OGE ENERGY CORP. (Form: 10-Q, Received: 11/07/2019 06:04:26)

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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 September 30, 2019

☐ 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 September 30, 2019, there were 200,176,215 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 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 5. Other Information	47

Item 6. Exhibits	48

Signature	49

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.
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
NO_X	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

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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions, except per share data)	2019			2018			2019			2018
OPERATING REVENUES
Revenues from contracts with customers	$	739.2		$	684.5		$	1,717.7		$	1,710.1
Other revenues	16.2			14.3			41.4			48.4
Operating revenues	755.4			698.8			1,759.1			1,758.5
COST OF SALES	234.0			244.4			625.3			663.6
OPERATING EXPENSES
Other operation and maintenance	129.8			123.3			368.6			353.2
Depreciation and amortization	94.1			81.1			260.8			240.8
Taxes other than income	23.2			22.7			70.4			69.3
Operating expenses	247.1			227.1			699.8			663.3
OPERATING INCOME	274.3			227.3			434.0			431.6
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	38.3			40.1			104.8			103.3
Allowance for equity funds used during construction	1.0			6.7			3.7			20.0
Other net periodic benefit expense	(1.4		)	(0.7		)	(8.7		)	(10.7		)
Other income	4.6			4.1			16.3			14.2
Other expense	(5.5		)	(3.4		)	(15.6		)	(11.1		)
Net other income	37.0			46.8			100.5			115.7
INTEREST EXPENSE
Interest on long-term debt	37.5			40.2			101.9			119.5
Allowance for borrowed funds used during construction	(0.6		)	(3.3		)	(2.2		)	(9.8		)
Interest on short-term debt and other interest charges	2.7			1.8			10.4			8.5
Interest expense	39.6			38.7			110.1			118.2
INCOME BEFORE TAXES	271.7			235.4			424.4			429.1
INCOME TAX EXPENSE	20.8			30.3			26.2			58.3
NET INCOME	$	250.9		$	205.1		$	398.2		$	370.8
BASIC AVERAGE COMMON SHARES OUTSTANDING	200.2			199.7			200.1			199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.8			200.6			200.6			200.4
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	1.25		$	1.03		$	1.99		$	1.86
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	1.25		$	1.02		$	1.98		$	1.85

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2019			2018			2019			2018
Net income	$	250.9		$	205.1		$	398.2		$	370.8
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, $0.8 and $0.8, respectively	0.9			0.8			2.6			2.5
Settlement cost, net of tax of $0.3, $1.1, $2.6 and $1.1, respectively	0.8			3.1			7.9			3.1
Postretirement Benefit Plans:
Amortization of prior service credit, net of tax of ($0.2), ($0.1), ($0.4) and ($0.4), respectively	(0.4		)	(0.5		)	(1.3		)	(1.3		)
Amortization of deferred net gain, net of tax of $0.0, $0.0, $0.0 and $0.0, respectively	—			—			(0.1		)	—
Other comprehensive loss from unconsolidated affiliates, net of tax of ($0.2), $0.0, ($0.2) and $0.0, respectively	(0.6		)	—			(0.6		)	—
Other comprehensive income, net of tax	0.7			3.4			8.5			4.3
Comprehensive income	$	251.6		$	208.5		$	406.7		$	375.1

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	398.2		$	370.8
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	260.8			240.8
Deferred income taxes and investment tax credits, net	25.2			63.7
Equity in earnings of unconsolidated affiliates	(104.8		)	(103.3		)
Distributions from unconsolidated affiliates	107.3			103.3
Allowance for equity funds used during construction	(3.7		)	(20.0		)
Stock-based compensation expense	10.8			9.7
Regulatory assets	(48.1		)	(4.8		)
Regulatory liabilities	(32.1		)	(3.7		)
Other assets	(4.3		)	2.1
Other liabilities	5.1			(1.4		)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	(76.4		)	(56.4		)
Fuel, materials and supplies inventories	8.0			14.9
Fuel recoveries	(44.8		)	37.5
Other current assets	3.4			19.3
Accounts payable	(69.1		)	(34.1		)
Other current liabilities	(17.5		)	73.3
Net cash provided from operating activities	418.0			711.7
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(476.5		)	(413.8		)
Investment in unconsolidated affiliates	(5.9		)	(1.9		)
Return of capital - unconsolidated affiliates	—			2.6
Net cash used in investing activities	(482.4		)	(413.1		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	296.4			396.0
Increase (decrease) in short-term debt	168.8			(168.4		)
Payment of long-term debt	(250.0		)	(250.0		)
Dividends paid on common stock	(221.7		)	(199.4		)
Cash paid for employee equity-based compensation and expense of common stock	(10.2		)	(0.5		)
Net cash provided from (used in) financing activities	(16.7		)	(222.3		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(81.1		)	76.3
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	94.3			14.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	13.2		$	90.7

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30,		December 31,
(In millions)	2019		2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	13.2	$	94.3
Accounts receivable, less reserve of $1.7 and $1.7, respectively	226.6		174.7
Accrued unbilled revenues	87.6		62.6
Income taxes receivable	12.6		9.9
Fuel inventories	43.6		57.6
Materials and supplies, at average cost	93.5		126.7
Fuel clause under recoveries	48.7		2.0
Other	23.3		29.5
Total current assets	549.1		557.3
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,175.9		1,177.5
Other	83.2		73.4
Total other property and investments	1,259.1		1,250.9
PROPERTY, PLANT AND EQUIPMENT
In service	12,662.1		11,994.8
Construction work in progress	125.2		376.4
Total property, plant and equipment	12,787.3		12,371.2
Less: accumulated depreciation	3,826.1		3,727.4
Net property, plant and equipment	8,961.2		8,643.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	304.7		285.8
Other	9.6		10.8
Total deferred charges and other assets	314.3		296.6
TOTAL ASSETS	$	11,083.7	$	10,748.6

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)



	September 30,			December 31,
(In millions)	2019			2018
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	168.8		$	—
Accounts payable	159.0			239.3
Dividends payable	77.6			72.9
Customer deposits	82.7			83.6
Accrued taxes	60.7			44.0
Accrued interest	35.7			44.5
Accrued compensation	33.9			47.8
Long-term debt due within one year	—			250.0
Fuel clause over recoveries	2.2			0.3
Other	76.0			87.0
Total current liabilities	696.6			869.4
LONG-TERM DEBT	3,194.7			2,896.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	205.6			225.7
Deferred income taxes	1,362.1			1,310.9
Deferred investment tax credits	7.1			7.2
Regulatory liabilities	1,233.3			1,270.7
Other	198.1			162.7
Total deferred credits and other liabilities	3,006.2			2,977.2
Total liabilities	6,897.5			6,743.5
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,128.3			1,127.7
Retained earnings	3,078.3			2,906.3
Accumulated other comprehensive loss, net of tax	(20.4		)	(28.9		)
Total stockholders' equity	4,186.2			4,005.1
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	11,083.7		$	10,748.6

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(Unaudited)



(In millions)	Shares Outstanding	Common Stock		Premium on Common Stock			Retained Earnings			Accumulated Other Comprehensive (Loss) Income			Total
Balance at December 31, 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
Net income	—	—		—			250.9			—			250.9
Other comprehensive income, net of tax	—	—		—			—			0.7			0.7
Dividends declared on common stock ($0.3875 per share)	—	—		—			(77.5		)	—			(77.5		)
Stock-based compensation	—	—		4.9			—			—			4.9
Balance at September 30, 2019	200.2	$	2.0	$	1,126.3		$	3,078.3		$	(20.4	)	$	4,186.2

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
Net income	—	—		—			205.1			—			205.1
Other comprehensive income, net of tax	—	—		—			—			3.4			3.4
Dividends declared on common stock ($0.3650 per share)	—	—		—			(72.9		)	—			(72.9		)
Stock-based compensation	—	—		3.9			—			—			3.9
Balance at September 30, 2018	199.7	$	2.0	$	1,122.0		$	2,924.5		$	(18.9	)	$	4,029.6

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

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.	Summary of Significant Accounting Policies

The Company's significant accounting policies are detailed in "Note 1. Summary of Significant Accounting Policies" in the Company's 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 September 30, 2019 and December 31, 2018, the consolidated results of its operations for the three and nine months ended September 30, 2019 and 2018 and its consolidated cash flows for the nine months ended September 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 September 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 nine months ended September 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.

Accounting Records

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

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

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



	September 30,		December 31,
(In millions)	2019		2018
REGULATORY ASSETS
Current:
Fuel clause under recoveries	$	48.7	$	2.0
Production tax credit rider over credit (A)	4.6		6.9
Oklahoma demand program rider under recovery (A)	—		6.4
Other (A)	4.4		3.2
Total current regulatory assets	$	57.7	$	18.5
Non-current:
Benefit obligations regulatory asset	$	168.0	$	188.2
Deferred storm expenses	64.5		36.5
Sooner Dry Scrubbers	20.8		4.5
Smart Grid	20.2		25.6
Unamortized loss on reacquired debt	10.8		11.4
Arkansas deferred pension expenses	7.8		6.8
Other	12.6		12.8
Total non-current regulatory assets	$	304.7	$	285.8
REGULATORY LIABILITIES
Current:
Reserve for tax refund and interim surcharge (B)	$	21.2	$	15.4
SPP cost tracker over recovery (B)	7.3		16.8
Oklahoma demand program rider over recovery (B)	4.8		—
Fuel clause over recoveries	2.2		0.3
Transmission cost recovery rider over recovery (B)	0.7		2.7
Other (B)	3.4		1.4
Total current regulatory liabilities	$	39.6	$	36.6
Non-current:
Income taxes refundable to customers, net	$	912.3	$	937.1
Accrued removal obligations, net	313.9		308.1
Pension tracker	1.0		18.7
Other	6.1		6.8
Total non-current regulatory liabilities	$	1,233.3	$	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.

