10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2019

OR

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

For the transition period from _____to_____

Commission File Number: 1-12579

OGE ENERGY CORP.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1481638
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

321 North Harvey

P.O. Box 321

Oklahoma City, Oklahoma 73101-0321

(Address of principal executive offices)

(Zip Code)

Registrant's telephone number, including area code: 405-553-3000

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

þ  Yes  o  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.

o  Yes   þ  No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  þ  Yes   o  No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  þ  Yes   o  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☑	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   þ  No

At June 28, 2019, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $8,519,482,559 based on the number of shares held by non-affiliates (200,175,812) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $42.56.

At January 31, 2020, there were 200,177,358 shares of common stock, par value $0.01 per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The Proxy Statement for the Company's 2020 annual meeting of shareowners is incorporated by reference into Part III of this Form 10-K.

OGE ENERGY CORP.

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2019

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS	ii
FORWARD-LOOKING STATEMENTS	1
Part I
Item 1. Business	2
The Company	2
Electric Operations - OG&E	3
Natural Gas Midstream Operations	8
Environmental Matters	9
Information About Our Executive Officers	10
Item 1A. Risk Factors	11
Item 1B. Unresolved Staff Comments	36
Item 2. Properties	37
Item 3. Legal Proceedings	38
Item 4. Mine Safety Disclosures	38
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6. Selected Financial Data	39
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	62
Item 8. Financial Statements and Supplementary Data	64
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	118
Item 9A. Controls and Procedures	118
Item 9B. Other Information	121
Part III
Item 10. Directors, Executive Officers and Corporate Governance	121
Item 11. Executive Compensation	121
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	121
Item 13. Certain Relationships and Related Transactions, and Director Independence	121
Item 14. Principal Accountant Fees and Services	121
Part IV
Item 15. Exhibits, Financial Statement Schedules	122
Item 16. Form 10-K Summary	127
Signatures	128

i

GLOSSARY OF TERMS

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

Abbreviation	Definition
2017 Tax Act	Tax Cuts and Jobs Act of 2017
2018 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2018
401(k) Plan	Qualified defined contribution retirement plan
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
Code	Internal Revenue Code of 1986
Company	OGE Energy Corp., collectively with its subsidiaries
Dry Scrubber	Dry flue gas desulfurization unit with spray dryer absorber
EGT	Enable Gas Transmission, LLC, a wholly-owned subsidiary of Enable that operates a 5,900-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex Basins in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas
Enable	Enable Midstream Partners, LP, 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 June 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EOIT	Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly-owned subsidiary of Enable that operates a 2,300-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
Federal Clean Air Act	Federal Clean Air Act of 1970, as amended
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.
kV	Kilovolt
LDC	Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area
MATS	Mercury and Air Toxics Standards
MBbl/d	Thousand barrels per day
MMBtu	Million British thermal unit
MRT	Enable Mississippi River Transmission, LLC, a wholly-owned subsidiary of Enable that operates a 1,600-mile interstate pipeline that provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois
MW	Megawatt
MWh	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NGLs	Natural gas liquids
NOX	Nitrogen oxide
OCC	Oklahoma Corporation Commission
OG&E	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Energy	Holding company
OGE Holdings	OGE Enogex Holdings LLC, wholly-owned subsidiary of OGE Energy, parent company of Enogex Holdings (prior to May 1, 2013) and 25.5 percent owner of Enable
OSHA	Federal Occupational Safety and Health Act of 1970
Pension Plan	Qualified defined benefit retirement plan
QF	Qualified cogeneration facility
QF contract	Contract with QFs and small power production producers

ii

Regional Haze Rule	The EPA's Regional Haze Rule
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SESH	Southeast Supply Header, LLC, in which Enable owns a 50 percent interest as of December 31, 2019, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast
SIP	State Implementation Plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
Stock Incentive Plan	2013 Stock Incentive Plan
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day
U.S.	United States of America

iii

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed within this Form 10-K, including those matters discussed within "Item 7. 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" and "Item 7. 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 OG&E's 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-K;

•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" herein.

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

1

PART I

Item 1. Business.

The Company

Introduction

The Company, incorporated in August 1995 in the State of Oklahoma, 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 electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly-owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

The natural gas midstream operations segment represents the Company's investment in Enable through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is 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. At December 31, 2019, the Company owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units.

The Company's principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321 (telephone 405-553-3000). At December 31, 2019, the Company had 2,425 employees, of which 80 are seconded to Enable. The Company's website address is www.ogeenergy.com. Through the Company's website under the heading "Investors," "SEC Filings," the Company makes available, free of charge, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. The Company's website and the information contained therein or connected thereto are not intended to be incorporated into this Form 10-K and should not be considered a part of this Form 10-K. Reports filed with the Securities and Exchange Commission are also made available on its website at www.sec.gov.

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. 

OG&E is focused on:

•providing exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity;

•providing safe, reliable energy to the communities and customers it serves, with a particular focus on enhancing the value of the grid by improving distribution grid reliability by reducing the frequency and duration of customer interruptions and leveraging previous grid technology investments;

•having strong regulatory and legislative relationships for the long-term benefit of customers, investors and members;

2

•continuing to grow a zero-injury culture and deliver top-quartile safety results;

•ensuring it has the necessary mix of generation resources to meet the long-term needs of its customers; and

•continuing focus on operational excellence and efficiencies in order to protect the customer bill.

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 projecting dividend increases to be consistent with utility earnings growth. 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.

Electric Operations - OG&E

General

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E. OG&E furnishes retail electric service in 267 communities and their contiguous rural and suburban areas. The service area covers 30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state. Of the 267 communities that OG&E serves, 241 are located in Oklahoma, and 26 are in Arkansas. OG&E derived 92 percent of its total electric operating revenues in 2019 from sales in Oklahoma and the remainder from sales in Arkansas. OG&E does not currently serve wholesale customers in either state.

OG&E's system control area peak demand in 2019 was 6,817 MWs on August 12, 2019. OG&E's load responsibility peak demand was 6,065 MWs on August 12, 2019. The following table shows system sales and variations in system sales for 2019, 2018 and 2017.

Year Ended December 31	2019	2019 vs. 2018	2018	2018 vs. 2017	2017
System sales (Millions of MWh)	28.4	1.1%	28.1	6.8%	26.3

OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.

Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. It is possible that changes in regulatory policies or advances in technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells will reduce costs of new technology to levels that are equal to or below that of most central station electricity production. Our ability to maintain relatively low cost, efficient and reliable operations is a significant determinant of our competitiveness.

3

OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year Ended December 31	2019		2018		2017
ELECTRIC ENERGY (Millions of MWh)
Generation (exclusive of station use)	17.0		18.2		18.5
Purchased	14.0		12.6		11.0
Total generated and purchased	31.0		30.8		29.5
OG&E use, free service and losses	(1.4)		(1.3)		(1.4)
Electric energy sold	29.6		29.5		28.1
ELECTRIC ENERGY SOLD (Millions of MWh)
Residential	9.7		9.7		8.8
Commercial	6.5		6.6		6.7
Industrial	4.5		4.5		4.0
Oilfield	4.6		4.2		3.7
Public authorities and street light	3.1		3.1		3.1
System sales	28.4		28.1		26.3
Integrated market	1.2		1.4		1.8
Total sales	29.6		29.5		28.1
ELECTRIC OPERATING REVENUES (In millions)
Residential	$	891.1	$	901.0	$	884.1
Commercial	503.1		519.9		532.8
Industrial	223.0		234.5		229.7
Oilfield	204.0		193.5		185.9
Public authorities and street light	195.7		204.0		208.0
Sales for resale	0.1		0.2		0.2
System sales revenues	2,017.0		2,053.1		2,040.7
Provision for rate refund	(0.9)		(6.0)		26.8
Integrated market	38.4		48.7		23.5
Transmission	148.0		147.4		151.2
Other	29.1		27.1		18.9
Total operating revenues	$	2,231.6	$	2,270.3	$	2,261.1
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential	731,797		725,440		719,441
Commercial	98,565		96,660		95,073
Industrial	2,965		3,072		3,096
Oilfield	7,071		7,110		7,139
Public authorities and street light	17,356		17,090		17,081
Total customers	857,754		849,372		841,830
AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue	$	1,223.05	$	1,247.22	$	1,234.92
Average annual use (kilowatt-hour)	13,344		13,466		12,324
Average price per kilowatt-hour (cents)	9.17		9.26		10.02

4

Regulation and Rates

OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2019, 86 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and six percent to the FERC.

The OCC and the APSC require that, among other things, (i) the Company permits the OCC and the APSC access to the books and records of the Company and its affiliates relating to transactions with OG&E; (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers; and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions. In addition, the FERC has access to the books and records of the Company and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

For information concerning OG&E's recently completed and currently pending regulatory proceedings, see Note 16 within "Item 8. Financial Statements and Supplementary Data."

Regulatory Assets and Liabilities

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. 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. See Note 1 within "Item 8. Financial Statements and Supplementary Data" for further discussion of OG&E's regulatory assets and liabilities.

Rate Structures

Oklahoma

OG&E's standard tariff rates include a cost of service component (including an authorized return on capital) plus a fuel adjustment clause mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power.

OG&E offers several alternative customer programs and rate options, as described below.

•Under OG&E's Smart Grid-enabled SmartHours programs, "time-of-use" and "variable peak pricing" rates offer customers the ability to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity is lowest.

•The guaranteed flat bill option for residential and small general service accounts allows qualifying customers the opportunity to purchase their electricity needs at a set monthly price for an entire year.

•The Renewable Energy Credit purchase program, a rate option that provides a "renewable energy" resource, is available as a voluntary option to all of OG&E's Oklahoma retail customers. OG&E's ownership and access to wind and solar resources makes the renewable option a possible choice in meeting the renewable energy needs of OG&E's conservation-minded customers.

•Load Reduction is a voluntary load curtailment program that provides OG&E's commercial and industrial customers with the opportunity to curtail usage on a voluntary basis when OG&E's system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days but may not be able to curtail every time that a curtailment event is required.

5

•OG&E offers certain qualifying customers "day-ahead price" and "flex price" rate options which allow participating customers to adjust their electricity consumption based on price signals received from OG&E. The prices for the "day-ahead price" and "flex price" rate options are based on OG&E's projected next day hourly operating costs.

OG&E has Public Schools-Demand and Public Schools Non-Demand rate classes that provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E also provides service level, seasonal and time period fuel charge differentiation that allows customers to pay fuel costs that better reflect the underlying costs of providing electric service. Lastly, OG&E has a military base rider that demonstrates Oklahoma's continued commitment to our military partners.

The previously discussed rate options, coupled with OG&E's other rate choices, provide many tariff options for OG&E's Oklahoma retail customers. The revenue impacts associated with these options are not determinable in future years because customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices. Revenue variations may occur in the future based upon changes in customers' usage characteristics if they choose alternative rate options.

Arkansas

OG&E's standard tariff rates include a cost of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power. OG&E's current rate order from the APSC includes a formula rate rider that provides for an annual adjustment to rates if the earned rate of return falls outside of a plus or minus 50 basis point dead-band around the allowed return on equity. Adjustments are limited to plus or minus four percent of revenue for each rate class for the 12 months preceding the test period. The initial term for the formula rate rider is not to exceed five years from the date of the APSC final order in the last general rate review, May 18, 2017, unless additional approval is obtained from the APSC.

OG&E offers several alternative customer programs and rate options, as described below.

•The "time-of-use" and "variable peak pricing" tariffs allow participating customers to save on their electricity bills by shifting some of the electricity consumption to off-peak times when demand for electricity is lowest.

•The Renewable Energy Credit purchase program, a tariff rate option that provides a "renewable energy" resource, is available as a voluntary option to all of OG&E's Arkansas retail customers. OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers.

•Load Reduction is a voluntary load curtailment program that provides OG&E's commercial and industrial customers with the opportunity to curtail usage on a voluntary basis and receive a billing credit when OG&E's system conditions merit curtailment action.

•OG&E offers certain qualifying customers a "day-ahead price" rate option which allows participating customers to adjust their electricity consumption based on a price signal received from OG&E. The "day-ahead price" is based on OG&E's projected next day hourly operating costs.

Fuel Supply and Generation

The OG&E-generated energy produced and the weighted average cost of fuel used, by type, for the last three years is presented below.

	Fuel Mix (A)			Fuel Cost (In cents/Kilowatt-Hour)
Fuel	2019	2018	2017	2019	2018	2017
Natural gas	64%	48%	39%	2.188	2.517	2.821
Coal	28%	45%	54%	2.029	2.025	2.069
Renewable	8%	7%	7%	—	—	—
Total fuel	100%	100%	100%	1.973	2.122	2.211

(A)Fuel mix calculated as a percent of net MWhs generated.

The decreases in the weighted average cost of fuel in 2019 compared to 2018 and in 2018 compared to 2017 were primarily due to lower natural gas prices. These fuel costs are recovered through OG&E's fuel adjustment clauses that are approved by the OCC and the APSC.

6

OG&E participates in the SPP Integrated Marketplace. As part of the Integrated Marketplace, the SPP has balancing authority responsibilities for its market participants. The SPP Integrated Marketplace functions as a centralized dispatch, where market participants, including OG&E, submit offers to sell power to the SPP from their resources and bid to purchase power from the SPP for their customers. The SPP Integrated Marketplace is intended to allow the SPP to optimize supply offers and demand bids based upon reliability and economic considerations and to determine which generating units will run at any given time for maximum cost-effectiveness within the SPP area. As a result, OG&E's generating units produce output that is different from OG&E's customer load requirements. Net fuel and purchased power costs are recovered through fuel adjustment clauses.

Of OG&E's 7,081 total MWs of generation capability reflected in the table within "Item 2. Properties," 4,766 MWs, or 67.3 percent, are from natural gas generation, 1,854 MWs, or 26.2 percent, are from coal generation, 449 MWs, or 6.3 percent, are from wind generation and 12 MWs, or 0.2 percent, are from solar generation.

Coal

OG&E's coal-fired units are designed to burn low sulfur western sub-bituminous coal. In May 2019, OG&E added the River Valley units to its coal-fired fleet, which burns a blend of bituminous coal from the Arkoma Basin in Oklahoma and low-sulfur western sub-bituminous coal. The combination of all 2019 coal purchased had a weighted average sulfur content of 0.24 percent. Based on the average sulfur content and EPA-certified data, OG&E's coal units have an approximate emission rate of 0.1 lbs. of SO₂ per MMBtu.

For the first two quarters of 2020, OG&E has coal supply agreements for 100 percent of its coal requirements for the Sooner and Muskogee facilities. OG&E has secured 100 percent of its Arkoma Basin coal needs through May of 2021. OG&E plans to fill the remainder of its 2020 coal needs through additional term agreements, spot purchases and the use of existing inventory. OG&E has no coal supply agreements beyond May 2021. In 2019, OG&E purchased 2.8 million tons of coal from its Wyoming supplier and 0.1 million tons from its Oklahoma supplier. See "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of environmental matters which may affect OG&E in the future, including its utilization of coal.

Natural Gas

As a participant in the SPP Integrated Marketplace, OG&E purchases its natural gas supply through short-term agreements. OG&E relies on a combination of natural gas base load agreements and call agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP Integrated Marketplace.

Wind

OG&E owns the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms. OG&E's current wind power portfolio also includes purchased power contracts as listed in the table below.

Company	Location	Original Term of Contract	Expiration of Contract	MWs
CPV Keenan	Woodward County, OK	20 years	2030	152.0
Edison Mission Energy	Dewey County, OK	20 years	2031	130.0
NextEra Energy	Blackwell, OK	20 years	2032	60.0

Solar

In 2015, OG&E placed two solar sites, located in Oklahoma City, Oklahoma at the Mustang generating facility, into service. The Mustang solar sites have a combined maximum capacity of 2.5 MWs and consist of almost 10,000 photovoltaic panels.

In 2018, OG&E placed one solar site, located near Covington, Oklahoma, into service. The Covington solar site has a maximum capacity of 9.7 MWs and consists of almost 38,000 photovoltaic panels.

Currently, OG&E is building two solar sites, one near Durant, Oklahoma and one near Davis, Oklahoma, that will have a combined maximum capacity of 10.0 MWs and consist of over 30,000 photovoltaic panels. OG&E will continue to evaluate the need to add additional solar sites to its generation portfolio based on customer demand, cost and reliability.

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Safety and Health Regulation

OG&E is subject to a number of federal and state laws and regulations, including OSHA, the EPA and comparable state statutes, whose purpose is to protect the safety and health of workers.

In addition, the OSHA Hazard Communication Standard, the EPA Emergency Planning and Community Right-to-Know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials stored, used or produced in OG&E's operations and that this information be provided or made available to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.

Natural Gas Midstream Operations - Enable

Overview

Enable is a publicly traded Delaware limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. Enable serves current and emerging production areas in the U.S., including several unconventional shale resource plays and local and regional end-user markets in the U.S. Enable's assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Enable's gathering and processing segment primarily provides natural gas gathering and processing to its producer customers and crude oil, condensate and produced water gathering services to its producer and refiner customers. Enable's transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to its producer, power plant, LDC and industrial end-user customers.

Gathering and Processing

Enable owns and operates substantial natural gas gathering and processing and crude oil, condensate and produced water gathering assets in five states. Enable's gathering and processing operations consist primarily of natural gas gathering and processing assets serving the Anadarko, Arkoma and Ark-La-Tex Basins, crude oil and condensate gathering assets serving the Anadarko Basin and crude oil and produced water gathering assets serving the Williston Basin. Enable provides a variety of services to the active producers in its operating areas, including gathering, compressing, treating and processing natural gas, fractionating NGLs and gathering crude oil, condensate and produced water. Enable serves shale and other unconventional plays in the basins in which it operates.

Enable generates revenues from producers in the basins in which it operates. For the year ended December 31, 2019, Enable's top ten natural gas producer customers accounted for approximately 68 percent of its natural gas gathered volumes. Enable's Anadarko Basin crude oil gathering systems gathers crude oil and condensate from producers, which are primarily delivered to one customer. The rates and terms of service on Enable's Anadarko Basin crude oil and condensate gathering system are regulated by the OCC. Enable's Williston Basin crude oil and produced water gathering systems serve one customer. The rates and terms of service on Enable's Williston Basin crude oil gathering systems, but not its produced water gathering systems, are regulated by the FERC. Enable's contracts typically provide for crude oil, condensate and produced water gathering services that are fee-based and for natural gas gathering and processing arrangements that are fee-based, or percent-of-liquids, percent-of-proceeds or keep-whole based.

Competition for Enable's gathering and processing systems is primarily a function of gathering rate, processing value, system reliability, fuel rate, system run time, construction cycle time and prices at the wellhead. Enable's gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable's primary competitors are other midstream companies who are active in the regions where Enable operates.

While the results of Enable's gathering and processing segment are not materially affected by seasonality, from time to time, its operations and construction of assets can be impacted by inclement weather.

Transportation and Storage

Enable owns and operates interstate and intrastate natural gas transportation and storage systems across nine states. Enable's transportation and storage systems consist primarily of its interstate systems, EGT and MRT, its intrastate system,

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EOIT, and its investment in SESH. Enable's transportation and storage assets transport natural gas from areas of production and interconnected pipelines to power plants, LDCs and industrial end users as well as interconnected pipelines for delivery to additional markets. Enable's transportation and storage assets also provide facilities where natural gas can be stored by customers.

Enable's interstate and intrastate natural gas transportation and storage systems generate revenue primarily by serving large natural gas and electric utilities, as well as natural gas producers, industrial end-users and natural gas marketers. For the year ended December 31, 2019, approximately 26 percent of EGT's service revenue was attributable to contracts with one customer, CenterPoint. All of EGT's firm transportation and storage contracts for CenterPoint's LDCs are scheduled to expire in March 2021. CenterPoint's LDCs have received the required regulatory approvals to extend transportation and storage services with EGT. The term for the transportation and storage services provided to CenterPoint's LDCs in Arkansas, Louisiana, Oklahoma and northeast Texas is expected to be extended beyond March 2021, pursuant to the terms of the approved contracts.

For the year ended December 31, 2019, approximately 70 percent of MRT's service revenue was attributable to contracts with one customer, Spire Inc. MRT's firm transportation contracts representing 64 percent, 24 percent and 12 percent of Spire Inc.'s firm transportation capacity are scheduled to expire in July 2024, October 2025 and March 2026, respectively. All of Spire Inc.'s firm storage contracts are scheduled to expire in May 2021, which are subject to FERC rate case approval.

Enable's EGT, MRT and SESH transportation and storage services are typically provided under firm, fee-based transportation and storage agreements, with rates and terms of service regulated by the FERC. EOIT provides fee-based firm and interruptible transportation and storage services on both an intrastate and interstate basis.

Enable's interstate and intrastate pipelines compete with a variety of other interstate and intrastate pipelines in providing transportation and storage services within its operating areas. Enable's management views the principal elements of competition among pipelines as rates, terms of services, flexibility and reliability of service.

Customer demand for natural gas on EGT and MRT is usually greater during the winter, primarily due to LDC demand to serve residential and commercial natural gas requirements. Customer demand for natural gas transportation and storage services on EOIT is usually greater during the summer, primarily due to demand by natural gas-fired power plants to serve residential and commercial electricity requirements, including for OG&E. SESH is generally not impacted by seasonality.

Environmental Matters

General

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 or 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.

In the past, environmental regulation caused the Company to incur significant costs because the trend was to place more and more restrictions and limitations on the Company's activities. The Trump administration has delayed, reversed or proposed to repeal some of these regulations and generally has not sought to adopt new, more stringent regulations. Nonetheless, the Company continues to have obligations to take or complete action under previously adopted environmental rules, and the Company cannot assure that future events, such as changes in political administrations, existing laws, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause it to incur significant costs for environmental matters.

Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market but at the current time does not expect capital expenditures for environmental control facilities to be material for 2020 or 2021. For further discussion of environmental matters and capital expenditures related to environmental factors that may affect the Company, see "2019 Capital Requirements, Sources of Financing and Financing Activities," "Future Capital Requirements" and "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

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Information About Our Executive Officers

The table below includes the names, titles and business experience for the most recent five years for those persons serving as Executive Officers of the Registrant as of February 26, 2020:

Name	Age	Current Title and Business Experience
Sean Trauschke	52	2015 - Present:	Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp.
		2015:	President of OGE Energy Corp.
Stephen E. Merrill	55	2015 - Present:	Chief Financial Officer of OGE Energy Corp.
Sarah R. Stafford	38	2018 - Present:	Controller and Chief Accounting Officer of OGE Energy Corp.
		2016 - 2018:	Accounting Research Officer of OGE Energy Corp.
		2015 - 2016:	Senior Manager - Ernst & Young, LLP
Andrea M. Dennis	43	2019 - Present:	Vice President - Transmission and Distribution Operations of OG&E
		2019:	Managing Director Transmission and Distribution Operations of OG&E
		2015 - 2019:	Director System Operations of OG&E
Kenneth R. Grant	55	2016 - Present:	Vice President - Sales and Marketing of OG&E
		2015:	Vice President - Marketing and Product Development of OG&E
		2015:	Managing Director Tech Solutions & Ops of OG&E
Patricia D. Horn	61	2015 - Present:	Vice President - Governance and Corporate Secretary of OGE Energy Corp.
Donnie O. Jones	53	2019 - Present:	Vice President - Utility Operations of OG&E
		2015 - 2019:	Vice President - Power Supply Operations of OG&E
Jean C. Leger, Jr.	61	2019 - Present:	Senior Vice President - Utility Operations of OG&E
		2015 - 2019:	Vice President - Utility Operations of OG&E
Cristina F. McQuistion	55	2017 - Present:	Vice President - Chief Information Officer of OG&E
		2016 - 2017:	Vice President - Chief Information Officer and Utility Strategy of OG&E
		2015:	Vice President - Strategic Planning, Performance Improvement and Chief Information Officer of OG&E
Kenneth A. Miller	53	2019 - Present:	Vice President - State Regulatory and Legislative Affairs of OG&E
		2015 - 2018:	State Treasurer of Oklahoma
E. Keith Mitchell	57	2015 - Present:	Chief Operating Officer of OG&E
		2015:	Executive Vice President and Chief Operating Officer of Enable Midstream Partners, LP
William H. Sultemeier	52	2017 - Present:	General Counsel of OGE Energy Corp.
		2016:	Partner - Jones Day
		2015:	Shareholder - Greenberg Traurig, LLP
Charles B. Walworth	45	2015 - Present:	Treasurer of OGE Energy Corp.

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Trauschke, Merrill, Sultemeier, Walworth and Mses. Horn and Stafford are also officers of OG&E. Each Executive Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareholders, currently scheduled for May 21, 2020.

Messrs. Trauschke and Merrill are members of the Board of Directors of Enable GP, LLC, the general partner of Enable.

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Item 1A. Risk Factors.

In the discussion of risk factors set forth below, unless the context otherwise requires, the terms "we," "our" and "us" refer to the Company. In addition to the other information in this Form 10-K and other documents filed by us and/or our subsidiaries with the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OGE Energy and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us or our subsidiaries. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.

REGULATORY RISKS

OG&E's profitability depends to a large extent on the ability to fully recover its costs from its customers in a timely manner, and there may be changes in the regulatory environment that impair its ability to recover costs from its customers.

OG&E is subject to comprehensive regulation by several federal and state utility regulatory agencies, which significantly influences its operating environment and its ability to fully recover its costs from utility customers. Recoverability of any under recovered amounts from OG&E's customers due to a rise in fuel costs is a significant risk. The utility commissions in the states where OG&E operates regulate many aspects of its utility operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the utility operations is dependent on OG&E's ability to fully recover costs related to providing energy and utility services to its customers in a timely manner. Any failure to obtain utility commission approval to increase rates to fully recover costs, or a delay in the receipt of such approval, could have an adverse impact on OG&E's results of operations. In addition, OG&E's jurisdictions have fuel adjustment clauses that permit OG&E to recover fuel costs through rates without a general rate case, subject to a later determination that such fuel costs were prudently incurred. If the state regulatory commissions determine that the fuel costs were not prudently incurred, recovery could be disallowed.

In recent years, the regulatory environments in which OG&E operates have received an increased amount of attention. It is possible that there could be changes in the regulatory environment that would impair OG&E's ability to fully recover costs historically paid by OG&E's customers. State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. OG&E cannot assure that the OCC, APSC and the FERC will grant rate increases in the future or in the amounts requested, and they could instead lower OG&E's rates.

OG&E is unable to predict the impact on its operating results from future regulatory activities of any of the agencies that regulate OG&E. Changes in regulations or the imposition of additional regulations could have an adverse impact on OG&E's results of operations.

OG&E's rates are subject to rate regulation by the states of Oklahoma and Arkansas, as well as by a federal agency, whose regulatory paradigms and goals may not be consistent.

OG&E is a vertically integrated electric utility. Most of its revenue results from the sale of electricity to retail customers subject to bundled rates that are approved by the applicable state utility commission.

OG&E operates in Oklahoma and western Arkansas and is subject to rate regulation by the OCC and the APSC, in addition to FERC regulation of its transmission activities and any wholesale sales. Exposure to inconsistent state and federal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate, including a change in our authorized return on equity, may harm our financial position and results of operations.

Costs of compliance with environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, consolidated financial position or liquidity.

We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future. 

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In response to recent regulatory and judicial decisions and international accords, emissions of greenhouse gases including, most significantly, CO₂, could be restricted in the future as a result of federal or state legal requirements or litigation relating to greenhouse gas emissions. No rules are currently in effect that require us to reduce our greenhouse gas emissions, but if such rules were to become effective, they could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

There is inherent risk of the incurrence of environmental costs and liabilities in our operations and historical industry operations practices. These activities are subject to stringent and complex federal, state and local laws and regulations that can restrict or impact OG&E's business activities in many ways, such as restricting the way OG&E can handle or dispose of its wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. OG&E may be unable to recover these costs from insurance or other regulatory mechanisms. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.

For further discussion of environmental matters that may affect the Company, see "Environmental Laws and Regulations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

We may not be able to recover the costs of our substantial investments in capital improvements and additions.

OG&E's business plan calls for extensive investments in capital improvements and additions, including modernizing existing infrastructure as well as other initiatives. Significant portions of OG&E's facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with environmental requirements or to provide reliable operations. OG&E currently provides service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates OG&E charges, it would not be able to recover the costs associated with its planned extensive investment. This could adversely affect OG&E's financial position and results of operations. While OG&E may seek to limit the impact of any denied recovery by attempting to reduce the scope of its capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.

The regional power market in which OG&E operates has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.

OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority (but not ownership) of OG&E's transmission facilities to the SPP. The SPP has implemented regional day ahead and real-time markets for energy and operating reserves, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. The Company records the SPP Integrated Marketplace transactions as sales or purchases with results reported as Revenues from Contracts with Customers or Cost of Sales in its Consolidated Financial Statements. OG&E's revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation of the SPP Integrated Marketplace by the FERC or the SPP.

Increased competition resulting from restructuring efforts could have a significant financial impact on us and consequently impact our revenue.

We have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes have occurred and additional changes have been proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to possible impairments of assets, a loss of retail customers, impact profit margins and/or increased costs of capital. Any such restructuring could have a significant impact on our consolidated financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our consolidated financial position, results of operations or cash flows.

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Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business, consolidated financial position, results of operations, cash flows and access to capital.

As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, consolidated financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our consolidated financial position, results of operations and cash flows.

We are subject to substantial utility and energy regulation by governmental agencies. Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.

We are subject to substantial regulation from federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain permits, approvals and certifications from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.

The NERC is responsible for the development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. OG&E's plan is to comply with all applicable standards and to expediently correct a violation should it occur. One of OG&E's regulators, the NERC, has comprehensive regulations and standards related to the reliability and security of our operating systems and is continuously developing additional mandatory compliance requirements for the utility industry. The increasing development of NERC rules and standards will increase compliance costs and our exposure for potential violations of these standards.

OPERATIONAL RISKS

Our results of operations may be impacted by disruptions beyond our control.

We are exposed to risks related to performance of contractual obligations by our suppliers. We are dependent on coal and natural gas for much of our electric generating capacity. We rely on suppliers to deliver coal and natural gas in accordance with short- and long-term contracts. We have certain supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal and natural gas to us. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply coal and natural gas to us under certain circumstances, such as in the event of a natural disaster. Deliveries may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment. Failure or delay by our suppliers of coal and natural gas deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.

Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event such as a severe storm, generator or transmission facility outage on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our consolidated financial position, results of operations and cash flows.

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OG&E's electric generation, transmission and distribution assets are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, increased purchase power costs, accidents and third-party liability.  

OG&E owns and operates coal-fired, natural gas-fired, wind-powered and solar-powered generating assets. Operation of electric generation, transmission and distribution assets involves risks that can adversely affect energy output and efficiency levels or that could result in loss of human life, significant damage to property, environmental pollution and impairment of OG&E's operations. Included among these risks are:

•increased prices for fuel and fuel transportation as existing contracts expire;

•facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;

•operator error or safety related stoppages;

•disruptions in the delivery of electricity; and

•catastrophic events such as fires, explosions, tornadoes, floods, earthquakes or other similar occurrences.

The occurrence of any of these events, if not fully covered by insurance, could have a material effect on our consolidated financial position and results of operations. Further, when unplanned maintenance work is required on power plants or other equipment, OG&E will not only incur unexpected maintenance expenses, but it may also have to make spot market purchases of replacement electricity that could exceed OG&E's costs of generation or be forced to retire a generation unit if the cost or timing of the maintenance is not reasonable and prudent. If OG&E is unable to recover any of these increased costs in rates, it could have a material adverse effect on our financial performance.

Changes in technology, regulatory policies and customer electricity consumption may cause our assets to be less competitive and impact our results of operations.

OG&E primarily generates electricity at large central facilities. This method typically results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies or changes in regulatory policies will reduce costs of new technology to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations. OG&E's widespread use of Smart Grid technology allowing for two-way communications between the utility and its customers could enable the entry of technology companies into the interface between OG&E and its customers, resulting in unpredictable effects on our current business.

