	$	115	$	86	$	228	$	191

The following table reconciles the Company's equity in earnings of unconsolidated affiliates for the three and six months ended June 30, 2019 and 2018.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2019			2018			2019			2018
Enable net income	$	114.8		$	86.4		$	228.0		$	191.0
Differences due to timing of OGE Energy and Enable accounting close	—			—			0.1			—
Enable net income used to calculate OGE Energy's equity in earnings	$	114.8		$	86.4		$	228.1		$	191.0
OGE Energy's percent ownership at period end	25.5		%	25.6		%	25.5		%	25.6		%
OGE Energy's portion of Enable net income	$	29.3		$	22.2		$	58.2		$	49.0
Amortization of basis difference and dilution recognition (A)	6.5			7.1			8.3			14.2
Equity in earnings of unconsolidated affiliates	$	35.8		$	29.3		$	66.5		$	63.2

(A) Includes loss on dilution, net of proportional basis difference recognition.

15

The following table reconciles the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference) from December 31, 2018 to June 30, 2019.

(In millions)
Basis difference at December 31, 2018	$	680.3
Amortization of basis difference (A)	(13.5		)
Basis difference at June 30, 2019	$	666.8

(A) Includes proportional basis difference recognition due to dilution.

On August 2, 2019, Enable announced a quarterly dividend distribution of $0.33050 per unit on its outstanding common units, which is an increase from the previous quarter's dividend distribution of $0.31800 per unit. 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.

Distributions received from Enable were $35.3 million and $70.6 million during both the three months ended and both the six months ended June 30, 2019 and 2018, respectively.

Related Party Transactions

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.

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 $0.1 million and $0.2 million during the three months ended June 30, 2019 and 2018, respectively, and $0.2 million and $0.3 million during the six months ended June 30, 2019 and 2018, respectively.

Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of June 30, 2019, 85 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $4.0 million and $5.2 million during the three months ended June 30, 2019 and 2018, respectively, and $16.4 million and $16.8 million during the six months ended June 30, 2019 and 2018, 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 $12.0 million. Settlement and curtailment charges associated with the Enable 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 $1.2 million as of June 30, 2019 and $1.7 million as of December 31, 2018, which are included in Accounts Receivable in the Company's Condensed Consolidated Balance Sheets.

16

OG&E and Enable

As discussed in the Company's 2018 Form 10-K, Enable provides gas transportation services to OG&E pursuant to an agreement that grants Enable the responsibility of delivering natural gas to OG&E's generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable's deliveries exceed OG&E's pipeline receipts. Enable purchases gas from OG&E when OG&E's pipeline receipts exceed Enable's deliveries. The following table summarizes related party transactions between OG&E and Enable during the three and six months ended June 30, 2019 and 2018.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2019			2018		2019			2018
Operating revenues:
Electricity to power electric compression assets	$	3.8		$	3.6	$	7.6		$	7.6
Cost of sales:
Natural gas transportation services	$	9.3		$	8.8	$	24.1		$	17.5
Natural gas (sales) purchases	$	(3.3	)	$	2.2	$	(4.3	)	$	2.5

6. Fair Value Measurements

The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1), and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows:

Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.

Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.  

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). 

The Company had no financial instruments measured at fair value on a recurring basis at June 30, 2019 and December 31, 2018. The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy, with the exception of the Tinker Debt which is classified as Level 3 in the fair value hierarchy as its fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate. The following table summarizes the fair value and carrying amount of the Company's financial instruments at June 30, 2019 and December 31, 2018.

	June 30,				December 31,
	2019				2018
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term Debt (including Long-term Debt due within one year):
Senior Notes	$	3,048.6	$	3,428.0	$	3,001.9	$	3,178.2
OG&E Industrial Authority Bonds	$	135.4	$	135.4	$	135.4	$	135.4
Tinker Debt	$	9.6	$	9.3	$	9.6	$	8.7

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7. Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three and six months ended June 30, 2019 and 2018 related to the Company's performance units and restricted stock.

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2019		2018		2019		2018
Performance units:
Total shareholder return	$	2.3	$	2.1	$	4.5	$	4.1
Earnings per share	0.4		1.0		0.9		1.7
Total performance units	2.7		3.1		5.4		5.8
Restricted stock	0.2		—		0.5		—
Total compensation expense	$	2.9	$	3.1	$	5.9	$	5.8
Income tax benefit	$	0.7	$	0.8	$	1.5	$	1.5

During the three and six months ended June 30, 2019, the Company issued an immaterial amount of shares and 443,497 shares, respectively, of new common stock pursuant to the Company's Stock Incentive Plan to satisfy restricted stock grants and payouts of earned performance units.

8. Income Taxes

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, state and local tax examinations by tax authorities for years prior to 2015. 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 will be 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.

9. Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and six months ended June 30, 2019.  

Earnings Per Share

Basic earnings per share is calculated by dividing net income attributable to the Company by the weighted-average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted-average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units and restricted stock units. The following table calculates basic and diluted earnings per share for the Company.

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions except per share data)	2019		2018		2019		2018
Net income	$	100.2	$	110.7	$	147.3	$	165.7
Average common shares outstanding:
Basic average common shares outstanding	200.2		199.7		200.1		199.7
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.4		0.8		0.4		0.6
Diluted average common shares outstanding	200.6		200.5		200.5		200.3
Basic earnings per average common share	$	0.50	$	0.55	$	0.74	$	0.83
Diluted earnings per average common share	$	0.50	$	0.55	$	0.73	$	0.83
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

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10. Long-Term Debt

At June 30, 2019, 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)
1.46%	-	2.50%	Garfield Industrial Authority, January 1, 2025	$	47.0
1.43%	-	2.35%	Muskogee Industrial Authority, January 1, 2025	32.4
1.45%	-	2.48%	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 Balance Sheets. OG&E believes that it has sufficient liquidity to meet these obligations.

Issuance of Long-Term Debt

In June 2019, OG&E issued $300.0 million of 3.30 percent senior notes due March 15, 2030. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to repay short-term debt (including debt pertaining to the acquisition of the River Valley plant) and to fund ongoing capital expenditures and working capital.

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11. Short-Term Debt and Credit Facilities

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. As of June 30, 2019, the Company had $207.5 million of short-term debt as compared to no short-term debt at December 31, 2018. The following table provides information regarding the Company's revolving credit agreements at June 30, 2019.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
(In millions)
OGE Energy (B)	$	450.0	$	207.5	2.63	%	(D)	March 8, 2023
OG&E (C)	450.0		0.3		1.15	%	(D)	March 8, 2023
Total	$	900.0	$	207.8	2.63	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2019.

(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.

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, 2019 and ending December 31, 2020.

12. 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 six months of 2019, 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, which resulted in the Company recording a pension settlement charge of $20.6 million. 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.

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Net Periodic Benefit Cost

The following table presents 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 Expense in 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 Expense in the Company's Condensed Consolidated Statements of Income.