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

Investment in Unconsolidated Affiliates

The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable; therefore, the Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable at September 30, 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 nine months ended September 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 Gain (Loss)			Prior Service Cost (Credit)		Net Gain (Loss)			Prior Service Cost (Credit)			Other Comprehensive Loss from Unconsolidated Affiliates			Total
Balance at December 31, 2018	$	(38.8	)	$	—	$	4.6		$	5.3		$	—		$	(28.9	)
Other comprehensive income (loss) before reclassifications	—			—		—			—			(0.6		)	(0.6		)
Amounts reclassified from accumulated other comprehensive income (loss)	2.6			—		(0.1		)	(1.3		)	—			1.2
Settlement cost	7.9			—		—			—			—			7.9
Balance at September 30, 2019	$	(28.3	)	$	—	$	4.5		$	4.0		$	(0.6	)	$	(20.4	)



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net Gain (Loss)			Prior Service Cost (Credit)		Net Gain (Loss)		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)	2.5			—		—		(1.3		)	1.2
Settlement cost	3.1			—		—		—			3.1
Balance at September 30, 2018	$	(27.1	)	$	—	$	2.5	$	5.7		$	(18.9	)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and nine months ended September 30, 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						Nine Months Ended
	September 30,						September 30,
(In millions)	2019			2018			2019			2018
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses	$	(1.2	)	$	(1.1	)	$	(3.4	)	$	(3.3	)	(A)
Settlement cost	(1.1		)	(4.2		)	(10.5		)	(4.2		)	(A)
	(2.3		)	(5.3		)	(13.9		)	(7.5		)	Income Before Taxes
	(0.6		)	(1.4		)	(3.4		)	(1.9		)	Income Tax Expense
	$	(1.7	)	$	(3.9	)	$	(10.5	)	$	(5.6	)	Net Income

Amortization of postretirement benefit plans items:
Prior service credit	$	0.6		$	0.6		$	1.7		$	1.7		(A)
Actuarial gains	—			—			0.1			—			(A)
	0.6			0.6			1.8			1.7			Income Before Taxes
	0.2			0.1			0.4			0.4			Income Tax Expense
	$	0.4		$	0.5		$	1.4		$	1.3		Net Income

Total reclassifications for the period, net of tax	$	(1.3	)	$	(3.4	)	$	(9.1	)	$	(4.3	)	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.

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

Financial Instruments-Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, "Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Information." The amendments in this update require entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions and reasonable and supportable forecasts in order to record credit losses in a more timely manner. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. ASU 2016-13 is effective for fiscal years beginning after December 2019 and will be applied utilizing a modified-retrospective approach. Early adoption is permitted. The Company continues to evaluate the impact of this ASU and does not believe it will have a material effect on its Condensed Consolidated Financial Statements.

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 continues to evaluate 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 September 30,					Nine Months Ended September 30,
(In millions)	2019			2018		2019			2018
Residential	$	318.9		$	281.0	$	692.4		$	694.6
Commercial	172.9			150.8		383.7			386.6
Industrial	66.8			67.2		172.0			174.6
Oilfield	58.6			52.4		156.9			140.1
Public authorities and street light	65.7			58.7		150.2			151.5
System sales revenues	682.9			610.1		1,555.2			1,547.4
Provision for rate refund	(2.3		)	13.5		(2.9		)	(6.2		)
Integrated market	12.8			16.9		29.8			38.7
Transmission	36.7			33.2		112.6			109.2
Other	9.1			10.8		23.0			21.0
Revenues from contracts with customers	$	739.2		$	684.5	$	1,717.7		$	1,710.1


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.

Financial Statement Information and Maturity Analysis of Lease Liabilities

Operating lease cost was $1.5 million and $4.5 million for the three and nine months ended September 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.



	Nine Months Ended
(In millions)	September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	4.9
Right-of-use assets obtained in exchange for new operating lease liabilities	$	10.7

(Dollars in millions)	September 30, 2019
Right-of-use assets at period end (A)	$	42.0
Operating lease liabilities at period end (B)	$	46.8
Operating lease weighted-average remaining lease term (in years)	13.2
Operating lease weighted-average discount rate	3.9		%



Future minimum operating lease payments as of: (In millions)	September 30, 2019		December 31, 2018 (C)(D)
2019	$	0.8	$	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	61.0		$	72.9
Less: Imputed interest	14.2
Present value of net minimum lease payments	$	46.8


(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 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 September 30, 2019, the Company owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units. On September 30, 2019, Enable's common unit price closed at $12.03. The Company recorded equity in earnings of unconsolidated affiliates of $38.3 million and $40.1 million for the three months ended September 30, 2019 and 2018, respectively, and $104.8 million and $103.3 million for the nine months ended September 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 September 30, 2019 and December 31, 2018 and for the three and nine months ended September 30, 2019 and 2018.



	September 30,		December 31,
Balance Sheet	2019		2018
(In millions)
Current assets	$	417	$	449
Non-current assets	$	12,018	$	11,995
Current liabilities	$	819	$	1,615
Non-current liabilities	$	4,076	$	3,211



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Income Statement	2019		2018		2019		2018
(In millions)
Total revenues	$	699	$	928	$	2,229	$	2,481
Cost of natural gas and NGLs	$	263	$	516	$	958	$	1,335
Operating income	$	175	$	171	$	507	$	436
Net income	$	123	$	129	$	351	$	320

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2019			2018			2019			2018
Enable net income	$	123.0		$	129.0		$	351.0		$	320.0
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	$	123.0		$	129.0		$	351.1		$	320.0
OGE Energy's percent ownership at period end	25.5		%	25.6		%	25.5		%	25.6		%
OGE Energy's portion of Enable net income	$	31.2		$	33.0		$	89.4		$	82.0
Amortization of basis difference and dilution recognition (A)	7.1			7.1			15.4			21.3
Equity in earnings of unconsolidated affiliates	$	38.3		$	40.1		$	104.8		$	103.3

(A) Includes 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 September 30, 2019.



(In millions)
Basis difference at December 31, 2018	$	680.3
Amortization of basis difference (A)	(20.5		)
Basis difference at September 30, 2019	$	659.8

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

On November 5, 2019, Enable announced a quarterly dividend distribution of $0.33050 per unit on its outstanding common units, which is unchanged from the previous quarter. If cash distributions to Enable's unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable's cash distributions at the time of the exercise of this reset election.

Distributions received from Enable were $36.7 million and $35.3 million during the three months ended September 30, 2019 and 2018, respectively, and $107.3 million and $105.9 million during the nine months ended September 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 September 30, 2019 and 2018, respectively, and $0.3 million and $0.5 million during the nine months ended September 30, 2019 and 2018, respectively.

Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of September 30, 2019, 83 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $3.6 million and $5.3 million during the three months ended September 30, 2019 and 2018, respectively, and $20.0 million and $22.1 million during the nine months ended September 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 $10.9 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 $0.9 million as of September 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.

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 nine months ended September 30, 2019 and 2018.



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2019			2018		2019			2018
Operating revenues:
Electricity to power electric compression assets	$	4.5		$	4.7	$	12.1		$	12.2
Cost of sales:
Natural gas transportation services	$	9.4		$	8.8	$	33.5		$	26.3
Natural gas (sales) purchases	$	(1.1	)	$	0.1	$	(5.4	)	$	2.6


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 September 30, 2019 and December 31, 2018. The following table summarizes the carrying amount and fair value of the Company's financial instruments at September 30, 2019 and December 31, 2018, as well as the classification level within the fair value hierarchy.



	September 30,				December 31,
	2019				2018
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Classification
Long-term Debt (including Long-term Debt due within one year):
Senior Notes	$	3,049.7	$	3,580.0	$	3,001.9	$	3,178.2	Level 2
OG&E Industrial Authority Bonds	$	135.4	$	135.4	$	135.4	$	135.4	Level 2
Tinker Debt	$	9.6	$	10.3	$	9.6	$	8.7	Level 3


7.	Stock-Based Compensation

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2019		2018		2019		2018
Performance units:
Total shareholder return	$	2.3	$	2.0	$	6.8	$	6.1
Earnings per share	2.3		1.9		3.2		3.6
Total performance units	4.6		3.9		10.0		9.7
Restricted stock	0.3		—		0.8		—
Total compensation expense	$	4.9	$	3.9	$	10.8	$	9.7
Income tax benefit	$	1.3	$	1.0	$	2.8	$	2.5

During the three and nine months ended September 30, 2019, the Company issued an immaterial number of shares and 443,900 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 examinations by tax authorities for years prior to 2016 or 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 nine months ended September 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 September 30,				Nine Months Ended September 30,
(In millions except per share data)	2019		2018		2019		2018
Net income	$	250.9	$	205.1	$	398.2	$	370.8
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)	0.6		0.9		0.5		0.7
Diluted average common shares outstanding	200.8		200.6		200.6		200.4
Basic earnings per average common share	$	1.25	$	1.03	$	1.99	$	1.86
Diluted earnings per average common share	$	1.25	$	1.02	$	1.98	$	1.85
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—


10.	Long-Term Debt

At September 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)
1.30%	-	2.50%	Garfield Industrial Authority, January 1, 2025	$	47.0
1.34%	-	2.35%	Muskogee Industrial Authority, January 1, 2025	32.4
1.36%	-	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.


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 September 30, 2019, the Company had $168.8 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 September 30, 2019.



	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
(In millions)
OGE Energy (B)	$	450.0	$	168.8	2.31	%	(D)	March 8, 2023
OG&E (C)	450.0		0.3		1.15	%	(D)	March 8, 2023
Total	$	900.0	$	169.1	2.30	%


(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 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 nine 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 pension settlement charges of $23.8 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.