Reductions in customer electricity consumption, thereby reducing utility electric sales, could result from increased deployment of renewable energy technologies as well as increased efficiency of household appliances, among other general efficiency gains in technology. However, this potential reduction in load would not reduce our need for ongoing investments in our infrastructure to reliably serve our customers. Continued utility infrastructure investment without increased electricity sales could cause increased rates for customers, potentially resulting in further reductions in electricity sales and reduced profitability.

Economic conditions could negatively impact our business and our results of operations.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital. Economic conditions may also impact the valuation of certain long-lived assets, including our investment in unconsolidated affiliates, that are subject to impairment testing, potentially resulting in impairment charges, which could have a material adverse impact on our results of operations.

Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.

In addition, economic conditions, particularly budget shortfalls, could increase the pressure on federal, state and local governments to raise additional funds by increasing corporate tax rates and/or delaying, reducing or eliminating tax credits, grants or other incentives that could have a material adverse impact on our consolidated results of operations and cash flows.

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We are subject to financial risks associated with climate change.

Climate change creates financial risk. Potential regulation associated with climate change legislation could pose financial risks to the Company. On November 4, 2019, President Trump announced that the U.S. has officially notified the United Nations that the U.S. will withdraw from the "Paris Agreement" on climate change after having announced in 2017 that the U.S. would begin negotiations to re-enter the agreement with different terms. The withdrawal would become effective on November 4, 2020. While the "Paris Agreement" is not formally binding, it could lead to increased compliance costs for the Company should the U.S. not officially withdraw. In addition, to the extent that any climate change adversely affects the national or regional economic health through physical impacts or increased rates caused by the inclusion of additional regulatory imposed costs, CO₂ taxes or costs associated with additional regulatory requirements, the Company may be adversely impacted. There are also increasing financial risks for energy companies from private party litigation relating to greenhouse gas emissions and from shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change who may elect in the future to shift some or all of their investments into entities that emit lower levels of greenhouse gases or into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

In addition, we may be subject to climate change lawsuits. Defense costs associated with such litigation can be significant and an adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.

We are subject to cybersecurity risks and increased reliance on processes automated by technology.

In the regular course of our businesses, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our consolidated financial position, results of operations and cash flows.

OG&E operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems which may result in a loss of service to customers and also subject OG&E to financial harm due to the significant expense to repair security breaches or system damage. OG&E's Smart Grid program further increases potential risks associated with cybersecurity attacks. Our generation and transmission systems are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers' operations could also negatively impact our business. If the technology systems were to fail or be breached and not recovered in a timely manner, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on our consolidated financial position, results of operations and cash flows.

Security threats continue to evolve and adapt. We and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems, or confidential data, or to disrupt operations. None of these attempts has individually or in aggregate resulted in a security incident with a material impact on our financial condition or results of operations. Despite implementation of security and control measures, there can be no assurance that we will be able to prevent the unauthorized access of our systems and data, or the disruption of our operations, either of which could have a material impact. Our security procedures, which include among others, virus protection software, cybersecurity and our business continuity planning, including disaster recovery policies and back-up systems, may not be adequate or implemented properly to fully address the adverse effect of cybersecurity attacks on our systems, which could adversely impact our operations.

We maintain property, casualty and cybersecurity insurance that may cover certain resultant physical damage or third-party injuries caused by potential cyber events. However, damage and claims arising from such incidents may exceed the amount of any insurance available and other damage and claims arising from such incidents may not be covered at all. For these reasons, a significant cyber incident could reduce future net income and cash flows and impact financial condition.

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Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities or sustained military campaigns may adversely impact our consolidated financial position, results of operations and cash flows.

The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility and natural gas midstream industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities or sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.

Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, flooding, earthquakes, prolonged droughts and the occurrence of wildfires, as well as seasonal temperature variations may adversely affect our consolidated financial position, results of operations and cash flows.

Weather conditions directly influence the demand for electric power. In OG&E's service area, demand for power peaks during the hot summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Unusually mild weather in the future could reduce our revenues, net income, available cash and borrowing ability. Severe weather, such as tornadoes, thunderstorms, ice storms, wind storms, flooding, earthquakes, prolonged droughts and the occurrence of wildfires may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned, as described above, would be particularly burdensome during a peak demand period. In addition, prolonged droughts could cause a lack of sufficient water for use in cooling during the electricity generating process. Additionally, if climate change exacerbates physical changes in weather, operations may be impacted as discussed above.

FINANCIAL RISKS

Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with our Pension Plan, health care plans and other employee-related benefits may adversely affect our consolidated financial position, results of operations or cash flows.

We have a Pension Plan that covers a significant amount of our employees hired before December 1, 2009. We also have defined benefit postretirement plans that cover a significant amount of our employees hired prior to February 1, 2000. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our results of operations and funding requirements. Based on our assumptions at December 31, 2019, we expect to make future contributions to maintain required funding levels. It has been our practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. We may continue to make voluntary contributions in the future. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.

If the employees who participate in the Pension Plan retire when they become eligible for retirement over the next several years, or if our plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations if we are unable to recover these costs through our electric rates. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our consolidated financial position and results of operations. Those factors are outside of our control.

In addition to the costs of our Pension Plan, the costs of providing health care benefits to our employees and retirees have increased in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees, will continue to rise. The increasing costs and funding requirements with our Pension Plan, health care plans and other employee benefits may adversely affect our consolidated financial position, results of operations or liquidity.

Finally, the Company provides retirement benefits and retiree health care benefits to 80 employees seconded to Enable. 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 $17.3 million. Settlement and curtailment charges

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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.

We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.

Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Over the next three years, 30 percent of our current employees will meet the eligibility requirements to retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.

We are a holding company with our primary assets being investments in our subsidiary and equity investments.

We are a holding company and thus our investments in our subsidiary and unconsolidated affiliate, accounted for under the equity method, are our primary assets. Substantially all of our operations are conducted by our subsidiary and unconsolidated affiliate. Consequently, our operating cash flow and our ability to pay our dividends and service our indebtedness utilizes the operating cash flow of our subsidiary and unconsolidated affiliate and the payment of funds by them to us in the form of dividends or distributions. At December 31, 2019, the Company and its subsidiary had outstanding indebtedness and other liabilities of $6.9 billion. Our subsidiary and unconsolidated affiliate are separate legal entities that have no obligation to pay any amounts due on our indebtedness or to make any funds available for that purpose, whether by dividends or otherwise. In addition, their ability to pay dividends to us depends on any statutory and contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of working capital and other assets. Claims of creditors, including general creditors, of our subsidiary or unconsolidated affiliate on their respective assets will generally have priority over our claims (except to the extent that we may be a creditor of the subsidiaries and our claims are recognized) and claims by our shareholders.

In addition, as discussed above, OG&E is regulated by state utility commissions in Oklahoma and Arkansas as well as a federal regulatory agency which generally possess broad powers to ensure that the needs of the utility customers are being met. To the extent that the state commissions or federal regulatory agency attempt to impose restrictions on the ability of OG&E to pay dividends to us, it could adversely affect our ability to continue to pay dividends.

Certain provisions in our charter documents have anti-takeover effects.

Certain provisions of our certificate of incorporation and bylaws, as well as the Oklahoma corporation statute, may have the effect of delaying, deferring or preventing a change in control of the Company. Such provisions, including those regulating the nomination of directors, limiting who may call special stockholders' meetings and eliminating stockholder action by written consent, together with the possible issuance of preferred stock of the Company without stockholder approval, may make it more difficult for other persons, without the approval of our Board of Directors, to make a tender offer or otherwise acquire substantial amounts of our common stock or to launch other takeover attempts that a stockholder might consider to be in such stockholder's best interest.

We may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.

The terms of the indentures governing our debt securities do not fully prohibit us or our subsidiaries from incurring additional indebtedness. If we are in compliance with the financial covenants set forth in our revolving credit agreements and the indentures governing our debt securities, we may be able to incur substantial additional indebtedness. If we incur additional indebtedness, the related risks that we now face may intensify.

Any reductions in our credit ratings or changes in benchmark interest rates could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.

We cannot assure you that any of our current credit ratings or the ratings of our subsidiaries will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with our 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 our short-term borrowings, but a reduction in our 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 us to post collateral or letters of credit.

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Further, changes in benchmark interest rates, such as the United Kingdom's Financial Conduct Authority's announcement that it intends to phase out the London interbank offered rate, or LIBOR, by the end of 2021, could result in increased financing costs. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index. If the method for calculation of LIBOR changes, if LIBOR is no longer available or if lenders have increased costs due to changes in LIBOR, the Company may incur increases in interest rates on any borrowings and/or may need to renegotiate our credit facilities that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with the new standard that is established.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

We have revolving credit agreements for working capital, capital expenditures, acquisitions and other corporate purposes. The levels of our debt could have important consequences, including the following:

•the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;

•a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and

•our debt levels may limit our flexibility in responding to changing business and economic conditions.

We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our consolidated financial position, results of operations and cash flows.

We are exposed to credit risks in our generation and retail distribution operations. Credit risk includes the risk that counterparties who owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses.

RISKS ASSOCIATED WITH OUR INVESTMENT IN ENABLE MIDSTREAM PARTNERS

The Company does not control Enable and therefore is not able to cause or prevent certain actions by Enable. The general partnership of Enable is equally controlled by the Company and CenterPoint.

Enable has its own governing board; therefore, the Company is not able to exercise control over Enable. Accordingly, the Company is unable to cause or prevent certain actions by Enable. Further, the Company cannot control the actions of the other general partner, CenterPoint. Our interests may not align with those of CenterPoint, and this lack of control could adversely impact our investment in Enable.

A portion of our earnings and operating cash flows are based on the performance of Enable. If any of the following risks were to occur, our business, financial condition, results of operations or cash flows could be materially adversely affected.

Our operating cash flow is derived partially from cash distributions we receive from Enable.

Our operating cash flow is derived partially from cash distributions we receive from Enable. The amount of cash Enable can distribute on its units principally depends upon the amount of cash generated from its operations, which will fluctuate from quarter to quarter based on, among other things:

•the fees and gross margins it realizes with respect to the volume of natural gas, NGLs and crude oil that it handles;

•the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;

•the volume of natural gas, NGLs and crude oil it gathers, compresses, treats, dehydrates, processes, fractionates, transports and stores;

•the relationship among prices for natural gas, NGLs and crude oil;

•cash calls and settlements of hedging positions;

•margin requirements on open price risk management assets and liabilities;

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•the level of competition from other companies offering midstream services;

•adverse effects of governmental and environmental regulation;

•the level of its operation and maintenance expenses and general and administrative costs; and

•prevailing economic conditions.

In addition, the actual amount of cash Enable will have available for distribution will depend on other factors, including:

•the level and timing of capital expenditures it makes;

•the cost of acquisitions;

•its debt service requirements and other liabilities;

•fluctuations in working capital needs;

•its ability to borrow funds and access capital markets;

•restrictions contained in its debt agreements;

•the amount of cash reserves established by its general partner;

•distributions paid on its Series A Preferred Units; and

•other business risks affecting its cash levels.

Enable's contracts are subject to renewal risks.

As contracts with Enable's existing suppliers and customers expire, Enable generally seeks to negotiate extensions or renewals of those contracts or enters into new contracts with other suppliers and customers. Enable may be unable to extend or renew existing contracts or enter into new contracts on favorable commercial terms, if at all. Depending on prevailing market conditions at the time of an extension or renewal, gathering and processing customers with fee-based contracts may desire to enter into contracts under different fee arrangements, and gathering and processing customers with contracts that contain minimum volume commitments may desire to enter into contracts without minimum volume commitments. Likewise, Enable's transportation and storage customers may choose not to extend or renew expiring contracts based on the economics of the related areas of production. To the extent Enable is unable to renew or replace its expiring contracts on terms that are favorable to Enable, if at all, or successfully manage its overall contract mix over time, its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected.

Enable depends on a small number of customers for a significant portion of its gathering and processing revenues and its transportation and storage revenues. The loss of, or reduction in volumes from, these customers could result in a decline in sales of its gathering and processing or transportation and storage services and adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.

For the year ended December 31, 2019, 57 percent of Enable's natural gas gathered volumes were attributable to the affiliates of Continental Resources, Inc., Vine Oil and Gas, GeoSouthern Energy Corporation, XTO Energy Inc. and Tapstone Corporation and 48 percent of its transportation and storage service revenues were attributable to affiliates of CenterPoint, Spire Inc., Continental Resources, Inc., American Electric Power Co. and the Company. The loss of all or even a portion of the gathering and processing or transportation and storage services for any of these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us.

The businesses of Enable are dependent, in part, on the drilling and production decisions of others.

The businesses of Enable are dependent on the drilling and production of natural gas and crude oil. Enable has no control over the level of drilling activity in its areas of operation, or the amount of natural gas, NGLs and crude oil reserves associated with wells connected to its systems. In addition, as the rate at which production from wells currently connected to its system naturally declines over time, its gross margin associated with those wells will also decline. To maintain or increase throughput levels on its gathering and transportation systems and the asset utilization rates at its natural gas processing plants, its customers must continually obtain new natural gas, NGLs and crude oil supplies. The primary factors affecting its ability to obtain new supplies of natural gas, NGLs and crude oil and attract new customers to its assets are the level of successful drilling activity near its systems, its ability to compete for volumes from successful new wells and its ability to expand its capacity as needed. If Enable is not able to obtain new supplies of natural gas, NGLs and crude oil to replace the natural decline in volumes from existing wells, throughput on its gathering, processing, transportation and storage facilities would decline, which could

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adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us. Enable has no control over producers or their drilling and production decisions, which are affected by, among other things:

•the availability and cost of capital;

•prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;

•demand for natural gas, NGLs and crude oil;

•levels of reserves;

•geological considerations;

•environmental or other governmental regulations, including the availability of drilling permits, the regulation of hydraulic fracturing and the regulation of air emissions; and

•the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of new natural gas, NGLs and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond its control. Because of these and other factors, even if new reserves are known to exist in areas served by Enable's assets, producers may choose not to develop those reserves. Declines in natural gas, NGLs or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. Sustained low natural gas, NGLs or crude oil prices could also lead producers to shut in production from their existing wells. Sustained reductions in exploration or production activity in its areas of operation could lead to further reductions in the utilization of its systems, which could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.

In addition, it may be more difficult to maintain or increase the current volumes on its gathering systems and in its processing plants, as several of the formations in the unconventional resource plays in which Enable operates generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, it may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time.

Enable's industry is highly competitive and increased competitive pressure could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.

Enable competes with similar enterprises in its respective areas of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Competitors include public and private energy companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than Enable. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services Enable provides to its customers. Excess pipeline capacity in the regions served by Enable's interstate pipelines could also increase competition and adversely impact the ability to renew or enter into new contracts with respect to available capacity when existing contracts expire. In addition, Enable's customers that are significant producers of natural gas or crude oil may develop their own gathering, processing, transportation and storage systems in lieu of using Enable. Enable's ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, transportation and storage services. All of these competitive pressures could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.

Enable derives a substantial portion of its gross margin from subsidiaries through which it holds a substantial portion of its assets.

Enable derives a substantial portion of its gross margin from, and holds a substantial portion of its assets through, its subsidiaries. As a result, it depends on distributions from its subsidiaries in order to meet its payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide Enable with funds for its payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit its subsidiaries' ability to make payments or other distributions, and its subsidiaries could agree to contractual restrictions on its ability to make distributions.

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The right by Enable to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary's creditors, including trade creditors. In addition, even if Enable were a creditor of any subsidiary, its rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by them.

The amount of cash Enable has available for distribution to its limited partners depends primarily on its cash flow rather than on its profitability, which may prevent Enable from making distributions, even during periods in which it records net income.

The amount of cash Enable has available for distribution depends primarily upon its cash flow rather than on profitability. Profitability is affected by non-cash items but cash flow is not. As a result, Enable may make cash distributions during periods when it records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.

Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates.

Enable's business plan calls for investment in capital improvements and additions. Capital expenditures could range from approximately $160 million to $240 million and maintenance capital could range from approximately $110 million to $130 million for the year ending December 31, 2020.

The construction of additions or modifications to Enable's existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond its control and may require the expenditure of significant amounts of capital, which may exceed estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating, processing, compression or other facilities is subject to construction cost overruns due to labor costs, costs and availability of equipment and materials such as steel, labor shortages or weather or other delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner, if at all, or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. Moreover, revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if an existing pipeline is expanded or a new pipeline is constructed, the construction may occur over an extended period of time, and Enable may not receive any material increases in revenues or cash flows until the project is completed. In addition, Enable may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, the new facilities may not be able to achieve an expected investment return, which could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.

In connection with its capital investments, Enable may estimate, or engage a third party to estimate, potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent Enable relies on estimates of future production in deciding to construct additions to its systems, those estimates may prove to be inaccurate either in volume or timing due to numerous uncertainties inherent in estimating future production. To the extent estimates of the volume of new production are inaccurate, new facilities may not be able to attract sufficient throughput to achieve expected investment return, which could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us. To the extent estimates in the timing of new production are inaccurate, new facilities may be constructed in advance of the actual need for capacity or may not be constructed in time to accommodate volume flows, which could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable, and it may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected.

Natural gas, NGLs and crude oil prices are volatile, and changes in these prices could adversely affect Enable's financial position, results of operations and its ability to make cash distributions to unitholders, including us.

Enable's financial position, results of operations and ability to make cash distributions to us could be negatively affected by adverse changes in the prices of natural gas, NGLs and crude oil depending on factors that are beyond its control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and

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other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, liquefied natural gas, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.

Enable's natural gas processing arrangements expose Enable to commodity price fluctuations. In 2019, 4 percent, 26 percent and 70 percent of Enable's processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids and fee-based, respectively. If the price at which Enable sells natural gas or NGLs is less than the cost at which it purchases natural gas or NGLs under these arrangements, then its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected. Enable uses certain derivative instruments to manage its commodity price risk exposures.

At any given time, Enable's overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that it is a net buyer of natural gas) and a net long position in NGLs (meaning that it is a net seller of NGLs). As a result, Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected to the extent the price of NGLs decreases in relation to the price of natural gas.

Enable's exposure to credit risks of its customers, and any material nonpayment or nonperformance by its customers could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.

Some of Enable's customers may experience financial problems that could have a significant effect on its customers' creditworthiness. Severe financial problems encountered by its customers could limit Enable's ability to collect amounts owed to it, or to enforce performance of obligations under contractual arrangements. In addition, many of Enable's customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of its customers' liquidity and limit its customers' ability to make payments or perform on obligations to Enable. Furthermore, some of Enable's customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to Enable. Financial problems experienced by its customers could result in the impairment of its assets, reduction of its operating cash flows and may also reduce or curtail its customers' future use of its products and services, which could reduce revenues.

Enable provides certain transportation and storage services under fixed-price "negotiated rate" contracts that are not subject to adjustment, even if the cost to perform such services exceeds the revenues received from such contracts, and, as a result, costs could exceed revenues received under such contracts.

Enable has been authorized by the FERC to provide transportation and storage services at its facilities at negotiated rates. As of December 31, 2019, approximately 37 percent of Enable's aggregate contracted firm transportation capacity on EGT and MRT and 93 percent of its aggregate contracted firm storage capacity on EGT and MRT was subscribed under such "negotiated rate" contracts. The majority of Enable's aggregate contracted firm transportation capacity and all of Enable's aggregate contracted firm storage capacity under negotiated rate contracts on MRT are subject to FERC rate case approval. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by the FERC. Successful recovery of any shortfall of revenue, representing the difference between "recourse rates" (if higher) and negotiated rates, is not assured under current FERC policies. If Enable's costs increase and it is not able to recover any shortfall of revenue associated with its negotiated rate contracts, the cash flow realized by its systems could decrease and, therefore, the cash Enable has available for distribution to its unitholders, including us, could also decrease.

If third-party pipelines and other facilities interconnected to Enable's gathering, processing or transportation facilities become partially or fully unavailable to Enable for any reason, Enable's financial position, results of operations and its ability to make cash distributions to unitholders, including us, could be adversely affected.

Enable depends upon (i) third-party pipelines to deliver natural gas to, and take natural gas from, its natural gas transportation systems, (ii) third-party pipelines and other facilities to take crude oil and produced water from its crude oil and produced water gathering systems, and, in some cases, (iii) third-party facilities to process natural gas from its gathering systems. It also depends on third-party facilities to transport and fractionate NGLs that are delivered to the third party at the tailgates of its processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual

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components for end-use sale. For example, an outage or disruption on certain pipelines or fractionators operated by a third party could result in the shutdown of certain of Enable's processing plants and gathering systems, and a prolonged outage or disruption could ultimately result in a reduction in the volume of natural gas Enable gathers and NGLs it is able to produce. Additionally, Enable depends on third parties to provide electricity for compression at many of its facilities. Since it does not own or operate any of these third-party pipelines or other facilities, continuing operation of those facilities is not within its control. If any of these third-party pipelines or other facilities become partially or fully unavailable to Enable for any reason, its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected.

Enable does not own all of the land on which its pipelines and facilities are located, which could disrupt its operations.

Enable does not own all of the land on which its pipelines and facilities have been constructed, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate. Enable may obtain the rights to construct and operate its pipelines for a specific period of time on lands owned by governmental agencies, American Indian tribes or other third parties, including on American Indian allotments, title to which is held in trust by the U.S. A loss of these rights, through its inability to renew right-of-way contracts or otherwise, could cause a cease in operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere, and adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.

Enable conducts a portion of its operations through joint ventures, which subjects them to additional risks that could adversely affect the success of its operations and financial position, results of operations and ability to make cash distributions to unitholders, including us.

Enable conducts a portion of its operations through joint ventures with third parties, including Enbridge Inc., DCP Midstream Partners, LP, CVR Energy, Inc., Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering, LLC. It may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The performance of these third-party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside the control of Enable. If these parties do not satisfy their obligations under these arrangements, Enable's business may be adversely affected.

The joint venture arrangements of Enable may involve risks not otherwise present when operating assets directly, including, for example:

•joint venture partners may share certain approval rights over major decisions;

•joint venture partners may not pay their share of the obligations, leaving Enable liable for the liabilities created as a result of those unpaid obligations;

•possible inability to control the amount of cash it will receive from the joint venture;

•it may incur liabilities as a result of an action taken by its joint venture partners;

•it may be required to devote significant management time to the requirements of and matters relating to the joint ventures;

•its insurance policies may not fully cover loss or damage incurred by both them and its joint venture partners in certain circumstances;

•its joint venture partners may be in a position to take actions contrary to its instructions or requests or contrary to its policies or objectives; and

•disputes between them and its joint venture partners may result in delays, litigation or operational impasses.

The risks described above or the failure to continue joint ventures or to resolve disagreements with joint venture partners could adversely affect Enable's ability to transact the business that is the subject of such joint venture, which would in turn adversely affect its financial position and results of operations ability to make cash distributions to unitholders, including us. The agreements under which certain joint ventures were formed may subject them to various risks, limit the actions it may take with respect to the assets subject to the joint venture and require them to grant rights to its joint venture partners that could limit its ability to benefit fully from future positive developments. Some joint ventures require Enable to make significant capital expenditures. If it does not timely meet its financial commitments or otherwise do not comply with its joint venture agreements, its rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of its joint venture partners may have substantially greater financial resources than Enable has and it may not be able to secure the funding necessary to participate in operations its joint venture partners propose, thereby reducing its ability to benefit from the joint venture.

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Under certain circumstances, Enbridge Inc. could have the right to purchase an ownership interest in SESH at fair market value.

Enable owns a 50 percent ownership interest in SESH. The remaining 50 percent ownership interests are held by Enbridge Inc. As of December 31, 2019, CenterPoint owns 53.7 percent of Enable's common units, 100.0 percent of its Series A Preferred Units and a 40 percent economic interest in Enable GP, LLC. Pursuant to the terms of the limited liability company agreement of SESH, as amended (the SESH LLC Agreement), if, at any time, CenterPoint has a right to receive less than 50 percent of Enable's distributions through its interests in Enable and in the general partner, or does not have the ability to exercise certain control rights, Enbridge Inc. could have the right to purchase Enable's interest in SESH at fair market value, subject to certain exceptions.

An impairment of long-lived assets, including intangible assets, equity method investments or goodwill could reduce Enable's earnings.

Long-lived assets, including intangible assets with finite useful lives and property, plant and equipment, are evaluated for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment of long-lived assets is recognized if the carrying amount is not recoverable and exceeds fair value.

Equity method investments are evaluated for impairment when events or circumstances indicate that the carrying value of the investment might not be recoverable. An impairment of an equity method investment is recognized if the fair value of the investment as a whole, and not the underlying assets, has declined and the decline is other than temporary. An example of an investment that Enable accounts for under the equity method is its investment in SESH. If Enable enters into additional joint ventures, it could have additional equity method investments.

Goodwill is evaluated for impairment on an annual basis as well as when events or circumstances change that would more likely than not reduce the fair value of a reporting unit to below its carrying amount. An impairment of goodwill is recognized if the carrying value of a reporting unit exceeds its fair value. Enable recorded an impairment to goodwill of $86 million during the year ended December 31, 2019. As of December 31, 2019, Enable has goodwill of $12 million associated with the Ark-La-Tex Basin reporting unit, which is included in the gathering and processing segment as a result of the acquisition of Align Midstream, LLC in the fourth quarter of 2017.

Enable could experience future events or circumstances that result in an impairment of long-lived assets, including intangible assets, equity method investments, or goodwill. If Enable recognizes an impairment, it would take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. As a result, an impairment could have an adverse effect on Enable's results of operations and its ability to satisfy the financial ratios or other covenants under its existing or future debt agreements.

Enable's business involves many hazards and operational risks, some of which may not be fully covered by insurance. Insufficient insurance coverage and increased insurance costs could adversely affect its financial position, results of operations or ability to make cash distributions to unitholders, including us.

Enable's operations are subject to all of the risks and hazards inherent in the gathering, processing, transportation and storage of natural gas and crude oil, including:

•damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties;

•inadvertent damage from construction, vehicles and farm and utility equipment;

•leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;

•ruptures, fires and explosions; and

•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of its operations. A natural disaster or other hazard affecting the areas in which it operates could adversely affect Enable's results of operations. Enable is not fully insured against all risks inherent in its business. Enable currently has general liability and property insurance in place to cover certain of its facilities in amounts that it considers appropriate. Such policies are subject to certain limits and deductibles. Enable has business interruption insurance coverage for some but not all of its operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of Enable's facilities may not be sufficient to restore the loss or damage without adversely affecting its financial position, results of operations and ability to make cash distributions to its unitholders, including us.

The use of derivative contracts by Enable and its subsidiaries in the normal course of business could result in financial losses that could adversely affect its financial position, results of operations and its ability to make cash distributions to unitholders, including us.

Enable and its subsidiaries periodically use derivative instruments, such as swaps, options, futures and forwards, to manage its commodity and financial market risks. Enable and its subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Failure to attract and retain an appropriately qualified workforce could adversely impact Enable's results of operations.

Enable's business is dependent on its ability to recruit, retain and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Enable's costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Enable's ability to manage and operate its business. If Enable is unable to successfully attract and retain an appropriately qualified workforce, its results of operations could be negatively affected.

As of December 31, 2019, Enable has 80 employees who are participants under OGE Energy Corp.'s defined benefit and retiree medical plans, who are seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy Corp. If seconding is terminated, employees of OGE Energy Corp. that Enable determines to hire are under no obligation to accept Enable's offer of employment on the terms Enable provides, or at all.

Enable's ability to grow is dependent in part on its ability to access external financing sources on acceptable terms.

Enable expects its operating subsidiaries will distribute all of their available cash to Enable and that it will distribute all of its available cash to its unitholders. As a result, Enable expects that it and its operating subsidiaries will rely significantly upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. To the extent Enable or its operating subsidiaries are unable to finance growth externally or through internally generated cash flows, Enable's and its operating subsidiaries' cash distribution policy may significantly impair Enable's and its operating subsidiaries' ability to grow. In addition, because Enable and its operating subsidiaries distribute all available cash, Enable's and its operating subsidiaries' growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

To the extent Enable issues additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk it will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that Enable has to distribute on each unit. There are no limitations in the partnership agreement on its ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by Enable or its operating subsidiaries to finance its growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that its operating subsidiaries have to distribute to it, and thus that it has to distribute to its unitholders, including us.

Enable depends in part on access to the capital markets and other external financing sources to fund its expansion capital expenditures, although Enable has also increasingly relied on cash flow generated from its operations to fund its

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expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable's common units are yield-based securities, rising market interest rates could impact the relative attractiveness of its common units to investors. As a result of capital market volatility, Enable may be unable to issue equity or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.

Enable's merger and acquisition activities may not be successful or may result in completed acquisitions that do not perform as anticipated, which could adversely affect its financial position, results of operations or future growth.

From time to time, Enable has made, and it intends to continue to make, acquisitions of businesses and assets. Such acquisitions involve substantial risks, including the following:

•acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;

•acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;

•it may assume liabilities that were not disclosed to it, that exceed its estimates, or for which its rights to indemnification from the seller are limited;

•it may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and

•acquisitions, or the pursuit of acquisitions, could disrupt its ongoing businesses, distract management, divert resources and make it difficult to maintain its current business standards, controls and procedures.

In addition, Enable's growth strategy includes, in part, the ability to make acquisitions on economically acceptable terms. If Enable is unable to make acquisitions or if its acquisitions do not perform as anticipated, Enable's future growth may be adversely affected.

Enable and its operating subsidiaries' debt levels may limit their flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2019, Enable had approximately $4.0 billion of long-term debt outstanding, excluding the premiums, discounts and unamortized debt expense on senior notes. In addition, as of December 31, 2019, Enable had $155.0 million outstanding under its commercial paper program and $250.0 million outstanding under its EOIT senior notes, excluding unamortized premium. Enable also has a $1.75 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, with no borrowings outstanding, of which approximately $1.59 billion in borrowing capacity was available as of December 31, 2019. As of January 31, 2020, Enable had $119 million outstanding under its commercial paper program and $1.63 billion of available capacity under its revolving credit facility. Enable has the ability to incur additional debt, subject to limitations in its credit facilities. The levels of debt could have important consequences, including the following:

•the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;

•a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;

•the debt level will make Enable more vulnerable to competitive pressures or a downturn in the business or the economy generally; and

•the debt level may limit flexibility in responding to changing business and economic conditions.

Enable's and its operating subsidiaries' ability to service their debt will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions, commodity prices and financial, business, regulatory and other factors, some of which are beyond its control. If operating results are not sufficient to service Enable's and its operating subsidiaries' current or future indebtedness, Enable and its subsidiaries may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all.

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Enable's credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond its control, which could adversely affect its financial condition, results of operations and ability to make cash distributions to its unitholders, including us.

Enable's credit facilities contain customary covenants that, among other things, limit the ability to:

•permit its subsidiaries to incur or guarantee additional debt;

•incur or permit to exist certain liens on assets;

•dispose of assets;

•merge or consolidate with another company or engage in a change of control;

•enter into transactions with affiliates on non-arm's length terms; and

•change the nature of its business.

Enable's credit facilities also require it to maintain certain financial ratios. Its ability to meet those financial ratios can be affected by events beyond its control, and assurance it will meet those ratios cannot be guaranteed. In addition, its credit facilities contain events of default customary for agreements of this nature.

Enable's ability to comply with the covenants and restrictions contained in its credit facilities may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, its ability to comply with these covenants may be impaired. If any of the restrictions, covenants, ratios or tests in its credit facilities is violated, a significant portion of its indebtedness may become immediately due and payable. In addition, its lenders' commitments to make further loans to Enable under the revolving credit facility may be suspended or terminated. Enable might not have, or be able to obtain, sufficient funds to make these accelerated payments.

Affiliates of Enable's general partner, including CenterPoint and the Company, may compete with Enable, and neither the general partner nor its affiliates have any obligation to present business opportunities to Enable.

Under Enable's omnibus agreement, both CenterPoint and the Company are prohibited from, directly or indirectly, owning, operating, acquiring or investing in any business engaged in midstream operations located within the U.S., other than through Enable. This requirement applies to both CenterPoint and the Company for so long as either CenterPoint or the Company holds any interest in Enable's general partner or at least 20 percent of its common units. However, if CenterPoint or the Company acquires any business with midstream operations assets that have a value in excess of $50.0 million (or $100.0 million in the aggregate with such party's other acquired midstream operations assets that have not been offered to Enable), the acquiring party will be required to offer to Enable such assets for such value. If Enable does not purchase such assets, the acquiring party will be free to retain and operate such midstream assets, so long as the value of the assets does not reach certain thresholds.