	Pension Plan												Restoration of Retirement Income Plan
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
(In millions)	2019 (A)			2018 (A)			2019 (B)			2018 (B)			2019 (A)		2018 (A)		2019 (B)		2018 (B)
Service cost	$	2.8		$	3.4		$	6.3		$	7.5		$	0.1	$	0.1	$	0.2	$	0.2
Interest cost	5.2			5.8			10.9			11.7			0.1		0.1		0.2		0.2
Expected return on plan assets	(8.9		)	(11.0		)	(17.6		)	(22.3		)	—		—		—		—
Amortization of net loss	4.8			4.4			8.6			8.3			0.1		0.3		0.2		0.4
Settlement cost	0.9			—			20.6			—			—		—		—		—
Total net periodic benefit cost	4.8			2.6			28.8			5.2			0.3		0.5		0.6		0.8
Less: Amount paid by unconsolidated affiliates	0.8			0.7			1.7			1.2			—		—		—		—
Net periodic benefit cost	$	4.0		$	1.9		$	27.1		$	4.0		$	0.3	$	0.5	$	0.6	$	0.8

(A) In addition to the $4.3 million and $2.4 million of net periodic benefit cost recognized during the three months ended June 30, 2019 and 2018, respectively, the Company recognized a decrease of pension expense of $0.7 million and an increase of $3.8 million during the three months ended June 30, 2019 and 2018, 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).

(B) In addition to the $27.7 million and $4.8 million of net periodic benefit cost recognized during the six months ended June 30, 2019 and 2018, respectively, the Company recognized the following:

• a decrease of pension expense of $1.7 million and an increase of $7.8 million during the six months ended June 30, 2019 and 2018, 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 six months ended June 30, 2019 of $11.7 million related to the pension settlement charge of $20.6 million in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during the six months ended June 30, 2019 of $1.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $20.6 million (see Note 1).

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	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2019 (B)			2018 (B)			2019 (C)			2018 (C)
Service cost	$	—		$	0.1		$	0.1		$	0.2
Interest cost	1.4			1.3			2.8			2.6
Expected return on plan assets	(0.4		)	(0.5		)	(0.9		)	(1.0		)
Amortization of net loss	0.4			0.9			1.0			1.9
Amortization of unrecognized prior service cost (A)	(2.1		)	(2.1		)	(4.2		)	(4.2		)
Total net periodic benefit cost	(0.7		)	(0.3		)	(1.2		)	(0.5		)
Less: Amount paid by unconsolidated affiliates	(0.1		)	(0.1		)	(0.3		)	(0.2		)
Net periodic benefit cost	$	(0.6	)	$	(0.2	)	$	(0.9	)	$	(0.3	)

(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 $0.6 million and $0.2 million of net periodic benefit income recognized during the three months ended June 30, 2019 and 2018, respectively, the Company recognized an increase in postretirement medical expense during the three months ended June 30, 2019 and 2018 of $0.5 million and $2.2 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 $0.9 million and $0.3 million of net periodic benefit income recognized during the six months ended June 30, 2019 and 2018, respectively, the Company recognized an increase in postretirement medical expense during the six months ended June 30, 2019 and 2018 of $0.8 million and $4.3 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).

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2019		2018		2019		2018
Capitalized portion of net periodic pension benefit cost	$	0.8	$	0.9	$	1.8	$	1.9
Capitalized portion of net periodic postretirement benefit cost	$	—	$	0.1	$	0.1	$	0.1

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13. Report of Business Segments

The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy and (ii) the natural gas midstream operations segment. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. The following tables summarize the results of the Company's business segments during the three and six months ended June 30, 2019 and 2018.

Three Months Ended June 30, 2019	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	513.7	$	—		$	—		$	—		$	513.7
Cost of sales	178.7		—			—			—			178.7
Other operation and maintenance	120.0		0.3			(0.5		)	—			119.8
Depreciation and amortization	84.3		—			—			—			84.3
Taxes other than income	20.1		0.1			0.7			—			20.9
Operating income (loss)	110.6		(0.4		)	(0.2		)	—			110.0
Equity in earnings of unconsolidated affiliates	—		35.8			—			—			35.8
Other income (expense)	1.5		(0.4		)	1.0			(0.6		)	1.5
Interest expense	33.3		—			3.2			(0.6		)	35.9
Income tax expense (benefit)	4.3		8.1			(1.2		)	—			11.2
Net income (loss)	$	74.5	$	26.9		$	(1.2	)	$	—		$	100.2
Investment in unconsolidated affiliates	$	—	$	1,157.2		$	14.1		$	—		$	1,171.3
Total assets	$	9,733.8	$	1,160.0		$	104.5		$	(112.1	)	$	10,886.2

Three Months Ended June 30, 2018	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	567.0	$	—		$	—		$	—		$	567.0
Cost of sales	208.7		—			—			—			208.7
Other operation and maintenance	117.5		0.3			(0.6		)	—			117.2
Depreciation and amortization	80.9		—			—			—			80.9
Taxes other than income	21.6		0.2			0.7			—			22.5
Operating income (loss)	138.3		(0.5		)	(0.1		)	—			137.7
Equity in earnings of unconsolidated affiliates	—		29.3			—			—			29.3
Other income (expense)	4.0		—			(0.6		)	(0.9		)	2.5
Interest expense	39.2		—			2.6			(0.9		)	40.9
Income tax expense	11.1		6.7			0.1			—			17.9
Net income (loss)	$	92.0	$	22.1		$	(3.4	)	$	—		$	110.7
Investment in unconsolidated affiliates	$	—	$	1,144.6		$	9.0		$	—		$	1,153.6
Total assets	$	9,447.8	$	1,147.9		$	95.6		$	(147.7	)	$	10,543.6

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Six Months Ended June 30, 2019	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,003.7	$	—		$	—		$	—		$	1,003.7
Cost of sales	391.3		—			—			—			391.3
Other operation and maintenance	240.3		0.7			(2.2		)	—			238.8
Depreciation and amortization	166.7		—			—			—			166.7
Taxes other than income	44.5		0.3			2.4			—			47.2
Operating income (loss)	160.9		(1.0		)	(0.2		)	—			159.7
Equity in earnings of unconsolidated affiliates	—		66.5			—			—			66.5
Other income (expense)	4.1		(7.8		)	1.7			(1.0		)	(3.0		)
Interest expense	65.7		—			5.8			(1.0		)	70.5
Income tax expense (benefit)	5.2		9.5			(9.3		)	—			5.4
Net income	$	94.1	$	48.2		$	5.0		$	—		$	147.3
Investment in unconsolidated affiliates	$	—	$	1,157.2		$	14.1		$	—		$	1,171.3
Total assets	$	9,733.8	$	1,160.0		$	104.5		$	(112.1	)	$	10,886.2

Six Months Ended June 30, 2018	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,059.7	$	—		$	—		$	—		$	1,059.7
Cost of sales	419.2		—			—			—			419.2
Other operation and maintenance	231.1		0.6			(1.8		)	—			229.9
Depreciation and amortization	159.7		—			—			—			159.7
Taxes other than income	44.3		0.4			1.9			—			46.6
Operating income (loss)	205.4		(1.0		)	(0.1		)	—			204.3
Equity in earnings of unconsolidated affiliates	—		63.2			—			—			63.2
Other income (expense)	8.5		—			(1.3		)	(1.5		)	5.7
Interest expense	76.5		—			4.5			(1.5		)	79.5
Income tax expense (benefit)	14.1		16.5			(2.6		)	—			28.0
Net income (loss)	$	123.3	$	45.7		$	(3.3	)	$	—		$	165.7
Investment in unconsolidated affiliates	$	—	$	1,144.6		$	9.0		$	—		$	1,153.6
Total assets	$	9,447.8	$	1,147.9		$	95.6		$	(147.7	)	$	10,543.6

14. Commitments and Contingencies

Except as set forth below, in Note 15 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 14 and 15 to the Consolidated Financial Statements included in the Company's 2018 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 2018 Form 10-K, OG&E has a QF contract with Oklahoma Cogeneration LLC which expires on August 31, 2019. For this 120 MW contract, OG&E purchases 100 percent of the electricity generated. OG&E also had a 320 MW contract with AES that expired on January 15, 2019, through which OG&E purchased 100 percent of the electricity generated.