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						Nine Months Ended						Three Months Ended				Nine Months Ended
	September 30,						September 30,						September 30,				September 30,
(In millions)	2019			2018			2019			2018			2019		2018		2019		2018
Service cost	$	3.4		$	3.6		$	9.7		$	11.1		$	0.1	$	0.1	$	0.3	$	0.3
Interest cost	4.6			6.1			15.5			17.8			0.1		0.1		0.3		0.3
Expected return on plan assets	(9.5		)	(10.7		)	(27.1		)	(33.0		)	—		—		—		—
Amortization of net loss	4.4			3.9			13.0			12.2			0.1		0.1		0.3		0.5
Amortization of unrecognized prior service cost (A)	—			—			—			—			—		0.1		—		0.1
Settlement cost	2.8			12.2			23.4			12.2			0.4		0.6		0.4		0.6
Total net periodic benefit cost	5.7			15.1			34.5			20.3			0.7		1.0		1.3		1.8
Less: Amount paid by unconsolidated affiliates	0.5			0.7			2.2			1.9			0.1		0.1		0.1		0.1
Net periodic benefit cost	$	5.2		$	14.4		$	32.3		$	18.4		$	0.6	$	0.9	$	1.2	$	1.7


(A)	Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

In addition to the net periodic benefit cost amounts presented in the above table for the three and nine months ended September 30, 2019 and 2018, the Company also recognized the following:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2019		2018		2019			2018
Increase (decrease) of pension expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	1.5	$	—	$	(0.2	)	$	7.8
Deferral of pension expense related to pension settlement charges:
Oklahoma jurisdiction (A)	$	2.3	$	10.5	$	14.0		$	10.5
Arkansas jurisdiction (A)	$	0.2	$	1.0	$	1.3		$	1.0


(A)	Included in the Pension tracker regulatory liability for the Oklahoma jurisdiction and in the deferred pension expenses regulatory asset for the Arkansas jurisdiction (see Note 1).



	Postretirement Benefit Plans
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2019			2018			2019			2018
Service cost	$	0.1		$	—		$	0.2		$	0.2
Interest cost	1.2			1.5			4.2			4.1
Expected return on plan assets	(0.5		)	(0.5		)	(1.4		)	(1.5		)
Amortization of net loss	0.5			1.0			1.5			2.9
Amortization of unrecognized prior service cost (A)	(2.1		)	(2.1		)	(6.3		)	(6.3		)
Total net periodic benefit cost	(0.8		)	(0.1		)	(1.8		)	(0.6		)
Less: Amount paid by unconsolidated affiliates	(0.2		)	(0.2		)	(0.5		)	(0.4		)
Net periodic benefit cost	$	(0.6	)	$	0.1		$	(1.3	)	$	(0.2	)


(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.

In addition to the net periodic benefit income and cost amounts presented in the above table for the three and nine months ended September 30, 2019 and 2018, the Company also recognized the following:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2019		2018		2019		2018
Increase of postretirement expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	0.1	$	0.1	$	0.9	$	4.3


(A)	Included in the Pension tracker regulatory liability (see Note 1).



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2019		2018		2019		2018
Capitalized portion of net periodic pension benefit cost	$	0.9	$	0.9	$	2.7	$	2.8
Capitalized portion of net periodic postretirement benefit cost	$	—	$	—	$	0.1	$	0.1

Pension Plan Funding

In August 2019, the Company contributed $20.0 million to its Pension Plan. No additional contributions are expected in 2019.


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 nine months ended September 30, 2019 and 2018.



Three Months Ended September 30, 2019	Electric Utility			Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	755.4		$	—		$	—		$	—		$	755.4
Cost of sales	234.0			—			—			—			234.0
Other operation and maintenance	130.0			0.6			(0.8		)	—			129.8
Depreciation and amortization	94.1			—			—			—			94.1
Taxes other than income	22.3			0.1			0.8			—			23.2
Operating income (loss)	275.0			(0.7		)	—			—			274.3
Equity in earnings of unconsolidated affiliates	—			38.3			—			—			38.3
Other income (expense)	(0.1		)	(0.6		)	0.6			(1.2		)	(1.3		)
Interest expense	38.0			—			2.8			(1.2		)	39.6
Income tax expense	9.7			8.5			2.6			—			20.8
Net income (loss)	$	227.2		$	28.5		$	(4.8	)	$	—		$	250.9
Investment in unconsolidated affiliates	$	—		$	1,159.1		$	16.8		$	—		$	1,175.9
Total assets	$	10,019.7		$	1,161.5		$	108.3		$	(205.8	)	$	11,083.7



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



Nine Months Ended September 30, 2019	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,759.1	$	—		$	—		$	—		$	1,759.1
Cost of sales	625.3		—			—			—			625.3
Other operation and maintenance	370.3		1.3			(3.0		)	—			368.6
Depreciation and amortization	260.8		—			—			—			260.8
Taxes other than income	66.8		0.4			3.2			—			70.4
Operating income (loss)	435.9		(1.7		)	(0.2		)	—			434.0
Equity in earnings of unconsolidated affiliates	—		104.8			—			—			104.8
Other income (expense)	4.0		(8.4		)	2.3			(2.2		)	(4.3		)
Interest expense	103.7		—			8.6			(2.2		)	110.1
Income tax expense (benefit)	14.9		18.0			(6.7		)	—			26.2
Net income	$	321.3	$	76.7		$	0.2		$	—		$	398.2
Investment in unconsolidated affiliates	$	—	$	1,159.1		$	16.8		$	—		$	1,175.9
Total assets	$	10,019.7	$	1,161.5		$	108.3		$	(205.8	)	$	11,083.7



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


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 had a QF contract with AES which expired on January 15, 2019 and a QF contract with Oklahoma Cogeneration LLC which expired on August 31, 2019. For the 320 MW AES QF contract and the 120 MW Oklahoma Cogeneration LLC QF contract, OG&E purchased 100 percent of the electricity generated by the QFs.

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

plant from AES, and in August 2019, OG&E acquired the plant from Oklahoma Cogeneration LLC. In August 2019, OG&E received final approval from the APSC to acquire both plants. 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.

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 expired 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.

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. On August 30, 2019, the APSC issued an order approving issues regarding depreciation rates

and prudence of action associated with the acquisitions. Issues regarding prudence of cost will be reviewed in OG&E's 2019 Formula Rate Plan filing.

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. In August 2019, OG&E completed the acquisition of the power plant from Oklahoma Cogeneration LLC and placed it into service, which is now named the Frontier power plant.

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 Administrative Law Judge 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.

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, 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 certain other 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. 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 were subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate review. On September 19, 2019, the OCC issued a final order which approved the settlement agreement.

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.

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, rates are currently being applied by the SPP pursuant to the terms of the settlement agreement.

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 September 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. A hearing on the merits is scheduled for November 14, 2019.

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. A hearing on the merits is scheduled for December 17, 2019.

Arkansas Formula Rate Plan Filing

On October 1, 2019, OG&E filed its second evaluation report under its Formula Rate Plan, requesting a $5.9 million revenue increase. If approved, new rates will be effective April 1, 2020.

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

Introduction

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.

Summary of Operating Results

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

Net income was $250.9 million, or $1.25 per diluted share, during the three months ended September 30, 2019 as compared to $205.1 million, or $1.02 per diluted share, during the same period in 2018. The increase in net income of $45.8 million, or $0.23 per diluted share, is further discussed below.

•

An increase in net income at OG&E of $43.3 million, or $0.21 per diluted share of the Company's common stock, was primarily due to higher gross margin (driven primarily by favorable weather and the expiration of the cogeneration credit rider) and lower income tax expense. This increase was partially offset by higher depreciation and amortization expense due to additional assets being placed into service, higher other operation and maintenance expense and lower allowance for funds used during construction due to certain environmental projects being completed and placed into service.


•	A decrease in net loss of other operations of $2.4 million, or $0.02 per diluted share of the Company's common stock, was primarily due to lower other operation and maintenance expense and higher other income, partially offset by higher income tax expense.


•	An increase in net income at OGE Holdings of $0.1 million was primarily due to lower income tax expense offset by lower equity in earnings of Enable.

Nine Months Ended September 30, 2019 as compared to Nine Months Ended September 30, 2018

Net income was $398.2 million, or $1.98 per diluted share, during the nine months ended September 30, 2019 as compared to $370.8 million, or $1.85 per diluted share, during the same period in 2018. The increase in net income of $27.4 million, or $0.13 per diluted share, is further discussed below.

•

An increase in net income at OG&E of $14.1 million, or $0.07 per diluted share of the Company's common stock, was primarily due to higher gross margin (driven primarily by favorable weather and the expiration of the cogeneration credit rider), lower income tax expense and lower interest expense. This increase was partially offset by higher depreciation and amortization expense due to additional assets being placed into service, higher other operation and maintenance expense and lower allowance for funds used during construction due to certain environmental projects being completed and placed into service.


•	An increase in net income of other operations of $10.7 million, or $0.05 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, higher other income and lower other operation and maintenance expense, partially offset by higher interest expense.


•	An increase in net income at OGE Holdings of $2.6 million, or $0.01 per diluted share of the Company's common stock, was primarily due to lower income tax expense, which was driven by favorable federal and state deferred tax adjustments, and higher equity in earnings of Enable, 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

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. In August 2019, the APSC issued an order approving issues regarding depreciation rates and prudence of action associated with the acquisitions. Issues regarding prudence of cost will be reviewed in OG&E's 2019 Formula Rate Plan filing.

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. OG&E completed the acquisition of the power plant from Oklahoma Cogeneration LLC and placed it into service in August 2019, which is now named the Frontier power plant.

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 Transmission 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, 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 certain other parties associated with the requested rate increase. 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 were subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate review. In September 2019, the OCC issued a final order which approved the settlement agreement.

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. A hearing on the merits is scheduled for December 17, 2019.