As a result, under the circumstances described above, CenterPoint and the Company have the ability to construct or acquire assets that directly compete with Enable's assets. Pursuant to the terms of Enable's partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to Enable's general partner or any of its affiliates, including its executive officers and directors and CenterPoint and the Company. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for Enable will not have any duty to communicate or offer such opportunity to Enable. Any such person or entity will not be liable to Enable or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to Enable. This may create actual and potential conflicts of interest between Enable and affiliates of its general partner and result in less than favorable treatment of Enable and its common unitholders.

If Enable fails to maintain an effective system of internal controls, then it may not be able to accurately report financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in its financial reporting, which would harm Enable's business and the trading price of its common units.

Effective internal controls are necessary for Enable to provide reliable financial reports, prevent fraud and operate successfully as a public company. If its efforts to maintain an effective system of internal controls are not successful, it is unable to maintain adequate controls over its financial processes and reporting in the future or it is unable to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, its operating results could be harmed or fail to meet its reporting obligations. Ineffective internal controls also could cause investors to lose confidence in its reported financial information, which would likely have a negative effect on the trading price of Enable's common units.

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Cybersecurity attacks or other disruptions of Enable's systems, networks and technology could adversely impact Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us.

Enable has become increasingly dependent on the systems, networks and technology that it uses to conduct almost all aspects of its business, including the operation of its gathering, processing, transportation and storage assets, the recording of commercial transactions and the reporting of financial information. Enable depends on both its own systems, networks and technology as well as the systems, networks and technology of its vendors, customers and other business partners. Any disruption of these systems, networks and technology could disrupt the operation of Enable's business. Disruptions can result from a variety of causes, including natural disasters, the failure of software or equipment and manmade events, such as cybersecurity attacks or information security breaches. Cybersecurity attacks and information security breaches could result in the unauthorized use of confidential, proprietary or other information and in the disruption of Enable's critical business functions and operations, adversely affecting its reputation and subjecting it to possible legal claims and liability. In addition, Enable is not fully insured against all cybersecurity risks.

As cybersecurity attacks continue to evolve, Enable may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerabilities to cybersecurity attacks. In particular, Enable's implementation of various procedures and controls to monitor and mitigate security threats and to increase security for its personnel, information, facilities and infrastructure may result in increased capital and operating costs. To date Enable has not experienced any material losses relating to cybersecurity attacks; however, there can be no assurance that it will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us.

Terrorist attacks or other physical security threats could adversely affect Enable's business.

Enable's gathering, processing, transportation and storage assets may be targets of terrorist activities or other physical security threats that could disrupt its ability to conduct its business. It is possible that any of these occurrences, or a combination of them, could adversely affect Enable's financial position, results of operations and ability to make cash distributions to unitholders, including us. In addition, any physical damage to Enable's assets resulting from acts of terrorism may not be fully covered by Enable's insurance.

Enable may be unable to obtain or renew permits necessary for its operations, which could inhibit its ability to do business.

Performance of its operations require it obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of Enable's compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect its ability to initiate or continue operations at the affected location or facility and on its financial condition, results of operations and ability to make cash distributions to unitholders, including us.

Additionally, in order to obtain permits and renewals of permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and American Indian tribal lands. Certain approval procedures may require preparation of archaeological surveys, wetland delineations, endangered species surveys and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements may be expensive and may significantly lengthen the time required to prepare applications and to receive authorizations and consequently could disrupt Enable's project construction schedules.

Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect Enable's financial position, results of operations and its ability to make cash distributions to unitholders, including us.

Enable is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay or increase costs of construction, restrict or limit the output of certain facilities and/or require additional

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pollution control equipment and otherwise increase costs. For instance, in May 2016, the EPA issued final standards governing methane emissions imposing more stringent controls on methane and volatile organic compounds emissions at new and modified oil and natural gas production, processing, storage and transmission facilities. These rules have required changes to Enable's operations, including the installation of new equipment to control emissions. Most recently, in August 2019, the EPA proposed amendments to the 2016 standards, and legal challenges to any final rulemaking that rescinds the 2016 standards are expected. As a result, Enable cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, several states are pursuing similar measures to regulate emissions of methane from new and existing sources. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations. Future federal and state regulations relating to Enable's gathering and processing, transmission and storage operations remain a possibility and could result in increased compliance costs on Enable's operations. Furthermore, if new or more stringent federal, state or local legal restrictions are adopted in areas where Enable's oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which could adversely affect demand for Enable's services to those customers.

There is inherent risk of the incurrence of environmental costs and liabilities in Enable's operations due to the handling of natural gas, NGLs, crude oil and produced water as well as air emissions related to its operations and historical industry operations and waste disposal practices. These matters are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact business activities in many ways, such as restricting the handling or disposing of wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from its properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under its control. Private parties, including the owners of the properties through which its gathering and transportation systems pass and facilities where its wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non- compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of its pipelines could subject them to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Enable may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. Further, stricter requirements could negatively impact its customers' production and operations, resulting in less demand for its services.

Increased regulation of hydraulic fracturing and waste water injection wells could result in reductions or delays in natural gas production by Enable's customers, which could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.

Hydraulic fracturing is a common practice that is used by many of Enable's customers to stimulate production of natural gas and crude oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, certain federal agencies have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process. The EPA has also issued regulations and guidance for hydraulic fracturing operations under several statutes.

Some states have adopted, and other states have considered adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, in some cases banning hydraulic fracturing entirely. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Enable's oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which activities could adversely affect demand for Enable's services to those customers.

State and federal regulatory agencies have also focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may

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also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies have adopted their regulations or issued orders to address induced seismicity. For example, the OCC has implemented volume reduction plans, and at times required shut-ins, for disposal wells injecting wastewater from oil and gas operations into the Arbuckle formation. In February 2018, the OCC revised well completion seismicity guidelines for operators in the South Central Oklahoma Oil Province and the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties to reduce the threshold of seismic readings required to suspend hydraulic fracturing operations in some circumstances. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. Enable cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal. Additional legislation or regulation could also lead to operational delays or increased operating costs for Enable's customers, which in turn could reduce the demand for Enable's services.

Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing or other regulatory mechanisms.

Enable and its customers' operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, adversely impact Enable's results of operations and ability to make cash distributions to unitholders, including us, limit the areas in which oil and natural gas production may occur and reduce demand for the products and services Enable provides.

There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases as well as to restrict or eliminate such future emissions. As a result, Enable's operations as well as the operations of its oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of greenhouse gases.

In the U.S., no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gas emissions constitute a pollutant under the Clean Air Act, the EPA has adopted regulations that, among other things, increase permit reviews and monitoring of facilities emitting greenhouse gases and or restrict the emissions of greenhouse gases. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions. On November 4, 2019, President Trump announced that the U.S. has officially notified the United Nations that the U.S. will withdraw from the "Paris Agreement" on climate change after having announced in 2017 that the U.S. would 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.

Governmental, scientific and public concern over the threat of climate change arising from greenhouse gas emissions has resulted in increasing political risks in the U.S., including climate change related pledges, made by certain candidates seeking the office of the President of the U.S. in 2020, to take actions banning hydraulic fracturing of oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

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The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for greenhouse gas emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate greenhouse gas emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for Enable's services and products. Additionally, political, litigation and financial risks may result in Enable's oil and natural gas customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes or impairing their ability to continue to operate in an economic manner, which also could reduce demand for Enable's services and products. One or more of these developments could have a material adverse effect on Enable's business, financial condition, results of operations and ability to make cash distributions to unitholders, including us.

Finally, many scientists have concluded that increasing concentrations of greenhouse gases in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect Enable's results of operations and ability to make cash distributions to unitholders, including us.

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

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

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

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

•certification and construction of new facilities;

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

•maintenance of accounts and records;

•acquisition and disposition of facilities;

•initiation and discontinuation of services;

•depreciation and amortization policies;

•conduct and relationship with certain affiliates;

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

•various other matters.

Should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 to impose penalties for current violations of up to approximately $1.3 million per day for each violation and possible criminal penalties of up to approximately $1.3 million per violation.

The FERC's jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to expansions, lateral and other facilities and abandonment of facilities and services. Prior to commencing construction of significant new interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or an order amending its existing certificate, from the FERC. Certain minor expansions are authorized by blanket certificates that the FERC has issued by rule. Typically, a significant expansion project requires

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review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any failure by an agency to issue sufficient authorizations or permits in a timely manner for one or more of these projects may mean that Enable will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that Enable did not anticipate. Enable's inability to obtain sufficient permits and authorizations in a timely manner could materially and negatively impact the additional revenues expected from these projects.

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

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

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

Enable's operations may also be subject to regulation by state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect its financial position, results of operations and ability to make cash distributions to unitholders, including us.

The pipeline operations of Enable that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural gas and transportation services. State and local regulations generally focus on safety, environmental and, in some circumstances, prohibition of undue discrimination among shippers. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. The effect, if any, such changes might have on operations cannot be predicted, but Enable could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect the business. Any such state or local regulation could have an adverse effect on the business and the financial position, results of operations and ability to make cash distributions to unitholders, including us.

A change in the jurisdictional characterization of some of Enable's assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

Enable's natural gas gathering and intrastate transportation systems are generally exempt from the jurisdiction of the FERC under the Natural Gas Act, and its crude oil gathering system in the Anadarko Basin is generally exempt from the jurisdiction of FERC under the Interstate Commerce Act. Nevertheless, FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC's policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, it cannot be assured that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business. Although the FERC has not made a formal determination with respect to all of Enable's facilities it considers to be engaged in natural gas gathering or a formal determination with respect to its facilities that it considers to be engaged in intrastate crude oil gathering, Enable believes that its natural gas gathering facilities meet the

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traditional tests that the FERC has used to determine that a pipeline is a natural gas gathering pipeline and Enable's intrastate crude oil gathering facilities meet the traditional tests that the FERC has used to determine that a pipeline is not engaged in interstate crude oil transportation. The distinction between FERC-regulated facilities, however, has been the subject of substantial litigation, and the FERC determines whether facilities are subject to regulation under the Natural Gas Act or the Interstate Commerce Act on a case-by-case basis, so the classification and regulation of its facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, could adversely affect Enable's financial condition, results of operations and ability to make cash distributions to its unitholders, including us. In addition, if any of Enable's facilities were found to have provided services or otherwise operated in violation of the Natural Gas Act, Natural Gas Policy Act or Interstate Commerce Act regulations, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by the FERC.

Natural gas gathering and intrastate crude oil gathering may receive greater regulatory scrutiny at the state level; therefore, these operations could be adversely affected should it become subject to the application of state regulation of rates and services. Enable's gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. The effect, if any, such changes might have on its operations cannot be predicted, but additional capital expenditures could be required and increased costs could be incurred depending on future legislative and regulatory changes.

Enable may incur significant costs and liabilities resulting from compliance with pipeline safety laws and regulations, pipeline integrity and other similar programs and related repairs.

Certain of Enable's pipeline operations are subject to pipeline safety laws and regulations. The U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration regulates safety requirements for the design, construction, maintenance and operation of its jurisdictional natural gas and hazardous liquids pipeline facilities. All of Enable's interstate and intrastate natural gas transportation pipeline facilities are Pipeline and Hazardous Materials Safety Administration jurisdictional and certain of Enable's natural gas gathering, NGLs and crude oil pipeline facilities are Pipeline and Hazardous Materials Safety Administration jurisdictional. Among other things, these laws and regulations require pipeline operators to develop integrity management programs, including more frequent inspections and other measures, for pipelines located in “high consequence areas.” The regulations require operators, including Enable, to, among other things:

•perform ongoing assessments of pipeline integrity;

•develop a baseline plan to prioritize the assessment of a covered pipeline segment;

•identify and characterize applicable threats that could impact a high consequence area;

•improve data collection, integration, and analysis;

•repair and remediate pipelines as necessary; and

•implement preventive and mitigating action.

Failure to comply with the Pipeline and Hazardous Materials Safety Administration or comparable state pipeline safety regulations could result in a number of consequences which may have an adverse effect on Enable's operations. Enable incurs significant costs associated with its compliance with existing Pipeline and Hazardous Materials Safety Administration and comparable state pipeline regulations. Enable incurred maintenance capital expenditures and operation and maintenance expenses of $79.0 million in 2019 and currently estimates that it will incur maintenance capital expenditures and operation and maintenance expenses of up to $84.0 million in 2020 under its pipeline safety program, including costs related to integrity assessments and repairs, threat and risk analyses, implementing preventative and mitigative measures, and conducting activities to support the maximum allowable operating pressure for gas pipelines or the maximum operating pressure for hazardous liquid pipelines. Enable may incur significant cost associated with repair, remediation, preventive and mitigation measures associated with its integrity management programs for pipelines that are not currently subject to regulation by the Pipeline and Hazardous Materials Safety Administration.

Changes to existing pipeline safety regulations may result in increased operating and compliance costs. For example, the Pipeline and Hazardous Materials Safety Administration published three final rules on pipeline safety in October 2019. Enable is in the process of assessing the impact of these rules on its future costs of operations and revenue from operations. The Pipeline and Hazardous Materials Safety Administration is also working on two additional rules related to gas pipeline safety, which are expected to be effective by mid-2020. The adoption of these or other regulations requiring more comprehensive or stringent safety standards could require Enable to install new or modified safety controls, pursue new capital projects or

33

conduct maintenance programs on an accelerated basis, all of which could require Enable to incur increased and potentially significant operational costs.

Financial reform regulations under the Dodd-Frank Act could adversely affect Enable's ability to use derivative instruments to hedge risks associated with its business.

At times, Enable may hedge all or a portion of its commodity risk and its interest rate risk. The federal government regulates the derivatives markets and entities, including businesses like Enable, that participate in those markets through the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the Commodity Futures Trading Commission and the Securities and Exchange Commission to promulgate rules and regulations implementing the legislation. Under the Commodity Futures Trading Commission's regulations, Enable is subject to reporting and recordkeeping obligations for transactions involving non-financial swap transactions. The Commodity Futures Trading Commissions initially adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, but these rules were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. In December 2013, the Commodity Futures Trading Commission published a notice of proposed rulemaking designed to implement new position limits regulation and in December 2016, the Commodity Futures Trading Commission's re-proposed regulations for position limits. The ultimate form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain.

The Commodity Futures Trading Commission has imposed mandatory clearing requirements on certain categories of swaps, including certain interest rate swaps, but has exempted derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement, where a counterparty such as Enable has required identification number, is not a financial entity as defined by the regulations, and meets a minimum asset test. Enable's management believes its hedging transactions qualify for this "commercial end-user" exception. The Dodd-Frank Act may also require Enable to comply with margin requirements in connection with its hedging activities, although the application of those provisions to Enable is uncertain at this time. The Dodd-Frank Act may also require the counterparties to its derivative instruments to spin off some of their hedging activities to a separate entity, which may not be as creditworthy as the current counterparty.

The Dodd-Frank Act and related regulations could significantly increase the cost of derivatives contracts for Enable's industry (including requirements to post collateral which could adversely affect Enable's available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks Enable encounters, reduce its ability to monetize or restructure its existing derivatives contracts, and increase its exposure to less creditworthy counterparties, particularly if Enable is unable to utilize the commercial end user exception with respect to certain of its hedging transactions. If Enable reduces its use of hedging as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Enable's revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could adversely affect its financial position, results of operations and its ability to make cash distributions to unitholders, including us.

Any reductions in Enable's credit ratings could increase its financing costs and the cost of maintaining certain contractual relationships.

Enable cannot provide assurance that its credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant. If any of Enable's credit ratings are below investment grade, it may have higher future borrowing costs and it or its subsidiaries may be required to post cash collateral or letters of credit under certain contractual agreements. If cash collateral requirements were to occur at a time when Enable was experiencing significant working capital requirements or otherwise lacked liquidity, its financial position, results of operations and ability to make cash distributions to unitholders, including us, could be adversely affected.

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Enable's Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.

Enable's Series A Preferred Units rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. Enable cannot declare or pay a distribution to its common unitholders for any quarter unless full distributions have been or contemporaneously are being paid on all outstanding Series A Preferred Units for such quarter. These preferences could adversely affect the cash distributions we receive from Enable, could adversely affect the market price for Enable's common units or could make it more difficult for Enable to sell its common units in the future.

Holders of the Series A Preferred Units will receive, on a non-cumulative basis and if and when declared by Enable's general partner, a quarterly cash distribution, subject to certain adjustments, equal to an annual rate of 10 percent on the stated liquidation preference from the date of original issue to, but not including, the five year anniversary of the original issue date, and an annual rate of the London Interbank Offered Rate plus a spread of 850 basis points on the stated liquidation preference thereafter. In connection with certain transfers of the Series A Preferred Units, the Series A Preferred Units will automatically convert into one or more new series of preferred units (the "other preferred units") on the later of the date of transfer or the second anniversary of the date of issue. The other preferred units will have the same terms as Enable's Series A Preferred Units except that unpaid distributions on the other preferred units will accrue from the date of their issuance on a cumulative basis until paid. Enable's Series A Preferred Units are convertible into common units by the holders of such units in certain circumstances. Payment of distributions on Enable's Series A Preferred Units, or on the common units issued following the conversion of such Series A Preferred Units, could impact its liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Enable's obligations to the holders of Series A Preferred Units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on its financial condition.

Enable's Series A Preferred Units contain covenants that may limit its business flexibility.

Enable's Series A Preferred Units contain covenants preventing it from taking certain actions without the approval of the holders of 66 2/3 percent of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede Enable's ability to take certain actions that its management or its board of directors may consider to be in the best interests of its unitholders. The affirmative vote of 66 2/3 percent of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend Enable's Partnership Agreement in any manner that would or could reasonably be expected to have a material adverse effect on the rights, preferences, obligations or privileges of the Series A Preferred Units. The affirmative vote of 66 2/3 percent of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) create or issue certain party securities with proceeds in an aggregate amount in excess of $700.0 million or create or issue any senior securities or (B) subject to Enable's right to redeem the Series A Preferred Units, approve certain fundamental transactions.

Enable's Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange, and Enable may not have sufficient funds to redeem its Series A Preferred Units if it is required to do so.

The holders of Enable's Series A Preferred Units may request that Enable list those units for trading on the New York Stock Exchange. If Enable is unable to list the Series A Preferred Units in certain circumstances, it will be required to redeem the Series A Preferred Units. There can be no assurance that Enable would have sufficient financial resources available to satisfy its obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of Enable's Series A Preferred Units could adversely affect its financial position, results of operations and ability to make cash distributions to its unitholders, including us.

Enable may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.

Enable's partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that it may issue at any time without the approval of its unitholders. The issuance by Enable of additional common units or other equity securities of equal or senior rank will have the following effects:

•Enable's existing unitholders' proportionate ownership interest in Enable will decrease;

•the amount of distributable cash flow on each unit may decrease;

•because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

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•the ratio of taxable income to distributions may increase;

•the relative voting strength of each previously outstanding unit may be diminished; and

•the market price of the common units may decline.

In addition, upon a change of control or certain fundamental transactions, Enable's Series A Preferred Units are convertible into common units at the option of the holders of such units. If a substantial portion of the Series A Preferred Units were converted into common units, common unitholders could experience significant dilution. In addition, if holders of such converted Series A Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for Enable's common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for Enable to sell its common units in the future.

Affiliates of Enable's general partner may sell common units in the public or private markets, which could have an adverse impact on the trading price of the common units and may sell their interest in its general partner, which may impact its strategic direction.

As of January 31, 2020, CenterPoint held 233,856,623 of Enable's common units and 14,520,000 Series A Preferred Units, and the Company held 110,982,805 of Enable's common units. Enable's Series A Preferred Units are convertible into common units upon a change of control or certain fundamental transactions at the option of the holders of such units. Both Enable's common units held by CenterPoint and the Company, as well as Enable's Series A Preferred Units held by CenterPoint, are subject to certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. In addition, any sale of Enable's general partner by CenterPoint or the Company may impact Enable's strategic direction, business or results of operations.

Item 1B. Unresolved Staff Comments.

None.

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Item 2. Properties.

OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included 13 generating stations with an aggregate capability of 7,081 MWs at December 31, 2019. The following tables set forth information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.

					Fuel Capability	2019 Capacity Factor (A)		Unit Capability (MW)	Station Capability (MW)
			Year Installed
Station & Unit				Unit Design Type
Seminole	1		1971	Steam-Turbine	Gas	12.9	%	485
	2		1973	Steam-Turbine	Gas	10.6	%	500
	3		1975	Steam-Turbine	Gas/Oil	20.5	%	475	1,460
Muskogee	4		1977	Steam-Turbine	Gas	9.6	%	423
	5		1978	Steam-Turbine	Gas	9.3	%	442
	6		1984	Steam-Turbine	Coal	14.7	%	503	1,368
Sooner	1		1979	Steam-Turbine	Coal	41.7	%	516
	2		1980	Steam-Turbine	Coal	38.1	%	515	1,031
Horseshoe Lake	5A	(B)	1971	Combustion-Turbine	Gas/Jet Fuel	1.4	%	33
	5B	(B)	1971	Combustion-Turbine	Gas/Jet Fuel	1.3	%	31
	6		1958	Steam-Turbine	Gas/Oil	22.0	%	163
	7		1963	Combined Cycle	Gas/Oil	23.3	%	211
	8		1969	Steam-Turbine	Gas	0.4	%	403
	9		2000	Combustion-Turbine	Gas	28.7	%	44
	10		2000	Combustion-Turbine	Gas	28.8	%	42	927
Redbud (C)	1		2003	Combined Cycle	Gas	54.2	%	154
	2		2003	Combined Cycle	Gas	62.5	%	154
	3		2003	Combined Cycle	Gas	59.1	%	153
	4		2003	Combined Cycle	Gas	59.0	%	154	615
Mustang	6		2018	Combustion-Turbine	Gas	33.4	%	57
	7		2018	Combustion-Turbine	Gas	31.3	%	57
	8		2017	Combustion-Turbine	Gas	26.3	%	58
	9		2018	Combustion-Turbine	Gas	31.2	%	58
	10		2018	Combustion-Turbine	Gas	30.0	%	57
	11		2018	Combustion-Turbine	Gas	30.7	%	57
	12		2018	Combustion-Turbine	Gas	21.8	%	57	401
McClain (D)	1		2001	Combined Cycle	Gas	64.0	%	378	378
Frontier	1		1989	Combined Cycle	Gas	22.4	%	120	120
River Valley	1		1991	Steam-Turbine	Coal	17.7	%	160
	2		1991	Steam-Turbine	Coal	17.1	%	160	320
Total Generating Capability (all stations, excluding renewable)									6,620
Renewable						2019 Capacity Factor (A)		Unit Capability (MW)	Station Capability (MW)
	Year Installed			Number of Units	Fuel Capability
Station		Location
Crossroads	2011	Canton, OK		98	Wind	41.2	%	2.3	228
Centennial	2007	Laverne, OK		80	Wind	25.0	%	1.5	120
OU Spirit	2009	Woodward, OK		44	Wind	37.4	%	2.3	101
Mustang	2015	Oklahoma City, OK		90	Solar	21.3	%	—	2
Covington	2018	Covington, OK		4	Solar	25.7	%	2.4	10
Total Generating Capability (renewable)									461

(A)2019 Capacity Factor = 2019 Net Actual Generation / (2019 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours))

(B)Represents units located at Tinker Air Force Base that are maintained by Horseshoe Lake.

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(C)Represents OG&E's 51 percent ownership interest in the Redbud Plant.

(D)Represents OG&E's 77 percent ownership interest in the McClain Plant.

At December 31, 2019, OG&E's transmission system included: (i) 53 substations with a total capacity of 13.9 million kV-amps and 5,122 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.9 million kV-amps and 277 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 350 substations with a total capacity of 10.4 million kV-amps, 29,406 structure miles of overhead lines, 3,050 miles of underground conduit and 10,967 miles of underground conductors in Oklahoma and (ii) 30 substations with a total capacity of 1.0 million kV-amps, 2,786 structure miles of overhead lines, 315 miles of underground conduit and 679 miles of underground conductors in Arkansas.

During the three years ended December 31, 2019, the Company's gross property, plant and equipment (excluding construction work in progress) additions were $2.5 billion, and gross retirements were $408.5 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper), long-term borrowings and permanent financings. The additions during this three-year period amounted to 19.5 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 2019.

Item 3. Legal Proceedings.

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 Consolidated Financial Statements. At the present time, based on currently available information, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

Item 4. Mine Safety Disclosures.

Not Applicable.

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PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company's common stock is listed for trading on the New York Stock Exchange under the ticker symbol "OGE." At December 31, 2019, there were 13,570 holders of record of the Company's common stock.

Issuer Purchases of Equity Securities

None.

Item 6. Selected Financial Data.

HISTORICAL DATA

Year Ended December 31	2019			2018			2017			2016			2015
SELECTED FINANCIAL DATA
(In millions, except per share data)
Results of Operations Data
Operating revenues	$	2,231.6		$	2,270.3		$	2,261.1		$	2,259.2		$	2,196.9
Cost of sales	786.9			892.5			897.6			880.1			865.0
Operating expenses	940.4			888.2			831.6			848.3			825.0
Operating income	504.3			489.6			531.9			530.8			506.9
Equity in earnings of unconsolidated affiliates	113.9			152.8			131.2			101.8			15.5
Allowance for equity funds used during construction	4.5			23.8			39.7			14.2			8.3
Other net periodic benefit expense	9.8			10.8			21.6			27.5			25.7
Other income	21.9			21.7			46.4			26.0			27.0
Other expense	23.5			23.4			14.1			16.9			14.3
Interest expense	147.9			156.0			143.8			142.1			149.0
Income tax expense (benefit)	29.8			72.2			(49.3)			148.1			97.4
Net income	$	433.6		$	425.5		$	619.0		$	338.2		$	271.3
Basic earnings per average common share	$	2.17		$	2.13		$	3.10		$	1.69		$	1.36
Diluted earnings per average common share	$	2.16		$	2.12		$	3.10		$	1.69		$	1.36
Dividends declared per common share	$	1.50500		$	1.39500		$	1.27000		$	1.15500		$	1.05000
Balance Sheet Data (at period end)
Property, plant and equipment, net	$	9,044.6		$	8,643.8		$	8,339.9		$	7,696.2		$	7,322.4
Total assets	$	11,024.3		$	10,748.6		$	10,412.7		$	9,939.6		$	9,580.6
Long-term debt (including Long-term debt due within one year)	$	3,195.2		$	3,146.9		$	2,999.4		$	2,630.5		$	2,738.8
Total stockholders' equity	$	4,139.5		$	4,005.1		$	3,851.1		$	3,443.8		$	3,326.0
Capitalization Ratios (A)
Stockholders' equity	56.4		%	56.0		%	56.2		%	56.7		%	54.7		%
Long-term debt	43.6		%	44.0		%	43.8		%	43.3		%	45.3		%

(A)Capitalization ratios = [Total stockholders' equity / (Total stockholders' equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total stockholders' equity + Long-term debt + Long-term debt due within one year)].

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Introduction

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

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

The natural gas midstream operations segment represents the Company's investment in Enable through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is 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. At December 31, 2019, the Company owned 111.0 million common units, or 25.5 percent, of Enable's outstanding units. Enable's 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. For additional information on the Company's equity investment in Enable and related party transactions, see Note 5 within "Item 8. Financial Statements and Supplementary Data."

Enable's business is impacted by commodity prices which have declined and otherwise experienced significant volatility in recent years. Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by Enable's systems, and the volumes on Enable's systems are negatively impacted if producers decrease drilling and production in those areas served. Both Enable's gathering and processing segment and Enable's transportation and storage segment can be impacted by drilling and production. Enable's gathering and processing segment primarily serve producers, and many producers utilize the services provided by Enable's transportation and storage segment. A decrease in volumes will decrease the cash flows from Enable's systems. A portion of our earnings and operating cash flows depend on the performance of, and distributions from, Enable. As disclosed in this Form 10-K, Enable is subject to a number of risks, including contract renewal risks, the reliance on the drilling and production decisions of others and the volatility of natural gas, NGLs and crude oil prices. If any of those risks were to occur, the Company's business, financial condition, results of operations or cash flows could be materially adversely affected.

On February 7, 2020, 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."

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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. 

OG&E is focused on:

•providing exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity;

•providing safe, reliable energy to the communities and customers it serves, with a particular focus on enhancing the value of the grid by improving distribution grid reliability by reducing the frequency and duration of customer interruptions and leveraging previous grid technology investments;

•having strong regulatory and legislative relationships for the long-term benefit of customers, investors and members;

•continuing to grow a zero-injury culture and deliver top-quartile safety results;

•ensuring it has the necessary mix of generation resources to meet the long-term needs of its customers; and

•continuing focus on operational excellence and efficiencies in order to protect the customer bill.

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 projecting dividend increases to be consistent with utility earnings growth. 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 2019 Operating Results Compared to 2018

Net income was $433.6 million, or $2.16 per diluted share, in 2019 as compared to $425.5 million, or $2.12 per diluted share, in 2018. The increase in net income of $8.1 million, or $0.04 per diluted share, in 2019 as compared to 2018 is further discussed below.

•An increase in net income at OG&E of $22.2 million, or $0.10 per diluted share of the Company's common stock, was primarily due to higher gross margin driven primarily by 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, lower allowance for funds used during construction due to certain environmental projects being completed and placed into service and higher other operation and maintenance expense.

•An increase in net income of other operations of $13.3 million, or $0.07 per diluted share of the Company's common stock, was primarily due to higher other income, higher income tax benefit related to higher stock-based compensation payouts in 2019 and lower other operation and maintenance expense.

•A decrease in net income at OGE Holdings of $27.4 million, or $0.13 per diluted share of the Company's common stock, was primarily due to lower equity in earnings of Enable, which was driven by Enable's goodwill impairment charge and higher interest expense, and higher other expense due to higher pension settlement charges for seconded Enable employees, partially offset by lower income tax expense.

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A more detailed discussion regarding the financial performance of OG&E and OGE Holdings for the year ended December 31, 2019 as compared to December 31, 2018 can be found under "Results of Operations" below. A discussion of the financial performance for the year ended December 31, 2018 compared to December 31, 2017 can be found within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's 2018 Form 10-K.

Recent Developments and Regulatory Matters

Further discussion can be found in Note 16 within "Item 8. Financial Statements and Supplementary Data."

Arkansas 2018 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.

Arkansas 2019 Formula Rate Plan Filing

OG&E filed its second evaluation report under its Formula Rate Plan in October 2019. On January 29, 2020, OG&E, the General Staff of the APSC and the Office of the Arkansas Attorney General filed a settlement agreement requesting the APSC approve a $5.2 million revenue increase, with rates effective April 1, 2020. The settling parties agreed that the Series I grid modernization projects are prudent in both action and cost and that the Series II grid modernization projects are prudent in action only and the determination of prudence of costs will be reserved until the actual historical costs are reviewed. The settling parties also agreed that OG&E will no longer use projections for the remaining initial term or extension of its current Formula Rate Plan and that all costs will be included for recovery for the first time in the historical year. A hearing was held on February 5, 2020, and OG&E is awaiting a final decision from the APSC.

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 finding that the plants to be acquired were used and useful and that the acquisition of the plants was in the public interest. The APSC also approved the depreciation rates to be applied to the acquired plants. The cost OG&E paid for the acquired plants was reviewed by the APSC in OG&E's 2019 Formula Rate Plan filing, and parties reached a settlement agreement requesting the APSC approve the cost of the acquisition. OG&E is awaiting a final decision from the APSC.

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. On November 21, 2019, the FERC approved 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.

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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 was held on December 17, 2019. The primary question before the APSC is whether a company can utilize an environmental compliance plan rider while also regulated under a formula rate plan. OG&E is awaiting a final decision from the APSC.