In December 2018, OG&E announced its plan to acquire power plants from AES and Oklahoma Cogeneration LLC, pending regulatory approval, to meet customers' energy needs. In May 2019, OG&E received the necessary approval from the OCC and the FERC and conditional approval from the APSC to acquire both plants. In May 2019, OG&E acquired the power

24

plant from AES and expects to acquire the plant from Oklahoma Cogeneration LLC in the third quarter of 2019. Further discussion can be found in Note 15.

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. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.

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 have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

15. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 15 to the Consolidated Financial Statements included in the Company's 2018 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

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 in October 2018. On March 6, 2019, the APSC approved a settlement agreement for a $3.3 million revenue increase, and new rates were effective as of April 1, 2019.

OCC and FERC Approval for Acquisition of Existing Power Plants

In December 2018, OG&E filed an application for pre-approval from the OCC to acquire a 360 MW capacity coal- and natural gas-fired plant from AES and a 146 MW capacity natural gas-fired combined-cycle plant from Oklahoma Cogeneration LLC in 2019 for $53.5 million. The purchase of these assets replaces capacity provided by purchased power contracts that have expired or are expiring in 2019 and helps OG&E satisfy its customers' energy needs and load obligations to the SPP. In addition, the filing sought approval of a rider mechanism to collect costs associated with the purchase of these generating facilities. On May 13, 2019, the OCC approved OG&E's acquisition of both plants, the requested rider mechanism for the AES plant and regulatory asset treatment for the Oklahoma Cogeneration LLC plant that will defer non-fuel operation and maintenance expenses, depreciation and ad valorem taxes.

On January 23, 2019, OG&E filed an application for Federal Power Act Section 203 approval with a request for expedited consideration. This application requested FERC's prior authorization to acquire the AES and Oklahoma Cogeneration LLC plants. On May 22, 2019, OG&E received authorization from the FERC to acquire both plants.

In May 2019, OG&E completed the acquisition of the power plant from AES and placed it into service, which is now named the River Valley power plant. Closing for the acquisition of the power plant from Oklahoma Cogeneration LLC is anticipated during the third quarter of 2019.

25

Fuel Adjustment Clause Review for Calendar Year 2017

In July 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. On February 1, 2019, the ALJ recommended that OG&E's processes, costs, investments and decisions regarding fuel procurement for the 2017 calendar year be found prudent. On May 22, 2019, the OCC deemed OG&E's electric generation, purchased power and fuel procurement costs to be materially prudent.

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.

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. 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. In May 2019, all parties agreed to a settlement which provides for 10 percent base return on equity, plus a 50-basis point adder, and a five-year amortization period of the unprotected excess accumulated deferred income taxes associated with the 2017 Tax Act. While pending approval by the FERC, interim rates are currently being applied by the SPP pursuant to the terms of the settlement agreement.

Oklahoma Rate Review Filing - December 2018

In December 2018, OG&E filed a general rate review with the OCC, requesting a rate increase of $77.6 million per year to recover its investment in the Dry Scrubbers project and in the conversion of Muskogee Units 4 and 5 to natural gas. The filing also sought to align OG&E's return on equity more closely to the industry average and to align OG&E's depreciation rates to more realistically reflect its assets' lifespans.

On May 24, 2019, OG&E entered into a non-unanimous joint stipulation and settlement agreement with the OCC staff, the Attorney General's Office of Oklahoma, the Oklahoma Industrial Energy Consumers and other certain parties associated with the requested rate increase. The filing was further amended on May 30, 2019 to include Oklahoma Association of Electric Cooperatives as a settling party. The settlement is subject to OCC approval. Under the terms of the settlement agreement, OG&E would receive full recovery of its environmental investments in the Dry Scrubbers project and in the conversion of Muskogee Units 4 and 5 to natural gas. Base rates would not change as a result of the settlement agreement due to the reduction of costs related to cogeneration contracts and the acceleration of unprotected deferred tax savings over a 10-year period. Further, OG&E's current depreciation rates and return on equity of 9.5 percent for purposes of calculating the allowance for funds used during construction and OG&E's various recovery riders that include a full return component would remain unchanged.

On July 1, 2019, OG&E implemented interim rates, which are subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate review.

On July 12, 2019, the ALJ issued a report that recommended approval of the settlement agreement and found the settlement agreement fair, just, reasonable and in the public interest. The ALJ's report also recommended that OG&E's environmental compliance decisions and costs related to the Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas be found prudent and used and useful with cost recovery allowed. These recommendations are subject to approval by the OCC. A hearing on exceptions was held on August 6, 2019, and OG&E is awaiting a final order from the OCC.

The Dry Scrubbers project, which includes the installation of two dry scrubbers at the Sooner plant, and the conversion of Muskogee Units 4 and 5 to natural gas were initiated in response to the EPA's MATS and Regional Haze Rule FIP. The Dry Scrubber systems on Sooner Unit 1 and Unit 2 were placed into service in October 2018 and January 2019, respectively. Muskogee Units 4 and 5 were placed into service in March 2019. As of June 30, 2019, OG&E has invested $512.4 million in the Dry Scrubbers and $57.0 million in the Muskogee natural gas conversion.

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FERC Order for Sponsored Transmission Upgrades within SPP

Under the SPP Open Access Transmission Tariff, costs of participant-funded, or "sponsored," transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP Open Access Transmission Tariff allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades due to information system limitations. However, SPP had informed participants in the market that these charges would be forthcoming. In July 2016, the FERC granted SPP's request to recover the charges not billed since 2008. SPP subsequently billed OG&E for these charges and credited OG&E related to transmission upgrades that OG&E had sponsored, which resulted in OG&E being a net receiver of sponsored upgrade credits. The majority of these net credits were refunded to customers through OG&E's various rate riders that include SPP activity with the remaining amounts retained by OG&E.

Several impacted companies sought rehearing of the FERC's July 2016 order; however, in November 2017, the FERC denied the rehearing requests. In January 2018, one of the impacted companies appealed the FERC's decision to the U.S. Court of Appeals for the District of Columbia. In July 2018, the U.S. Court of Appeals for the District of Columbia granted a motion requested by the FERC that the case be remanded back to the FERC for further examination and proceedings. In February 2019, the FERC reversed its July 2016 order and ordered SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, on April 1, 2019, OG&E filed a request for rehearing with the FERC, and on May 24, 2019, OG&E filed a FERC 206 complaint against SPP, alleging SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement. OG&E's filing requested that the FERC rule that SPP is not entitled to seek refunds or in any other way seek to unwind the revenue credit payments it had paid to OG&E pursuant to the Sponsored Upgrade Agreement.