Arkansas Formula Rate Plan Filing

On October 1, 2019, OG&E filed its second evaluation report under its Formula Rate Plan, requesting a $5.9 million revenue increase. If approved, new rates will be effective April 1, 2020.

2019 Outlook

The Company is updating its outlook for 2019 earnings and, as described below, is increasing projected earnings at OG&E and consolidated OGE. Key assumptions for 2019 include:

OG&E

The Company projects OG&E to earn approximately $349 million to $357 million, or $1.74 to $1.78 per average diluted share, which is an increase from the previously issued guidance of net income between $311 million and $325 million, or $1.55 to $1.62 per average diluted share, in 2019. The earnings guidance is based on the following updated assumptions:


•	gross margin on revenues of approximately $1.446 billion to $1.449 billion and assumes normal weather for the remainder of the year;


•	operating expenses of approximately $935 million to $939 million, with operation and maintenance expenses approximately 53 percent of the total;


•	net interest expense of approximately $140 million to $142 million which assumes a $2.5 million allowance for borrowed funds used during construction reduction to interest expense; and


•	an effective tax rate of approximately 5.4 percent.

OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.

OGE Holdings

The projected earnings contribution from the Company's ownership interest in Enable for 2019 is unchanged and remains at the low end of the previously issued earnings guidance of approximately $104 million to $117 million, or $0.52 to $0.58 per average diluted share. Cash distributions for common units are expected to increase from approximately $140 million to approximately $145 million for 2019 due to the increase in the quarterly common unit distribution rate in August 2019.

Consolidated OGE

The Company's 2019 earnings guidance is between approximately $449 million and $461 million of net income, or $2.24 to $2.30 per average diluted share, which is an increase from the previously issued guidance of net income between $412 million and $442 million, or $2.05 to $2.20 per average diluted share. The earnings guidance is based on the following assumptions:


•	approximately 201 million average diluted shares outstanding;


•	an effective tax rate of approximately 7 percent; and


•	a $0.00 to ($0.02) or up to $4 million loss at OGE Energy due to interest expense, which is unchanged from previously issued 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 nine months ended September 30, 2019 and 2018, see "OG&E (Electric Utility) Results of Operations" below.

Detailed below is a reconciliation of gross margin to revenue included in the 2019 Outlook.



(In millions)	Twelve Months Ended December 31, 2019 (A)
Operating revenues	$	2,139
Cost of sales	691
Gross margin	$	1,448

(A) Based on the midpoint of OG&E earnings guidance for 2019.

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 nine months ended September 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 nine months ended September 30, 2019 as compared to the same periods in 2018 and the Company's consolidated financial position at September 30, 2019. Due to seasonal fluctuations and other factors, the Company's operating results for the three and nine months ended September 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				Nine Months Ended
	September 30,				September 30,
(In millions except per share data)	2019		2018		2019		2018
Net income	$	250.9	$	205.1	$	398.2	$	370.8
Basic average common shares outstanding	200.2		199.7		200.1		199.7
Diluted average common shares outstanding	200.8		200.6		200.6		200.4
Basic earnings per average common share	$	1.25	$	1.03	$	1.99	$	1.86
Diluted earnings per average common share	$	1.25	$	1.02	$	1.98	$	1.85
Dividends declared per common share	$	0.38750	$	0.36500	$	1.11750	$	1.03000

Results by Business Segment



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2019			2018			2019		2018
Net income:
OG&E (Electric Utility)	$	227.2		$	183.9		$	321.3	$	307.2
OGE Holdings (Natural Gas Midstream Operations)	28.5			28.4			76.7		74.1
Other operations (A)	(4.8		)	(7.2		)	0.2		(10.5		)
Consolidated net income	$	250.9		$	205.1		$	398.2	$	370.8


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

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

OG&E (Electric Utility)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(Dollars in millions)	2019			2018		2019			2018
Operating revenues	$	755.4		$	698.8	$	1,759.1		$	1,758.5
Cost of sales	234.0			244.4		625.3			663.6
Other operation and maintenance	130.0			121.1		370.3			352.2
Depreciation and amortization	94.1			81.1		260.8			240.8
Taxes other than income	22.3			21.9		66.8			66.2
Operating income	275.0			230.3		435.9			435.7
Allowance for equity funds used during construction	1.0			6.7		3.7			20.0
Other net periodic benefit income (expense)	(0.7		)	0.5		(0.3		)	(9.5		)
Other income	2.0			3.6		4.5			10.2
Other expense	2.4			0.6		3.9			2.0
Interest expense	38.0			37.8		103.7			114.3
Income tax expense	9.7			18.8		14.9			32.9
Net income	$	227.2		$	183.9	$	321.3		$	307.2
Operating revenues by classification:
Residential	$	328.0		$	286.4	$	710.0		$	714.7
Commercial	176.6			156.0		396.7			402.6
Industrial	68.1			68.6		176.0			179.0
Oilfield	59.4			53.0		159.5			142.5
Public authorities and street light	67.0			60.4		154.3			156.9
Sales for resale	—			—		0.1			0.1
System sales revenues	699.1			624.4		1,596.6			1,595.8
Provision for rate refund	(2.3		)	13.5		(2.9		)	(6.2		)
Integrated market	12.8			16.9		29.8			38.7
Transmission	36.7			33.2		112.6			109.2
Other	9.1			10.8		23.0			21.0
Total operating revenues	$	755.4		$	698.8	$	1,759.1		$	1,758.5
Reconciliation of gross margin to revenue:
Operating revenues	$	755.4		$	698.8	$	1,759.1		$	1,758.5
Cost of sales	234.0			244.4		625.3			663.6
Gross margin	$	521.4		$	454.4	$	1,133.8		$	1,094.9
MWh sales by classification (In millions)
Residential	3.2			2.9		7.6			7.6
Commercial	2.1			1.9		5.1			5.1
Industrial	1.2			1.2		3.4			3.4
Oilfield	1.2			1.1		3.5			3.1
Public authorities and street light	1.0			0.9		2.4			2.4
System sales	8.7			8.0		22.0			21.6
Integrated market	0.3			0.5		0.9			1.1
Total sales	9.0			8.5		22.9			22.7
Number of customers	855,904			846,817		855,904			846,817
Weighted-average cost of energy per kilowatt-hour (In cents)
Natural gas	1.943			2.158		2.234			2.328
Coal	2.025			2.046		2.005			2.035
Total fuel	1.857			2.029		2.002			2.046
Total fuel and purchased power	2.528			2.730		2.616			2.791
Degree days (A)
Heating - Actual	—			12		2,277			2,220
Heating - Normal	19			19		2,023			2,020
Cooling - Actual	1,477			1,265		1,958			2,051
Cooling - Normal	1,382			1,380		2,021			2,018

(A)

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

OG&E's net income increased $43.3 million, or 23.5 percent, and $14.1 million, or 4.6 percent, during the three and nine months ended September 30, 2019, respectively, as compared to the same periods in 2018. Primary drivers of the increases in net income are further discussed below.

Gross margin increased $67.0 million, or 14.7 percent, and $38.9 million, or 3.6 percent, during the three and nine months ended September 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		Nine Months Ended
Weather (price and quantity) (A)	$	36.3	$	15.5
Price variance (B)	26.3		12.1
New customer growth	3.9		8.6
Other	0.5		2.7
Change in gross margin	$	67.0	$	38.9


(A)	Increased primarily due to a 17 percent increase in cooling degree days for the three months ended September 30, 2019. While total cooling degree days did not increase for the nine months ended September 30, 2019, cooling degree days were higher for certain summer months during the period, which resulted in favorable weather impacts.


(B)	Increased primarily due to the expiration of the cogeneration credit rider.

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 $10.4 million, or 4.3 percent, and $38.3 million, or 5.8 percent, during the three and nine months ended September 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			Nine Months Ended			Three Months Ended		Nine Months Ended
Fuel expense (A)	$	(16.0	)	$	(28.9	)	(12.5	)%	(9.7	)%
Purchased power costs:
Purchases from SPP (B)	31.3			64.3			60.7	%	37.1	%
Cogeneration (C)	(27.1		)	(66.4		)	(90.1	)%	(81.9	)%
Wind (D)	2.7			(5.0		)	24.3	%	(11.0	)%
Other	0.2			0.2			3.1	%	3.0	%
Transmission expense (E)	(1.5		)	(2.5		)	(8.2	)%	(4.4	)%
Change in cost of sales	$	(10.4	)	$	(38.3	)


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


(B)	Increased primarily due to a 59.7 percent and 37.1 percent increase in MWhs purchased for the three and nine months ended September 30, 2019, respectively.


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


(D)	Increased due to a 9.6 percent increase in MWs purchased during the three months ended September 30, 2019. Decreased due to a 20.8 percent decrease in MWs purchased during the nine months ended September 30, 2019.


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

Other operation and maintenance expense increased $8.9 million, or 7.3 percent, and $18.1 million, or 5.1 percent, during the three and nine months ended September 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			Nine Months Ended			Three Months Ended		Nine Months Ended
New expenses related to River Valley power plant (A)	$	5.6		$	7.0		*		*
Contract technical and construction services (B)	4.5			11.9			50.0	%	43.3	%
Other	(1.2		)	(0.8		)	(1.1	)%	—	%
Change in other operation and maintenance expense	$	8.9		$	18.1

* Not applicable, as prior year expenses were zero.


(A)	Additional other operation and maintenance expenses are primarily recovered through a rider mechanism.


(B)	Increased primarily due to additional maintenance work at power plants.

Depreciation and amortization expense increased $13.0 million, or 16.0 percent, and $20.0 million, or 8.3 percent, during the three and nine months ended September 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 $5.7 million, or 85.1 percent, and $16.3 million, or 81.5 percent, during the three and nine months ended September 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 $9.2 million, or 96.8 percent, during the nine months ended September 30, 2019, as compared to the same period in 2018, primarily due to lower pension costs reflected in base rates as a result of the June 2018 Oklahoma rate review settlement.