2020 Outlook

Key assumptions for 2020 include:

OG&E

The Company projects OG&E to earn approximately $346 million to $357 million, or $1.72 to $1.78 per average diluted share, in 2020 and is based on the following assumptions:

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

•gross margin on revenues of approximately $1.515 billion to $1.521 billion based on sales growth of approximately one percent on a weather-adjusted basis;

•operating expenses of approximately $980 million to $984 million, with operation and maintenance expenses comprising approximately 51 percent of the total;

•net interest expense of approximately $148 million to $150 million which assumes a $1.8 million allowance for borrowed funds used during construction reduction to interest expense;

•other income of approximately $3.0 million including approximately $4.5 million of allowance for equity funds used during construction; and

•an effective tax rate of approximately 10.0 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 its earnings in the third quarter due to the seasonal nature of air conditioning demand.

OGE Holdings

The Company projects the earnings contribution from its ownership interest in Enable for 2020 to be at the lower end of Enable's guidance between approximately $94 million to $106 million, or $0.47 to $0.53 per average diluted share, and receive approximately $147 million in cash distributions.

Consolidated OGE

The Company's 2020 earnings guidance is between approximately $440 million and $463 million of net income, or $2.19 to $2.31 per average diluted share, and is based on the following assumptions:

•approximately 201 million average diluted shares outstanding;

•an effective tax rate of approximately 12.0 percent; and

•breakeven results projected at OGE Energy.

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

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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 years ended December 31, 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 2020 Outlook.

(In millions)	Twelve Months Ended December 31, 2020 (A)
Operating revenues	$	2,247
Cost of sales	729
Gross margin	$	1,518

(A)Based on the midpoint of OG&E earnings guidance for 2020.

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 years ending December 31, 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 years ended December 31, 2019 and 2018 and the Company's consolidated financial position at December 31, 2019 and 2018. The following information should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

	Year Ended December 31,
(In millions except per share data)	2019		2018
Net income	$	433.6	$	425.5
Basic average common shares outstanding	200.1		199.7
Diluted average common shares outstanding	200.7		200.5
Basic earnings per average common share	$	2.17	$	2.13
Diluted earnings per average common share	$	2.16	$	2.12
Dividends declared per common share	$	1.50500	$	1.39500

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Results by Business Segment

	Year Ended December 31,
(In millions)	2019		2018
Net income (loss):
OG&E (Electric Utility)	$	350.2	$	328.0
OGE Holdings (Natural Gas Midstream Operations)	81.4		108.8
Other operations (A)	2.0		(11.3)
Consolidated net income	$	433.6	$	425.5

(A)Other operations primarily includes the operations of OGE Energy and consolidating eliminations.

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

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OG&E (Electric Utility)

Year Ended December 31 (Dollars in millions)	2019		2018
Operating revenues	$	2,231.6	$	2,270.3
Cost of sales	786.9		892.5
Other operation and maintenance	492.5		473.8
Depreciation and amortization	355.0		321.6
Taxes other than income	89.5		88.2
Operating income	507.7		494.2
Allowance for equity funds used during construction	4.5		23.8
Other net periodic benefit expense	1.2		8.9
Other income	6.7		14.1
Other expense	6.9		3.4
Interest expense	140.5		151.8
Income tax expense	20.1		40.0
Net income	$	350.2	$	328.0
Operating revenues by classification:
Residential	$	891.1	$	901.0
Commercial	503.1		519.9
Industrial	223.0		234.5
Oilfield	204.0		193.5
Public authorities and street light	195.7		204.0
Sales for resale	0.1		0.2
System sales revenues	2,017.0		2,053.1
Provision for rate refund	(0.9)		(6.0)
Integrated market	38.4		48.7
Transmission	148.0		147.4
Other	29.1		27.1
Total operating revenues	$	2,231.6	$	2,270.3
Reconciliation of gross margin to revenue:
Operating revenues	$	2,231.6	$	2,270.3
Cost of sales	786.9		892.5
Gross margin	$	1,444.7	$	1,377.8
MWh sales by classification (In millions)
Residential	9.7		9.7
Commercial	6.5		6.6
Industrial	4.5		4.5
Oilfield	4.6		4.2
Public authorities and street light	3.1		3.1
System sales	28.4		28.1
Integrated market	1.2		1.4
Total sales	29.6		29.5
Number of customers	857,754		849,372
Weighted-average cost of energy per kilowatt-hour (In cents)
Natural gas	2.188		2.517
Coal	2.029		2.025
Total fuel	1.973		2.122
Total fuel and purchased power	2.534		2.900
Degree days (A)
Heating - Actual	3,771		3,776
Heating - Normal	3,354		3,349
Cooling - Actual	2,018		2,123
Cooling - Normal	2,095		2,092

(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

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between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.

OG&E's net income increased $22.2 million, or 6.8 percent, in 2019 as compared to 2018. Primary drivers for this increase in net income are further discussed below.

Gross margin increased $66.9 million, or 4.9 percent, in 2019 as compared to 2018. The below factors contributed to the change in gross margin.

(In millions)	$ Change
Price variance (A)	$	43.6
Weather (price and quantity) (B)	18.2
Other	5.1
Change in gross margin	$	66.9

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

(B) Increased primarily due to higher cooling degree days for certain summer months during the period, which resulted in favorable weather impacts.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC. OG&E's cost of sales decreased $105.6 million, or 11.8 percent, in 2019 as compared to 2018. The below factors contributed to the change in cost of sales.

(In millions)	$ Change		% Change
Fuel expense (A)	$	(50.7)	(13.1)	%
Purchased power costs:
Purchases from SPP (B)	41.0		16.0	%
Cogeneration (C)	(97.8)		(86.9)	%
Other	0.3		0.5	%
Transmission expense (D)	1.6		2.2	%
Change in cost of sales	$	(105.6)

(A)Decreased primarily due to lower natural gas prices during 2019.

(B)Increased primarily due to a 37.1 percent increase in MWhs purchased during 2019.

(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 15 within "Item 8. Financial Statements and Supplementary Data."

(D)Increased primarily due to higher SPP charges for the base plan projects of other utilities.

Other operation and maintenance expense increased $18.7 million, or 3.9 percent, in 2019 as compared to 2018. The below factors contributed to the change in other operation and maintenance expense.

(In millions)	$ Change		% Change
New expenses related to River Valley power plant (A)	$	13.7	*
Contract technical and construction services (B)	7.2		16.8	%
Other	(2.2)		(0.5)	%
Change in other operation and maintenance expense	$	18.7

*Not applicable, as prior year expenses were zero.

(A)Additional other operation and maintenance expenses related to the purchase of the River Valley plant are primarily recovered through a rider mechanism, as discussed in Note 16 within "Item 8. Financial Statements and Supplementary Data."

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

Depreciation and amortization expense increased $33.4 million, or 10.4 percent, primarily due to additional assets being placed into service.

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Allowance for equity funds used during construction decreased $19.3 million, or 81.1 percent, 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 $7.7 million, or 86.5 percent, primarily due to lower pension costs reflected in base rates as a result of a June 2018 Oklahoma rate review settlement.

Other income decreased $7.4 million, or 52.5 percent, 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 $19.1 million, or 12.1 percent, 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 8. Financial Statements and Supplementary Data."

Allowance for borrowed funds used during construction decreased $8.9 million, or 76.1 percent, primarily due to lower construction work in progress balances resulting from certain environmental projects being completed and placed into service.

Income tax expense decreased $19.9 million, or 49.8 percent, primarily due to an increase in the amortization of net refundable deferred taxes and higher tax credits.

OGE Holdings (Natural Gas Midstream Operations)

	Year Ended December 31,
(In millions)	2019		2018
Operating revenues	$	—	$	—
Cost of sales	—		—
Other operation and maintenance	2.8		1.4
Depreciation and amortization	—		—
Taxes other than income	0.4		0.6
Operating loss	(3.2)		(2.0)
Equity in earnings of unconsolidated affiliates	113.9		152.8
Other expense	8.6		4.9
Income before taxes	102.1		145.9
Income tax expense	20.7		37.1
Net income attributable to OGE Holdings	$	81.4	$	108.8

Reconciliation of Equity in Earnings of Unconsolidated Affiliates

See Note 5 within "Item 8. Financial Statements and Supplementary Data" for the reconciliation of Enable's net income to OGE Energy's equity in earnings of unconsolidated affiliates and the reconciliation of the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference).

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Enable Results of Operations and Operating Data

The following tables present summarized financial information of Enable for the years ended December 31, 2019 and 2018.

	Year Ended December 31,
(In millions)	2019		2018
Reconciliation of gross margin to revenue:
Total revenues	$	2,960	$	3,431
Cost of natural gas and NGLs	1,279		1,819
Gross margin	$	1,681	$	1,612
Operating income	$	569	$	648
Net income	$	360	$	485

	Year Ended December 31,
	2019	2018
Natural gas gathered volumes - TBtu/d	4.56	4.48
Transported volumes - TBtu/d	6.18	5.56
Natural gas processed volumes - TBtu/d	2.53	2.40
NGLs sold - MBbl/d (A)(B)	131.59	132.06
Crude oil and condensate gathered volumes - MBbl/d	128.46	41.07

(A)Excludes condensate.

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

OGE Holdings' income before taxes decreased $43.8 million, or 30.0 percent, primarily due to a decrease in equity in earnings of Enable of $38.9 million, which was driven by a goodwill impairment charge and higher interest expense, and an increase in other expense of $3.7 million driven by higher pension settlement charges for seconded Enable employees. The following table presents summarized information regarding Enable's income statement changes for the year ended December 31, 2019, compared to the same period in 2018, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

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

(In millions)	Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	69.0	$	17.6
Operation and maintenance, General and administrative	$	25.0	$	(6.4)
Depreciation and amortization	$	35.0	$	(8.9)
Impairment	$	86.0	$	(21.9)
Interest expense	$	38.0	$	(9.7)

Enable's gathering and processing business segment reported a decrease in operating income of $84.0 million. The following table presents summarized information regarding Enable's gathering and processing business segment income statement changes for the year ended December 31, 2019, compared to the same period in 2018, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

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

(In millions)	Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	58.0	$	14.8
Operation and maintenance, General and administrative	$	8.0	$	(2.0)
Depreciation and amortization	$	45.0	$	(11.5)
Impairment	$	86.0	$	(21.9)

Gathering and processing gross margin increased primarily due to the following:

•an increase in natural gas gathering fees due to higher fees and gathered volumes in the Anadarko and Ark-La-Tex Basins and higher revenue associated with the amendment of certain minimum volume commitment contracts in the Arkoma Basin, partially offset by lower gathered volumes in the Arkoma Basin and lower shortfall payments associated with the expiration of minimum volume commitments contracts in the Arkoma Basin;

•an increase in realized gains on natural gas, condensate and NGLs derivatives;

•an increase in crude oil, condensate and produced water gathering revenues due to an increase related to a 2018 acquisition and an increase in volumes in the Williston Basin, partially offset by lower average gathering rates in the Williston Basin; and

•an increase in intercompany management fees; partially offset by

•a decrease in changes in the fair value of natural gas, condensate and NGLs derivatives;

•a decrease in revenues from NGLs sales less the cost of NGLs due to lower average sales prices for all NGLs products, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins;

•a decrease in processing service fees due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangement due to a decrease in the average realized price, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins; and

•a decrease in revenues from natural gas sales less the cost of natural gas due to lower average natural gas sales prices and lower sales volumes.

Enable's transportation and storage business segment reported an increase of $6.0 million in operating income. The following table presents summarized information regarding Enable's transportation and storage business segment income statement changes for year ended December 31, 2019, compared to the same period in 2018, and the corresponding impact those changes had on the Company's equity in earnings of Enable.

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

(In millions)	Income Statement Change at Enable		Impact to Company's Equity in Earnings
Gross margin	$	13.0	$	3.3
Operation and maintenance, General and administrative	$	18.0	$	(4.6)
Depreciation and amortization	$	(10.0)	$	2.6

Transportation and storage gross margin increased primarily due to the following:

•an increase in firm transportation and storage services due to new intrastate and interstate transportation contracts, partially offset by lower revenue due to the reduction of contracted interstate storage capacity; and

•an increase in system management activities; partially offset by

•a decrease in revenues from NGLs sales less the cost of NGLs due to a decrease in average NGLs prices and lower volumes;

•a decrease in natural gas storage inventory due to additional lower of cost or net realizable value adjustments;

•a decrease in volume-dependent transportation revenues due to a decrease in off-system intrastate transportation offset by new off-system interstate transportation contracts; and

•a decrease in realized gains on natural gas derivatives.

Income tax expense decreased $16.4 million, or 44.2 percent, primarily due to lower pretax income combined with federal and state deferred tax adjustments related to the Company's investment in Enable.

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Off-Balance Sheet Arrangement 

OG&E Railcar Lease Agreement

As of December 31, 2019, OG&E has a noncancellable operating lease with a purchase option, covering 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. At the end of the lease term, which is 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.

Liquidity and Capital Resources

Cash Flows

Year Ended December 31 (In millions)	2019		2018		$ Change		% Change
Net cash provided from operating activities (A)	$	681.5	$	951.1	$	(269.6)	(28.3)	%
Net cash used in investing activities (B)	$	(624.7)	$	(576.0)	$	(48.7)	8.5	%
Net cash used in financing activities (C)	$	(151.1)	$	(295.2)	$	144.1	(48.8)	%

(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 December 31, 2019 compared to December 31, 2018.

Cash and Cash Equivalents decreased $94.3 million, or 100.0 percent, primarily due to normal business operations including the funding of capital expenditures.

Accounts Receivable and Accrued Unbilled Revenues decreased $18.8 million, or 7.9 percent, primarily due to mutual assistance payments received in 2019 and a decrease in customer billings.

Fuel Inventories decreased $11.3 million, or 19.6 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 $36.1 million, or 28.5 percent, primarily due to decreased inventory related to long-term service agreements.

Fuel Clause Under Recoveries increased $37.5 million, primarily due to lower recoveries from OG&E Oklahoma retail customers as compared to the actual cost of fuel and purchased power.

Other Current Assets decreased $5.1 million, or 17.3 percent, primarily due to a decrease in under-recovered riders, partially offset by transportation and demand prepayments.

Short-term Debt increased $112.0 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 $44.4 million, or 18.6 percent, primarily due to the timing of vendor payments.

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Accrued Interest decreased $6.6 million, or 14.8 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 $7.2 million, or 15.1 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.

Fuel Clause Over Recoveries increased $4.5 million, primarily due to higher recoveries from OG&E Arkansas retail customers as compared to the actual cost of fuel and purchased power.

Other Current Liabilities decreased $21.8 million, or 25.1 percent, primarily due to changes in amounts owed to customers. Included in the December 31, 2019 balance is SPP reserves of $18.9 million and reserves for tax refund and interim surcharge of $12.7 million.

2019 Capital Requirements, Sources of Financing and Financing Activities

Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $885.6 million, and contractual obligations, net of recoveries through fuel adjustment clauses, were $12.0 million, resulting in total net capital requirements and contractual obligations of $897.6 million in 2019, of which $20.9 million was to comply with environmental regulations. This compares to net capital requirements of $823.7 million and net contractual obligations of $76.4 million totaling $900.1 million in 2018, of which $139.8 million was to comply with environmental regulations.

In 2019, the Company's primary sources of capital were cash generated from operations, proceeds from the issuance of long- and short-term debt and distributions from Enable. Changes in working capital reflect the seasonal nature of the Company's business, the revenue lag between billing and collection from customers and fuel inventories. See "Working Capital" for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.

The Dodd-Frank Act

Derivative instruments have been used at times in managing OG&E's commodity price exposure. The Dodd-Frank Act, among other things, provides for regulation by the Commodity Futures Trading Commission of certain commodity-related contracts. Although OG&E qualifies for an end-user exception from mandatory clearing of commodity-related swaps, these regulations could affect the ability of OG&E to participate in these markets and could add additional regulatory oversight over its contracting activities.

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.

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Capital Expenditures

The Company's consolidated estimates of capital expenditures for the years 2020 through 2024 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)	2020		2021		2022		2023		2024		Total
Transmission	$	45	$	40	$	35	$	35	$	35	$	190
Oklahoma distribution	215		225		225		225		225		1,115
Arkansas distribution	30		15		15		15		15		90
Generation	135		60		60		90		60		405
Reliability, resiliency, technology and other	90		335		335		335		335		1,430
Other	60		50		60		55		55		280
Total	$	575	$	725	$	730	$	755	$	725	$	3,510

Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets, will be evaluated based upon their impact upon achieving the Company's financial objectives.  

Contractual Obligations

The following table summarizes the Company's contractual obligations at December 31, 2019. See the Company's Consolidated Statements of Capitalization and Notes 4 and 15 within "Item 8. Financial Statements and Supplementary Data" for additional information.

(In millions)	2020		2021-2022		2023-2024		After 2024		Total
Maturities of long-term debt	$	—	$	—	$	—	$	3,229.9	$	3,229.9
Operating lease obligations:
Railcars	2.4		4.6		2.4		—		9.4
Wind farm land leases	2.9		5.8		5.9		34.7		49.3
Office space lease	0.9		0.6		—		—		1.5
Total operating lease obligations	6.2		11.0		8.3		34.7		60.2
Purchase obligations and commitments:
Minimum purchase commitments	82.6		105.5		83.3		332.0		603.4
Expected wind purchase commitments	55.7		112.4		114.3		379.8		662.2
Long-term service agreement commitments	2.4		4.8		45.9		111.1		164.2
Environmental compliance plan expenditures	0.4		—		—		—		0.4
Total purchase obligations and commitments	141.1		222.7		243.5		822.9		1,430.2
Total contractual obligations	147.3		233.7		251.8		4,087.5		4,720.3
Amounts recoverable through fuel adjustment clause (A)	(140.7)		(222.5)		(200.0)		(711.8)		(1,275.0)
Total contractual obligations, net	$	6.6	$	11.2	$	51.8	$	3,375.7	$	3,445.3

(A)Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations, OG&E's minimum fuel purchase commitments and OG&E's expected wind purchase commitments.

The actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E's railcar leases shown above) and certain purchased power costs are passed on to OG&E's customers through fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of minimum fuel purchase commitments of OG&E noted above may increase capital requirements, such costs are recoverable through fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC.

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Pension and Postretirement Benefit Plans

At December 31, 2019, 35.8 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in corporate fixed income, other securities and U.S. Treasury notes and bonds as presented in Note 13 within "Item 8. Financial Statements and Supplementary Data." During 2019, actual returns on the Pension Plan were $85.2 million, compared to expected return on plan assets of $36.1 million. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, decreased. Funding levels are dependent on returns on plan assets and future discount rates. The Company made a $20.0 million and $15.0 million contribution to its Pension Plan in 2019 and 2018, respectively. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2020. The Company could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.

The following table presents the status of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 2019 and 2018. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E's portion, which is recorded as a regulatory asset as discussed in Note 1 within "Item 8. Financial Statements and Supplementary Data") in the Company's Consolidated Balance Sheets. The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods.

	Pension Plan				Restoration of Retirement Income Plan				Postretirement Benefit Plans
December 31 (In millions)	2019		2018		2019		2018		2019		2018
Benefit obligations	$	616.1	$	615.9	$	10.3	$	9.6	$	136.5	$	135.8
Fair value of plan assets	530.3		522.8		—		—		47.0		45.3
Funded status at end of year	$	(85.8)	$	(93.1)	$	(10.3)	$	(9.6)	$	(89.5)	$	(90.5)

Common Stock Dividends

The Company's dividend policy is reviewed by the Board of Directors at least annually and is based on numerous factors, including management's estimation of the long-term earnings power of its businesses. At the Company's September 2019 board meeting, the Board of Directors approved management's recommendation of a six percent increase in the quarterly dividend rate to $0.3875 per share from $0.3650 per share effective in October 2019.

Financing Activities and Future Sources of Financing

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

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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 agreement. The Company has unsecured five-year revolving credit facilities totaling $900.0 million ($450.0 million for the Company and $450.0 million for OG&E) that mature on March 8, 2023. These bank facilities can also be used as letter of credit facilities. The following tables highlight the Company's short-term debt activity as of and for the year ended December 31, 2019.

(Dollars in millions)	December 31, 2019
Balance of outstanding supporting letters of credit	$	0.3
Weighted-average interest rate of outstanding supporting letters of credit	1.00		%
Net available liquidity under revolving credit agreements	$	787.7
Balance of cash and cash equivalents	$	—
(Dollars in millions)	Year Ended December 31, 2019
Average balance of short-term debt	$	233.6
Weighted-average interest rate of average balance of short-term debt	2.62		%
Maximum month-end balance of short-term debt	$	479.7

OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2019 and ending December 31, 2020. See Note 12 within "Item 8. Financial Statements and Supplementary Data" for further discussion of the Company's short-term debt activity.

Issuance of Long-Term Debt

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

Security Ratings

	Moody's Investors Service	Outlook	S&P's Global Ratings	Outlook	Fitch Ratings	Outlook
OG&E Senior Notes	A3	Stable	A-	Stable	A	Stable
OG&E Commercial Paper	P2	Stable	A2	Stable	F2	Stable
OGE Energy Senior Notes	Baa1	Stable	BBB+	Stable	BBB+	Stable
OGE Energy Commercial Paper	P2	Stable	A2	Stable	F2	Stable

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

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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.

Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, commodity prices, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.

Common Stock

The Company does not expect to issue any common stock in 2020 from its Automatic Dividend Reinvestment and Stock Purchase Plan. See Note 10 within "Item 8. Financial Statements and Supplementary Data" for a discussion of the Company's common stock activity.

Distributions by Enable

Pursuant to the Enable Limited Partnership Agreement, Enable made distributions of $144.0 million, $141.2 million and $141.2 million to the Company during the years ended December 31, 2019, 2018 and 2017, respectively. As required by Enable's Limited Partnership Agreement and General Partner Agreement, respectively, the last permitted distribution date is 60 days after the close of each quarter, and the distribution deadline is five days following distributions by Enable.

Funding of Benefit Plans

The Company expects to purchase an immaterial amount of shares of its common stock on the open market from time to time commencing during the first quarter of 2020 through the first quarter of 2022. These shares will be used to satisfy the Company's obligation to deliver shares of common stock in connection with certain incentive compensation awards.

Critical Accounting Policies and Estimates

The Consolidated Financial Statements and Notes to Consolidated Financial Statements contain information that is pertinent to Management's Discussion and Analysis. In preparing the 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 Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Changes to these assumptions and estimates could have a material effect on the Company's 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 following critical accounting estimates have been discussed with the Audit Committee of the Company's Board of Directors. The Company discusses its significant accounting policies, including those that do not require management to make difficult, subjective or complex judgments or estimates, in Note 1 within "Item 8. Financial Statements and Supplementary Data."

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Pension and Postretirement Benefit Plans

The Company has a Pension Plan that covers a significant amount of the Company's employees hired before December 1, 2009. Effective December 1, 2009, the Company's Pension Plan is no longer being offered to employees hired on or after December 1, 2009. The Company also has defined benefit postretirement plans that cover a significant amount of its employees. Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The Pension Plan rate assumptions are shown in Note 13 within "Item 8. Financial Statements and Supplementary Data." The assumed return on plan assets is based on management's expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. Funding levels are dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the Pension Plan.

 The following table indicates the sensitivity of the Pension Plan funded status to these variables.

	Change	Impact on Funded Status
Actual plan asset returns	+/- 1 percent	+/- $5.3 million
Discount rate	+/- 0.25 percent	+/- $12.3 million
Contributions	+/- $10 million	+/- $10.0 million

Income Taxes

The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change.

The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Interpretations and guidance surrounding income tax laws and regulations change over time. Accordingly, it is necessary to make judgments regarding income tax exposure. As a result, changes in these judgments can materially affect amounts the Company recognized in its consolidated financial statements. Tax positions taken by the Company on its income tax returns that are recognized in the financial statements must satisfy a more likely than not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.

Asset Retirement Obligations

The Company has recorded asset retirement obligations that are being accreted over their respective lives ranging from ten to 68 years. The inputs used in the valuation of asset retirement obligations include the assumed life of the asset placed into service, the average inflation rate, market risk premium, the credit-adjusted risk free interest rate and the timing of incurring costs related to the retirement of the asset.

Regulatory Assets and Liabilities

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

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in future rates. Management continuously monitors the future recoverability of regulatory assets. When in management's judgement future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate.

Unbilled Revenues

OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues in the Consolidated Balance Sheets and in Operating Revenues in the Consolidated Statements of Income based on estimates of usage and prices during the period. At December 31, 2019, if the estimated usage or price used in the unbilled revenue calculation were to increase or decrease by one percent, this would cause a change in the unbilled revenues recognized of $0.4 million. At December 31, 2019 and 2018, Accrued Unbilled Revenues were $64.7 million and $62.6 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Allowance for Uncollectible Accounts Receivable

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate, which is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. At December 31, 2019, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of $0.1 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable in the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense in the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $1.5 million and $1.7 million at December 31, 2019 and 2018, respectively.

Accounting Pronouncements

See Note 2 within "Item 8. Financial Statements and Supplementary Data" for discussion of current accounting pronouncements that are applicable to the Company.

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 Consolidated Financial Statements. At the present time, based on available information, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows. See Notes 15 and 16 within "Item 8. Financial Statements and Supplementary Data" and "Item 3. Legal Proceedings" 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 or 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.

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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.

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 Cross-State Air Pollution Rule. The new rule applies to ozone-season NO_X emissions 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 2016 rule reduces the 2011 Cross-State Air Pollution Rule emissions cap for all of OG&E's coal and gas facilities (except the River Valley and Frontier facilities which were not owned by OG&E until 2019) 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. Subsequently, all of OG&E's judicial challenges were voluntarily dismissed, but the administrative petitions for reconsideration remain pending at the EPA.

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. 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 coal units (not including the River Valley facility which was not owned by OG&E until 2019). 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 December 31, 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 indicated 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. The State of Oklahoma's monitoring preliminarily indicates that ambient SO₂ emissions in the area are well within the NAAQS. The EPA has indicated that it anticipates finalizing a designation at the end of 2020. At this time, the Company cannot determine with any certainty whether the proposed designation of Muskogee County will cause a material impact to the Company's financial results.

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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 CO_2, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the earth's atmosphere. On November 4, 2019, President Trump announced that the U.S. has officially notified the United Nations that the U.S. will withdraw from the "Paris Agreement" on climate change after having announced in 2017 that the U.S. would 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 reduced carbon dioxide emissions by over 40 percent compared to 2005 levels, and during the same period, emissions of ozone-forming NO_x have been reduced by approximately 75 percent and emissions of SO₂ have been reduced by approximately 90 percent. OG&E expects to further reduce carbon dioxide emissions to 50 percent of 2005 levels by 2030. To comply with the EPA's MATS rule and Regional Haze Rule FIP, OG&E 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 published the Affordable Clean Energy rule. 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. 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 and applications remain pending for other units. The Company does not anticipate capital expenditures, or a material impact to its consolidated financial position, results of operations or cash flows, as a result of adoption of this rule.

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Regional Haze Regulation - Second Planning Period

In January 2017, the EPA finalized a rule that would revise certain provisions of the Regional Haze Rule. Notably, the EPA extended the due date for the second Regional Haze implementation period by three years to 2021 and made changes to the provisions for impacts to national parks and other protected wilderness areas. Petitions for Reconsideration to the EPA were filed by industry groups. While not acting on the petitions, the EPA announced on January 17, 2018 that it intends to commence a notice-and-comment rulemaking revisiting certain aspects of the rule. During 2019, the EPA released technical resources to assist states in developing SIPs, including a significant non-binding guidance document and updated atmospheric modeling which will allow states to better account for international emissions affecting regional haze in the U.S. At this time, the Company cannot predict the outcome of this rulemaking or SIP development or how it will affect the Company.

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 currently recycles and provides approximately 86 percent of its ash to the concrete and cement industries for use as a component within their products. Using fly ash in this way enables aggregate manufacturers to minimize their impact on the environment by avoiding the need to extract and process other natural resources.

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. In 2019, the Company obtained refunds of $2.8 million from the recycling of scrap metal, salvaged transformers and used transformer oil. This figure does not include the additional savings 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

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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. On November 22, 2019, the EPA published a proposed rule to revise the technology-based effluent limitations for flue gas desulfurization waste water and bottom ash transport water. 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.

Since the purchase of the Redbud facility in 2008, OG&E's average use of treated municipal effluent for all of the needed cooling water at Redbud and McClain is approximately 2.6 billion gallons per year. This use of treated municipal effluent offsets the need for fresh water as cooling water, making fresh water available for other beneficial uses like drinking water, irrigation and recreation.

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 15 within "Item 8. Financial Statements and Supplementary Data."

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Market risks are, in most cases, risks that are actively traded in a marketplace and have been well studied in regards to quantification. Market risks include, but are not limited to, changes in interest rates and commodity prices. The Company's exposure to changes in interest rates relates primarily to short-term variable-rate debt and commercial paper. The Company is exposed to commodity prices in its operations.

Risk Oversight Committee

Management monitors market risks using a risk committee structure. The Company's Risk Oversight Committee, which consists primarily of corporate officers, is responsible for the overall development, implementation and enforcement of strategies and policies for all market risk management activities of the Company. This committee's emphasis is a holistic perspective of risk measurement and policies targeting the Company's overall financial performance. On a quarterly basis, the Risk Oversight Committee reports to the Audit Committee of the Company's Board of Directors on the Company's risk profile affecting anticipated financial results, including any significant risk issues.

The Company also has a Corporate Risk Management Department. This group, in conjunction with the aforementioned committees, is responsible for establishing and enforcing the Company's risk policies.

Risk Policies

Management utilizes risk policies to control the amount of market risk exposure. These policies are designed to provide the Audit Committee of the Company's Board of Directors and senior executives of the Company with confidence that the risks taken on by the Company's business activities are in accordance with their expectations for financial returns and that the approved policies and controls related to market risk management are being followed.

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 Interest Rate Risk

The Company's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper. The Company manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates. The Company may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio, but the Company has no intent at this time to utilize interest rate derivatives.

The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities or by calculating the net present value of the monthly payments discounted by the Company's current borrowing rate. The following table shows the Company's long-term debt maturities and the weighted-average interest rates by maturity date.

Year Ended December 31 (Dollars in millions)	2020			2021			2022			2023			2024			Thereafter			Total			12/31/19 Fair Value
Fixed-rate debt (A):
Principal amount	$	—		$	—		$	—		$	—		$	—		$	3,094.5		$	3,094.5		$	3,510.4
Weighted-average interest rate	—		%	—		%	—		%	—		%	—		%	4.60		%	4.60		%
Variable-rate debt (B):
Principal amount	$	—		$	—		$	—		$	—		$	—		$	135.4		$	135.4		$	135.4
Weighted-average interest rate	—		%	—		%	—		%	—		%	—		%	1.77		%	1.77		%

(A)Prior to or when these debt obligations mature, the Company may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.

(B)A hypothetical change of 100 basis points in the underlying variable interest rate incurred by the Company would change interest expense by $1.4 million annually.

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Item 8. Financial Statements and Supplementary Data.

OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

Year Ended December 31 (In millions except per share data)	2019		2018		2017
OPERATING REVENUES
Revenues from contracts with customers	$	2,175.5	$	2,211.7	$	—
Other revenues	56.1		58.6		—
Operating revenues	2,231.6		2,270.3		2,261.1
COST OF SALES	786.9		892.5		897.6
OPERATING EXPENSES
Other operation and maintenance	491.8		474.6		458.7
Depreciation and amortization	355.0		321.6		283.5
Taxes other than income	93.6		92.0		89.4
Operating expenses	940.4		888.2		831.6
OPERATING INCOME	504.3		489.6		531.9
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	113.9		152.8		131.2
Allowance for equity funds used during construction	4.5		23.8		39.7
Other net periodic benefit expense	(9.8)		(10.8)		(21.6)
Other income	21.9		21.7		46.4
Other expense	(23.5)		(23.4)		(14.1)
Net other income	107.0		164.1		181.6
INTEREST EXPENSE
Interest on long-term debt	138.3		157.4		153.6
Allowance for borrowed funds used during construction	(2.8)		(11.7)		(18.0)
Interest on short-term debt and other interest charges	12.4		10.3		8.2
Interest expense	147.9		156.0		143.8
INCOME BEFORE TAXES	463.4		497.7		569.7
INCOME TAX EXPENSE (BENEFIT)	29.8		72.2		(49.3)
NET INCOME	$	433.6	$	425.5	$	619.0
BASIC AVERAGE COMMON SHARES OUTSTANDING	200.1		199.7		199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.7		200.5		200.0
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	2.17	$	2.13	$	3.10
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	2.16	$	2.12	$	3.10

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

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OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31 (In millions)	2019		2018		2017
Net income	$	433.6	$	425.5	$	619.0
Other comprehensive income (loss), net of tax:
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $1.1, $1.1 and $1.4, respectively	3.4		3.3		2.5
Amortization of prior service credit, net of tax of $0.0, $0.0 and $0.0, respectively	—		—		(0.1)
Net gain (loss) arising during the period, net of tax of $(2.6), ($4.7) and $0.2, respectively	(8.3)		(14.1)		0.4
Settlement cost, net of tax of $2.7, $1.6 and $1.4, respectively	8.6		4.7		2.2
Postretirement Benefit Plans:
Amortization of prior service credit, net of tax of ($0.6), ($0.6) and ($0.3), respectively	(1.7)		(1.7)		(0.6)
Amortization of deferred net gain, net of tax of $0.0, $0.0 and $0.0, respectively	(0.2)		—		—
Prior service cost arising during the period, net of tax of $0.0, $0.0 and $4.0, respectively	—		—		6.3
Net gain (loss) arising during the period, net of tax of ($0.1), $0.7 and ($0.2), respectively	(0.2)		2.1		(0.6)
Settlement cost, net of tax of $0.0, $0.0 and $0.2, respectively	—		—		0.5
Other comprehensive loss from unconsolidated affiliates, net of tax ($0.2), $0.0 and $0.0, respectively	(0.6)		—		—
Other comprehensive income (loss), net of tax	1.0		(5.7)		10.6
Comprehensive income	$	434.6	$	419.8	$	629.6

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

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OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31 (In millions)	2019		2018		2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	433.6	$	425.5	$	619.0
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	355.0		321.6		283.5
Deferred income taxes and investment tax credits, net	27.6		78.5		(50.0)
Equity in earnings of unconsolidated affiliates	(113.9)		(152.8)		(131.2)
Distributions from unconsolidated affiliates	125.5		141.2		131.2
Allowance for equity funds used during construction	(4.5)		(23.8)		(39.7)
Stock-based compensation expense	13.9		13.4		9.1
Regulatory assets	(47.1)		(10.8)		3.7
Regulatory liabilities	(45.6)		(16.5)		(3.7)
Other assets	(3.8)		6.2		(0.7)
Other liabilities	19.2		1.0		(65.5)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	18.8		19.8		(21.8)
Income taxes receivable	(1.0)		(4.1)		13.6
Fuel, materials and supplies inventories	4.2		27.3		(3.6)
Fuel recoveries	(33.0)		(3.4)		53.0
Other current assets	5.1		25.1		27.2
Accounts payable	(34.5)		29.7		27.1
Other current liabilities	(38.0)		73.2		(66.7)
Net cash provided from operating activities	681.5		951.1		784.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(635.5)		(573.6)		(824.1)
Investment in unconsolidated affiliates	(7.7)		(2.5)		(8.5)
Return of capital - unconsolidated affiliates	18.5		—		10.0
Proceeds from sale of assets	—		0.1		0.7
Net cash used in investing activities	(624.7)		(576.0)		(821.9)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase (decrease) in short-term debt	112.0		(168.4)		(67.8)
Proceeds from long-term debt	296.5		396.0		592.1
Payment of long-term debt	(250.1)		(250.1)		(225.1)
Dividends paid on common stock	(299.2)		(272.2)		(247.6)
Cash paid for employee equity-based compensation and expense of common stock	(10.3)		(0.5)		(0.1)
Net cash provided from (used in) financing activities	(151.1)		(295.2)		51.5
NET CHANGE IN CASH AND CASH EQUIVALENTS	(94.3)		79.9		14.1
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	94.3		14.4		0.3
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	—	$	94.3	$	14.4

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

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OGE ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

December 31 (In millions)	2019		2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	94.3
Accounts receivable, less reserve of $1.5 and $1.7, respectively	153.8		174.7
Accrued unbilled revenues	64.7		62.6
Income taxes receivable	10.9		9.9
Fuel inventories	46.3		57.6
Materials and supplies, at average cost	90.6		126.7
Fuel clause under recoveries	39.5		2.0
Other	24.4		29.5
Total current assets	430.2		557.3
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,151.5		1,177.5
Other	82.7		73.4
Total other property and investments	1,234.2		1,250.9
PROPERTY, PLANT AND EQUIPMENT
In service	12,771.1		11,994.8
Construction work in progress	141.6		376.4
Total property, plant and equipment	12,912.7		12,371.2
Less: accumulated depreciation	3,868.1		3,727.4
Net property, plant and equipment	9,044.6		8,643.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	306.0		285.8
Other	9.3		10.8
Total deferred charges and other assets	315.3		296.6
TOTAL ASSETS	$	11,024.3	$	10,748.6

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

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OGE ENERGY CORP.

CONSOLIDATED BALANCE SHEETS (Continued)

December 31 (In millions)	2019		2018
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	112.0	$	—
Accounts payable	194.9		239.3
Dividends payable	77.6		72.9
Customer deposits	83.0		83.6
Accrued taxes	41.9		44.0
Accrued interest	37.9		44.5
Accrued compensation	40.6		47.8
Long-term debt due within one year	—		250.0
Fuel clause over recoveries	4.8		0.3
Other	65.2		87.0
Total current liabilities	657.9		869.4
LONG-TERM DEBT	3,195.2		2,896.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	225.0		225.7
Deferred income taxes	1,375.8		1,310.9
Deferred investment tax credits	7.1		7.2
Regulatory liabilities	1,223.5		1,270.7
Other	200.3		162.7
Total deferred credits and other liabilities	3,031.7		2,977.2
Total liabilities	6,884.8		6,743.5
COMMITMENTS AND CONTINGENCIES (NOTE 15)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,131.3		1,127.7
Retained earnings	3,036.1		2,906.3
Accumulated other comprehensive loss, net of tax	(27.9)		(28.9)
Total stockholders' equity	4,139.5		4,005.1
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	11,024.3	$	10,748.6

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

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OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31 (In millions except per share data)		2019		2018
STOCKHOLDERS' EQUITY
Common stock, par value $0.01 per share; authorized 450.0 shares; and outstanding 200.1 shares and 199.7 shares, respectively		$	2.0	$	2.0
Premium on common stock		1,129.3		1,125.7
Retained earnings		3,036.1		2,906.3
Accumulated other comprehensive loss, net of tax		(27.9)		(28.9)
Total stockholders' equity		4,139.5		4,005.1
LONG-TERM DEBT
SERIES	DUE DATE
Senior Notes - OG&E
8.25%	Senior Notes, Series Due January 15, 2019	—		250.0
6.65%	Senior Notes, Series Due July 15, 2027	125.0		125.0
6.50%	Senior Notes, Series Due April 15, 2028	100.0		100.0
3.80%	Senior Notes, Series Due August 15, 2028	400.0		400.0
3.30%	Senior Notes, Series Due March, 15, 2030	300.0		—
5.75%	Senior Notes, Series Due January 15, 2036	110.0		110.0
6.45%	Senior Notes, Series Due February 1, 2038	200.0		200.0
5.85%	Senior Notes, Series Due June 1, 2040	250.0		250.0
5.25%	Senior Notes, Series Due May 15, 2041	250.0		250.0
3.90%	Senior Notes, Series Due May 1, 2043	250.0		250.0
4.55%	Senior Notes, Series Due March 15, 2044	250.0		250.0
4.00%	Senior Notes, Series Due December 15, 2044	250.0		250.0
4.15%	Senior Notes, Series Due April 1, 2047	300.0		300.0
3.85%	Senior Notes, Series Due August 15, 2047	300.0		300.0
3.80%	Tinker Debt, Due August 31, 2062	9.5		9.6
Other Bonds - OG&E
1.20% - 2.50%	Garfield Industrial Authority, January 1, 2025	47.0		47.0
1.19% - 2.35%	Muskogee Industrial Authority, January 1, 2025	32.4		32.4
1.20% - 2.48%	Muskogee Industrial Authority, June 1, 2027	56.0		56.0
Unamortized debt expense		(24.2)		(22.9)
Unamortized discount		(10.5)		(10.2)
Total long-term debt		3,195.2		3,146.9
Less: long-term debt due within one year		—		(250.0)
Total long-term debt (excluding long-term debt due within one year)		3,195.2		2,896.9
Total capitalization (including long-term debt due within one year)		$	7,334.7	$	7,152.0

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

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OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(In millions)	Shares Outstanding	Common Stock		Premium on Common Stock		Retained Earnings		Accumulated Other Comprehensive (Loss) Income		Total
Balance at December 31, 2016	199.7	$	2.0	$	1,103.8	$	2,367.3	$	(29.3)	$	3,443.8
Net income	—	—		—		619.0		—		619.0
Cumulative effect of change in accounting principles	—	—		—		26.8		(4.5)		22.3
Other comprehensive income, net of tax	—	—		—		—		10.6		10.6
Dividends declared on common stock ($1.2700 per share)	—	—		—		(253.6)		—		(253.6)
Expense of common stock	—	—		(0.1)		—		—		(0.1)
Stock-based compensation	—	—		9.1		—		—		9.1
Balance at December 31, 2017	199.7	$	2.0	$	1,112.8	$	2,759.5	$	(23.2)	$	3,851.1
Net income	—	—		—		425.5		—		425.5
Other comprehensive loss, net of tax	—	—		—		—		(5.7)		(5.7)
Dividends declared on common stock ($1.3950 per share)	—	—		—		(278.7)		—		(278.7)
Expense of common stock	—	—		(0.1)		—		—		(0.1)
Stock-based compensation	—	—		13.0		—		—		13.0
Balance at December 31, 2018	199.7	$	2.0	$	1,125.7	$	2,906.3	$	(28.9)	$	4,005.1
Net income	—	—		—		433.6		—		433.6
Other comprehensive income, net of tax	—	—		—		—		1.0		1.0
Dividends declared on common stock ($1.5050 per share)	—	—		—		(303.8)		—		(303.8)
Stock-based compensation	0.4	—		3.6		—		—		3.6
Balance at December 31, 2019	200.1	$	2.0	$	1,129.3	$	3,036.1	$	(27.9)	$	4,139.5

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

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OGE ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.Summary of Significant Accounting Policies

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 Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.

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

The natural gas midstream operations segment represents the Company's investment in Enable through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is 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. Enable's 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.

The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and Enable are assigned as such. Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method. The "Distrigas" method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. The Company adopted this method as a result of a recommendation by the OCC Staff. The Company believes this method provides a reasonable basis for allocating common expenses.

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.

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

December 31 (In millions)	2019		2018
REGULATORY ASSETS
Current:
Fuel clause under recoveries	$	39.5	$	2.0
Production tax credit rider over credit (A)	1.7		6.9
Oklahoma demand program rider under recovery (A)	—		6.4
Other (A)	7.5		3.2
Total current regulatory assets	$	48.7	$	18.5
Non-current:
Benefit obligations regulatory asset	$	167.2	$	188.2
Deferred storm expenses	65.5		36.5
Sooner Dry Scrubbers	20.6		4.5
Smart Grid	18.4		25.6
Unamortized loss on reacquired debt	10.6		11.4
Arkansas deferred pension expenses	8.0		6.8
Pension tracker	2.3		—
Other	13.4		12.8
Total non-current regulatory assets	$	306.0	$	285.8
REGULATORY LIABILITIES
Current:
Reserve for tax refund and interim surcharge (B)	$	12.7	$	15.4
Fuel clause over recoveries	4.8		0.3
SPP cost tracker over recovery (B)	2.6		16.8
Oklahoma demand program rider over recovery (B)	2.0		—
Transmission cost recovery rider over recovery (B)	—		2.7
Other (B)	6.9		1.4
Total current regulatory liabilities	$	29.0	$	36.6
Non-current:
Income taxes refundable to customers, net	$	899.2	$	937.1
Accrued removal obligations, net	318.5		308.1
Pension tracker	—		18.7
Other	5.8		6.8
Total non-current regulatory liabilities	$	1,223.5	$	1,270.7

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

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

Fuel clause under and over recoveries are generated from OG&E's customers when OG&E's cost of fuel either exceeds or is less than the amount billed to its customers, respectively. OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.

As approved by the OCC, OG&E utilizes a rider separate from base rates to credit customers for production tax credits.

OG&E recovers program costs related to the Demand and Energy Efficiency Program in Oklahoma through the Demand Program Rider, which operates on a three-year program cycle. The current program cycle, which runs through 2021,

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includes recovery of (i) energy efficiency program costs, (ii) lost revenues associated with certain achieved energy efficiency and demand savings, (iii) performance-based incentives and (iv) costs associated with research and development investments.

The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost. These expenses are recorded as a regulatory asset as OG&E historically has recovered and currently recovers pension and postretirement benefit plan expense in its electric rates. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the benefit obligations regulatory asset balance to be reclassified to accumulated other comprehensive income.

The following table is a summary of the components of the benefit obligations regulatory asset:

December 31 (In millions)	2019		2018
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	160.5	$	185.3
Postretirement Benefit Plans:
Net loss	23.3		25.6
Prior service cost	(16.6)		(22.7)
Total	$	167.2	$	188.2

The following amounts in the benefit obligations regulatory asset at December 31, 2019 are expected to be recognized as components of net periodic benefit cost in 2020: 

(In millions)
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	11.4
Postretirement Benefit Plans:
Net loss	2.8
Prior service cost	(6.1)
Total	$	8.1

OG&E includes in expense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million annually and defers to a regulatory asset any additional expenses incurred over $2.7 million. OG&E expects to recover the amounts deferred each year over a five-year period in accordance with historical practice.

As approved by the OCC in June 2018, OG&E deferred the non-fuel incremental operation and maintenance expenses, depreciation, debt cost associated with the capital investment and related ad valorem taxes for the Dry Scrubbers at Sooner Units 1 and 2 as a regulatory asset. As approved by the OCC, these costs are being recovered over 25 years.

OG&E deferred to a regulatory asset the incremental and stranded costs that were accumulated during Smart Grid deployment, including (i) costs for web portal access, (ii) costs for education and home energy reports and (iii) stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters. As approved by the OCC and APSC, these costs are being recovered over a six-year period.

Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt. These amounts are recorded in interest expense and are being amortized over the term of the long-term debt which replaced the previous long-term debt. The unamortized loss on reacquired debt is recovered as a part of OG&E's cost of capital.

Arkansas includes a certain level of pension expense in base rates. When the Pension Plan experiences a settlement, which represents an acceleration of future pension costs, OG&E defers to a regulatory asset the Arkansas jurisdictional portion of each settlement, which historically was recovered from customers over the average life of the remaining plan participants. A portion of these settlements is being recovered in current rates, and recovery of additional amounts will be requested as additional settlements occur. For additional information related to settlements, see Note 13.

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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 regulatory asset in the table above.

As a result of 2018 filings with the OCC, APSC and FERC, OG&E established mechanisms to refund to customers the amount of excess taxes received through rates, with an ongoing adjustment for any excess accumulated deferred income taxes resulting from the 2017 Tax Act. Additional amounts due to customers will be refunded in accordance with agreements in each jurisdiction.

OG&E recovers certain SPP costs related to base plan charges from its customers and refunds certain SPP revenues received to its customers in Oklahoma through the SPP cost tracker and in Arkansas through the transmission cost recovery rider.

Income taxes refundable to customers, net, represents the reduction in accumulated deferred income taxes resulting from the reduction in the federal income tax rate as part of the 2017 Tax Act and includes income taxes recoverable from customers that represent income tax benefits previously used to reduce OG&E's revenues (treated as regulatory assets). These liabilities will be returned to customers in varying amounts over approximately 80 years, and the assets will be amortized over the estimated remaining life of the assets to which they relate, as the temporary differences that generated the income tax benefits turn around.

Accrued removal obligations, net represents asset retirement costs previously recovered from ratepayers for other than legal obligations.

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.

Use of Estimates

In preparing the 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 Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Changes to these assumptions and estimates could have a material effect on the Company's 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 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.

Cash and Cash Equivalents

For purposes of the Consolidated Financial Statements, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.

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Allowance for Uncollectible Accounts Receivable

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate, which is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable in the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense in the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $1.5 million and $1.7 million at December 31, 2019 and 2018, respectively.

New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers whose outside credit scores indicate an elevated risk are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored, and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.

Fuel Inventories

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was $46.3 million and $57.6 million at December 31, 2019 and 2018, respectively.

Property, Plant and Equipment

All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances, and the cost of such property net of any salvage proceeds is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation, and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Other Expense. Repair and replacement of minor items of property are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense.

The tables below present OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant, such as fuel, maintenance expense and other operating expenses, are included in the applicable financial statement captions in the Consolidated Statements of Income.

December 31, 2019 (In millions)	Percentage Ownership		Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
McClain Plant (A)	77	%	$	254.4	$	83.5	$	170.9
Redbud Plant (A)(B)	51	%	$	529.9	$	159.0	$	370.9

(A)Construction work in progress was $0.2 million and $1.4 million for the McClain and Redbud Plants, respectively.

(B)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.

December 31, 2018 (In millions)	Percentage Ownership		Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
McClain Plant (A)	77	%	$	227.2	$	78.2	$	149.0
Redbud Plant (A)(B)	51	%	$	493.9	$	145.3	$	348.6

(A)Construction work in progress was $0.2 million and $0.9 million for the McClain and Redbud Plants, respectively.

(B)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.

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The Company's property, plant and equipment and related accumulated depreciation are divided into the following major classes: 

December 31, 2019 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
OGE Energy:
Property, plant and equipment	$	6.1	$	—	$	6.1
OGE Energy property, plant and equipment	6.1		—		6.1
OG&E:
Distribution assets	4,468.6		1,381.1		3,087.5
Electric generation assets (A)	4,838.6		1,601.0		3,237.6
Transmission assets (B)	2,901.1		565.5		2,335.6
Intangible plant	225.2		145.4		79.8
Other property and equipment	473.1		175.1		298.0
OG&E property, plant and equipment	12,906.6		3,868.1		9,038.5
Total property, plant and equipment	$	12,912.7	$	3,868.1	$	9,044.6

(A)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.

(B)This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.8 million.

December 31, 2018 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
OGE Energy:
Property, plant and equipment	$	6.1	$	—	$	6.1
OGE Energy property, plant and equipment	6.1		—		6.1
OG&E:
Distribution assets	4,229.4		1,324.5		2,904.9
Electric generation assets (A)	4,657.2		1,572.8		3,084.4
Transmission assets (B)	2,846.7		534.2		2,312.5
Intangible plant	187.6		135.1		52.5
Other property and equipment	444.2		160.8		283.4
OG&E property, plant and equipment	12,365.1		3,727.4		8,637.7
Total property, plant and equipment	$	12,371.2	$	3,727.4	$	8,643.8

(A)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.

(B)This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.7 million.

OG&E's unamortized computer software costs, included in intangible plant above, were $71.3 million and $44.3 million at December 31, 2019 and 2018, respectively.

The following table summarizes the Company's amortization expense for computer software costs.

Year Ended December 31 (In millions)	2019		2018		2017
OGE Energy	$	—	$	—	$	0.2
OG&E	11.0		9.6		8.8
Total	$	11.0	$	9.6	$	9.0

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Depreciation and Amortization

The provision for depreciation, which was 2.7 percent of the average depreciable utility plant for both 2019 and 2018, is calculated using the straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant and is based on the average life group method. In 2020, the provision for depreciation is projected to be 2.7 percent of the average depreciable utility plant.

Amortization of intangible assets is calculated using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2019, 98.9 percent will be amortized over 10.4 years with the remaining 1.1 percent of the intangible plant balance at December 31, 2019 being amortized over 23.7 years.  

Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired assets. Plant acquisition adjustments include $148.3 million for the Redbud Plant, which is being amortized over a 27 year life and $3.3 million for certain transmission substation facilities in OG&E's service territory, which are being amortized over a 37 to 59 year period.

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 December 31, 2019 as presented in Note 14. 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 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 Consolidated Statements of Cash Flows.

Asset Retirement Obligations

OG&E has asset retirement obligations primarily associated with the removal of company-owned wind turbines on leased land, as well as the removal of asbestos from certain power generating stations. The Company has recorded asset retirement obligations that are being accreted over their respective lives ranging from ten to 68 years. 

The following table summarizes changes to the Company's asset retirement obligations during the years ended December 31, 2019 and 2018.

(In millions)	2019		2018
Balance at January 1	$	83.9	$	75.1
Accretion expense	1.0		3.4
Revisions in estimated cash flows (A)	(2.4)		6.8
Liabilities settled (B)	(9.0)		(1.4)
Balance at December 31	$	73.5	$	83.9

(A)Assumptions changed related to the estimated cost of the removal of wind turbine assets and asbestos removal at OG&E's generating facilities.

(B)Asset retirement obligations were settled for asbestos removal and for the closure of an ash pond at OG&E's generating facilities.

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Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost. The Company had $18.7 million and $23.4 million in accrued environmental liabilities at December 31, 2019 and 2018, respectively, which are included in the Company's asset retirement obligations.

Allowance for Funds Used During Construction

Allowance for funds used during construction, a non-cash item, is reflected as an increase to Net Other Income and a reduction to Interest Expense in the Consolidated Statements of Income and as an increase to Construction Work in Progress in the Consolidated Balance Sheets. Allowance for funds used during construction is calculated according to the FERC requirements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction rates, compounded semi-annually, were 7.6 percent, 7.6 percent and 8.2 percent for the years ended December 31, 2019, 2018 and 2017, respectively.  

Collection of Sales Tax

In the normal course of its operations, OG&E collects sales tax from its customers. OG&E records a current liability for sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. OG&E excludes the sales tax collected from its operating revenues.

Revenue Recognition

General

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

Integrated Market and Transmission

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

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

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

Other Revenues

Revenues from Alternative Revenue Programs

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

Fuel Adjustment Clauses

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.

Leases

The Company evaluates all contracts under ASC 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 ASC 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.

Income Taxes

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. 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. The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company recognizes interest related to unrecognized tax benefits in Interest Expense and recognizes penalties in Other Expense in the Consolidated Statements of Income.

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Accrued Vacation

The Company accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned but not taken.

Accumulated Other Comprehensive Income (Loss)

The following tables summarize changes in the components of accumulated other comprehensive income (loss) attributable to the Company during 2018 and 2019. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan		Postretirement Benefit Plans
(In millions)	Net Gain  (Loss)		Net Gain (Loss)		Prior Service Cost (Credit)		Other Comprehensive Loss from Unconsolidated Affiliates		Total
Balance at December 31, 2017	$	(32.7)	$	2.5	$	7.0	$	—	$	(23.2)
Other comprehensive income (loss) before reclassifications	(14.1)		2.1		—		—		(12.0)
Amounts reclassified from accumulated other comprehensive income (loss)	3.3		—		(1.7)		—		1.6
Settlement cost	4.7		—		—		—		4.7
Net current period other comprehensive income (loss)	(6.1)		2.1		(1.7)		—		(5.7)
Balance at December 31, 2018	(38.8)		4.6		5.3		—		(28.9)
Other comprehensive income (loss) before reclassifications	(8.3)		(0.2)		—		(0.6)		(9.1)
Amounts reclassified from accumulated other comprehensive income (loss)	3.4		(0.2)		(1.7)		—		1.5
Settlement cost	8.6		—		—		—		8.6
Net current period other comprehensive income (loss)	3.7		(0.4)		(1.7)		(0.6)		1.0
Balance at December 31, 2019	$	(35.1)	$	4.2	$	3.6	$	(0.6)	$	(27.9)

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The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the years ended December 31, 2019 and 2018.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)				Affected Line Item in the Consolidated Statements of Income
	Year Ended December 31,
(In millions)	2019		2018
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses	$	(4.5)	$	(4.4)	(A)
Settlement cost	(11.3)		(6.3)		(A)
	(15.8)		(10.7)		Income Before Taxes
	(3.8)		(2.7)		Income Tax Expense
	$	(12.0)	$	(8.0)	Net Income
Amortization of postretirement benefit plans items:
Prior service credit	$	2.3	$	2.3	(A)
Actuarial gains	0.2		—		(A)
	2.5		2.3		Income Before Taxes
	0.6		0.6		Income Tax Expense
	$	1.9	$	1.7	Net Income
Total reclassifications for the period, net of tax	$	(10.1)	$	(6.3)	Net Income

(A)These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 13 for additional information).

The amounts in accumulated other comprehensive loss (gain) at December 31, 2019 that are expected to be recognized into earnings in 2020 are as follows:

(In millions)
Pension Plan and Restoration of Retirement Income Plan:
Net gain	$	(4.2)
Postretirement Benefit Plans:
Net loss	0.2
Prior service cost	2.3
Total, net of tax	$	(1.7)

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 ASC 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, ASC 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

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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 ASC 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 ASC 842 land easements that exist or expired before the entity's adoption of ASC 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 ASC 842 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 ASC 840 disclosures for all periods that continue to be reported under ASC 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 Consolidated Balance Sheet. The new standard did not have a material impact on the Company's 2019 Consolidated Statement 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 ASC 842.

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 is applied utilizing a modified-retrospective approach. The Company determined the only financial instrument that the Company currently holds and is required to measure under ASU 2016-13 is its trade receivables. Upon adoption of this ASU, the Company considers forecasts of future economic conditions in addition to the historical data utilized prior to ASU 2016-13 when measuring the reserve for trade receivables. The Company evaluated its reserve for trade receivables in light of the new guidance and determined that no adjustment was necessary to the amount recorded as of January 1, 2020.

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. The Company adopted and prospectively applied the new guidance beginning in the first quarter of 2020, which did not have a material effect on the Consolidated Financial Statements upon adoption.

Issued Accounting Standards Not Yet Adopted

Simplifying the Accounting for Income Taxes. In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740)." The new guidance simplifies the accounting for income taxes by removing certain exceptions to the general principles in ASC 740 and improves consistent application of existing guidance. ASU 2019-12 will be effective for the Company as of January 1, 2021 and can be early adopted. The Company is currently assessing the impact of these rule changes on its Consolidated Financial Statements.

Investments - Equity Method and Joint Ventures. In January 2020, the FASB issued ASU 2020-01, "Investments - Equity Securities (Topic 321), Investments - Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815)." The new guidance makes targeted improvements to address certain aspects of accounting for financial instruments, clarifying the interaction of the accounting for equity securities under ASC 321 and investments accounted for under the equity method of accounting in ASC 323. ASU 2020-01 should be applied prospectively and will be effective for the

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Company as of January 1, 2021. The Company is currently assessing the impact of these rule changes on its 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 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

	Year Ended December 31,
(In millions)	2019		2018
Residential	$	865.8	$	877.8
Commercial	486.6		500.0
Industrial	217.8		228.9
Oilfield	200.4		190.4
Public authorities and street light	190.3		197.4
System sales revenues	1,960.9		1,994.5
Provision for rate refund	(0.9)		(6.0)
Integrated market	38.4		48.7
Transmission	148.0		147.4
Other	29.1		27.1
Revenues from contracts with customers	$	2,175.5	$	2,211.7

4.Leases

Based on its evaluation of all contracts under ASC 842, as described in Note 1, 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

OG&E 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.

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Financial Statement Information and Maturity Analysis of Lease Liabilities

Operating lease cost was $6.0 million, $4.9 million and $6.2 million for the years ended December 31, 2019, 2018 and 2017, respectively. The following table presents amounts recognized for operating leases in the Company's 2019 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.

(In millions)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	5.6
Right-of-use assets obtained in exchange for new operating lease liabilities	$	10.7
(Dollars in millions)	December 31, 2019
Right-of-use assets at period end (A)	$	40.9
Operating lease liabilities at period end (B)	$	45.8
Operating lease weighted-average remaining lease term (in years)	13.1
Operating lease weighted-average discount rate	3.9		%

	December 31,
Future minimum operating lease payments as of:	2019		2018(C)(D)
(In millions)
2019	$	—	$	22.1
2020	6.2		3.9
2021	5.8		3.5
2022	5.2		2.9
2023	5.2		2.9
2024	3.1		3.0
Thereafter	34.7		34.6
Total future minimum lease payments	60.2		$	72.9
Less: Imputed interest	14.4
Present value of net minimum lease payments	$	45.8

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

(B) Included in Other Deferred Credits and Other Liabilities in the 2019 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.

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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 December 31, 2019, the Company owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units. On December 31, 2019, Enable's common unit price closed at $10.03. The Company recorded equity in earnings of unconsolidated affiliates of $113.9 million, $152.8 million and $131.2 million for the years ended December 31, 2019, 2018 and 2017, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex LLC and its underlying equity in the net assets of Enable. The basis difference is being amortized, 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 as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017.

	December 31,
Balance Sheet	2019		2018
(In millions)
Current assets	$	389	$	449
Non-current assets	$	11,877	$	11,995
Current liabilities	$	780	$	1,615
Non-current liabilities	$	4,077	$	3,211

	Year Ended December 31,
Income Statement	2019		2018		2017
(In millions)
Total revenues	$	2,960	$	3,431	$	2,803
Cost of natural gas and NGLs	$	1,279	$	1,819	$	1,381
Operating income	$	569	$	648	$	528
Net income	$	360	$	485	$	400

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The following table reconciles OGE Energy's equity in earnings of unconsolidated affiliates for the years ended December 31, 2019, 2018 and 2017.

	Year Ended December 31,
(In millions)	2019			2018			2017
Enable net income	$	360.0		$	485.3		$	400.3
OGE Energy's percent ownership at period end	25.5		%	25.6		%	25.7		%
OGE Energy's portion of Enable net income	$	91.8		$	124.4		$	102.7
Amortization of basis difference and dilution recognition (A)	22.1			28.4			28.5
Equity in earnings of unconsolidated affiliates	$	113.9		$	152.8		$	131.2

(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 December 31, 2019.

(In millions)
Basis difference at December 31, 2018	$	680.3
Amortization of basis difference (A)	(27.8)
Basis difference at December 31, 2019	$	652.5

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

On February 7, 2020, 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 $144.0 million, $141.2 million and $141.2 million during the years ended December 31, 2019, 2018 and 2017, 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 $0.5 million, $0.6 million and $2.3 million for December 31, 2019, 2018 and 2017, respectively.

Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of December 31, 2019, 80 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $23.2 million, $27.5 million and $29.5 million in 2019, 2018 and 2017, respectively, under the seconding agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by $17.3 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.

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The Company had accounts receivable from Enable for amounts billed for support services, including the cost of seconded employees, of $0.8 million and $1.7 million as of December 31, 2019 and 2018, which are included in Accounts Receivable in the Company's Consolidated Balance Sheets.

OG&E and Enable

Enable provides gas transportation services to OG&E pursuant to an agreement, which expires in May 2024, 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. Further, an additional gas transportation services contract with Enable became effective in December 2018 related to the project to convert Muskogee Units 4 and 5 from coal to natural gas. The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2019, 2018 and 2017.

	Year Ended December 31,
(In millions)	2019		2018		2017
Operating revenues:
Electricity to power electric compression assets	$	15.9	$	16.3	$	14.0
Cost of sales:
Natural gas transportation services	$	41.2	$	37.9	$	35.0
Natural gas (sales) purchases	$	(6.0)	$	(3.2)	$	(2.1)

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

	2019				2018
December 31 (In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Classification
Long-term Debt (including Long-term Debt due within one year):
OG&E Senior Notes	$	3,050.3	$	3,500.4	$	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	$	9.5	$	10.0	$	9.6	$	8.7	Level 3

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7.Stock-Based Compensation

In 2013, the Company adopted, and its shareholders approved, the Stock Incentive Plan. Under the Stock Incentive Plan, restricted stock, restricted stock units, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of the Company and its subsidiaries. The Company has authorized the issuance of up to 7,400,000 shares under the Stock Incentive Plan.

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the years ended December 31, 2019, 2018 and 2017 related to the Company's performance units and restricted stock units.

Year Ended December 31 (In millions)	2019		2018		2017
Performance units:
Total shareholder return	$	8.7	$	8.2	$	7.6
Earnings per share	4.3		5.1		1.4
Total performance units	13.0		13.3		9.0
Restricted stock units	0.9		0.1		0.1
Total compensation expense	$	13.9	$	13.4	$	9.1
Income tax benefit	$	3.6	$	3.4	$	3.5

The Company has issued new shares of common stock to satisfy restricted stock unit grants and payouts of earned performance units. In 2019, 2018 and 2017, there were 443,900 shares, 26,211 shares and 2,298 shares, respectively, of new common stock issued pursuant to the Company's Stock Incentive Plan related to restricted stock unit grants and payouts of earned performance units.