The Company cannot predict the outcome of this proceeding based on currently available information, and as of June 30, 2019 and at present time, the Company has not reserved an amount for a potential refund. If the reversal of the July 2016 FERC order remains intact, OG&E estimates it would be required to refund $13.0 million, which is net of amounts paid to other utilities for upgrades and would be subject to interest at the FERC-approved rate. If refunds were required, recovery of these upgrade credits would shift to future periods. Of the $13.0 million, the Company would be impacted by $5.0 million in expense that initially benefited the Company in 2016, and OG&E customers would incur a net impact of $8.0 million in expense through rider mechanisms or the FERC formula rate.

Fuel Adjustment Clause Review for Calendar Year 2018

In June 2019, the OCC staff filed an application to review OG&E's fuel adjustment clause for the calendar year 2018, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs.

APSC - Environmental Compliance Plan Rider

On May 31, 2019, OG&E filed an environmental compliance plan rider in Arkansas to recover its investment for the environmentally mandated costs associated with the Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas. The filing is an interim surcharge, subject to refund, that began with the first billing cycle of June 2019. OG&E is reserving the amounts collected through the interim surcharge, pending APSC approval of OG&E's filing.

APSC Approval for Acquisition of Existing Power Plants

On April 24, 2019, OG&E filed an application with the APSC requesting approval of the acquisition, as well as depreciation rates, of the AES and Oklahoma Cogeneration LLC plants, and on May 8, 2019, OG&E received conditional approval for the purchase of the generating facilities. Issues related to depreciation rates and prudence of action will continue to be addressed in the existing docket. Issues regarding prudence of cost may be addressed in the existing docket or in the Formula Rate Plan.

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

Introduction

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.

The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries and ultimately OGE Holdings. Enable was formed in 2013, and its general partner 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 accounts for its interest in Enable using the equity method of accounting. Enable is primarily 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 in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama. As disclosed in the Company's 2018 Form 10-K, 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, NGLs 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 the Company's 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 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.

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Summary of Operating Results

Three Months Ended June 30, 2019 as compared to Three Months Ended June 30, 2018

Net income was $100.2 million, or $0.50 per diluted share, during the three months ended June 30, 2019 as compared to $110.7 million, or $0.55 per diluted share, during the same period in 2018. The decrease in net income of $10.5 million, or $0.05 per diluted share, is further discussed below.

• A decrease in net income at OG&E of $17.5 million, or $0.09 per diluted share of the Company's common stock, was primarily due to lower gross margin (driven by unfavorable weather and lower rates primarily resulting from lower income tax expense), higher depreciation and amortization expense due to additional assets being placed into service and higher other operation and maintenance expense. This decrease was partially offset by lower income tax expense and lower interest expense.

• An increase in net income at OGE Holdings of $4.8 million, or $0.02 per diluted share of the Company's common stock, was primarily due to higher equity in earnings of Enable driven by increased net income from Enable's gathering and processing business resulting from gains on commodity derivative activity and higher natural gas gathering fees and gathered volumes, partially offset by higher income tax expense.

• An increase in net income of other operations of $2.2 million, or $0.02 per diluted share of the Company's common stock, was primarily due to higher other income and higher income tax benefit, partially offset by higher interest expense.

Six Months Ended June 30, 2019 as compared to Six Months Ended June 30, 2018

Net income was $147.3 million, or $0.73 per diluted share, during the six months ended June 30, 2019 as compared to $165.7 million, or $0.83 per diluted share, during the same period in 2018. The decrease in net income of $18.4 million, or $0.10 per diluted share, is further discussed below.

• A decrease in net income at OG&E of $29.2 million, or $0.15 per diluted share of the Company's common stock, was primarily due to lower gross margin (driven by unfavorable weather and lower rates primarily resulting from lower income tax expense), lower allowance for equity funds used during construction due to certain environmental projects being completed and placed into service, higher other operation and maintenance expense and higher depreciation and amortization expense due to additional assets being placed into service. This decrease was partially offset by lower interest expense, lower other net periodic benefit expense and lower income tax expense.

• An increase in net income of other operations of $8.3 million, or $0.04 per diluted share of the Company's common stock, was primarily due to higher income tax benefit related to higher stock-based compensation payouts in 2019 and higher other income, partially offset by higher interest expense.

• An increase in net income at OGE Holdings of $2.5 million, or $0.01 per diluted share of the Company's common stock, was primarily due to lower income tax expense due to favorable state tax rate adjustments and higher equity in earnings of Enable driven by increased net income from Enable's gathering and processing business resulting from higher processed volumes and higher natural gas gathering fees and gathered volumes, partially offset by higher other expense due to higher pension settlement charges for seconded Enable employees.

Recent Developments and Regulatory Matters

Further discussion can be found in Note 15 within "Item 1. Financial Statements."

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 in October 2018. On March 6, 2019, the APSC approved a settlement agreement for a $3.3 million revenue increase, and new rates were effective as of April 1, 2019.

Approval for Acquisition of Existing Power Plants

In May 2019, OG&E received approval from both the OCC and the FERC to acquire plants from AES and Oklahoma Cogeneration LLC. The OCC approved OG&E's acquisition price of $53.5 million, the requested rider mechanism for the AES plant and regulatory asset treatment for the Oklahoma Cogeneration LLC plant that will defer non-fuel operation and maintenance expenses, depreciation and ad valorem taxes. OG&E received conditional approval from the APSC to acquire both plants, and

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issues related to depreciation rates and prudence of action will continue to be addressed in the existing docket, while issues regarding prudence of cost may be addressed in the existing docket or in the Formula Rate Plan.

OG&E completed the acquisition of the power plant from AES and placed it into service in May 2019, which is now named the River Valley power plant. Closing for the acquisition of the power plant from Oklahoma Cogeneration LLC is anticipated during the third quarter of 2019.

FERC - Section 206 Filing

In May 2019, OG&E and the Oklahoma Municipal Power Authority agreed to a settlement regarding OG&E's formula transmission rates under the SPP Open Access Tariff which provides for 10 percent base return on equity, plus a 50-basis point adder, and a five-year amortization period of the unprotected excess accumulated deferred income taxes associated with the 2017 Tax Act. While pending approval by the FERC, interim rates are currently being applied by the SPP pursuant to the terms of the settlement agreement.

Oklahoma Rate Review Filing - December 2018

In May 2019, OG&E entered into a non-unanimous joint stipulation and settlement agreement regarding OG&E's general rate review request with the OCC staff, the Attorney General's Office of Oklahoma and other certain parties associated with the requested rate increase. The settlement is subject to OCC approval. Under the terms of the settlement agreement, OG&E would receive full recovery of its environmental investments in the Dry Scrubbers project and in the conversion of Muskogee Units 4 and 5 to natural gas. Base rates would not change as a result of the settlement agreement due to the reduction of costs related to cogeneration contracts and the acceleration of unprotected deferred tax savings over a 10-year period. Further, OG&E's current depreciation rates and return on equity of 9.5 percent for purposes of calculating the allowance for funds used during construction and OG&E's various recovery riders that include a full return component would remain unchanged.