Other income decreased $1.6 million, or 44.4 percent, and $5.7 million, or 55.9 percent, during the three and nine months ended September 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 $2.7 million, or 6.7 percent, and $17.6 million, or 14.7 percent, during the three and nine months ended September 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 $2.7 million, or 81.8 percent, and $7.6 million, or 77.6 percent, during the three and nine months ended September 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 $9.1 million, or 48.4 percent, and $18.0 million, or 54.7 percent, during the three and nine months ended September 30, 2019, respectively, as compared to the same periods in 2018. The decrease during the three months ended September 30, 2019 was primarily due to higher tax credits and an increase in the amortization of net refundable deferred taxes, partially offset by higher pretax income. The decrease during the nine months ended September 30, 2019 was primarily due to an increase in the amortization of net refundable deferred taxes, higher tax credits and lower pretax income.

OGE Holdings (Natural Gas Midstream Operations)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2019			2018			2019			2018
Operating revenues	$	—		$	—		$	—		$	—
Cost of sales	—			—			—			—
Other operation and maintenance	0.6			0.5			1.3			1.1
Taxes other than income	0.1			0.1			0.4			0.5
Operating loss	(0.7		)	(0.6		)	(1.7		)	(1.6		)
Equity in earnings of unconsolidated affiliates	38.3			40.1			104.8			103.3
Other expense	0.6			1.2			8.4			1.2
Income before taxes	37.0			38.3			94.7			100.5
Income tax expense	8.5			9.9			18.0			26.4
Net income attributable to OGE Holdings	$	28.5		$	28.4		$	76.7		$	74.1

Reconciliation of Equity in Earnings of Unconsolidated Affiliates

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2019			2018			2019			2018
Enable net income	$	123.0		$	129.0		$	351.0		$	320.0
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	$	123.0		$	129.0		$	351.1		$	320.0
OGE Energy's percent ownership at period end	25.5		%	25.6		%	25.5		%	25.6		%
OGE Energy's portion of Enable net income	$	31.2		$	33.0		$	89.4		$	82.0
Amortization of basis difference and dilution recognition (A)	7.1			7.1			15.4			21.3
Equity in earnings of unconsolidated affiliates	$	38.3		$	40.1		$	104.8		$	103.3

(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.



(In millions)
Basis difference at December 31, 2018	$	680.3
Amortization of basis difference (A)	(20.5		)
Basis difference at September 30, 2019	$	659.8

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

Enable Results of Operations and Operating Data

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2019		2018		2019		2018
Reconciliation of gross margin to revenue:
Total revenues	$	699	$	928	$	2,229	$	2,481
Cost of natural gas and NGLs	263		516		958		1,335
Gross margin	$	436	$	412	$	1,271	$	1,146
Operating income	$	175	$	171	$	507	$	436
Net income	$	123	$	129	$	351	$	320

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



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019	2018	2019	2018
Natural gas gathered volumes - TBtu/d	4.47	4.61	4.54	4.44
Transported volumes - TBtu/d	5.97	5.40	6.22	5.49
Natural gas processed volumes - TBtu/d (A)	2.49	2.50	2.52	2.35
NGLs sold - MBbl/d (B)(C)	118.29	146.29	131.49	130.18
Crude oil and condensate gathered volumes - MBbl/d	132.99	31.87	120.17	29.11


(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 decreased $1.3 million for the three months ended September 30, 2019 as compared to the same period in 2018, primarily due to a decrease in equity in earnings of Enable of $1.8 million, partially offset by a decrease in other expense. OGE Holdings' income before taxes decreased $5.8 million for the nine months ended September 30, 2019 as compared to the same period in 2018, primarily due to an increase in other expense of $7.2 million driven by higher pension settlement charges for seconded Enable employees, partially offset by an increase in equity in earnings of Enable of $1.5 million. The following table presents summarized information regarding Enable's income statement changes for the three and nine months ended September 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 the Company's equity in earnings of Enable were primarily due to the following:



	Three Months Ended					Nine 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	$	24.0	$	6.1		$	125.0	$	31.9
Operation and maintenance, General and administrative	$	10.0	$	(2.6	)	$	19.0	$	(4.8	)
Depreciation and amortization	$	8.0	$	(2.0	)	$	31.0	$	(7.9	)
Taxes other than income tax	$	2.0	$	(0.5	)	$	4.0	$	(1.0	)
Interest expense	$	8.0	$	(2.0	)	$	33.0	$	(8.4	)

Enable's gathering and processing business segment reported an increase in operating income of $6.0 million and $68.0 million for the three and nine months ended September 30, 2019, respectively. The following table presents summarized information regarding Enable's gathering and processing business segment income statement changes for the three and nine

months ended September 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 Enable's gathering and processing business segment operating income was primarily due to the following:



	Three Months Ended					Nine 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	$	19.0	$	4.8		$	116.0	$	29.6
Depreciation and amortization	$	11.0	$	(2.8	)	$	38.0	$	(9.7	)
Operating and maintenance, General and administrative	$	1.0	$	(0.3	)	$	8.0	$	(2.0	)
Taxes other than income tax	$	1.0	$	(0.3	)	$	2.0	$	(0.5	)

Gathering and processing gross margin during the three months ended September 30, 2019 increased primarily due to: (i) an increase in changes in the fair value and realized gains of natural gas, condensate and NGLs derivatives; (ii) 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; (iii) an increase in natural gas gathering fees due to higher fees in the Anadarko Basin, partially offset by lower gathered volumes and lower shortfall payments associated with the expiration of minimum volume commitments in the Arkoma Basin; and (iv) an increase in revenues from natural gas sales less the cost of natural gas due to lower operational gas purchases, partially offset by lower average natural gas sales prices. These increases were partially offset by a decrease in processing service fees due to lower processing arrangement consideration received due to a decrease in the average realized price and a decrease in revenues from NGLs sales less the cost of NGLs due to lower average realized sales prices and lower processed volumes.

Gathering and processing gross margin during the nine months ended September 30, 2019 increased primarily due to: (i) an increase in natural gas gathering fees due to higher fees and gathered volumes in the Anadarko Basin, partially offset by lower gathered volumes and lower shortfall payments associated with the expiration of minimum volume commitments in the Arkoma Basin; (ii) 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; (iii) an increase due to the changes in the fair value and realized gains of natural gas, condensate and NGLs derivatives; and (iv) an increase in intercompany management fees. These increases were partially offset by (i) a decrease in processing service fees due to lower processing arrangement consideration received due to a decrease in the average realized price, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins; (ii) a decrease in revenues from NGLs sales less the cost of NGLs due to lower average sales prices, partially offset by higher processed volumes; and (iii) 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 $3.0 million in operating income during the three and nine months ended September 30, 2019, respectively. The following table presents summarized information regarding Enable's transportation and storage business segment income statement changes for the three and nine months ended September 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						Nine 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	$	3.0		$	0.8		$	9.0		$	2.3
Depreciation and amortization	$	(3.0	)	$	0.8		$	11.0		$	(2.8	)
Operation and maintenance, General and administrative	$	9.0		$	(2.3	)	$	(7.0	)	$	1.8
Taxes other than income taxes	$	1.0		$	(0.3	)	$	2.0		$	(0.5	)

Transportation and storage gross margin during the three months ended September 30, 2019 increased primarily due to an increase in firm transportation and storage services due to new transportation contracts and an increase in volume-dependent transportation revenues due to an increase in off-system transportation due to new contracts. These increases were partially offset by a decrease in system management activities and 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.

Transportation and storage gross margin during the nine months ended September 30, 2019 increased primarily due to an increase in firm transportation and storage services due to new transportation contracts and 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) an increase in realized losses on natural gas derivatives; (iii) a decrease in storage primarily due to a lower of cost or net realizable value adjustment on natural gas inventory; and (iv) 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.

Income tax expense decreased $1.4 million, or 14.1 percent, and $8.4 million, or 31.8 percent, during the three and nine months ended September 30, 2019, respectively, as compared to the same periods in 2018. The decrease during the three months ended September 30, 2019 was primarily due to lower pretax income. The decrease during the nine months ended September 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



	Nine Months Ended
	September 30,						2019 vs. 2018
(Dollars in millions)	2019			2018			$ Change			% Change
Net cash provided from operating activities (A)	$	418.0		$	711.7		$	(293.7	)	(41.3	)%
Net cash used in investing activities (B)	$	(482.4	)	$	(413.1	)	$	(69.3	)	16.8	%
Net cash used in financing activities (C)	$	(16.7	)	$	(222.3	)	$	205.6		(92.5	)%


(A)	Decreased primarily due to decreased amounts received from customers at OG&E and an increase in vendor payments.


(B)	Increased primarily due to the acquisition of the River Valley and Frontier power plants.


(C)	Decreased primarily due to an increase in short-term debt, partially offset by the issuance of less long-term debt by OG&E in 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 September 30, 2019 compared to December 31, 2018.

Cash and Cash Equivalents decreased $81.1 million, or 86.0 percent, primarily due to normal business operations including the funding of capital expenditures.

Accounts Receivable and Accrued Unbilled Revenues increased $76.9 million, or 32.4 percent, primarily due to an increase in billings to OG&E's retail customers reflecting higher usage due to warmer weather in September 2019 as compared to December 2018, partially offset by mutual assistance payments received.

Income Taxes Receivable increased $2.7 million, or 27.3 percent, primarily due to a favorable tax benefit from filing the 2018 federal return, partially offset by a change in state tax law resulting in a difference in timing for the recognition of certain tax credits.

Fuel Inventories decreased $14.0 million, or 24.3 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 $33.2 million, or 26.2 percent, primarily due to decreased inventory related to long-term service agreements.