Performance Units

Under the Stock Incentive Plan, the Company has issued performance units which represent the value of one share of the Company's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with the Company or a subsidiary prior to the end of the primarily three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle. The Company estimates expected forfeitures in accounting for performance unit compensation expense.

The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of the Company's common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a primarily three-year award cycle (i.e., three-year cliff vesting period) is dependent on the Company's total shareholder return ranking relative to a peer group of companies. The performance units granted based on earnings per share are contingently awarded and will be payable in shares of the Company's common stock based on the Company's earnings per share growth over a primarily three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of the Company's Board of Directors. All of these performance units are classified as equity in the Consolidated Balance Sheets. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of the Company's Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee.

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Performance Units – Total Shareholder Return

The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the primarily three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends are accrued on a quarterly basis pending achievement of payout criteria and are included in the fair value calculations. Expected price volatility is based on the historical volatility of the Company's common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to the Company's performance units based on total shareholder return. The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table.

	2019			2018			2017
Number of units granted	208,647			261,916			260,570
Fair value of units granted	$	47.00		$	36.86		$	41.77
Expected dividend yield	4.0		%	3.6		%	3.8		%
Expected price volatility	17.0		%	19.0		%	19.9		%
Risk-free interest rate	2.47		%	2.38		%	1.44		%
Expected life of units (in years)	2.86			2.86			2.80

Performance Units – Earnings Per Share

The fair value of the performance units based on earnings per share is based on grant date fair value which is equivalent to the price of one share of the Company's common stock on the date of grant. The fair value of performance units based on earnings per share varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. The Company reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to the Company's performance units based on earnings per share. In 2019, the Compensation Committee of the Company's Board of Directors voted to grant restricted stock units in lieu of performance units based on earnings per share. For 2018 and 2017, the number of performance units granted based on earnings per share and the grant date fair value are shown in the following table. 

	2018		2017
Number of units granted	87,308		86,857
Fair value of units granted	$	31.03	$	34.83

Restricted Stock Units

Under the Stock Incentive Plan, the Company has issued restricted stock units to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace, and for the 2019 grant cycle, restricted stock units were granted in lieu of performance units based on earnings per share. The restricted stock units vest primarily in a three-year award cycle (i.e., three-year cliff vesting period). Prior to vesting, each restricted stock unit is subject to forfeiture if the recipient ceases to render substantial services to the Company or a subsidiary. These restricted stock units may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.

The fair value of the restricted stock units was based on the closing market price of the Company's common stock on the grant date. Compensation expense for the restricted stock units is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a primarily three-year vesting period. Also, for those restricted stock units that vest in one-third annual increments over a three-year cycle, the Company treats its restricted stock units as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period.

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Dividends will only be paid on restricted stock unit awards that vest; therefore, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock units is based on the non-vested period since inception of the primarily three-year award cycle. There are no post-vesting restrictions related to the Company's restricted stock units. The number of restricted stock units granted and the grant date fair value are shown in the following table. 

	2019		2018		2017
Restricted stock units granted	75,929		826		3,145
Fair value of restricted stock units granted	$	41.71	$	36.28	$	34.96

Performance Units and Restricted Stock Units Activity

A summary of the activity for the Company's performance units and restricted stock units at December 31, 2019 and changes in 2019 are shown in the following table.

	Performance Units								Restricted Stock Units
	Total Shareholder Return				Earnings Per Share
(Dollars in millions)	Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value		Number of Shares	Aggregate Intrinsic Value
Units/shares outstanding at 12/31/18	755,480				251,825				2,711
Granted	208,647	(A)			—				75,929
Converted	(274,078)	(B)	$	19.8	(91,356)	(B)	$	7.2	N/A
Vested	N/A				N/A				(2,161)	$	0.1
Forfeited	(25,232)				(5,298)				(3,599)
Units/shares outstanding at 12/31/19	664,817		$	35.4	155,171		$	11.5	72,880	$	3.2
Units/shares fully vested at 12/31/19	222,163		$	11.5	74,053		$	6.6

(A)For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.

(B)These amounts represent performance units that vested at December 31, 2018 which were settled in February 2019.

A summary of the activity for the Company's non-vested performance units and restricted stock units at December 31, 2019 and changes in 2019 are shown in the following table.

	Performance Units								Restricted Stock Units
	Total Shareholder Return				Earnings Per Share
	Number of Units		Weighted-Average Grant Date Fair Value		Number of Units		Weighted-Average Grant Date Fair Value		Number of Shares		Weighted-Average Grant Date Fair Value
Units/shares non-vested at 12/31/18	481,402		$	39.17	160,469		$	32.82	2,711		$	35.00
Granted	208,647	(A)	$	47.00	—		$	—	75,929		$	41.71
Vested	(222,163)		$	41.76	(74,053)		$	34.83	(2,161)		$	34.66
Forfeited	(25,232)		$	41.45	(5,298)		$	32.07	(3,599)		$	41.78
Units/shares non-vested at 12/31/19	442,654		$	41.43	81,118		$	31.03	72,880		$	41.66
Units/shares expected to vest	418,331	(B)			77,617	(B)			54,102	(B)

(A)For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.

(B)The intrinsic value of the performance units based on total shareholder return and earnings per share is $22.8 million and $4.7 million, respectively. The intrinsic value of restricted stock units is $2.4 million.

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Fair Value of Vested Performance Units and Restricted Stock Units

A summary of the Company's fair value for its vested performance units and restricted stock units is shown in the following table.

Year Ended December 31 (In millions)	2019		2018		2017
Performance units:
Total shareholder return	$	9.3	$	5.9	$	6.3
Earnings per share	$	5.2	$	4.9	$	1.2
Restricted stock units	$	0.1	$	0.1	$	0.1

Unrecognized Compensation Cost

A summary of the Company's unrecognized compensation cost for its non-vested performance units and restricted stock units and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

December 31, 2019	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance units:
Total shareholder return	$	8.7	1.67
Earnings per share	0.8		1.00
Total performance units	9.5
Restricted stock units	1.5		1.98
Total unrecognized compensation cost	$	11.0

8.Supplemental Cash Flow Information

The following table presents information about investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments. Cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds are also presented in the table.

Year Ended December 31 (In millions)	2019		2018		2017
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement	$	28.9	$	(9.2)	$	(2.6)
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of interest capitalized) (A)	$	152.2	$	153.8	$	139.6
Income taxes (net of income tax refunds)	$	5.5	$	2.8	$	(16.0)

(A)Net of interest capitalized of $2.8 million, $11.7 million and $18.0 million in 2019, 2018 and 2017, respectively.

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9.Income Taxes

Income Tax Expense (Benefit)

The items comprising income tax expense (benefit) are as follows: 

Year Ended December 31 (In millions)	2019		2018		2017
Provision (benefit) for current income taxes:
Federal	$	(6.4)	$	(1.9)	$	4.9
State	5.1		(4.4)		(4.2)
Total provision (benefit) for current income taxes	(1.3)		(6.3)		0.7
Provision (benefit) for deferred income taxes, net:
Federal	48.5		74.7		(75.9)
State	(17.4)		3.7		26.0
Total provision (benefit) for deferred income taxes, net	31.1		78.4		(49.9)
Deferred federal investment tax credits, net	—		0.1		(0.1)
Total income tax expense (benefit)	$	29.8	$	72.2	$	(49.3)

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal tax or state and local examinations by tax authorities for years prior to 2016. 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. Additionally, OG&E earns federal tax credits associated with production from its wind facilities. Oklahoma production and investment state tax credits are also earned on investments in electric and solar generating facilities which further reduce OG&E's effective tax rate.

The following schedule reconciles the statutory tax rates to the effective income tax rate:

Year Ended December 31	2019		2018		2017
Statutory federal tax rate	21.0	%	21.0	%	35.0	%
Executive compensation limitation	0.2		0.2		—
Federal renewable energy credit (A)	(6.0)		(5.1)		(4.8)
Amortization of net unfunded deferred taxes	(4.5)		(2.1)		0.7
State income taxes, net of federal income tax benefit	(1.2)		0.4		2.0
Stock-based compensation	(1.2)		—		—
Remeasurement of state deferred tax liabilities	(0.8)		(0.4)		0.4
Other	(0.7)		0.4		(0.1)
401(k) dividends	(0.4)		(0.3)		(0.5)
Federal deferred tax revaluation	—		0.4		(41.2)
Federal investment tax credits, net	—		—		(0.1)
Effective income tax rate	6.4	%	14.5	%	(8.6)	%

(A)Represents credits associated with the production from OG&E's wind farms.

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The deferred tax provisions are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E. The components of Deferred Income Taxes at December 31, 2019 and 2018 were as follows:

December 31 (In millions)	2019		2018
Deferred income tax liabilities, net:
Accelerated depreciation and other property related differences	$	1,656.8	$	1,605.3
Investment in Enable	478.2		469.9
Regulatory assets	28.4		17.4
Company Pension Plan	4.1		7.6
Bond redemption-unamortized costs	2.2		2.4
Derivative instruments	1.6		1.7
Other	0.4		1.1
Federal tax credits	(238.0)		(237.8)
Income taxes recoverable from customers, net	(229.9)		(239.6)
State tax credits	(185.8)		(156.0)
Regulatory liabilities	(68.1)		(78.8)
Postretirement medical and life insurance benefits	(23.3)		(23.6)
Asset retirement obligations	(19.2)		(21.5)
Net operating losses	(16.6)		(20.2)
Accrued liabilities	(10.7)		(12.5)
Accrued vacation	(2.1)		(2.3)
Deferred federal investment tax credits	(1.8)		(1.8)
Uncollectible accounts	(0.4)		(0.4)
Total deferred income tax liabilities, net	$	1,375.8	$	1,310.9

As of December 31, 2019, the Company has classified $16.4 million of unrecognized tax benefits as a reduction of deferred tax assets recorded. Management is currently unaware of any issues under review that could result in significant additional payments, accruals or other material deviation from this amount.

Following is a reconciliation of the Company's total gross unrecognized tax benefits as of the years ended December 31, 2019, 2018 and 2017.

(In millions)	2019		2018		2017
Balance at January 1	$	20.7	$	20.7	$	20.7
Tax positions related to current year:
Additions	—		—		—
Balance at December 31	$	20.7	$	20.7	$	20.7

As of each of December 31, 2019, 2018 and 2017, there were $16.4 million of unrecognized tax benefits that, if recognized, would affect the annual effective tax rate.

Where applicable, the Company classifies income tax-related interest and penalties as interest expense and other expense, respectively. During the year ended December 31, 2019, there were no income tax-related interest or penalties recorded with regard to uncertain tax positions.

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The Company sustained federal and state tax operating losses through 2012 caused primarily by bonus depreciation and other book versus tax temporary differences. As a result, the Company had accrued federal and state income tax benefits carrying into 2017, when the remaining federal net operating loss was utilized. State operating losses are being carried forward for utilization in future years. In addition to the tax operating losses, the Company was unable to utilize the various tax credits that were generated during these years. These tax losses and credits are being carried as deferred tax assets and will be utilized in future periods. Under current law, the Company anticipates future taxable income will be sufficient to utilize remaining losses and credits before they begin to expire after 2020. The following table summarizes these carry forwards:

(In millions)	Carry Forward Amount		Deferred Tax Asset		Earliest Expiration Date
State operating loss	$	371.6	$	16.6	2030
Federal tax credits	$	238.0	$	238.0	2032
State tax credits:
Oklahoma investment tax credits	$	183.9	$	145.3	N/A
Oklahoma capital investment board credits	$	12.4	$	12.4	N/A
Oklahoma zero emission tax credits	$	34.9	$	28.0	2020
Louisiana inventory credits	$	0.2	$	0.1	2020

N/A - not applicable

10.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 in 2019. The Company may, from time to time, issue shares under its Automatic Dividend Reinvestment and Stock Purchase Plan or purchase shares traded on the open market. At December 31, 2019, there were 4,774,442 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

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.

(In millions except per share data)	2019		2018		2017
Net income	$	433.6	$	425.5	$	619.0
Average common shares outstanding:
Basic average common shares outstanding	200.1		199.7		199.7
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.6		0.8		0.3
Diluted average common shares outstanding	200.7		200.5		200.0
Basic earnings per average common share	$	2.17	$	2.13	$	3.10
Diluted earnings per average common share	$	2.16	$	2.12	$	3.10
Anti-dilutive shares excluded from earnings per share calculation	—		—		—

Dividend Restrictions

The Company's Certificate of Incorporation places restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Before the Company can pay any dividends on its common stock, the holders of any of its preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. As there is no preferred stock outstanding, that restriction did not place any effective limit on the Company's ability to pay dividends to its shareholders.

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The Company utilizes receipts from its equity investment in Enable and dividends from OG&E to pay dividends to its shareholders. Enable's partnership agreement requires that it distribute all "available cash," as defined as cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter.

Pursuant to the leverage restriction in the Company's revolving credit agreement, the Company must maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $661.4 million of the Company's retained earnings from being paid out in dividends. Accordingly, approximately $2.4 billion of the Company's retained earnings as of December 31, 2019 are unrestricted for the payment of dividends.

Pursuant to the Federal Power Act, OG&E is restricted from paying dividends from its capital accounts. Dividends are paid from retained earnings. Pursuant to the leverage restriction in OG&E's revolving credit agreement, OG&E must also maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $694.9 million of OG&E's retained earnings from being paid out in dividends. Accordingly, approximately $2.2 billion of OG&E's retained earnings as of December 31, 2019 are unrestricted for the payment of dividends.

11.Long-Term Debt

A summary of the Company's long-term debt is included in the Consolidated Statements of Capitalization. The Company has no long-term debt maturing in the next five years. At December 31, 2019, the Company was in compliance with all of its debt agreements.

The Company has previously incurred costs related to debt refinancing. Unamortized loss on reacquired debt is classified as a Non-Current Regulatory Asset. Unamortized debt expense and unamortized premium and discount on long-term debt are classified as Long-Term Debt in the Consolidated Balance Sheets and are being amortized over the life of the respective debt.

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 as follows:

Series			Date Due	Amount
				(In millions)
1.20%	-	2.50%	Garfield Industrial Authority, January 1, 2025	$	47.0
1.19%	-	2.35%	Muskogee Industrial Authority, January 1, 2025	32.4
1.20%	-	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 Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

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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.

12.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 agreement. As of December 31, 2019, the Company had $112.0 million 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 December 31, 2019.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
	(In millions)
OGE Energy (B)	$	450.0	$	112.0	2.06	%	(D)	March 8, 2023
OG&E (C)	450.0		0.3		1.00	%	(D)	March 8, 2023
Total	$	900.0	$	112.3	2.06	%

(A)Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 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 and OG&E's credit facilities each have a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent, as defined in each such facility. The Company and OG&E's facilities each also contain covenants which restrict the respective borrower and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. The Company and OG&E's facilities are each subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facilities, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in each such facility), nonpayment of uninsured judgments in excess of $100.0 million and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods.

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.

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13.Retirement Plans and Postretirement Benefit Plans

Pension Plan and Restoration of Retirement Income Plan

It is the Company's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by the Company's actuarial consultants. Such contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. The Company made a $20.0 million and $15.0 million contribution to its Pension Plan in 2019 and 2018, respectively. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2020. Any contribution to the Pension Plan during 2020 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. The Company could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.

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 2019, 2018 and 2017, 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 plan settlement charges as presented in the net periodic benefit cost table below. The pension settlement charges did not require a cash outlay by the Company and did not increase the Company's total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.

The Company provides a Restoration of Retirement Income Plan to those participants in the Company's Pension Plan whose benefits are subject to certain limitations of the Code. Participants in the Restoration of Retirement Income Plan receive the same benefits that they would have received under the Company's Pension Plan in the absence of limitations imposed by the federal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan.

Obligations and Funded Status

The following table presents the status of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 2019 and 2018. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E's portion, which is recorded as a regulatory asset as discussed in Note 1) in the Company's Consolidated Balance Sheets. The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods. The benefit obligation for the Company's Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for the Company's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2019 was $563.3 million and $8.1 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2018 was $561.9 million and $7.8 million, respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Consolidated Balance Sheets are included in the following table.

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	Pension Plan				Restoration of Retirement Income Plan				Postretirement Benefit Plans
December 31 (In millions)	2019		2018		2019		2018		2019		2018
Change in benefit obligation
Beginning obligations	$	615.9	$	687.5	$	9.6	$	8.1	$	135.8	$	149.4
Service cost	12.9		14.9		0.5		0.4		0.2		0.3
Interest cost	20.7		23.8		0.4		0.3		5.6		5.4
Plan settlements	(83.1)		(73.7)		(1.2)		(2.0)		—		—
Plan amendments	—		—		0.3		—		—		—
Participants' contributions	—		—		—		—		4.1		3.8
Actuarial losses (gains)	64.3		(22.0)		0.7		2.8		2.9		(9.6)
Benefits paid	(14.6)		(14.6)		—		—		(12.1)		(13.5)
Ending obligations	$	616.1	$	615.9	$	10.3	$	9.6	$	136.5	$	135.8
Change in plans' assets
Beginning fair value	$	522.8	$	635.3	$	—	$	—	$	45.3	$	50.2
Actual return on plans' assets	85.2		(39.2)		—		—		4.6		(0.6)
Employer contributions	20.0		15.0		1.2		2.0		5.1		5.4
Plan settlements	(83.1)		(73.7)		(1.2)		(2.0)		—		—
Participants' contributions	—		—		—		—		4.1		3.8
Benefits paid	(14.6)		(14.6)		—		—		(12.1)		(13.5)
Ending fair value	$	530.3	$	522.8	$	—	$	—	$	47.0	$	45.3
Funded status at end of year	$	(85.8)	$	(93.1)	$	(10.3)	$	(9.6)	$	(89.5)	$	(90.5)

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Net Periodic Benefit Cost

The following table presents the net periodic benefit cost components, before consideration of capitalized amounts, of the Company's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the 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 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 Consolidated Statements of Income.

	Pension Plan						Restoration of Retirement Income Plan						Postretirement Benefit Plans
Year Ended December 31 (In millions)	2019		2018		2017		2019		2018		2017		2019		2018		2017
Service cost	$	12.9	$	14.9	$	15.5	$	0.5	$	0.4	$	0.3	$	0.2	$	0.3	$	0.6
Interest cost	20.7		23.8		26.2		0.4		0.3		0.3		5.6		5.4		7.2
Expected return on plan assets	(36.1)		(44.1)		(42.6)		—		—		—		(1.9)		(2.0)		(2.2)
Amortization of net loss	17.3		16.2		17.4		0.5		0.7		0.4		2.0		3.8		2.0
Amortization of unrecognized prior service cost (A)	—		—		(0.1)		—		0.1		0.1		(8.4)		(8.4)		(3.5)
Settlement cost	27.6		25.1		15.3		0.5		1.0		—		—		—		0.6
Total net periodic benefit cost	42.4		35.9		31.7		1.9		2.5		1.1		(2.5)		(0.9)		4.7
Less: Amount paid by unconsolidated affiliates	2.9		2.5		4.3		0.1		0.1		—		(0.6)		(0.5)		0.3
Net periodic benefit cost	$	39.5	$	33.4	$	27.4	$	1.8	$	2.4	$	1.1	$	(1.9)	$	(0.4)	$	4.4

(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 recognized, as presented in the table above, for the Pension and Restoration of Retirement Income Plans in 2019, 2018 and 2017, the Company recognized the following:

Year Ended December 31 (In millions)	2019		2018		2017
Decrease of pension expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	(16.1)	$	(14.1)	$	(2.3)
Deferral of pension expense related to pension settlement charges:
Oklahoma jurisdiction (A)	$	17.9	$	22.1	$	13.2
Arkansas jurisdiction (A)	$	1.7	$	2.1	$	1.1

(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

In addition to the net periodic benefit income and cost amounts recognized, as presented in the table above, for the postretirement benefit plans in 2019, 2018 and 2017, the Company recognized the following:

Year Ended December 31 (In millions)	2019		2018		2017
Increase of postretirement expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	1.0	$	4.4	$	6.2

(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

(In millions)	2019		2018		2017
Capitalized portion of net periodic pension benefit cost	$	3.6	$	3.8	$	4.4
Capitalized portion of net periodic postretirement benefit cost	$	0.2	$	0.2	$	1.2

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Rate Assumptions

	Pension Plan and Restoration of Retirement Income Plan						Postretirement Benefit Plans
Year Ended December 31	2019		2018		2017		2019		2018		2017
Assumptions to determine benefit obligations:
Discount rate	3.15	%	4.20	%	3.60	%	3.25	%	4.30	%	3.70	%
Rate of compensation increase	4.20	%	4.20	%	4.20	%	N/A		N/A		N/A
Assumptions to determine net periodic benefit cost:
Discount rate	3.63	%	3.73	%	4.00	%	4.30	%	3.70	%	4.20	%
Expected return on plan assets	7.50	%	7.50	%	7.50	%	4.00	%	4.00	%	4.00	%
Rate of compensation increase	4.20	%	4.20	%	4.20	%	N/A		N/A		4.20	%

N/A - not applicable

The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The discount rate used to determine net benefit cost for the current year is the same discount rate used to determine the benefit obligation as of the previous year's balance sheet date, unless a plan settlement occurs during the current year that requires an updated discount rate for net periodic cost measurement. For 2019 and 2018, the Pension Plan discount rates used to determine net periodic benefit cost are disclosed on a weighted-average basis.

The overall expected rate of return on plan assets assumption was 7.50 percent in both 2019 and 2018, which was used in determining net periodic benefit cost due to recent returns on the Company's long-term investment portfolio. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans' current and expected asset allocation.

The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 7.00 percent in 2020 with the rates trending downward to 4.50 percent by 2030. The effects of a one-percentage point change in the assumed health care cost trend rate are presented in the following tables. 

ONE-PERCENTAGE POINT INCREASE
Year Ended December 31 (In millions)	2019		2018		2017
Effect on aggregate of the service and interest cost components	$	—	$	—	$	—
Effect on accumulated postretirement benefit obligations	$	0.1	$	0.1	$	0.1

ONE-PERCENTAGE POINT DECREASE
Year Ended December 31 (In millions)	2019		2018		2017
Effect on aggregate of the service and interest cost components	$	—	$	—	$	—
Effect on accumulated postretirement benefit obligations	$	0.3	$	0.3	$	0.3

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Pension Plan

Pension Plan Investments, Policies and Strategies

The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability-driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.

Projected Benefit Obligation Funded Status Thresholds	<90%	95%	100%	105%	110%	115%	120%
Fixed income	50%	58%	65%	73%	80%	85%	90%
Equity	50%	42%	35%	27%	20%	15%	10%
Total	100%	100%	100%	100%	100%	100%	100%

Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below.

Asset Class	Target Allocation	Minimum	Maximum
Domestic Large Cap Equity	40%	35%	60%
Domestic Mid-Cap Equity	15%	5%	25%
Domestic Small-Cap Equity	25%	5%	30%
International Equity	20%	10%	30%

The Company has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of the Company's members and the Company's Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager's respective portfolio. 

The portfolio is rebalanced at least on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust's exposure to any asset class to exceed or fall below the established allowable guidelines.

To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:

Asset Class	Comparative Benchmark(s)
Active Duration Fixed Income	Bloomberg Barclays Aggregate
Long Duration Fixed Income	Duration blended Barclays Long Government/Credit & Barclays Universal
Equity Index	Standard & Poor's 500 Index
Mid-Cap Equity	Russell Midcap Index
	Russell Midcap Value Index
Small-Cap Equity	Russell 2000 Index
	Russell 2000 Value Index
International Equity	Morgan Stanley Capital International ACWI ex-U.S.

The fixed income managers are expected to use discretion over the asset mix of the trust assets in their efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies or its instrumentalities (which have no limits), is limited to five percent of the fixed income portfolio as measured by market value. At

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least 75 percent of the invested assets must possess an investment-grade rating at or above Baa3 or BBB- by Moody's Investors Service, S&P's Global Ratings or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 15 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. The purchase of any of the Company's equity, debt or other securities is prohibited.

The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index. The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-U.S. Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-U.S. Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the U.S. All of the equities which are purchased for the international portfolio are thoroughly researched. All securities are freely traded on a recognized stock exchange, and there are no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).

For all domestic equity investment managers, no more than five percent can be invested in any one stock at the time of purchase and no more than 10 percent after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval of the Company's Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of the Company's equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager's organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.

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Pension Plan Investments

The following tables summarize the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2019 and 2018. There were no Level 3 investments held by the Pension Plan at December 31, 2019 and 2018. 

(In millions)	December 31, 2019		Level 1		Level 2		Net Asset Value (A)
Common stocks	$	202.0	$	202.0	$	—	$	—
U.S. Treasury notes and bonds (B)	134.8		134.8		—		—
Mortgage- and asset-backed securities	45.8		—		45.8		—
Corporate fixed income and other securities	130.5		—		130.5		—
Commingled fund (C)	23.9		—		—		23.9
Foreign government bonds	3.0		—		3.0		—
U.S. municipal bonds	1.1		—		1.1		—
Money market fund	7.5		—		—		7.5
Mutual fund	2.4		2.4		—		—
Preferred stocks	0.7		0.7		—		—
Futures:
U.S. Treasury futures (receivable)	22.9		—		22.9		—
U.S. Treasury futures (payable)	(10.9)		—		(10.9)		—
Cash collateral	0.6		0.6		—		—
Forward contracts:
Receivable (foreign currency)	0.1		—		0.1		—
Total Pension Plan investments	564.4		$	340.5	$	192.5	$	31.4
Interest and dividends receivable	2.4
Payable to broker for securities purchased	(36.5)
Total Pension Plan assets	$	530.3

(A)GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

(B)This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.

(C)This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

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(In millions)	December 31, 2018		Level 1		Level 2		Net Asset Value (A)
Common stocks	$	169.3	$	169.3	$	—	$	—
U.S. Treasury notes and bonds (B)	137.9		137.9		—		—
Mortgage- and asset-backed securities	65.9		—		65.9		—
Corporate fixed income and other securities	143.2		—		143.2		—
Commingled fund (C)	19.7		—		—		19.7
Foreign government bonds	4.4		—		4.4		—
U.S. municipal bonds	0.6		—		0.6		—
Money market fund	0.3		—		—		0.3
Mutual fund	8.0		8.0		—		—
Futures:
U.S. Treasury futures (receivable)	27.0		—		27.0		—
U.S. Treasury futures (payable)	(20.4)		—		(20.4)		—
Cash collateral	0.7		0.7		—		—
Forward contracts:
Receivable (foreign currency)	0.1		—		0.1		—
Total Pension Plan investments	556.7		$	315.9	$	220.8	$	20.0
Interest and dividends receivable	3.0
Payable to broker for securities purchased	(36.9)
Total Pension Plan assets	$	522.8

(A)GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

(B)This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.

(C)This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

As defined in the fair value hierarchy, Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan 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 Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

Expected Benefit Payments

The following table summarizes the benefit payments the Company expects to pay related to OGE Energy's Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure the Company's benefit obligation at the end of the year and include benefits attributable to estimated future employee service. 

(In millions)	Projected Benefit Payments
2020	$	58.4
2021	$	56.8
2022	$	56.2
2023	$	55.7
2024	$	56.6
After 2024	$	249.4

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Postretirement Benefit Plans

In addition to providing pension benefits, the Company provides certain medical and life insurance benefits for eligible retired members. Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained at least age 55 with 10 or more years of service at the time of retirement are entitled to postretirement medical benefits, while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Eligible retirees must contribute such amount as the Company specifies from time to time toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. OG&E charges postretirement benefit costs to expense and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.

The Company's contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level, and the Company covers future annual medical inflationary cost increases up to five percent. Increases in excess of five percent annually are covered by the pre-65 aged retiree in the form of premium increases. The Company provides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to a Company-sponsored health reimbursement arrangement. Medicare-eligible retirees are able to purchase individual insurance policies supplemental to Medicare through a third-party administrator and use their health reimbursement arrangement funds for reimbursement of medical premiums and other eligible medical expenses.

Postretirement Plans Investments

The following tables summarize the postretirement benefit plans' investments that are measured at fair value on a recurring basis at December 31, 2019 and 2018. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2019 and 2018.

(In millions)	December 31, 2019		Level 1		Level 3
Group retiree medical insurance contract	$	34.8	$	—	$	34.8
Mutual funds	10.9		10.9		—
Money market fund	1.2		1.2		—
Total plan investments	$	46.9	$	12.1	$	34.8

(In millions)	December 31, 2018		Level 1		Level 3
Group retiree medical insurance contract	$	36.0	$	—	$	36.0
Mutual funds	8.9		8.9		—
Cash	0.9		0.9		—
Total plan investments	$	45.8	$	9.8	$	36.0

The group retiree medical insurance contract invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans' pro-rata share of the total assets in the contract.

The following table summarizes the postretirement benefit plans' investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

Year Ended December 31 (In millions)	2019
Group retiree medical insurance contract:
Beginning balance	$	36.0
Claims paid	(3.8)
Investment fees	(0.1)
Net unrealized gains related to instruments held at the reporting date	1.4
Interest income	0.8
Dividend income	0.5
Ending balance	$	34.8

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Medicare Prescription Drug, Improvement and Modernization Act of 2003

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs. The following table summarizes the gross benefit payments the Company expects to pay related to its postretirement benefit plans, including prescription drug benefits.

(In millions)	Gross Projected Postretirement Benefit Payments
2020	$	11.2
2021	$	11.2
2022	$	11.1
2023	$	9.5
2024	$	9.4
After 2024	$	42.3

Post-Employment Benefit Plan

Disabled employees receiving benefits from the Company's Group Long-Term Disability Plan are entitled to continue participating in the Company's Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in the Company's Group Long-Term Disability Plan and their dependents, as defined in the Company's Medical Plan.

The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from the Company's Group Long-Term Disability Plan due to death, recovery from disability or eligibility for retiree medical benefits. The Company's post-employment benefit obligation was $2.1 million and $1.9 million at December 31, 2019 and 2018, respectively.

401(k) Plan

The Company provides a 401(k) Plan, and each regular full-time employee of the Company or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of the Company or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have reached age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof, (ii) a contribution made on a non-Roth after-tax basis or (iii) a Roth contribution. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have their future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, the Company contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation.

No Company contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, the Company's contribution may be directed to any available investment option in the 401(k) Plan. The Company match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their Company contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan requirements, in the event of their termination

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due to death or permanent disability or upon attainment of age 65 while employed by the Company or its affiliates. The Company contributed $14.4 million, $13.2 million and $13.2 million in 2019, 2018 and 2017, respectively, to the 401(k) Plan.

Deferred Compensation Plan

The Company provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of the Company and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace.

Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers. The Company matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of the Company or termination of the plan. Deferrals, plus any Company match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2019, those investment options included a Company Common Stock fund, whose value was determined based on the stock price of the Company's common stock. The Company accounts for the contributions related to the Company's executive officers in this plan as Accrued Benefit Obligations, and the Company accounts for the contributions related to the Company's directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in the Consolidated Balance Sheets. The appreciation of these investments is accounted for as Other Income, and the increase in the liability under the plan is accounted for as Other Expense in the Consolidated Statements of Income.

Supplemental Executive Retirement Plan

The Company provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of the Company's Board of Directors who may not otherwise qualify for a sufficient level of benefits under the Company's Pension Plan and Restoration of Retirement Income Plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limitations of the Code. For the actuarial equivalence calculations, the supplemental executive retirement plan provides that (i) mortality rates shall be based on the unisex mortality table issued under Internal Revenue Service 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 (ii) the interest rate shall be five percent.

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14.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) natural gas midstream operations segment. Other operations primarily includes the operations of the holding company. 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 for the years ended December 31, 2019, 2018 and 2017.