In July 2019, OG&E implemented interim rates, which are subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate review. Recommendations made by the ALJ are subject to approval by the OCC. A hearing on the exceptions was held in August 2019, and OG&E is awaiting a final order from the OCC.

APSC - Environmental Compliance Plan Rider

In May 2019, OG&E filed an environmental compliance plan rider in Arkansas to recover its investment for the environmentally mandated costs associated with the Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas. The filing is an interim surcharge, subject to refund, that began with the first billing cycle of June 2019. OG&E is reserving the amounts collected through the interim surcharge, pending APSC approval of OG&E's filing.

2019 Outlook

The Company's 2019 earnings contribution from its ownership interest in Enable is projected to be at the lower end of the previously issued earnings guidance of approximately $104 million to $117 million of net income, or $0.52 to $0.58 per average diluted share, due to lower forecasted commodity prices. The Company's consolidated 2019 earnings guidance remains unchanged and is between $412 million to $442 million of net income, or $2.05 to $2.20 per average diluted share. The guidance assumes, among other things, approximately 201 million average diluted shares outstanding and normal weather for the year. See the Company's 2018 Form 10-K for other key factors and assumptions underlying its 2019 earnings guidance.

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 six months ended June 30, 2019 and 2018, see "OG&E (Electric Utility) Results of Operations" below.

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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 Enable sells. 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 six months ended June 30, 2019 and 2018, 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 six months ended June 30, 2019 as compared to the same periods in 2018 and the Company's consolidated financial position at June 30, 2019. Due to seasonal fluctuations and other factors, the Company's operating results for the three and six months ended June 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 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				Six Months Ended
	June 30,				June 30,
(In millions except per share data)	2019		2018		2019		2018
Net income	$	100.2	$	110.7	$	147.3	$	165.7
Basic average common shares outstanding	200.2		199.7		200.1		199.7
Diluted average common shares outstanding	200.6		200.5		200.5		200.3
Basic earnings per average common share	$	0.50	$	0.55	$	0.74	$	0.83
Diluted earnings per average common share	$	0.50	$	0.55	$	0.73	$	0.83
Dividends declared per common share	$	0.36500	$	0.33250	$	0.73000	$	0.66500

Results by Business Segment

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2019			2018			2019		2018
Net income:
OG&E (Electric Utility)	$	74.5		$	92.0		$	94.1	$	123.3
OGE Holdings (Natural Gas Midstream Operations)	26.9			22.1			48.2		45.7
Other operations (A)	(1.2		)	(3.4		)	5.0		(3.3		)
Consolidated net income	$	100.2		$	110.7		$	147.3	$	165.7

(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. 

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OG&E (Electric Utility)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Dollars in millions)	2019			2018			2019			2018
Operating revenues	$	513.7		$	567.0		$	1,003.7		$	1,059.7
Cost of sales	178.7			208.7			391.3			419.2
Other operation and maintenance	120.0			117.5			240.3			231.1
Depreciation and amortization	84.3			80.9			166.7			159.7
Taxes other than income	20.1			21.6			44.5			44.3
Operating income	110.6			138.3			160.9			205.4
Allowance for equity funds used during construction	1.2			6.3			2.7			13.3
Other net periodic benefit income (expense)	—			(5.2		)	0.4			(10.0		)
Other income	1.1			3.5			2.5			6.6
Other expense	0.8			0.6			1.5			1.4
Interest expense	33.3			39.2			65.7			76.5
Income tax expense	4.3			11.1			5.2			14.1
Net income	$	74.5		$	92.0		$	94.1		$	123.3
Operating revenues by classification:
Residential	$	186.6		$	226.2		$	382.0		$	428.3
Commercial	119.8			140.9			220.1			246.6
Industrial	54.3			58.5			107.9			110.4
Oilfield	49.9			46.7			100.1			89.5
Public authorities and street light	45.8			53.0			87.3			96.5
Sales for resale	0.1			—			0.1			0.1
System sales revenues	456.5			525.3			897.5			971.4
Provision for rate refund	(0.5		)	(16.5		)	(0.6		)	(19.7		)
Integrated market	10.3			13.2			17.0			21.8
Transmission	39.8			40.2			75.9			76.0
Other	7.6			4.8			13.9			10.2
Total operating revenues	$	513.7		$	567.0		$	1,003.7		$	1,059.7
Reconciliation of gross margin to revenue:
Operating revenues	$	513.7		$	567.0		$	1,003.7		$	1,059.7
Cost of sales	178.7			208.7			391.3			419.2
Gross margin	$	335.0		$	358.3		$	612.4		$	640.5
MWh sales by classification (In millions)
Residential	2.0			2.3			4.4			4.7
Commercial	1.5			1.9			2.9			3.3
Industrial	1.2			1.1			2.3			2.1
Oilfield	1.2			1.0			2.4			2.0
Public authorities and street light	0.7			0.8			1.4			1.5
System sales	6.6			7.1			13.4			13.6
Integrated market	0.3			0.3			0.6			0.6
Total sales	6.9			7.4			14.0			14.2
Number of customers	853,500			845,244			853,500			845,244
Weighted-average cost of energy per kilowatt-hour (In cents)
Natural gas	2.113			2.338			2.527			2.475
Coal	2.067			2.058			1.993			2.028
Total fuel	1.909			2.047			2.118			2.058
Total fuel and purchased power	2.471			2.721			2.672			2.827
Degree days (A)
Heating - Actual	197			328			2,277			2,208
Heating - Normal	204			203			2,004			2,001
Cooling - Actual	481			776			481			786
Cooling - Normal	626			625			639			638

(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.

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OG&E's net income decreased $17.5 million, or 19.0 percent, and $29.2 million, or 23.7 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. The decrease during the three months ended June 30, 2019 was primarily due to lower gross margin, higher depreciation and amortization expense and higher other operation and maintenance expense, partially offset by lower income tax expense and lower interest expense. The decrease during the six months ended June 30, 2019 was primarily due to lower gross margin, lower allowance for equity funds used during construction, higher other operation and maintenance expense and higher depreciation and amortization expense, partially offset by lower interest expense, lower other net periodic benefit expense and lower income tax expense.

Gross margin decreased $23.3 million, or 6.5 percent, and $28.1 million, or 4.4 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. The below factors contributed to the changes in gross margin.

	$ Change
(In millions)	Three Months Ended			Six Months Ended
Weather (price and quantity) (A)	$	(23.9	)	$	(20.8	)
Price variance (B)	(4.0		)	(14.4		)
Non-residential demand and related revenue	(1.2		)	(2.4		)
New customer growth	2.6			4.7
Other	3.2			4.8
Change in gross margin	$	(23.3	)	$	(28.1	)

(A) Decreased primarily due to an approximately 39 percent decrease in cooling degree days for both the three and six months ended June 30, 2019.

(B) Decreased primarily due the implementation of new rate design, which included moving production tax credits from base rates into a rider mechanism and reflecting lower income tax expense within base rates resulting from 2017 Tax Act impacts.

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 $30.0 million, or 14.4 percent, and $27.9 million, or 6.7 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. The below factors contributed to the changes in cost of sales.