Fuel Clause Under Recoveries increased $46.7 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 decreased $6.2 million, or 21.0 percent, primarily due to recovery of the final cogeneration credit rider balance through the fuel clause mechanism, as approved in the September 2019 Oklahoma rate review settlement, partially offset by prepayments associated with software expense.

Short-term Debt increased $168.8 million, primarily due to normal business operations including the funding of capital expenditures. 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 $80.3 million, or 33.6 percent, primarily due to the timing of vendor payments.

Accrued Taxes increased $16.7 million, or 38.0 percent, primarily resulting from the timing of ad valorem payments, partially offset by tax accruals.

Accrued Interest decreased $8.8 million, or 19.8 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 $13.9 million, or 29.1 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 $11.0 million, or 12.6 percent, primarily due to changes in amounts owed to customers. Included in the September 30, 2019 balance is the reserve for tax refund of $20.8 million resulting from the 2017 Tax Act, SPP reserves of $13.0 million and the over recovery of the SPP cost tracker of $7.3 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 for the years 2019 through 2023 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company's businesses) plus capital expenditures for known and committed projects. Estimated capital expenditures for Enable are not included in the table below.



(In millions)	2019		2020		2021		2022		2023		Total
Transmission	$	50	$	45	$	40	$	35	$	35	$	205
Oklahoma distribution	230		215		225		225		225		1,120
Arkansas distribution	45		30		15		15		15		120
Generation	255		135		60		60		90		600
Reliability, resiliency, technology and other	—		90		335		335		335		1,095
Other	55		60		50		60		55		280
Total	$	635	$	575	$	725	$	730	$	755	$	3,420

Financing Activities and Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long- and short-term debt, proceeds from the sales of common stock to the public through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings and distributions from Enable will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. The Company utilizes short-term borrowings 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

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 September 30, 2019 and for the three and nine months ended September 30, 2019.



(Dollars in millions)	September 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	$	730.9
Balance of cash and cash equivalents	$	13.2



(Dollars in millions)	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Average balance of short-term debt	$	195.7		$	270.7
Weighted-average interest rate of average balance of short-term debt	2.45		%	2.70		%
Maximum month-end balance of short-term debt	$	247.8		$	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

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.

On October 25, 2019, S&P's Global Ratings raised its long-term issuer credit rating for OG&E from BBB+ to A- and raised its issue-level rating on OG&E's senior unsecured debt from BBB+ to A-. The S&P's Global Ratings commercial paper rating for OG&E was not changed, and the outlook for OG&E remains at stable. S&P's Global Ratings indicated the upgrade reflects its view of OG&E's separateness, insulation measures and stand-alone credit profile in accordance with their revised criteria. S&P's Global Ratings indicated the stable outlook on OG&E reflects their expectation that OG&E will continue to manage its regulatory risk in line with its peers and maintain financial measures consistent with S&P's Global Ratings' significant financial risk profile.

Quarterly Distributions by Enable

Pursuant to the Enable Limited Partnership Agreement, during the three and nine months ended September 30, 2019, Enable made a distribution of $36.7 million and $107.3 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.

Cross-State Air Pollution Rule

On September 7, 2016, the EPA finalized an update to the 2011 CSAPR. The new rule applies to ozone-season NO_Xemissions from power plants in 22 eastern states (including Oklahoma). The rule utilizes a cap and trade program for NO_X emissions and went into effect on May 1, 2017 in Oklahoma. The rule reduces the 2011 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. On September 13, 2019, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion that deferred a decision on our challenges to the rule pending an EPA review and decision on a separate administrative petition that we filed. OG&E is reviewing the court's opinion.

Due to the pending administrative proceedings currently at the EPA, the ultimate outcome of our challenge to the reduction in our emission allowances and any associated timing and impact on our operations cannot be determined with certainty at this time. OG&E is in compliance with the 2016 rule requirements which remain in effect. The Company does not anticipate, at this time, additional capital expenditures for compliance with the 2016 rule.

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. 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 September 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. The EPA has a deadline for making a decision pursuant to a consent decree entered by the U.S. District Court for the Northern District of California to resolve a citizen suit. The deadline has been extended several times, with the current deadline being August 26, 2017, but a decision has yet to be reached. The EPA has indicated that it anticipates finalizing a designation at the end of 2020. It is unclear what impact, if any, the consent decree deadline will have on the monitoring plan or the EPA's anticipated schedule for finalizing a designation. 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.

OG&E's current business strategy has resulted in a reduced carbon emissions rate compared to previous levels. We are meeting our previously announced CO₂ emissions reductions of 40 percent from 2005 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 authorized 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 July 8, 2019, the EPA officially repealed the 2015 Clean Power Plan and published the Affordable Clean Energy rule to replace it. Numerous parties, not including OG&E, have filed petitions for judicial review of the Affordable Clean Energy rule in the U.S. Court of Appeals for the District of Columbia Circuit. 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, including all of OG&E's coal units, 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. By rule, units have 24 months after approval of the state plan to comply. 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.

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. In August 2019, the EPA proposed revisions to the 2015 coal ash rule in response to the D.C. Circuit Court of Appeals issuing a decision regarding the ongoing Coal Combustion Residuals litigation. The proposed changes do not appear to be material to OG&E at this time. OG&E completed the clean closure of one regulated inactive coal ash impoundment in August 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.

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."

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).

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 5. Other Information.

On November 4, 2019, Mr. E. Keith Mitchell, Chief Operating Officer of OG&E, and Mr. Jean C. Leger, Jr., Vice President, Utility Operations of OG&E, both named executive officers of the Company, announced that they plan to retire mid-year 2020 and at year-end 2020, respectively.

On November 5, 2019, the OGE Energy Board of Directors amended and restated the OGE Energy Corp. Supplemental Executive Retirement Plan ("SERP"), to, among other things, change the benefit formula under the SERP. Also on November 5, 2019, the Compensation Committee of the Board of Directors designated Sean Trauschke, Chairman, President and Chief Executive Officer of OGE Energy as participant in the SERP. Mr. Trauschke is currently the only participant in the SERP.

The SERP, which originally was adopted in 1993, provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee who may not otherwise qualify for a sufficient level of benefits under OGE Energy's Pension Plan and Restoration of Retirement Income Plan. The SERP is an unfunded supplemental executive retirement plan that is not subject to the benefit limits imposed by the Internal Revenue Code.

The SERP, as amended, will provide to designated participants a retirement benefit at or after age 60 equal to the actuarial equivalent of 1.32 percent of the participant's average compensation (equal to base salary, plus target amount of annual incentive award in effect) during his or her final 36 months of employment, multiplied by his or her years of service (or portions thereof). For this purpose, years of service commence upon the later to occur of the participant's commencement of employment with the Company or January 1, 2019. Prior to the amendments, the SERP generally provided an annual retirement benefit for participants who retired on or after age 55 after 10 years of service, with the maximum benefit received by participants who retired on or after age 65. The maximum benefit amount under the pre-amendment SERP was equal to the actuarial equivalent of 65 percent of the participant's average compensation (subject to certain exceptions, equal to compensation paid and reported on a Form W-2) during his or her final 36 months of employment, reduced by other specified benefits and income and for early retirement prior to age 65. SERP payments will be made in a lump sum after becoming eligible for benefits and following termination, as provided in the SERP, in an amount equal to the actuarial equivalent of the monthly annuity. As a result of the amendments adopted on November 5, 2019, the SERP is expected to provide a lower, targeted level of benefits.

Item 6. Exhibits.



Exhibit No.	Description
10.01*	OGE Energy Corp. Supplemental Executive Retirement Plan, as amended and restated.
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).

* Represents executive compensation plans and arrangements.

SIGNATURE

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



	OGE ENERGY CORP.
	(Registrant)

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

November 6, 2019

Exhibit 10.01

OGE ENERGY CORP.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

(SERP)

(AS AMENDED AND RESTATED EFFECTIVE AS OF NOVEMBER 5, 2019)

Exhibit 10.01

OGE ENERGY CORP.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

(As Amended and Restated Effective as of November 5, 2019)

Purpose

The purpose of this Supplemental Executive Retirement Plan is to promote the best interests of the Company by enabling the Company: (a) to attract to its key management positions persons of outstanding ability, and (b) to retain in its employ those persons of outstanding competence who occupy key executive positions and who in the past contributed and who continue in the future to contribute materially to the success of the business by their ability, ingenuity and industry. This Supplemental Executive Retirement Plan was established to accomplish such purpose effective January 1, 1993, by Oklahoma Gas and Electric Company, assumed by the Company on November 18, 1998 and amended and restated effective as of January 1, 2005. OGE Energy Corp. hereby again amends and restates the Supplemental Executive Retirement Plan, as heretofore amended, effective as of November 5, 2019, as provided herein, to, among other things, reduce the amount of benefits payable to new participants hereunder as compared to benefits payable to participants in the past. It is intended to continue to be a plan which is unfunded and is maintained by the Company primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees.

ARTICLE 1

Definitions

The following words and phrases as used herein shall have the following meanings, unless a different meaning is plainly required from time to time.

1.1

“Affiliate” shall mean any corporation, partnership, joint venture, trust, association or other business enterprise which is a member of the same controlled group of corporations, trades or businesses as a Company within the meaning of Code Section 414(b) or (c); provided, however, that for purposes only of the term “Affiliate” when used in the definition of “Separation from Service” below, in applying Code Section 1563(a)(1), (2), and (3) in determining a controlled group of corporations under Code Section 414(b), the language “at least 50 percent” shall be used instead of “at least 80 percent” each place it appears in Code Section 1563(a)(1), (2), and (3), and in applying Treasury Reg. § 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code Section 414(c), “at least 50 percent” shall be used instead of “at least 80 percent” each place it appears in Treasury Reg. § 1.414(c)-2.