2019	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,231.6	$	—	$	—	$	—	$	2,231.6
Cost of sales	786.9		—		—		—		786.9
Other operation and maintenance	492.5		2.8		(3.5)		—		491.8
Depreciation and amortization	355.0		—		—		—		355.0
Taxes other than income	89.5		0.4		3.7		—		93.6
Operating income (loss)	507.7		(3.2)		(0.2)		—		504.3
Equity in earnings of unconsolidated affiliates	—		113.9		—		—		113.9
Other income (expense)	3.1		(8.6)		2.2		(3.6)		(6.9)
Interest expense	140.5		—		11.0		(3.6)		147.9
Income tax expense (benefit)	20.1		20.7		(11.0)		—		29.8
Net income	$	350.2	$	81.4	$	2.0	$	—	$	433.6
Investment in unconsolidated affiliates	$	—	$	1,132.9	$	18.6	$	—	$	1,151.5
Total assets	$	10,076.6	$	1,135.4	$	107.0	$	(294.7)	$	11,024.3
Capital expenditures	$	635.5	$	—	$	—	$	—	$	635.5

2018	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,270.3	$	—	$	—	$	—	$	2,270.3
Cost of sales	892.5		—		—		—		892.5
Other operation and maintenance	473.8		1.4		(0.6)		—		474.6
Depreciation and amortization	321.6		—		—		—		321.6
Taxes other than income	88.2		0.6		3.2		—		92.0
Operating income (loss)	494.2		(2.0)		(2.6)		—		489.6
Equity in earnings of unconsolidated affiliates	—		152.8		—		—		152.8
Other income (expense)	25.6		(4.9)		(3.4)		(6.0)		11.3
Interest expense	151.8		—		10.2		(6.0)		156.0
Income tax expense (benefit)	40.0		37.1		(4.9)		—		72.2
Net income (loss)	$	328.0	$	108.8	$	(11.3)	$	—	$	425.5
Investment in unconsolidated affiliates	$	—	$	1,166.6	$	10.9	$	—	$	1,177.5
Total assets	$	9,704.5	$	1,169.8	$	184.8	$	(310.5)	$	10,748.6
Capital expenditures	$	573.6	$	—	$	—	$	—	$	573.6

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2017	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,261.1	$	—	$	—	$	—	$	2,261.1
Cost of sales	897.6		—		—		—		897.6
Other operation and maintenance	469.8		(0.8)		(10.3)		—		458.7
Depreciation and amortization	280.9		—		2.6		—		283.5
Taxes other than income	84.8		1.0		3.6		—		89.4
Operating income (loss)	528.0		(0.2)		4.1		—		531.9
Equity in earnings of unconsolidated affiliates	—		131.2		—		—		131.2
Other income (expense)	57.7		(1.0)		(5.4)		(0.9)		50.4
Interest expense	138.4		—		6.3		(0.9)		143.8
Income tax expense (benefit) (A)	141.8		(195.2)		4.1		—		(49.3)
Net income (loss)	$	305.5	$	325.2	$	(11.7)	$	—	$	619.0
Investment in unconsolidated affiliates	$	—	$	1,151.9	$	8.5	$	—	$	1,160.4
Total assets	$	9,255.6	$	1,155.3	$	109.1	$	(107.3)	$	10,412.7
Capital expenditures	$	824.1	$	—	$	—	$	—	$	824.1

(A)The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act.

15.Commitments and Contingencies

Public Utility Regulatory Policy Act of 1978

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 power 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 16.

For the years ended December 31, 2019, 2018 and 2017, OG&E made total payments to cogenerators of $14.7 million, $112.4 million and $115.2 million, respectively, of which $7.4 million, $60.0 million and $63.0 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Consolidated Statements of Income as Cost of Sales.

Purchase Obligations and Commitments

The Company's future purchase obligations and commitments estimated for the next five years are as follows: 

(In millions)	2020		2021		2022		2023		2024		Total
Purchase obligations and commitments:
Minimum purchase commitments	$	82.6	$	55.1	$	50.4	$	50.4	$	32.9	$	271.4
Expected wind purchase commitments	55.7		56.0		56.4		56.8		57.5		282.4
Long-term service agreement commitments	2.4		2.4		2.4		13.8		32.1		53.1
Environmental compliance plan expenditures	0.4		—		—		—		—		0.4
Total purchase obligations and commitments	$	141.1	$	113.5	$	109.2	$	121.0	$	122.5	$	607.3

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OG&E Minimum Purchase Commitments

OG&E has coal contracts for purchases through June 30, 2020 and May 31, 2021, whereby OG&E has the right but not the obligation to purchase a defined quantity of coal. OG&E purchases its coal through spot purchases on an as-needed basis. As a participant in the SPP Integrated Marketplace, OG&E purchases its natural gas supply through short-term agreements. OG&E relies on a combination of natural gas base load agreements and call agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP Integrated Marketplace.

OG&E has natural gas transportation service contracts with Enable and ONEOK, Inc. The contract with Enable ends in May 2024, and the contract with ONEOK, Inc. ends in August 2037. These transportation contracts grant Enable and ONEOK, Inc. the responsibility of delivering natural gas to OG&E's generating facilities.

OG&E Wind Purchase Commitments

The following table summarizes OG&E's wind power purchase contracts.

Company	Location	Original Term of Contract	Expiration of Contract	MWs
CPV Keenan	Woodward County, OK	20 years	2030	152.0
Edison Mission Energy	Dewey County, OK	20 years	2031	130.0
NextEra Energy	Blackwell, OK	20 years	2032	60.0

The following table summarizes OG&E's wind power purchases for the years ended December 31, 2019, 2018 and 2017. 

Year Ended December 31 (In millions)	2019		2018		2017
CPV Keenan	$	27.2	$	27.0	$	29.0
Edison Mission Energy	23.1		21.7		22.1
NextEra Energy	7.4		6.8		7.4
FPL Energy (A)	—		2.1		2.6
Total wind power purchased	$	57.7	$	57.6	$	61.1

(A)OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018.

OG&E Long-Term Service Agreement Commitments

OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant. In May 2013, a new contract was signed that is expected to run for the earlier of 128,000 factored-fired hours or 4,800 factored-fired starts. In December 2015, the McClain Long-Term Service Agreement was amended to define the terms and conditions for the exchange of spare rotors between OG&E and General Electric International, Inc. Based on historical usage and current expectations for future usage, this contract is expected to run until 2033. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.

OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional 24,000 factored-fired hours resulting in a maximum of the earlier of 144,000 factored-fired hours or 4,500 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2030. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.

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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 or 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.

Affordable Clean Energy Rule

On July 8, 2019, the EPA published the Affordable Clean Energy rule. 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. The ultimate timing and impact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO₂ emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect the Company's future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

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 Consolidated Financial Statements. At the present time, based on currently available information, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows. 

16.Rate Matters and Regulation

Regulation and Rates

OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2019, 86 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and six percent to the FERC.

The OCC and the APSC require that, among other things, (i) the Company permits the OCC and the APSC access to the books and records of the Company and its affiliates relating to transactions with OG&E; (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers; and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions. In addition, the FERC has access to the books and records of the Company and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

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Completed Regulatory Matters

Arkansas 2018 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 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 finding that the plants to be acquired were used and useful and that the acquisition of the plants was in the public interest. The APSC also approved the depreciation rates to be applied to the acquired plants. The cost OG&E paid for the acquired plants was reviewed by the APSC in OG&E's 2019 Formula Rate Plan filing, and parties reached a settlement agreement requesting the APSC to approve the cost of the acquisitions. OG&E is awaiting a final decision from the APSC.

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.

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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.

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. On December 12, 2019, the OCC issued an order deeming OG&E's electric generation, purchased power and fuel procurement costs were prudent.

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. On November 21, 2019, the FERC approved the settlement agreement.

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 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 required SPP to charge for these upgrades beginning in 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 companies that were net payers of Z2 charges 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 Circuit. In July 2018, that court 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 November 2017 rehearing denial, ruled that SPP violated its tariff to charge for the 2008 - 2015 period in 2016, held that the SPP tariff provision that prohibited those charges could not be waived 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 that SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement and of the applicable tariff. 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. SPP's response to OG&E's filing agreed that OG&E should be entitled to keep its Z2 payments and argued that SPP should not be held responsible for those payments if refunds are ordered. Further, SPP has requested the FERC to

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negotiate a global settlement with all impacted parties, including other project sponsors who, like OG&E, have also filed complaints at FERC contending that the payments they have received cannot properly be unwound.

On February 20, 2020, the FERC denied OG&E's request for rehearing of its February 28, 2019 order, denying the waiver and ruling that SPP must seek refunds from project sponsors for Z2 payments for the 2008 - 2015 period and pay them back to transmission owners. The FERC also denied SPP's request for a stay and for institution of settlement procedures. The FERC stated it would not institute settlement procedures unless parties on both sides of the matter requested them. The FERC did not rule on OG&E's complaint or the complaints of other project sponsors, or consider SPP's refund plan. The FERC thus has not set any date for payment of refunds. The FERC's order denying the waiver and requiring refunds is now appealable, and OG&E intends to file a timely appeal.

The Company cannot predict the outcome of this proceeding based on currently available information, and as of December 31, 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.

SPP has recently proposed eliminating Attachment Z2 revenue crediting and replacing it with a different mechanism that would provide project sponsors such as OG&E the same level of recovery they would receive if payments continued under Attachment Z2. The FERC rejected that proposal to the extent it would limit recovery to the amount of the upgrade sponsor's directly assigned upgrade costs with interest, finding that providing the possibility of recovering greater than the cost of the investment could serve as an incentive for entities to build merchant transmission projects. The SPP can resubmit a proposal without that cap.

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 was held on December 17, 2019. The primary question before the APSC is whether a company can utilize an environmental compliance plan rider while also regulated under a formula rate plan. OG&E is awaiting a final decision from the APSC.

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Arkansas 2019 Formula Rate Plan Filing

OG&E filed its second evaluation report under its Formula Rate Plan in October 2019. On January 29, 2020, OG&E, the General Staff of the APSC and the Office of the Arkansas Attorney General filed a settlement agreement requesting the APSC approve a $5.2 million revenue increase, with rates effective April 1, 2020. The settling parties agreed that the Series I grid modernization projects are prudent in both action and cost and that the Series II grid modernization projects are prudent in action only and the determination of prudence of costs will be reserved until the actual historical costs are reviewed. The settling parties also agreed that OG&E will no longer use projections for the remaining initial term or extension of its current Formula Rate Plan and that all costs will be included for recovery for the first time in the historical year. A hearing was held on February 5, 2020, and OG&E is awaiting a final decision from the APSC.

Oklahoma Grid Enhancement Plan

On February 24, 2020, OG&E filed an application with the OCC for approval of a mechanism that allows for interim recovery of the costs associated with its grid enhancement plan. The plan includes approximately $800 million of strategic, data-driven investments, over five years, covering grid resiliency, grid automation, communication systems and technology platforms and applications. A procedural schedule has not been set by the OCC.

Oklahoma Retail Electric Supplier Certified Territory Act Causes

Certain rural electric cooperative electricity suppliers have filed complaints with the OCC alleging that OG&E has violated the Oklahoma Retail Electric Supplier Certified Territory Act. OG&E believes it is lawfully serving customers specifically exempted from this act and has presented evidence and testimony to the OCC supporting its position. If the OCC were to ultimately find that some or all of the customers being served are not exempted, then OG&E would have to evaluate the recoverability of some plant investment made to serve these customers. OG&E may also be required to reimburse certified territory suppliers for an amount of lost revenue.

17.Quarterly Financial Data (Unaudited)

Due to the seasonal fluctuations and other factors of the Company's businesses, the operating results for interim periods are not necessarily indicative of the results that may be expected for the year. In the Company's opinion, the following quarterly financial data includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present such amounts. Summarized consolidated quarterly unaudited financial data is as follows:

Quarter Ended (In millions, except per share data)		March 31		June 30		September 30		December 31		Total
Operating revenues	2019	$	490.0	$	513.7	$	755.4	$	472.5	$	2,231.6
	2018	$	492.7	$	567.0	$	698.8	$	511.8	$	2,270.3
Operating income	2019	$	49.7	$	110.0	$	274.3	$	70.3	$	504.3
	2018	$	66.6	$	137.7	$	227.3	$	58.0	$	489.6
Net income	2019	$	47.1	$	100.2	$	250.9	$	35.4	$	433.6
	2018	$	55.0	$	110.7	$	205.1	$	54.7	$	425.5
Basic earnings per average common share (A)	2019	$	0.24	$	0.50	$	1.25	$	0.18	$	2.17
	2018	$	0.28	$	0.55	$	1.03	$	0.27	$	2.13
Diluted earnings per average common share (A)	2019	$	0.24	$	0.50	$	1.25	$	0.18	$	2.16
	2018	$	0.27	$	0.55	$	1.02	$	0.27	$	2.12

(A)Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

115

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors of OGE Energy Corp.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of OGE Energy Corp. (the Company) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and financial statement schedule listed in the Index at Item 15(a)(collectively referred to as the "consolidated financial statements"). In our opinion, based on our audits and the report of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We did not audit the consolidated financial statements of Enable Midstream Partners, LP (Enable), a partnership in which the Company had a 25.5% interest at December 31, 2019. The Company's investment in Enable constituted 10.3% and 10.9% of the Company's assets as of December 31, 2019 and 2018, respectively, and the Company's equity earnings in the net income of Enable constituted 24.6%, 30.7% and 23.0% of the Company's income before taxes for the years ended December 31, 2019, 2018, and 2017, respectively. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Enable, is based solely on the report of the other auditors.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 26, 2020, expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosure to which it relates.

116

Regulatory Assets and Liabilities

Description of the Matter	As discussed in Note 1 to the consolidated financial statements, OG&E is a regulated utility subject to accounting principles for rate-regulated activities. As such, certain incurred costs that would otherwise be charged to expense are 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 are deferred as regulatory liabilities, based on the expected refund to customers in future rates. OG&E records items 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.
	Auditing regulatory assets and liabilities is complex as it requires specialized knowledge of rate-regulated activities and judgments as to matters that could affect the recording or updating of regulatory assets and liabilities.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design, and tested the operating effectiveness of internal controls over the Company’s accounting for regulatory assets and liabilities, including, among others, controls over management’s assessment of the likelihood of approval by regulators for new matters and controls over the evaluation of filings with regulatory bodies on existing regulatory assets and liabilities, including factors that may affect the timing or nature of recoverability.
	We performed audit procedures that included, among others, reviewing evidence of correspondence with regulatory bodies to test that the Company appropriately evaluated new information obtained from regulatory rulings. For example, we assessed the recoverability, considering information obtained from regulatory rulings, of various regulatory assets including deferred expenses, pensions and other regulatory assets. In addition, we tested that amortization of regulatory assets and liabilities corresponded to relevant regulatory rulings. For example, we tested whether the timing of customer refunds attributable to changes in the tax law were consistent with methods agreed to by regulatory bodies.

/s/  Ernst & Young LLP

We have served as the Company's auditor since 2002.

Oklahoma City, Oklahoma

February 26, 2020

117

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. 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).

118

Management's Report on Internal Control Over Financial Reporting

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control system was designed to provide reasonable assurance to the Company's management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The Company's management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2019. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2019, the Company's internal control over financial reporting is effective based on those criteria.

The Company's independent auditors have issued an attestation report on the Company's internal control over financial reporting. This report appears on the following page.

/s/ Sean Trauschke	/s/ Sarah R. Stafford
Sean Trauschke, Chairman of the Board, President	Sarah R. Stafford, Controller
and Chief Executive Officer	and Chief Accounting Officer
/s/ Stephen E. Merrill
Stephen E. Merrill
Chief Financial Officer

119

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors of OGE Energy Corp.

Opinion on Internal Control over Financial Reporting

We have audited OGE Energy Corp.'s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, OGE Energy Corp. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2019 consolidated financial statements of the Company and our report dated February 26, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed 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. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

February 26, 2020

120

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Code of Ethics Policy

The Company maintains a code of ethics for our chief executive officer and senior financial officers, including the chief financial officer and chief accounting officer, which is available for public viewing on the Company's website address www.ogeenergy.com under the heading "Investors," "Governance." The code of ethics will be provided, free of charge, upon request. The Company intends to satisfy the disclosure requirements under Section 5, Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the code of ethics by posting such information on its website at the location specified above. The Company will also include in its proxy statement information regarding the Audit Committee financial experts.

Item 11. Executive Compensation.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Item 14. Principal Accountant Fees and Services.

Items 10 through 14 (other than Item 10 information regarding the Code of Ethics) are omitted pursuant to General Instruction G of Form 10-K, because the Company will file copies of a definitive proxy statement with the Securities and Exchange Commission on or about April 6, 2020. Such proxy statement is incorporated herein by reference.

121

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) 1. Financial Statements

(i)The following Consolidated Financial Statements are included in Part II, Item 8 of this Annual Report:

•Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017

•Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017

•Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017

•Consolidated Balance Sheets at December 31, 2019 and 2018

•Consolidated Statements of Capitalization at December 31, 2019 and 2018

•Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2019, 2018 and 2017

•Notes to Consolidated Financial Statements

•Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)

•Management's Report on Internal Control Over Financial Reporting

•Report of Independent Registered Public Accounting Firm (Audit of Internal Control over Financial Reporting)

(i)The financial statements and Notes to Consolidated Financial Statements of Enable Midstream Partners, LP, required pursuant to Rule 3-09 of Regulation S-X are filed as Exhibit 99.01.

2. Financial Statement Schedule (included in Part IV)       

•Schedule II - Valuation and Qualifying Accounts 

All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective Consolidated Financial Statements or Notes thereto.

122

3. Exhibits

Exhibit No.	Description
2.01	Master Formation Agreement dated as of March 14, 2013 by and among CenterPoint Energy, Inc., OGE Energy Corp., Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC. (Filed as Exhibit 2.01 to OGE Energy's Form 8-K filed March 15, 2013 (File No. 1-12579) and incorporated by reference herein).
3.01	Copy of Restated OGE Energy Corp. Certificate of Incorporation. (Filed as Exhibit 3.01 to OGE Energy's Form 10-Q for the quarter ended June 30, 2013 (File No. 1-12579) and incorporated by reference herein).
3.02	Copy of Amended OGE Energy Corp. By-laws dated February 22, 2017. (Filed as Exhibit 3.01 to OGE Energy's Form 8-K filed February 23, 2017 (File No. 1-12579) and incorporated by reference herein).
4.01	Trust Indenture dated October 1, 1995, from OG&E to Boatmen's First National Bank of Oklahoma, Trustee. (Filed as Exhibit 4.29 to OG&E's Registration Statement No. 33-61821 and incorporated by reference herein).
4.02	Supplemental Indenture No. 2, dated as of July 1, 1997, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed July 17, 1997 (File No. 33-1532) and incorporated by reference herein).
4.03	Supplemental Indenture No. 3, dated as of April 1, 1998, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed April 16, 1998 (File No. 33-1532) and incorporated by reference herein).
4.04	Supplemental Indenture No. 5 dated as of October 24, 2001, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.06 to OG&E's Registration Statement No. 333-104615 and incorporated by reference herein).
4.05	Supplemental Indenture No. 6 dated as of August 1, 2004, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed August 6, 2004 (File No 1-1097) and incorporated by reference herein).
4.06	Supplemental Indenture No. 7 dated as of January 1, 2006 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed January 6, 2006 (File No. 1-1097) and incorporated by reference herein).
4.07	Supplemental Indenture No. 8 dated as of January 15, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed January 31, 2008 (File No. 1-1097) and incorporated by reference herein).
4.08	Supplemental Indenture No. 9 dated as of September 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed September 9, 2008 (File No. 1-1097) and incorporated by reference herein).
4.09	Supplemental Indenture No. 10 dated as of December 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed December 11, 2008 (File No. 1-1097) and incorporated by reference herein).
4.10	Supplemental Indenture No. 11 dated as of June 1, 2010 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed June 8, 2010 (File No. 1-1097) and incorporated by reference herein).
4.11	Supplemental Indenture No. 12 dated as of May 15, 2011 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed May 27, 2011 (File No. 1-1097) and incorporated by reference herein).
4.12	Supplemental Indenture No. 13 dated as of May 1, 2013 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed May 13, 2013 (File No. 1-1097) and incorporated by reference herein).
4.13	Supplemental Indenture No. 14 dated as of March 15, 2014 being supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed March 25, 2014 (File No. 1-1097) and incorporated by reference herein).
4.14	Supplemental Indenture No. 15 dated as of December 1, 2014 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed December 11, 2014 (File No. 1-1097) and incorporated by reference herein).
4.15	Supplemental Indenture No. 16 dated as of March 15, 2017 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed March 31, 2017 (File No. 1-1097) and incorporated by reference herein).
4.16	Supplemental Indenture No. 17 dated as of August 1, 2017 being supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed August 11, 2017 (File No. 1-1097) and incorporated by reference herein).
4.17	Supplemental Indenture No. 18 dated as of April 26, 2018 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.21 to the Company's Registration Statement on Form S-3ASR filed May 18, 2018 (File No. 333-225030) and incorporated by reference herein).

123

4.18	Supplemental Indenture No. 19 dated as of August 15, 2018 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company's Form 8-K filed August 17, 2018 (File No. 1-12579) and incorporated by reference herein).
4.19	Supplemental Indenture No. 20 dated as of June 1, 2019 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company's Form 8-K filed June 7, 2019 (File No. 1-12579) and incorporated by reference herein).
4.20	Indenture dated as of November 1, 2004 between OGE Energy Corp. and UMB Bank, N.A., as trustee. (Filed as Exhibit 4.01 to OGE Energy's Form 8-K filed November 12, 2004 (File No. 1-12579) and incorporated by reference herein).
4.21	Supplemental Indenture No. 2 dated as of November 24, 2014 between OGE Energy and UMB Bank, N.A, as trustee, creating the Senior Notes. (Filed as Exhibit 4.01 to OGE Energy's Form 8-K filed November 24, 2014 (File No. 1-12579) and incorporated by reference herein).
4.22	Supplemental Indenture No. 3 dated as of April 26, 2018 being a supplemental instrument to Exhibit 4.20 hereto. (Filed as Exhibit 4.04 to the Company's Registration Statement on Form S-3ASR filed May 18, 2018 (File No. 333-225030) and incorporated by reference herein).
4.23	Description of Capital Stock.
10.01	Amended and Restated Facility Operating Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.03 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein).
10.02	Amended and Restated Ownership and Operation Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein).
10.03	Operating and Maintenance Agreement for the Transmission Assets of the McClain Generating Facility dated as of August 25, 2003 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.05 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein).
10.04*	Form of Split Dollar Agreement. (Filed as Exhibit 10.32 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein).
10.05	Credit Agreement dated as of March 8, 2017 by and among OGE Energy Corp. and JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Banks, Ltd., MUFG Union Bank, N.A., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to time parties thereto. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed March 8, 2017 (File No. 1-12579) and incorporated by reference herein).
10.06	Credit Agreement dated as of March 8, 2017 by and among Oklahoma Gas and Electric Company and JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Banks, Ltd., MUFG Union Bank, N.A., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to time parties thereto. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed March 8, 2017 (File No. 1-12579) and incorporated by reference herein).
10.07*	OGE Energy Supplemental Executive Retirement Plan, as amended and restated. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended September 30, 2019 (File No. 1-12579) and incorporated by reference herein).
10.08*	OGE Energy Restoration of Retirement Income Plan, as amended and restated. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein).
10.09*	Form of Employment Agreement for all existing and future officers of OGE Energy relating to change of control. (Filed as Exhibit 10.28 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein).
10.10	Agreement, dated February 17, 2010, between OG&E and Oklahoma Department of Environmental Quality. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed February 23, 2010 (File No. 1-12579) and incorporated by reference herein).
10.11*	Amendment No. 1 to OGE Energy's Restoration of Retirement Income Plan. (Filed as Exhibit 10.40 to OGE Energy's Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein).
10.12*	Director Compensation.
10.13*	Executive Officer Compensation.
10.14	Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP, dated November 14, 2017. (Filed as Exhibit 3.1 to Enable Midstream Partners, LP's Form 8-K filed November 15, 2017 (File No. 1-36413) and incorporated by reference herein).

124

10.15	Third Amended and Restated Limited Liability Company Agreement of Enable GP, LLC, dated June 22, 2016. (Filed as Exhibit 10.02 to OGE Energy's Form 8-K filed June 28, 2016 (File No. 1-12579) and incorporated by reference herein).
10.16	Registration Rights Agreement dated as of May 1, 2013 by and among CenterPoint Energy Field Services LP, CenterPoint Energy Resources Corp., OGE Enogex Holdings LLC, and Enogex Holdings LLC. (Filed as Exhibit 10.03 to OGE Energy's Form 8-K filed May 7, 2013 (File No. 1-12579) and incorporated by reference herein).
10.17	Omnibus Agreement dated as of May 1, 2013 among CenterPoint Energy, Inc., OGE Energy Corp., Enogex Holdings LLC and CenterPoint Energy Field Services LP. (Filed as Exhibit 10.04 to OGE Energy's Form 8-K filed May 7, 2013 (File No. 1-12579) and incorporated by reference herein).
10.18*	OGE Energy's 2013 Stock Incentive Plan. (Filed as Annex B to OGE Energy's Proxy Statement for the 2013 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein).
10.19*	OGE Energy's 2013 Annual Incentive Compensation Plan. (Filed as Annex C to OGE Energy's Proxy Statement for the 2013 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein).
10.20*	OGE Energy Corp. Involuntary Severance Benefits Plans for Non-Officers (Applicable only to non-officers of Enogex LLC seconded to Enable Midstream Partners, LP or Enable GP, LLC or one of its subsidiaries). (Filed as Exhibit 10.02 to OGE Energy's Form 10-Q for the quarter ended September 30, 2013 (File No. 1-12579) and incorporated by reference herein).
10.21*	OGE Energy Corp. Involuntary Severance Benefits Plans for Officers (Applicable only to officers of Enogex LLC seconded to Enable Midstream Partners, LP or Enable GP, LLC or one of its subsidiaries). (Filed as Exhibit 10.03 to OGE Energy's Form 10-Q for the quarter ended September 30, 2013 (File No. 1-12579) and incorporated by reference herein).
10.22*	Retention Agreement effective as of October 24, 2013, by and between OGE Enogex Holdings, LLC and E. Keith Mitchell. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended September 30, 2013 (File No. 1-12579) and incorporated by reference herein).
10.23*	Form of Performance Unit Agreement under OGE Energy's 2013 Stock Incentive Plan. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended June 30, 2017 (File No. 1-12579) and incorporated by reference herein).
10.24*	Form of Restricted Stock Unit Agreement under OGE Energy's 2013 Stock Incentive Plan. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended March 31, 2019 (File No. 1-12579) and incorporated by reference herein).
10.25*	OGE Energy Corp. Deferred Compensation Plan (As amended and restated effective October 1, 2016). (Filed as Exhibit 10.37 to OGE Energy's Form 10-K for the year ended December 31, 2016 (File No. 1-12579) and incorporated by reference herein).
10.26	Copy of the Settlement Agreement filed with the APSC on April 20, 2017. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed May 24, 2017 (File No. 1-12579) and incorporated by reference herein).
10.27	Letter of extension dated as of March 9, 2018 for the Company's and OG&E's credit agreements dated as March 8, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., Syndication Agent, Mizuho Bank, Ltd. MUFG Union Bank, N.A. Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, the Lenders thereto, and the Company and OG&E, for their respective credit facility. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended March 31, 2018 (File No. 1-12579) and incorporated by reference herein).
21.01	Subsidiaries of the Registrant.
23.01	Consent of Ernst & Young LLP.
23.02	Consent of Deloitte & Touche LLP for the Financial Statements of Enable Midstream Partners, LP.
24.01	Power of Attorney.
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.
99.01	Financial Statements of Enable Midstream Partners, LP as of and for the three years ended December 31, 2019.
99.02	Copy of the APSC Settlement Agreement approval dated May 18, 2017. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed May 24, 2017 (File No. 1-12579) and incorporated by reference herein).
99.03	Copy of the Settlement Agreement filed with the OCC on May 24, 2019. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed May 30, 2019 (File No. 1-12579) and incorporated by reference herein).
101.INS	Inline 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	Inline XBRL Taxonomy Schema Document.
101.PRE	Inline XBRL Taxonomy Presentation Linkbase Document.

125

101.LAB	Inline XBRL Taxonomy Label Linkbase Document.
101.CAL	Inline XBRL Taxonomy Calculation Linkbase Document.
101.DEF	Inline 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.

126

OGE ENERGY CORP.

SCHEDULE II - Valuation and Qualifying Accounts

			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (A)		Balance at End of Period
(In millions)
Balance at December 31, 2017
Reserve for Uncollectible Accounts	$	1.5	$	2.6	$	2.6	$	1.5
Balance at December 31, 2018
Reserve for Uncollectible Accounts	$	1.5	$	3.4	$	3.2	$	1.7
Balance at December 31, 2019
Reserve for Uncollectible Accounts	$	1.7	$	2.2	$	2.4	$	1.5

(A)Uncollectible accounts receivable written off, net of recoveries.

Item 16. Form 10-K Summary.

None.

127

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on February 26th, 2020.

OGE ENERGY CORP.
(Registrant)
By /s/	Sean Trauschke
	Sean Trauschke
	Chairman of the Board, President
	and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Sean Trauschke
Sean Trauschke	Principal Executive
	Officer and Director;	February 26, 2020
/s/ Stephen E. Merrill
Stephen E. Merrill	Principal Financial Officer;	February 26, 2020
/s/ Sarah R. Stafford
Sarah R. Stafford	Principal Accounting Officer.	February 26, 2020
Frank A. Bozich	Director;
James H. Brandi	Director;
Peter D. Clarke	Director;
Luke R. Corbett	Director;
David L. Hauser	Director;
Judy R. McReynolds	Director;
David E. Rainbolt	Director;
J. Michael Sanner	Director;
Sheila G. Talton	Director;

/s/ Sean Trauschke
By Sean Trauschke (attorney-in-fact)	February 26, 2020

128

EX-4.23

Exhibit 4.23

DESCRIPTION OF SECURITIES

The following description of the common stock of OGE Energy Corp., an Oklahoma corporation, is a summary of the general terms thereof and is qualified in its entirety by the provisions of our certificate of incorporation, as amended and restated (the “Restated Certificate of Incorporation”), and bylaws, as amended and restated (the “Bylaws”), copies of both of which have been filed as exhibits to our most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission, and the laws of the state of Oklahoma.

Authorized Shares

Under our Restated Certificate of Incorporation, we are authorized to issue 450,000,000 shares of common stock, par value $0.01 per share, of which 200,177,358 shares were outstanding on January 31, 2020. We are also authorized to issue 5,000,000 shares of preferred stock, par value $0.01 per share. No shares of preferred stock are currently outstanding. Our common stock is our only security registered under Section 12 of the Securities Exchange Act of 1934.

Without shareholder approval, we may issue preferred stock in the future in such series as may be designated by our board of directors. In creating any such series, our board of directors has the authority to fix the rights and preferences of each series with respect to, among other things, the dividend rate, redemption provisions, liquidation preferences, sinking fund provisions, conversion rights and voting rights. The terms of any series of preferred stock that we may issue in the future may provide the holders of such preferred stock with rights that are senior to the rights of the holders of our common stock.

Dividend Rights

Before we can pay any dividends on our common stock, the holders of our preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. Currently, there are no shares of our preferred stock outstanding. Because we are a holding company and conduct all of our operations through our subsidiary and our equity investments, our cash flow and ability to pay dividends will be dependent on the earnings and cash flows of our subsidiary and our unconsolidated affiliate and the distribution or other payment of those earnings to us in the form of dividends or distributions, or in the form of repayments of loans or advances to us. We expect to derive principally all of the funds required by us to enable us to pay dividends on our common stock from dividends paid by OG&E, on OG&E's common stock, and from distributions paid by OGE Holdings on its interest in Enable Midstream Partners, LP (“Enable”). Our ability to receive dividends on OG&E's common stock is subject to the prior rights of the holders of any OG&E preferred stock that may be outstanding, any covenants of OG&E's certificate of incorporation and OG&E's debt instruments limiting the ability of OG&E to pay dividends and the ability of public utility commissions that regulate OG&E to effectively restrict the payment of dividends by OG&E. Our ability to receive distributions from Enable through our interest in OGE Holdings is dependent upon the cash flow of Enable and is subject to the prior rights of the holders of any Enable preferred units and any covenants of Enable’s debt instruments limiting the ability of Enable to pay distributions.