	$ Change						% Change
(In millions)	Three Months Ended			Six Months Ended			Three Months Ended		Six Months Ended
Fuel expense (A)	$	(26.9	)	$	(12.9	)	(28.6	)%	(7.6	)%
Purchased power costs:
Purchases from SPP (B)	21.5			33.0			42.3	%	27.1	%
Cogeneration (C)	(21.0		)	(39.3		)	(82.5	)%	(77.1	)%
Wind (D)	(3.4		)	(7.7		)	(18.4	)%	(22.0	)%
Transmission expense (E)	(0.2		)	(1.0		)	(1.2	)%	(2.6	)%
Change in cost of sales	$	(30.0	)	$	(27.9	)

(A) Decreased primarily due to lower fuel costs related to the generating assets utilized during the three and six months ended June 30, 2019.

(B) Increased primarily due to a 47.2 percent and 30.8 percent increase in MWhs purchased for the three and six months ended June 30, 2019, respectively.

(C) Decreased primarily due to the expiration of the AES cogeneration contract in January 2019, as discussed in Note 14 within "Item 1. Financial Statements."

(D) Decreased due to a 30.9 percent decrease in MWs purchased during both the three and six months ended June 30, 2019.

(E) Decreased primarily due to lower SPP charges for the base plan projects of other utilities.

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Other operation and maintenance expense increased $2.5 million, or 2.1 percent, and $9.2 million, or 4.0 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. The below factors contributed to the changes in other operation and maintenance expense.

	$ Change					% Change
(In millions)	Three Months Ended			Six Months Ended		Three Months Ended		Six Months Ended
Contract technical and construction services (A)	$	4.3		$	7.6	41.3	%	41.1	%
Other	(1.8		)	1.6		1.7	%	0.8	%
Change in other operation and maintenance expense	$	2.5		$	9.2

(A) Increased primarily due to the timing of work performed.

Depreciation and amortization expense increased $3.4 million, or 4.2 percent, and $7.0 million, or 4.4 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018, primarily due to additional assets being placed into service.

Allowance for equity funds used during construction decreased $5.1 million, or 81.0 percent, and $10.6 million, or 79.7 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018, 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 $5.2 million, or 100.0 percent, and $10.4 million during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018, primarily due to lower pension costs reflected in base rates as a result of the most recent Oklahoma rate review settlement in June 2018.

Other income decreased $2.4 million, or 68.6 percent, and $4.1 million, or 62.1 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018, primarily due to a decrease in the tax gross-up related to lower allowance for funds used during construction.

Interest on long-term debt decreased $7.9 million, or 19.9 percent, and $14.9 million, or 18.8 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018, primarily due to the timing of higher interest rate debt maturing and being replaced with lower interest rate debt and due to the deferral of interest expense for the Sooner Dry Scrubbers to a regulatory asset, as disclosed in Note 1 within "Item 1. Financial Statements."

Allowance for borrowed funds used during construction decreased $2.2 million, or 78.6 percent, and $4.9 million, or 75.4 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018, primarily due to lower construction work in progress balances resulting from certain environmental projects being completed and placed into service.

Income tax expense decreased $6.8 million, or 61.3 percent, and $8.9 million, or 63.1 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. The decrease during the three months ended June 30, 2019 was primarily due to lower pretax income, partially offset by lower tax credits. The decrease during the six months ended June 30, 2019 was primarily due to lower pretax income and an increase in the amortization of net refundable deferred taxes, partially offset by lower tax credits.

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OGE Holdings (Natural Gas Midstream Operations)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Operating revenues	$	—		$	—		$	—		$	—
Cost of sales	—			—			—			—
Other operation and maintenance	0.3			0.3			0.7			0.6
Taxes other than income	0.1			0.2			0.3			0.4
Operating loss	(0.4		)	(0.5		)	(1.0		)	(1.0		)
Equity in earnings of unconsolidated affiliates	35.8			29.3			66.5			63.2
Other expense	0.4			—			7.8			—
Income before taxes	35.0			28.8			57.7			62.2
Income tax expense	8.1			6.7			9.5			16.5
Net income attributable to OGE Holdings	$	26.9		$	22.1		$	48.2		$	45.7

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 six months ended June 30, 2019 and 2018.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2019			2018			2019			2018
Enable net income	$	114.8		$	86.4		$	228.0		$	191.0
Differences due to timing of OGE Energy and Enable accounting close	—			—			0.1			—
Enable net income used to calculate OGE Energy's equity in earnings	$	114.8		$	86.4		$	228.1		$	191.0
OGE Energy's percent ownership at period end	25.5		%	25.6		%	25.5		%	25.6		%
OGE Energy's portion of Enable net income	$	29.3		$	22.2		$	58.2		$	49.0
Amortization of basis difference and dilution recognition (A)	6.5			7.1			8.3			14.2
Equity in earnings of unconsolidated affiliates	$	35.8		$	29.3		$	66.5		$	63.2

(A) Includes loss on dilution, net of proportional basis difference recognition.

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. These amortizations may also include gain or loss on dilution, net of proportional basis difference recognition.

The following table reconciles the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference) from December 31, 2018 to June 30, 2019.

(In millions)
Basis difference at December 31, 2018	$	680.3
Amortization of basis difference (A)	(13.5		)
Basis difference at June 30, 2019	$	666.8

(A) Includes proportional basis difference recognition due to dilution.

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Enable Results of Operations and Operating Data

The following table presents summarized financial information of Enable for the three and six months ended June 30, 2019 and 2018.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2019		2018		2019		2018
Reconciliation of gross margin to revenue:
Total revenues	$	735	$	805	$	1,530	$	1,553
Cost of natural gas and NGLs	317		444		695		819
Gross margin	$	418	$	361	$	835	$	734
Operating income	$	167	$	126	$	332	$	265
Net income	$	115	$	86	$	228	$	191

The following table presents Enable's operating data for the three and six months ended June 30, 2019 and 2018.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
Natural gas gathered volumes - TBtu/d	4.62	4.43	4.58	4.35
Transported volumes - TBtu/d	6.04	5.28	6.36	5.53
Natural gas processed volumes - TBtu/d (A)	2.54	2.33	2.54	2.27
NGLs sold - MBbl/d (B)(C)	136.34	130.07	138.20	119.79
Crude oil and condensate gathered volumes - MBbl/d	119.34	30.55	113.65	27.70

(A) Includes volumes under third-party processing arrangements.

(B) Excludes condensate.