1.2	“Annual Incentive Compensation Plan” means the OGE Energy Corp. 2013 Annual Incentive Compensation Plan or any successor thereto, as determined by the Committee.


1.3	“Base Salary” means the actual base salary paid to a Participant during a month as shown in the payroll records of the Company.


1.4	“Beneficiary” means a Participant’s Surviving Spouse or, if none, his or her estate.


1.5	“Board of Directors” means the Board of Directors of OGE Energy Corp. as constituted from time to time.


1.6	“Code” means the Internal Revenue Code of 1986, as amended from time to time.


1.7	“Committee” means the Compensation Committee of the Board of Directors.

Exhibit 10.01


1.8	“Company” means OGE Energy Corp. and any of its domestic subsidiaries and divisions, as designated by the Board of Directors, and any successor of OGE Energy Corp. under the terms of Section 7.3.


1.9	“Company’s Pension Plan” means the OGE Energy Corp. Retirement Plan, as amended from time to time.


1.10	“Compensation” means, for each month of Service, the sum of (a) a Participant’s Base Salary plus (b) 1/12 of the target amount of a Participant’s annual incentive award in effect for such month under the Annual Incentive Compensation Plan (in the case of each of the preceding clauses (a) and (b), ignoring any deferral elections in effect).


1.11	“Effective Date” means January 1, 1993.


1.12	“Final Average Compensation” means the monthly average of a Participant’s Compensation for the last 36 consecutive months of Service. If a Participant does not have 36 consecutive months of Service, “Final Average Compensation” shall mean the monthly average of the Participant’s Compensation for his or her period of Service.


1.13	“Normal Retirement Date” means the 60th birthday of a Participant.


1.14	“Participant” means an employee of the Company specifically designated by the Committee to be covered under this Plan and who continues to fulfill all requirements for participation.


1.15	“Plan” means the Supplemental Executive Retirement Plan as herein set forth and as it may be amended from time to time.


1.16	“Service” means the period of time commencing upon the later to occur of a Participant’s commencement of employment or January 1, 2019 and ending upon the Participant’s Separation from Service.

1.17

“Separation from Service” means in respect of a Participant, any termination of employment with the Company employing the Participant and all its Affiliates due to retirement, death, Total and Permanent Disability or other reason; provided, however, that, no Separation from Service for reasons other than death shall be deemed to occur for purposes of the Plan while the Participant is on military leave, sick leave, or other bona fide leave of absence that does not exceed six months or, if longer, the period during which the Participant’s right to reemployment with the Company or its Affiliates is provided either under applicable statute or by contract; and provided further that, if the period of leave exceeds six months and the Participant does not retain a right to reemployment under an applicable statute or by contract, a Separation from Service will be deemed to have occurred on the first day following such six-month period. Whether or when a Separation from Service has occurred for purposes of the Plan shall be determined based on the meaning of “separation from service” under Code Section 409A and the regulations promulgated thereunder and, accordingly, shall be based on whether the facts and circumstances indicate that the Company employing the Participant and its Affiliates and the Participant reasonably anticipate that no further services will be performed after a certain date or that the level of bona fide services the Participant will perform after such date (whether as an employee or as an independent contractor) will permanently decrease to no more than 20% of the average level of bona fide services performed (whether as an employee or independent contractor) over the immediately preceding 36-month period (or the full period of services to such Company and its Affiliates if the Participant has been providing services to the Company and its Affiliates less than 36 months). A Participant shall be presumed for this purpose to have a Separation from Service where the level of bona fide services decreases to a level equal to 20% or less of such average level of services.

1.18

“Specified Employee” means, during the 12-month period beginning on April 1^st of 2005 or of any subsequent calendar year, an employee of a Participant’s employing Company or its Affiliates who met the requirements of Section 416(i)(1)(A)(i), (ii) or (iii) of the Code (applied in accordance with the regulations thereunder and without regard to Code Section 416(i)(5)) for being a “key employee” at any time during

Exhibit 10.01

the 12-month period ending on the December 31st immediately preceding such April 1st. Notwithstanding the foregoing, a Participant who otherwise would be a Specified Employee under the preceding sentence shall not be a Specified Employee for purposes of the Plan unless, as of the date of the Participant’s Separation from Service, stock of such Company or an Affiliate thereof is publicly traded on an established securities market or otherwise.


1.19	“Surviving Spouse” means the spouse to whom the Participant is lawfully married at the time of his or her death.

1.20 “Totally and Permanently Disabled” or “Total and Permanent Disability” means that the Participant is eligible to receive disability retirement benefits under the Company’s Pension Plan, determined without regard to Section 6.3(a)(ii) thereof.

ARTICLE 2

Retirement Benefits

2.1 Normal Retirement Benefit


(a)	Upon a vested Participant’s Separation from Service on or after his or her Normal Retirement Date for reasons other than death, the Company shall pay retirement benefits to the Participant in such amount and at such time as hereinafter described. Benefits payable upon the death of a Participant are described in Article 3.

(b)

Subject to Section 2.3 relating to delay in payment for Specified Employees and Section 5.1 relating to the form of payment, the normal retirement benefit payable to a Participant in monthly amounts during his or her lifetime and commencing as of the first day of the month coincident with or next following his or her Separation from Service (but subject to Section 7.10) shall equal 1.32% of the Participant’s Final Average Compensation multiplied by his or her years of Service (or portions thereof).


2.2	Disability Retirement Benefits

(a)

Subject to Section 2.3 relating to delay in payment for Specified Employees and Section 5.1 relating to the form of payment, a Participant who has a Separation from Service by reason of being Totally and Permanently Disabled shall be entitled to benefits under this Plan equal to 1.32% of the Participant’s Final Average Compensation as of the date of Total and Permanent Disability multiplied by his or her years of Service (or portions thereof) as of the date of Total and Permanent Disability.


(b)	Disability retirement benefits to which Participants are entitled under this Section 2.2 shall commence as of the first day of the month coincident with or next following the date of the Participant’s Separation from Service, but subject to Section 7.10.


2.3	Delay in Payment for Specified Employees

Notwithstanding the foregoing provisions of this Article 2, if a Participant is a Specified Employee at the time of his or her Separation from Service for reasons other than death and is to commence to receive payment under this Article 2 before the date that is six months after the date of such Separation from Service, no payment of the Participant’s benefits shall be made to or in respect of the Participant until the end of such six-month period (or until the Participant’s death, if earlier). Any such payment to which the Participant would otherwise be entitled to receive during such six-month period shall instead be accumulated and paid, with interest at the rate used in determining the actuarial equivalent lump sum amount of such payment, as of the first day of the seventh month following the date of Separation from Service or, in the event of the Participant’s earlier death, as soon as practicable after his or her death to his

Exhibit 10.01

or her Beneficiary. If a Participant dies after the date payment of retirement benefits would have commenced under this Article 2 but for this Section 2.3 and before payments commence due to the operation of this Section 2.3, he shall be deemed for purposes of Article 3 to have died after the commencement of benefits under the Plan.

ARTICLE 3

Death Benefits

3.1

Upon the death of a Participant while employed by the Company prior to his or her commencement of benefits under this Plan, the Participant’s Beneficiary shall receive, within 90 days following the Participant’s death, but subject to Section 7.10, a lump sum payment which is the actuarial equivalent as of the day before the date of the Participant’s death of a single life annuity payable to the Participant, commencing as of the day before the date of the Participant’s death (calculated without regard to the Participant’s death) and equal to 1.32% of the Participant’s Final Average Compensation as of the day before the date of the Participant’s death multiplied by the Participant’s years of Service (or portions thereof) as of the day before the date of the Participant’s death.


3.2	The benefits provided in this Article 3 shall be in addition to any pre- or post-retirement life insurance benefits under the Company’s insurance programs.


3.3	Except as provided in Sections 2.3 and 3.1, no other death benefits shall be payable under this Plan on the death of a Participant, whether or not vested.

ARTICLE 4

Vesting

4.1

Subject to the provisions of Section 7.2 of this Plan, a Participant shall be considered to have a vested right in his or her retirement benefits under this Plan upon the first to occur of the following while employed by the Company: his or her Normal Retirement Date, death or Total and Permanent Disability. Subject to Section 4.2, in the event that a Participant terminates employment prior to the occurrence of any of the foregoing events, he or she shall forfeit his or her rights to retirement benefits under this Plan.


4.2	By written action of the Committee and in its sole discretion, the vesting requirements specified in Section 4.1 of the Plan may be partially or fully waived for a specified Participant on such terms as the Committee may determine.

ARTICLE 5

Form of Payment of Benefits

5.1

Benefits under this Plan shall be payable in the form of a lump sum payment which is the actuarial equivalent as of the time described in Section 2.1(b) or 2.2(b), as applicable, of the monthly amount of benefit determined under Article 2 to which the Participant is entitled if such monthly amount were payable in the form of a single life annuity for the life of the Participant commencing at the time described in Section 2.1(b) or 2.2(b), as applicable.

5.2

Unfunded Plan. The undertakings of the Company herein constitute an unsecured promise of the Company to make the payments as provided in the Plan. This Plan is unfunded and no current beneficial interest in any asset of the Company shall accrue to any Participant or other person under the terms of this Plan. All Participants shall be entitled to the benefits provided by the Plan. It is the intent of the Company that the total cost of providing the benefits under this Plan will be borne by the Company.

Exhibit 10.01

ARTICLE 6

Administration

6.1

Authority of Administrator. The Committee shall have sole and absolute discretionary power and authority to interpret, construe and administer this Plan, to adopt appropriate procedures and to make all decisions, including deciding all questions of fact, necessary or proper in its judgment to carry out the terms of this Plan. The Committee’s interpretation and construction hereof, and actions hereunder, including any valuation of the amount or recipient of the payments to be made thereunder, shall be binding and conclusive on all persons for all purposes. The Company’s Chief Accounting Officer, shall act as the Committee’s agent in administering this Plan. Neither the Company, or its officers, employees or directors, nor the Committee or any member thereof shall be liable to any person for any action taken or omitted in connection with the interpretation and administration of this Plan.


6.2	Duty to Furnish Information. Each Participant shall furnish to the Committee such information as it may from time to time request for the purpose of the proper administration of this Plan.

6.3

Amendment and Termination. OGE Energy Corp., by action of the Board of Directors, reserves the exclusive right to amend, modify, alter or terminate this Plan in whole or in part without notice to the Participants. Except to the extent necessary to comply with Section 409A of the Code, no such termination, modification or amendment shall terminate or diminish the amount of benefits then being paid, or to be paid on subsequent termination of employment, to any Participant or Beneficiary. Notwithstanding the foregoing, no benefits may be distributed on termination of the Plan other than as provided in Articles 2 and 3 except to the extent acceleration of the time and form of payment is permitted under Section 409A of the Code and the regulations and guidance issued thereunder.


6.4	Administrator. OGE Energy Corp. shall be the “Administrator” of the Plan for purposes of ERISA.

ARTICLE 7

General Provisions

7.1

No Employment Rights. This Plan shall not be deemed to give any Participant or other person in the employ of the Company any right to be retained in the employment of the Company, or to interfere with the right of the Company to terminate any Participant or such other person at any time and to treat him without regard to the effect which such treatment might have upon him as a Participant in the Plan.


7.2	Forfeiture. In the event a Participant is discharged for cause involving illegal or fraudulent acts, such discharge may result in forfeiture of all benefits and rights under the Plan, in the sole discretion of the Committee.


7.3	Successors and Assigns. The rights, privileges, benefits and obligations under this Plan are intended to be, and shall be treated as, legal obligations of the Company and binding upon the Company, its successors and assigns, including successors by corporate merger, consolidation, reorganization or otherwise.


7.4	Statements. A copy of this Plan, together with copies of any approved procedures for administration, will be furnished to each Participant together with an annual statement of benefits over the signature of the Chairman of the Board or his or her designee.


7.5	Approval. This Plan was approved initially by resolution of the Board of Directors of Oklahoma Gas and Electric Company at a regular meeting on November 9, 1993 to be effective as of January 1, 1993 and was subsequently assumed and amended by resolutions of the Board of Directors.

Exhibit 10.01


7.6	Applicable Law. The provisions of this Plan shall be construed according to the law of the State of Oklahoma excluding the provisions of any such laws that would require the application of the laws of another jurisdiction.


7.7	Construction:


(a)	The masculine pronoun wherever used shall include the feminine. Wherever any words are used herein in the singular, they shall be construed as though they were also used in the plural in all cases where they shall so apply.


(b)	The titles to articles and headings of sections of this Plan are for convenience of reference and in case of any conflict the text of this Plan, rather than such titles and headings, shall control.

7.8

Form of Payment; Withholding. All payments under the Plan shall be made in cash. All amounts payable under the Plan shall be reduced to the extent of amounts required to be withheld by the Company under Federal, state, or local law. In furtherance of, but without limiting the foregoing, the Company may also withhold from any vested retirement benefits hereunder any amounts required pursuant to applicable state or Federal employment tax laws (or may make other suitable arrangements with the Participants to satisfy such withholding requirements) and may make appropriate adjustments to the retirement benefits hereunder to reflect such withholding payments.

7.9

Facility of Payment. Whenever and as often as any person entitled to payments under the Plan shall be under a legal disability or, in the sole judgment of the Committee, shall otherwise be unable to apply such payments to his or her own best interest and advantage, the Committee, in the exercise of its discretion may direct all or any portion of such payments to be made in any one or more of the following ways: (a) directly to him; (b) to his or her legal guardian or conservator; or (c) to his or her spouse or to any other person, to be expended for his or her benefit; and the decision of the Committee shall in each case be final and binding upon all person in interest.

7.10

Timing of Payments. Notwithstanding any provision of the Plan to the contrary, a distribution to be made as of a specified date in Article 2 or 3 shall be treated for purposes of Code Section 409A as made on the date specified if the distribution is made at such date specified or a later date in the same calendar year or, if later and provided that the Participant or other recipient is not permitted, directly or indirectly, to designate the year in which distribution is made, by the 15th day of the third calendar month following the specified date. In addition, if calculation of the amount of a payment is not administratively practicable due to events beyond the control of the Participant or his or her estate, a payment will be treated as made on the specified date for purposes of Code Section 409A if the payment is made during the first calendar year in which payment is administratively practicable.


7.11	Code Section 409A Compliance. To the extent applicable, it is intended that this Plan be in full compliance with the provisions of Section 409A of the Code. The Plan shall be interpreted, construed and administered in a manner consistent with this intent.

7.12

Restriction on Assignment. The interest of any Participant or Beneficiary may not be sold, transferred, assigned, or encumbered in any manner, either voluntarily or involuntarily, and any attempt so to anticipate, alienate, sell, transfer, assign, pledge, encumber or charge the same shall be null and void; neither shall the benefits hereunder be liable for or subject to the debts, contracts, liabilities, engagements or torts of any person to whom such benefits or funds are payable, nor shall they be subject to garnishment, attachment, or other legal or equitable process nor shall they be an asset in bankruptcy.


7.13	Actuarial Equivalence Factors. The following actuarial factors shall be used for purposes of determining actuarial equivalence under Section 3.1 or 5.1, as applicable:

Exhibit 10.01


(a)	Mortality Rates shall be based on the unisex mortality table issued under IRS Notice 2018-02 for purposes of determining the minimum present value under Code Section 417(e)(3) for distributions with annuity starting dates that occur during stability periods beginning in the 2019 calendar year; and


(b)	a 5% interest rate.

ARTICLE 8

Claims Procedure


8.1	Initial Claims Procedure

The Participant or his or her Surviving Spouse or any other person shall follow such procedures for making a claim as are provided by the Committee. The Committee shall make a decision upon each claim within 90 days of its receipt of such claim. If the claim is approved, the Committee shall determine the extent of benefits and initiate payment thereof. In the event that no action is taken on the applicant’s initial application for benefits within the period specified in this Section 8.1, the claim shall be deemed denied, and the applicant’s appeal rights under Section 8.3 will be in effect as of the end of such period.


8.2	Notice of Denial of Claim

If an application for benefits under Section 8.1 is denied in whole or in part, the Committee shall provide the applicant with a written notice of denial, setting forth: (a) the specific reason or reasons the claim was denied, (b) a specific reference to pertinent provisions of the Plan upon which the denial was based, (c) a description of the additional material or information (if any) necessary to perfect the claim, together with an explanation of why such material or information is necessary, and (d) an explanation of the Plan’s review procedure and the time limits applicable including a statement of the applicant’s rights to bring a civil action under Section 502(a) of ERISA following an adverse determination or review. This written notice of denial shall be furnished within 90 days after receipt of the claim by the Committee unless specific circumstances require an extension of time for processing. If an extension is required, written notice of the extension shall be furnished prior to the termination of the initial 90-day period. In no event shall such extension exceed a period of 90 days from the end of such initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Committee expects the render the final decision.

8.3

Within 60 days after receipt of a notice of denial, the applicant or his or her duly authorized representative may file a written notice of appeal of such denial with the Committee. Such notice of appeal must set forth the specific reasons for the appeal. In addition, within such appeal period the applicant or his or her duly authorized representative shall be provided, upon written request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the claim for benefits and may submit written comments, documents, records and other information relating to the claim. The 60-day period within which the request for review must be filed may be extended if the nature of the benefit which is the subject of the claim and other attendant circumstances so warrant and the 60-day limitations period would otherwise be unreasonable. In its sole discretion, the Committee may grant the applicant an oral hearing on his or her appeal. In considering the claim on review, the Committee will take into account all documents and information related to the claim that were submitted by the applicant and shall deliver to the applicant, or authorized representative, a written decision on the claim within 60 days after the receipt of the request for review, except that if there are special circumstances which require an extension of time, the 60 period may be extended to 120 days. If such extension is required, written notice shall be furnished to the applicant, or authorized representative, prior to the termination of the initial 60 day period. The decision shall be written in a manner calculated to be understood by the claimant, include the specific reason or

Exhibit 10.01

reasons for the decision and contain a specific reference to the pertinent Plan provisions upon which the decision is based, a statement that an applicant, or his/her authorized representative, shall have reasonable access to, and be entitled to receive, upon request and free of charge, copies of, all documents, records, and other information relevant to the applicant’s claim for benefits, and a statement describing the claimant’s right to bring an action under Section 502(a) of ERISA.

Dated: November 5, 2019

OGE ENERGY CORP.

By: /s/ Sean Trauschke

Title: President & CEO

Attest:

/s/ Patricia D. Horn

Secretary

Exhibit 31.01

CERTIFICATIONS

I, Sean Trauschke, certify that:

1. I have reviewed this quarterly report on Form 10-Q of OGE Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 6, 2019



/s/ Sean Trauschke
Sean Trauschke
President and Chief Executive Officer

Exhibit 31.01

CERTIFICATIONS

I, Stephen E. Merrill, certify that:

1. I have reviewed this quarterly report on Form 10-Q of OGE Energy Corp.;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 6, 2019



/s/ Stephen E. Merrill
Stephen E. Merrill
Chief Financial Officer

Exhibit 32.01

Certification Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of OGE Energy Corp. (the "Company") on Form 10-Q for the period ended September 30, 2019, as filed with the Securities and Exchange Commission (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2019



	/s/ Sean Trauschke
	Sean Trauschke
	President and Chief Executive Officer



	/s/ Stephen E. Merrill
	Stephen E. Merrill
	Chief Financial Officer