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

OGE Holdings' income before taxes increased $6.2 million for the three months ended June 30, 2019 as compared to the same period in 2018, primarily due to an increase in equity in earnings of Enable of $6.5 million, partially offset by an increase in other expense. OGE Holdings' income before taxes decreased $4.5 million for the six months ended June 30, 2019 as compared to the same period in 2018, primarily due to an increase in other expense of $7.8 million driven by higher pension settlement charges for seconded Enable employees, partially offset by an increase in equity in earnings of Enable of $3.3 million. The following table presents summarized information regarding Enable's income statement changes for the three and six months ended June 30, 2019, compared to the same periods in 2018, 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:

	Three Months Ended					Six Months Ended
(In millions)	Income Statement Change at Enable		Impact to Company's Equity in Earnings			Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	57.0	$	14.5		$	101.0	$	25.8
Depreciation and amortization	$	14.0	$	(3.6	)	$	23.0	$	(5.9	)
Operation and maintenance, General and administrative	$	1.0	$	(0.3	)	$	9.0	$	(2.3	)

Enable's gathering and processing business segment reported an increase in operating income of $46.0 million and $62.0 million for the three and six months ended June 30, 2019, respectively. The following table presents summarized information regarding Enable's gathering and processing business segment income statement changes for the three and six months ended June 30, 2019, compared to the same periods in 2018, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

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

	Three Months Ended						Six Months Ended
(In millions)	Income Statement Change at Enable			Impact to Company's Equity in Earnings			Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	60.0		$	15.3		$	97.0	$	24.7
Depreciation and amortization	$	15.0		$	(3.8	)	$	27.0	$	(6.9	)
Operating and maintenance, General and administrative	$	(1.0	)	$	0.3		$	7.0	$	(1.8	)

Gathering and processing gross margin during the three months ended June 30, 2019 increased primarily due to: (i) an increase in changes in the fair value of natural gas, condensate and NGLs derivatives; (ii) an increase in natural gas gathering fees due to higher fees and increased gathered volumes in the Anadarko and Ark-La-Tex Basins; (iii) an increase in crude oil, condensate and produced water gathering revenues due to an increase related to a 2018 gathering system acquisition and an increase in volumes in the Williston Basin, partially offset by lower average rates; (iv) an increase in revenues from NGLs sales less the cost of NGLs due to higher processed volumes, partially offset by lower average sales prices; and (v) an increase in processing service fees resulting from higher processed volumes in the Anadarko and Ark-La-Tex Basins, partially offset by lower consideration received from certain processing arrangements due to a decrease in the average realized price. These increases were partially offset by a decrease in revenues from natural gas sales less the cost of natural gas due to lower average natural gas sales prices, partially offset by higher sales volumes.

Gathering and processing gross margin during the six months ended June 30, 2019 increased primarily due to: (i) an increase in natural gas gathering fees due to higher fees and gathered volumes in the Anadarko and Ark-La-Tex Basins; (ii) an increase in revenues from NGLs sales less the cost of NGLs due to higher processed volumes, partially offset by lower average sales prices for all NGLs products other than ethane; (iii) an increase in crude oil, condensate and produced water gathering revenues due to an increase related to a 2018 gathering system acquisition and an increase in volumes in the Williston Basin, partially offset by lower average rates; (iv) an increase due to the changes in the fair value of natural gas, condensate and NGLs derivatives; and (v) an increase in processing service fees resulting from higher processed volumes in the Anadarko and Ark-La-Tex Basins, partially offset by lower consideration received from certain processing arrangements due to a decrease in the average realized price. These increases were partially offset by a decrease in revenues from natural gas sales less the cost of natural gas due to lower average natural gas sales prices, partially offset by higher sales volumes.

Enable's transportation and storage business segment reported a decrease of $4.0 million and an increase of $7.0 million in operating income during the three and six months ended June 30, 2019, respectively. The following table presents summarized information regarding Enable's transportation and storage business segment income statement changes for the three and six months ended June 30, 2019, compared to the same periods in 2018, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

The changes in transportation and storage business segment operating income were primarily due to the following:

	Three Months Ended						Six Months Ended
(In millions)	Income Statement Change at Enable			Impact to Company's Equity in Earnings			Income Statement Change at Enable			Impact to Company's Equity in Earnings
Gross margin	$	(1.0	)	$	(0.3	)	$	6.0		$	1.5
Depreciation and amortization	$	(1.0	)	$	0.3		$	(4.0	)	$	1.0
Operation and maintenance, General and administrative	$	3.0		$	(0.8	)	$	2.0		$	(0.5	)

Transportation and storage gross margin during the three months ended June 30, 2019 decreased primarily due to: (i) a decrease in system management activities; (ii) a decrease in storage primarily due to a lower of cost or net realizable value adjustment on natural gas inventory; and (iii) a decrease in revenues from NGLs sales less the cost of NGLs due to a decrease in average NGL prices, partially offset by higher volumes. These decreases were partially offset by an increase in firm transportation and storage services due to new intrastate and interstate transportation contracts and an increase in changes in the fair value of natural gas derivatives.

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Transportation and storage gross margin during the six months ended June 30, 2019 increased primarily due to: (i) an increase in firm transportation and storage services due to new intrastate and interstate transportation contracts; and (ii) an increase in changes in the fair value of natural gas derivatives. These increases were partially offset by: (i) a decrease in system management activities; (ii) a decrease in storage primarily due to a lower of cost or net realizable value adjustment on natural gas inventory; (iii) a decrease in revenues from NGLs sales less the cost of NGLs due to a decrease in average NGLs prices, partially offset by an increase in volumes; and (iii) a decrease in volume-dependent transportation primarily due to a decrease in commodity fees and interruptible volumes related to power-plant customers, partially offset by new interstate contracts.

Income tax expense increased $1.4 million, or 20.9 percent, and decreased $7.0 million, or 42.4 percent, during the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. The increase during the three months ended June 30, 2019 was primarily due to higher pretax income. The decrease during the six months ended June 30, 2019 was primarily due to lower pretax income combined with federal and state deferred tax adjustments related to the Company's investment in Enable.

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 2018 Form 10-K. The Company has no off-balance sheet arrangements with equity method investments that would affect its liquidity.

Liquidity and Capital Resources

Cash Flows

	Six Months Ended
	June 30,						2019 vs. 2018
(Dollars in millions)	2019			2018			$ Change			% Change
Net cash provided from operating activities	$	128.8		$	354.2		$	(225.4	)	(63.6	)%
Net cash used in investing activities	$	(317.7	)	$	(266.9	)	$	(50.8	)	19.0	%
Net cash provided from (used in) financing activities	$	94.6		$	(101.7	)	$	196.3		*

* Change is greater than 100 percent variance.

The decrease in net cash provided from operating activities was primarily due to decreased amounts received from customers at OG&E and an increase in vendor payments.

The increase in net cash used in investing activities was primarily due to an increase in capital expenditures related to various capital projects at OG&E and the River Valley plant acquisition.

The increase in net cash provided from financing activities was primarily due to the issuance of long-term debt by OG&E in June 2019 and an increase in short-term debt, partially offset by the payment of long-term debt by OG&E in January 2019.

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. The following discussion addresses changes in working capital balances at June 30, 2019 compared to December 31, 2018.

Cash and Cash Equivalents decreased $94.3 million, or 100.0 percent, primarily due to normal business operations and payment of the OG&E $250.0 million senior notes due January 15, 2019.

Accounts Receivable and Accrued Unbilled Revenues increased $12.5 million, or 5.3 percent, primarily due to an increase in billings to OG&E's retail customers reflecting higher usage due to warmer weather in June 2019 as compared to December 2018, partially offset by mutual assistance payments received.

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Income Taxes Receivable decreased $3.6 million, or 36.4 percent, primarily due to a change in state tax law resulting in a difference in timing for the recognition of certain tax credits, partially offset by the tax benefit related to 2018 incentive compensation payouts that occurred in the first quarter of 2019.

Fuel Inventories decreased $9.7 million, or 16.8 percent, primarily due to decreased coal inventory related to the Dry Scrubber systems on Sooner Units 1 and 2 being placed into service and decreased gas inventory.

Materials and Supplies, at Average Cost decreased $39.8 million, or 31.4 percent, primarily due to decreased inventory related to long-term service agreements.

Fuel Clause Under Recoveries increased $28.7 million, primarily due to lower recoveries from OG&E retail customers as compared to the actual cost of fuel and purchased power.

Other Current Assets increased $4.5 million, or 15.3 percent, primarily due to an increase in prepayments associated with software expense.

Short-term Debt increased $207.5 million, primarily due to the use of available cash to repay the OG&E $250.0 million senior notes due January 15, 2019. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements.

Accounts Payable decreased $87.7 million, or 36.6 percent, primarily due to the timing of vendor payments.

Accrued Taxes decreased $3.2 million, or 7.3 percent, primarily resulting from the timing of ad valorem payments, partially offset by tax accruals.

Accrued Interest decreased $8.7 million, or 19.6 percent, primarily due to the payment of the OG&E $250.0 million senior notes due January 15, 2019 and related interest, as well as timing of payments and accruals.

Accrued Compensation decreased $14.7 million, or 30.8 percent, primarily due to 2018 incentive compensation payouts that occurred in the first quarter of 2019, partially offset by 2019 accruals.

Long-term Debt Due Within One Year decreased $250.0 million, or 100.0 percent, due to the payment of the OG&E $250.0 million senior notes due January 15, 2019.

Other Current Liabilities decreased $9.6 million, or 11.0 percent, primarily due to changes in amounts owed to customers. Included in the June 30, 2019 balance is the reserve for tax refund of $17.3 million resulting from the 2017 Tax Act, SPP reserves of $20.6 million and the over recovery of the SPP cost tracker of $8.0 million.

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 2019 through 2023 are discussed in detail within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's 2018 Form 10-K. Additional capital expenditures beyond those identified in the Company's 2018 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

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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 unsecured five-year revolving credit facilities totaling $900.0 million ($450.0 million for the Company and $450.0 million for OG&E) that mature on March 8, 2023. These bank facilities can also be used as letter of credit facilities. The following tables highlight the Company's short-term debt activity as of and for the six month period ended June 30, 2019.

(Dollars in millions)	June 30, 2019
Balance of outstanding supporting letters of credit	$	0.3
Weighted-average interest rate of outstanding supporting letters of credit	1.15		%
Net available liquidity under revolving credit agreements	$	692.2
Balance of cash and cash equivalents	$	—
(Dollars in millions)	Six Months Ended June 30, 2019
Average balance of short-term debt	$	354.3
Weighted-average interest rate of average balance of short-term debt	2.75		%
Maximum month-end balance of short-term debt	$	479.7

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, 2019 and ending December 31, 2020. See Note 11 within "Item 1. Financial Statements" for further discussion of the Company's short-term debt activity.

Issuance of Long-Term Debt

In June 2019, OG&E issued $300.0 million of 3.30 percent senior notes due March 15, 2030. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to repay short-term debt (including debt pertaining to the acquisition of the River Valley plant) and to fund ongoing capital expenditures and working capital.

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 May 31, 2019, Moody's Investors Service lowered its rating for OG&E's senior unsecured and issuer ratings from A2 to A3 and commercial paper rating from P-1 to P-2. OG&E's industrial authority bond rating was lowered from VMIG 1 to VMIG 2. The Company's senior unsecured and commercial paper ratings were not changed, and the outlooks for both the Company and OG&E are stable. Increased debt-financed capital spending on mandated environmental compliance projects combined with lagging cash flow due to the 2017 Tax Act and recent Oklahoma rate reviews were cited as contributing factors to OG&E's downgrades. Moody's Investors Service indicated that the stable outlook for both the Company and OG&E reflects a reduced capital plan, fewer rate review filings and a more predictable financial profile.

40

Quarterly Distributions by Enable

Pursuant to the Enable Limited Partnership Agreement, during the three and six months ended June 30, 2019, Enable made a distribution of $35.3 million and $70.6 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 within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's 2018 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 have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows. See Notes 14 and 15 within "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 within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's 2018 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.

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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 was January 4, 2019 as a result of an appeal filed by OG&E and others.

To satisfy the FIP, OG&E installed Dry Scrubbers at Sooner Units 1 and 2 and converted Muskogee Units 4 and 5 to natural gas. As of June 30, 2019, OG&E has invested $512.4 million in the Dry Scrubbers and $57.0 million in the Muskogee natural 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 delayed the effective date 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. 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 went into 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 December 27, 2018, the EPA released a proposed rule reconsidering certain elements of the 2012 rule in response to lengthy litigation in the D.C. Circuit Court. The Company cannot predict the outcome of this 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 June 30, 2019, 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 was based on modeling that did not reflect the 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

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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.

The Company continues to monitor these 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.

Nonetheless, OG&E's current business strategy will result in a reduced carbon emissions rate compared to current levels. As discussed in Note 15 within "Item 8. Financial Statements and Supplementary Data" in the Company's 2018 Form 10-K, to comply with the EPA's MATS rule and Regional Haze Rule FIP, OG&E has converted 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.

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. On July 8, 2019, the EPA officially repealed the Clean Power Plan and published the Affordable Clean Energy rule to replace it. The Affordable Clean Energy rule requires states, including Oklahoma, to develop emission limitations for carbon dioxide for each existing coal-fired utility boiler within the state and submit a compliance and implementation plan to the EPA by July 2022. The EPA will approve or disapprove the proposed state plan within 18 months of submittal and develop a federal implementation plan if the proposed state plan is disapproved. OG&E's coal-fired units will be subject to the State of Oklahoma's implementation plan. At this time, the Company cannot determine with any certainty whether the implementation plan will cause a material impact to its financial results.

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.

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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. On August 21, 2018, the D.C. Circuit Court of Appeals issued a decision regarding the ongoing Coal Combustion Residuals litigation. Based upon this court decision, the EPA is required to revise the 2015 coal ash rule. OG&E manages one regulated inactive coal ash impoundment that is expected to be clean-closed in 2019.

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. On September 26, 2018, a citizen suit was filed against the EPA in the U.S. District Court in the District of Columbia concerning the final approval. OG&E and others have moved to intervene on behalf of the EPA. The Company is monitoring 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. 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.

In 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.

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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 further discussion regarding contingencies relating to environmental laws and regulations, see Note 14 within "Item 1. Financial Statements."

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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 2018 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).

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Reference is made to Item 3 of Part I of the Company's 2018 Form 10-K for a description of certain legal proceedings presently pending. Except as described above under "Environmental Laws and Regulations" within "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.

There have been no significant changes in the Company's risk factors from those discussed in the Company's 2018 Form 10-K, which are incorporated herein by reference.

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

None.

Item 6. Exhibits.

Exhibit No.	Description
4.01	Supplemental Indenture No. 20 dated as of June 1, 2019 between OG&E and BOKF, NA, as trustee (Filed as Exhibit 4.01 to the Company's Form 8-K filed June 7, 2019 (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 - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL 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.
104	Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101).

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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)

August 7, 2019

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