Voting Rights

Each holder of common stock is entitled to one vote per share upon all matters upon which shareowners have the right to vote and generally will vote together as one class. Our board of directors has the authority to fix conversion and voting rights for any new series of preferred stock (including the right to elect directors upon a failure to pay dividends), provided that no share of preferred stock can have more than one vote per share.

Our Restated Certificate of Incorporation also contains "fair price" provisions, which require the approval by the holders of at least 80 percent of the voting power of our outstanding voting stock as a condition for mergers, consolidations, sales of substantial assets, issuances of capital stock and certain other business combinations and transactions involving us and any substantial (10 percent or more) holder of our voting stock unless the transaction is either approved by a majority of the members of our board of directors who are unaffiliated with the substantial holder or specified minimum price and procedural requirements are met. The provisions summarized in the foregoing sentence may be amended only by the approval of the holders of at least 80 percent of the voting power of our outstanding voting stock. Our voting stock consists of all outstanding shares entitled to vote generally in the election of directors and currently consists of our common stock.

Our voting stock does not have cumulative voting rights for the election of directors. Our Restated Certificate of Incorporation and By- Laws currently contain provisions stating that: (1) directors may be removed

Exhibit 4.23

only with the approval of the holders of at least a majority of the voting power of our shares generally entitled to vote; (2) any vacancy on the board of directors will be filled only by the remaining directors then in office, though less than a quorum; (3) advance notice of introduction by shareowners of business at annual shareowner meetings and of shareowner nominations for the election of directors must be given and that certain information must be provided with respect to such matters; (4) shareowner action may be taken only at an annual meeting of shareowners or a special meeting of shareowners called by the President or the board of directors; and (5) the foregoing provisions may be amended only by the approval of the holders of at least 80 percent of the voting power of the shares generally entitled to vote. These provisions, along with the "fair price" provisions discussed above, the business combination and control share acquisition provision discussed below, may deter attempts to cause a change in control of our company (by proxy contest, tender offer or otherwise) and will make more difficult a change in control that is opposed by our board of directors.

Liquidation Rights

Subject to possible prior rights of holders of preferred stock that may be issued in the future, in the event of our liquidation, dissolution or winding up, whether voluntary or involuntary, the holders of our common stock are entitled to receive the remaining assets and funds pro rata, according to the number of shares of common stock held.

Other Provisions

Oklahoma has enacted legislation aimed at regulating takeovers of corporations and restricting specified business combinations with interested shareholders. Under the Oklahoma General Corporation Act, a shareowner who acquires more than 15 percent of the outstanding voting shares of a corporation subject to the statute, but less than 85 percent of such shares, is prohibited from engaging in specified "business combinations" with the corporation for three years after the date that the shareowner became an interested stockholder. This provision does not apply if (1) before the acquisition date the corporation's board of directors has approved either the business combination or the transaction in which the shareowner became an interested shareowner or (2) the corporation's board of directors approves the business combination and at least two- thirds of the outstanding voting stock of the corporation not owned by the interested shareowner vote to authorize the business combination. The term "business combination" encompasses a wide variety of transactions with or caused by an interested shareowner in which the interested shareowner receives or could receive a benefit on other than a pro rata basis with other shareowners, including mergers, specified asset sales, specified issuances of additional shares to the interested shareowner, transactions with the corporation that increase the proportionate interest of the interested shareowner or transactions in which the interested shareowner receives certain other benefits.

Oklahoma law also contains control share acquisition provisions. These provisions generally require the approval of the holders of a majority of the corporation's voting shares held by disinterested shareowners before a person purchasing one-fifth or more of the corporation's voting shares can vote the shares in excess of the one-fifth interest. Similar shareholder approvals are required at one-third and majority thresholds.

The board of directors may allot and issue shares of common stock for such consideration, not less than the par value thereof, as it may from time to time determine. No holder of common stock has the preemptive right to subscribe for or purchase any part of any new or additional issue of stock or securities convertible into stock. Our common stock is not subject to further calls or to assessment by us.

Listing

Our common stock is listed on the New York Stock Exchange.

Transfer Agent and Registrar

Computershare is the Transfer Agent and Registrar for our common stock.

EX-10.12

Exhibit 10.12

OGE Energy Corp.

Director Compensation

Compensation of non-management directors of OGE Energy Corp. (the "Company") in 2019 included an annual retainer fee of $230,000, of which $100,000 was payable in cash in quarterly installments and $130,000 was deposited in the director's account under the Company's Deferred Compensation Plan and converted to 3,043.1 common stock units based on the closing price of the Company's Common Stock on December 10, 2019. In 2019, the non-management directors did not receive additional compensation for attending Board or committee meetings but were instead paid a quarterly cash retainer. The lead director received an additional $25,000 cash retainer in 2019. The chair of the Audit Committee received an additional $15,000 cash retainer in 2019. The chair of each of the Compensation and Nominating and Corporate Governance Committees received an additional $12,500 annual cash retainer in 2019. Each member of the Audit Committee also received an additional annual retainer of $5,000. These amounts represent the total fees paid to directors in their capacities as directors of the Company and Oklahoma Gas and Electric Company in 2019.

Under the Company's Deferred Compensation Plan, non-management directors may defer payment of all or part of their quarterly and annual cash retainer fee, which deferred amounts in 2019 were credited to their account as of the scheduled payment date. Amounts credited to the accounts are assumed to be invested in one or more of the investment options permitted under the Company's Deferred Compensation Plan. In 2019, those investment options included a Company Common Stock fund, whose value was determined based on the stock price of the Company's Common Stock. When an individual ceases to be a director of the Company, all amounts credited under the Company's Deferred Compensation Plan are paid in cash in a lump sum or installments. In certain circumstances, participants may also be entitled to in-service withdrawals from the Company's Deferred Compensation Plan.

On December 3, 2019, the Compensation Committee met to consider director compensation. At that meeting, the Compensation Committee increased the annual equity retainer, noted above, credited on December 10, 2019, from $125,000 to $130,000.

EX-10.13

Exhibit 10.13

OGE Energy Corp.

Executive Officer Compensation

Executive Compensation

In December 2019, the Compensation Committee of the OGE Energy Corp. (the "Company") board of directors took actions setting executives' salaries and target amount of annual incentive awards for 2020. In February 2020, the Compensation Committee took action setting executives' target amounts of long-term compensation awards for 2020. Executive compensation was set by the Compensation Committee after consideration of, among other things, individual performance and market-based data on compensation for executives with similar duties. Payouts of 2020 annual incentive award targets and performance-based long-term awards are dependent on achievement of specified corporate goals established by the Compensation Committee, and no officer is assured of any payout.

Salary

The Compensation Committee established the base salaries for its senior executive group. The salaries for 2020 for the OGE Energy officers who are expected to be named in the Summary Compensation Table in OGE Energy's 2020 Proxy Statement are as follows:

Executive Officer	2020 Base Salary
Sean Trauschke, Chairman, President and Chief Executive Officer	$1,071,005
Stephen E. Merrill, Chief Financial Officer	$499,564
E. Keith Mitchell, Chief Operating Officer of OG&E	$544,952
Jean C. Leger, Jr., Senior Vice President, Utility Operations of OG&E	$386,253
William H. Sultemeier, General Counsel	$455,526

Establishment of 2020 Annual Incentive Awards

As stated above, at its December 2019 meeting, the Compensation Committee approved the target amount of annual incentive awards, expressed as a percentage of salary, with the officer having the ability, depending upon achievement of the 2020 corporate goals to receive from 0 percent to 150 percent of such targeted amount. For 2020, the targeted amount ranged from 65 percent to 105 percent of the approved 2020 base salary for the executive officers in the above table.

Establishment of Long-Term Awards

At its February 2020 meeting, the Compensation Committee approved the level of target long-term incentive awards, expressed as a percentage of salary. For 2020, the targeted amount ranged from 115 percent to 310 percent of the approved 2020 base salary for the executive officers in the above table. The performance-based portion of the long-term incentive awards allow the officer to receive from 0 percent to 200 percent of such targeted amount at the end of a three-year performance period depending upon achievement of the corporate goals. The time-based portion of the long-term incentive awards allow the officers to receive the granted amount at the end of a three-year vesting period depending upon continued employment.

Other Benefits

Retirement Benefits. A significant amount of the Company's employees hired before December 1, 2009, including executive officers, are eligible to participate in the Company's Pension Plan and certain employees are eligible to participate in the Company's Restoration of Retirement Income Plan that enables participants, including executive officers, to receive the same benefits that they would have received under the Company's Pension Plan in the absence of limitations imposed by the Federal tax laws. In addition, the supplemental executive retirement plan, which was adopted in 1993 and amended in subsequent years, provides a supplemental executive retirement plan in order to attract and retain executives designated by the Compensation Committee of the Company's Board of Directors who may not otherwise qualify for a sufficient level of benefits under the Company's Pension Plan and Restoration of Retirement Income Plan. Mr. Trauschke is the only employee who participates in the supplemental executive retirement plan.

Almost all employees of the Company, including executive officers, also are eligible to participate in our 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attained age 50 before the close of a year are allowed to

make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof; (ii) an after-tax Roth contribution; or (iii) a contribution made on a non Roth after-tax basis. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or her future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, the Company contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation. The Company contribution for employees hired or rehired before December 1, 2009 varies depending on the participant's hire date, election with respect to participation in the Pension Plan and, in some cases, years of service.

No Company contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions, or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, the Company's contribution may be directed to any available investment option in the 401(k) Plan. The Company match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their Company contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed by the Company or its affiliates.

The Company provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of the Company and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace. Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual incentive awards or (ii) eligible employees may elect a deferral percentage of base salary and annual incentive awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers.

The Company matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan, and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of the Company or termination of the plan.

Deferrals, plus any Company match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2019, those investment options included an OGE Energy Common Stock fund, whose value was determined based on the stock price of OGE Energy's Common Stock.

Normally, payments under the deferred compensation plan begin within one year after retirement. For these purposes, normal retirement age is 65 and the minimum age to qualify for early retirement is age 55 with at least five years of service. Benefits will be paid, at the election of the participant, either in a lump sum or a stream of annual payments for up to 15 years, or a combination thereof. Participants whose employment terminates before they qualify for retirement will receive their vested account balance in one lump sum following termination as provided in the plan. Participants also will be entitled to pre- and post-retirement survivor benefits. If the participant dies while in employment before retirement, his or her beneficiary will receive a payment of the account balance plus a supplemental survivor benefit equal to two times the total amount of base salary and annual incentive payments deferred under the plan. If the participant dies following retirement, his or her beneficiary will continue to receive the remaining vested account balance. Additionally, eligible surviving spouses will be entitled to a lifetime survivor annuity payable annually. The amount of the annuity is based on 50 percent of the participant's account balance at retirement, the spouse's age and actuarial assumptions established by the Company's Plan Administration Committee.

At any time prior to retirement, a participant may withdraw all or part of amounts attributable to his or her vested account balance under the deferred compensation plan at December 31, 2004, subject to a penalty of 10 percent of the amount withdrawn. In addition, at the time of the initial deferral election, a participant may elect to receive one or more in-service

distributions on specified dates without penalty. Hardship withdrawals, without penalty, may also be permitted at the discretion of the Company's Plan Administration Committee.

Perquisites. The Company also offers executive officers a limited amount of perquisites. These include payment of social membership dues at dining and country clubs for certain executive officers, an annual physical exam for all executive officers, a relocation program and in some instances the use of a company car. In reviewing the perquisites and the benefits under the 401(k) Plan, Deferred Compensation Plan, Pension Plan, Restoration of Retirement Income Plan and supplemental executive retirement plan, the Compensation Committee seeks to provide participants with benefits at least commensurate with those offered by other utilities of comparable size.

Change-of-Control Provisions and Employment Agreements. None of the Company's executive officers has an employment agreement with the Company. Each of the executive officers has a change of control agreement that becomes effective upon a change of control. If an executive officer's employment is terminated by the Company "without cause" following a change of control, the executive officer is entitled to the following payments: (i) all accrued and unpaid compensation and a prorated annual incentive payout and (ii) a severance payment equal to 2.99 times the sum of such officer's (a) annual base salary and (b) highest recent annual incentive payout. The change of control agreements are considered to be double trigger agreements because payment will only be made following a change of control and termination of employment. The 2.99 times multiple for change-of-control payments was selected because at the time it was considered standard. Although many companies also include provisions for tax gross-up payments to cover any excise taxes on excess parachute payments, the Company's Board of Directors decided not to include this additional benefit in the Company's agreements. Instead, under the Company's agreements if the excise tax would be imposed, the change-of-control payments will be reduced to a point where no excise tax would be payable, if such reduction would result in a greater after-tax payment.

In addition, pursuant to the terms of the Company's incentive compensation plans, upon a change of control, all performance units will vest and be paid out immediately in cash as if the applicable performance goals had been satisfied at target levels; all restricted stock units will vest and be paid out immediately in cash; and any annual incentive award outstanding for the year in which the participant's termination occurs for any reason, other than cause, within 24 months after the change of control will be paid in cash at target level on a prorated basis.

EX-21.01

Exhibit 21.01

OGE Energy Corp.

Subsidiaries of the Registrant

Name of Subsidiary	Jurisdiction of Incorporation	Percentage of Ownership
Oklahoma Gas and Electric Company	Oklahoma	100.0
OGE Enogex Holdings LLC	Delaware	100.0

The above listed subsidiaries have been consolidated in the Registrant's financial statements. Certain of the Company's subsidiaries have been omitted from the list above in accordance with Rule 1-02(w) of Regulation S-X.

EX-23.01

Exhibit 23.01

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-92423) pertaining to the deferred compensation plan, the Registration Statement (Form S-8 No. 333-104497) pertaining to the employees' stock ownership and retirement savings plan, Registration Statement (Form S-8 No. 333-190406) pertaining to the employees' stock ownership and retirement savings plan, Registration Statement (Form S-8 No. 333-190405) pertaining to the 2013 stock incentive plan, the Registration Statement (Form S-3ASR No. 333-221303) pertaining to the dividend reinvestment and stock purchase plan and the Registration Statement (Form S-3ASR No. 333-225030) pertaining to common stock and debt securities of our reports dated February 26, 2020, with respect to the consolidated financial statements and schedule of OGE Energy Corp., and the effectiveness of internal control over financial reporting of OGE Energy Corp., included in this Annual Report (Form 10-K) for the year ended December 31, 2019.

/s/  Ernst & Young LLP

Oklahoma City, Oklahoma

February 26, 2020

EX-23.02

Exhibit 23.02

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-92423, 333-104497, 333-190406, and 333-190405 on Form S-8; Registration Statement Nos. 333-225030, and 333-221303 on Form S-3ASR of our report dated February 19, 2020 relating to the consolidated financial statements of Enable Midstream Partners, LP and subsidiaries appearing in this Annual Report on Form 10-K of OGE Energy Corp. for the year ended December 31, 2019.

/s/ Deloitte & Touche LLP

Oklahoma City, Oklahoma

February 26, 2020

EX-24.01

Exhibit 24.01

Power of Attorney

WHEREAS, OGE ENERGY CORP., an Oklahoma corporation (herein referred to as the "Company"), is about to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2019; and

WHEREAS, each of the undersigned holds the office or offices in the Company herein-below set opposite his or her name, respectively;

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints SEAN TRAUSCHKE, STEPHEN E. MERRILL and SARAH R. STAFFORD and each of them individually, his or her attorney with full power to act for him or her and in his or her name, place and stead, to sign his or her name in the capacity or capacities set forth below to said Form 10-K and to any and all amendments thereto, and hereby ratifies and confirms all that said attorney may or shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 26th day of February, 2020.

Sean Trauschke, Chairman, Principal Executive Officer and Director	/s/	Sean Trauschke
Frank A. Bozich, Director	/s/	Frank A. Bozich
James H. Brandi, Director	/s/	James H. Brandi
Peter D. Clarke, Director	/s/	Peter D. Clarke
Luke R. Corbett, Director	/s/	Luke R. Corbett
David L. Hauser, Director	/s/	David L. Hauser
Judy R. McReynolds, Director	/s/	Judy R. McReynolds
David E. Rainbolt, Director	/s/	David E. Rainbolt
J. Michael Sanner, Director	/s/	J. Michael Sanner
Sheila G. Talton, Director	/s/	Sheila G. Talton
Stephen E. Merrill, Principal Financial Officer	/s/	Stephen E. Merrill
Sarah R. Stafford, Principal Accounting Officer	/s/	Sarah R. Stafford

STATE OF OKLAHOMA	)
	)	SS
COUNTY OF OKLAHOMA	)

On the date indicated above, before me, Kelly Hamilton-Coyer, Notary Public in and for said County and State, the above named directors and officers of OGE ENERGY CORP., an Oklahoma corporation, known to me to be the persons whose names are subscribed to the foregoing instrument, severally acknowledged to me that they executed the same as their own free act and deed.

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal on the 26th day of February, 2020.

/s/ Kelly Hamilton-Coyer

By: Kelly Hamilton-Coyer

Notary Public

My commission expires:

July 6, 2021

EX-31.01

Exhibit 31.01

CERTIFICATIONS

I, Sean Trauschke, certify that:

1. I have reviewed this annual report on Form 10-K 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: February 26, 2020

  /s/ Sean Trauschke

Sean Trauschke

Chairman of the Board, President and Chief Executive Officer

Exhibit 31.01

CERTIFICATIONS

I, Stephen E. Merrill, certify that:

1. I have reviewed this annual report on Form 10-K 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: February 26, 2020

  /s/ Stephen E. Merrill

Stephen E. Merrill

Chief Financial Officer

EX-32.01

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 Annual Report of OGE Energy Corp. (the "Company") on Form 10-K for the period ended December 31, 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.

February 26, 2020

          /s/ Sean Trauschke

               Sean Trauschke

Chairman of the Board, President and Chief Executive Officer

          /s/ Stephen E. Merrill

               Stephen E. Merrill

Chief Financial Officer

EX-99.01

Exhibit 99.01

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Enable GP, LLC and

Unitholders of Enable Midstream Partners, LP

Oklahoma City, Oklahoma

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Enable Midstream Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, cash flows, and partners’ equity for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2020, expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

1

Exhibit 99.01

Goodwill - Anadarko Basin Reporting Unit - Refer to Notes 1 and 10 to the consolidated financial statements

Critical Audit Matter Description

The Partnership’s evaluation of goodwill for impairment involves the comparison of the fair value of each reporting unit to its carrying value. The Partnership used the discounted cash flow model to estimate fair value, which requires management to make significant estimates and assumptions related to the weighted average cost of capital and forecasts of future revenues, including the revenue growth rate. Changes in these assumptions could have a significant impact on either the fair value, the amount of any goodwill impairment charge, or both. The goodwill balance allocated to the Anadarko Basin Reporting Unit (“Anadarko”) was $86 million as of October 1, 2019. The carrying value of Anadarko exceeded its fair value as of the measurement date and the goodwill associated with Anadarko was completely impaired in the amount of $86 million.

Given the significant judgments made by management to estimate the fair value of Anadarko, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to selection of the weighted average cost of capital and forecasts of future revenues, including the revenue growth rate, of Anadarko required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the weighted average cost of capital and forecasts of future revenues, including the revenue growth rate, used by management to estimate the fair value of Anadarko included the following, among others:

•We tested the effectiveness of controls over management’s goodwill impairment evaluation, including those over the determination of the fair value of Anadarko, such as controls related to management’s selection of the weighted average cost of capital and forecasts of future revenues, including the revenue growth rate.

•We evaluated management’s ability to accurately forecast future revenues by comparing actual results to management’s historical forecasts.

•We evaluated the reasonableness of management’s revenue forecasts by comparing the forecasts to:

▪Historical revenues.

▪Internal communications to management and the Board of Directors.

▪Forecasted information included in Partnership press releases as well as in analyst and industry reports for the Partnership and certain of its peer companies.

•With the assistance of our fair value specialists, we evaluated the reasonableness of the (1) valuation methodology and (2) weighted average cost of capital and revenue growth rate by:

–Testing the source information underlying the determination of the weighted average cost of capital and revenue growth rate and the mathematical accuracy of the calculation.

–Developing a range of independent estimates and comparing those to the weighted average cost of capital and revenue growth rate selected by management.

/s/ DELOITTE & TOUCHE

Oklahoma City, Oklahoma

February 19, 2020

We have served as the Partnership’s auditor since 2013.

2

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2019		2018		2017
	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 16)):
Product sales	$	1,533	$	2,106	$	1,653
Service revenues	1,427		1,325		1,150
Total Revenues	2,960		3,431		2,803
Cost and Expenses (including expenses from affiliates (Note 16)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	1,279		1,819		1,381
Operation and maintenance	423		388		369
General and administrative	103		113		95
Depreciation and amortization	433		398		366
Impairment (Note 10)	86		—		—
Taxes other than income taxes	67		65		64
Total Cost and Expenses	2,391		2,783		2,275
Operating Income	569		648		528
Other Income (Expense):
Interest expense	(190)		(152)		(120)
Equity in earnings of equity method affiliate	17		26		28
Other, net	3		—		—
Total Other Expense	(170)		(126)		(92)
Income Before Income Tax	399		522		436
Income tax benefit	(1)		(1)		(1)
Net Income	$	400	$	523	$	437
Less: Net income attributable to noncontrolling interests	4		2		1
Net Income Attributable to Limited Partners	$	396	$	521	$	436
Less: Series A Preferred Unit distributions (Note 7)	36		36		36
Net Income Attributable to Common and Subordinated Units (Note 6)	$	360	$	485	$	400
Basic earnings per unit (Note 6)
Common units	$	0.83	$	1.12	$	0.92
Subordinated units	$	—	$	—	$	0.93
Diluted earnings per unit (Note 6)
Common units	$	0.82	$	1.11	$	0.92
Subordinated units	$	—	$	—	$	0.93

See Notes to the Consolidated Financial Statements

3

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Net income	$	400	$	523	$	437
Other comprehensive loss:
Unrealized losses on derivative instruments	(3)		—		—
Reclassification of derivative losses to net income	—		—		—
Other comprehensive loss	(3)		—		—
Comprehensive income	397		523		437
Less: Comprehensive income attributable to noncontrolling interests	4		2		1
Comprehensive income attributable to Limited Partners	$	393	$	521	$	436

See Notes to the Consolidated Financial Statements

4

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2019		2018
	(In millions, except units)
Current Assets:
Cash and cash equivalents	$	4	$	8
Restricted cash	—		14
Accounts receivable, net of allowance for doubtful accounts (Note 1)	244		290
Accounts receivable—affiliated companies	25		19
Inventory	46		50
Gas imbalances	35		29
Other current assets	35		39
Total current assets	389		449
Property, Plant and Equipment:
Property, plant and equipment	13,161		12,899
Less accumulated depreciation and amortization	2,291		2,028
Property, plant and equipment, net	10,870		10,871
Other Assets:
Intangible assets, net	601		663
Goodwill	12		98
Investment in equity method affiliate	309		317
Other	85		46
Total other assets	1,007		1,124
Total Assets	$	12,266	$	12,444
Current Liabilities:
Accounts payable	$	161	$	288
Accounts payable—affiliated companies	1		4
Short-term debt	155		649
Current portion of long-term debt	251		500
Taxes accrued	32		31
Gas imbalances	19		22
Accrued compensation	31		26
Customer deposits	17		38
Other	113		57
Total current liabilities	780		1,615
Other Liabilities:
Accumulated deferred income taxes, net	4		5
Regulatory liabilities	24		23
Other	80		54
Total other liabilities	108		82
Long-Term Debt	3,969		3,129
Commitments and Contingencies (Note 17)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2019 and December 31, 2018, respectively)	362		362
Common units (435,201,365 issued and outstanding at December 31, 2019 and 433,232,411 issued and outstanding at December 31, 2018, respectively)	7,013		7,218
Accumulated other comprehensive loss	(3)		—
Noncontrolling interests	37		38
Total Partners’ Equity	7,409		7,618
Total Liabilities and Partners’ Equity	$	12,266	$	12,444

See Notes to the Consolidated Financial Statements

5

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Cash Flows from Operating Activities:
Net income	$	400	$	523	$	437
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	433		398		366
Deferred income taxes	(1)		(1)		(3)
Impairment	86		—		—
Loss on sale/retirement of assets	8		1		7
Equity in earnings of equity method affiliate	(17)		(26)		(28)
Return on investment in equity method affiliate	17		26		28
Equity-based compensation	16		16		15
Amortization of debt costs and discount (premium)	(1)		(1)		(2)
Changes in other assets and liabilities:
Accounts receivable, net	43		(10)		(23)
Accounts receivable—affiliated companies	(6)		(1)		(5)
Inventory	4		(10)		1
Gas imbalance assets	(6)		8		4
Other current assets	9		(21)		4
Other assets	11		(12)		1
Accounts payable	(75)		4		54
Accounts payable—affiliated companies	(3)		1		—
Gas imbalance liabilities	(3)		10		(23)
Other current liabilities	39		4		(4)
Other liabilities	(12)		15		5
Net cash provided by operating activities	942		924		834
Cash Flows from Investing Activities:
Capital expenditures	(432)		(728)		(416)
Acquisitions, net of cash acquired	—		(443)		(298)
Proceeds from sale of assets	1		8		1
Proceeds from insurance	1		2		2
Return of investment in equity method affiliate	8		7		5
Other, net	(8)		—		—
Net cash used in investing activities	(430)		(1,154)		(706)
Cash Flows from Financing Activities:
(Decrease) increase in short-term debt	(494)		244		405
Proceeds from long-term debt, net of issuance costs	1,544		787		691
Repayment of long-term debt	(700)		(450)		—
Proceeds from Revolving Credit Facility	—		350		1,200
Repayment of Revolving Credit Facility	(250)		(100)		(1,836)
Proceeds from issuance of common units, net of issuance costs	—		2		—
Distributions to common unitholders	(564)		(551)		(355)
Distributions to subordinated unitholders	—		—		(198)
Distributions to preferred unitholders	(36)		(36)		(36)
Distributions to non-controlling interests	(5)		(4)		(1)
Cash paid for employee equity-based compensation	(25)		(9)		(2)
Net cash (used in) provided by financing activities	(530)		233		(132)
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(18)		3		(4)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	22		19		23
Cash, Cash Equivalents and Restricted Cash at End of Period	$	4	$	22	$	19

See Notes to the Consolidated Financial Statements

6

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

	Series A Preferred Units			Common Units			Subordinated Units			Accumulated Other Comprehensive Earnings		Noncontrolling Interest		Total Partners’ Equity
	Units	Value		Units	Value		Units	Value		Value		Value		Value
	(In millions)
Balance as of Balance as of December 31, 2016	15	$	362	224	$	3,737	208	$	3,683	$	—	$	12	$	7,794
Net income	—	36		—	266		—	134		—		1		437
Conversion of subordinated units	—	—		208	3,619		(208)	(3,619)		—		—		—
Distributions	—	(36)		—	(355)		—	(198)		—		(1)		(590)
Equity-based compensation, net of units for employee taxes	—	—		1	13		—	—		—		—		13
Balance as of Balance as of December 31, 2017	15	$	362	433	$	7,280	—	$	—	$	—	$	12	$	7,654
Net income	—	36		—	485		—	—		—		2		523
Issuance of common units	—	—		—	2		—	—		—		—		2
Acquisition of EOCS	—	—		—	—		—	—		—		28		28
Distributions	—	(36)		—	(551)		—	—		—		(4)		(591)
Equity-based compensation, net of units for employee taxes	—	—		—	2		—	—		—		—		2
Balance as of Balance as of December 31, 2018	15	$	362	433	$	7,218	—	$	—	$	—	$	38	$	7,618
Net income	—	36		—	360		—	—		—		4		400
Other comprehensive loss	—	—		—	—		—	—		(3)		—		(3)
Distributions	—	(36)		—	(564)		—	—		—		(5)		(605)
Equity-based compensation, net of units for employee taxes	—	—		2	(1)		—	—		—		—		(1)
Balance as of December 31, 2019	15	$	362	435	$	7,013	—	$	—	$	(3)	$	37	$	7,409

See Notes to the Consolidated Financial Statements

7

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (Partnership) is a Delaware limited partnership formed on May 1, 2013. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in Oklahoma and serve crude oil production in the SCOOP and STACK plays of the Anadarko Basin and in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. The Partnership’s natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma, and our investment in SESH, a pipeline extending from Louisiana to Alabama.

CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP.

At December 31, 2019, CenterPoint Energy held approximately 53.7% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.5% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 7 for further information related to the Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s General Partner (Enable GP) on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class.

For the years ended December 31, 2019, 2018 and 2017, the Partnership owned a 50% interest in SESH. See Note 11 for further discussion of SESH. For the years ended December 31, 2019, 2018 and 2017, the Partnership held a 50% ownership interest in Atoka and consolidated Atoka in its Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, for the period November 1, 2018 through December 31, 2019, the Partnership owned a 60% interest in ESCP, which is consolidated in its Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.

Basis of Presentation

The accompanying consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP.

 For a description of the Partnership’s reportable segments, see Note 20.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

8

Exhibit 99.01

Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil, condensate and produced water gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. The Partnership reflects revenue as Product sales and Service revenues on the Consolidated Statements of Income as follows:

Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership’s midstream services.

Service revenues: Service revenues represent all other revenue generated as a result of performing the Partnership’s midstream services.

The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil, condensate and water gathering services to third parties in accordance with ASU No. 2014-09 “Revenue from Contracts with Customers” (Topic 606) upon its adoption on January 1, 2018. As the Partnership adopted using the modified retrospective method, revenue for all periods prior to January 1, 2018 were recognized in accordance with “Revenue Recognition” (Topic 605). Please see Note 3 for a description of the impact of adoption. Under Topic 606, revenue is recognized at an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services. The determination of that amount and the timing of recognition is based on identifying the contracts with customers, identifying the performance obligations in the contract, determining the transaction price, allocating the transaction price to the performance obligations in the contract, and ultimately recognizing revenue when (or as) the entity satisfies the performance obligation.

Service revenues for gathering, processing, transportation and storage services for the Partnership are recorded each month as services have been completed and performance obligations are met. Product revenues are recognized when control is transferred. Monthly revenues are based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated revenues are reflected in Accounts receivable, net or Accounts receivable—affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Total revenues on the Consolidated Statements of Income.

The Partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP.

The Partnership relies on certain key natural gas producer customers for a significant portion of natural gas and NGLs supply. The Partnership relies on certain key utilities for a significant portion of transportation and storage demand. The Partnership depends on third-party facilities to transport and fractionate NGLs that it delivers to third parties at the inlet of their facilities. For the year ended December 31, 2019, one non-affiliate customer accounted for approximately 11%, or $328 million of our consolidated revenue. These revenues were primarily included in our gathering and processing segment. There are no revenue concentrations with individual non-affiliate customers in the years ended December 31, 2018 and 2017. See note 16 for more information on revenues from affiliates.

Additionally, for the years ended December 31, 2019, 2018 and 2017, one third party purchased approximately 12%, 12% and 13%, respectively, of the NGLs delivered off our system, which accounted for approximately $131 million, $214 million and $140 million, or 4%, 6% and 5%, respectively, of total revenues. Additionally, in the years ended December 31, 2019, 2018 and 2017, another third party purchased 12%, 8% and 12%, respectively, of the NGLs delivered off our system, which accounted for $119 million, $152 million and $127 million, respectively, or 4%, 4% and 4%, respectively, of total revenues.

Natural Gas and Natural Gas Liquids Purchases

Cost of natural gas and natural gas liquids represents the cost of our natural gas and natural gas liquids purchased exclusive of depreciation, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. Estimates for gas purchases are based on estimated volumes and contracted purchase prices. Estimated

9

Exhibit 99.01

gas purchases are included in Accounts Payable or Accounts Payable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Cost of natural gas and natural gas liquids, excluding Depreciation and amortization on the Consolidated Statements of Income.

Operation and Maintenance and General and Administrative Expense

Operation and maintenance expense represents the cost of our service related revenues and consists primarily of labor expenses, lease costs, utility costs, insurance premiums and repairs and maintenance expenses directly related to the operations of assets. General and administrative expense represents cost incurred to manage the business. This expense includes cost of general corporate services, such as treasury, accounting, legal, information technology and human resources and all other expenses necessary or appropriate to the conduct of business. Any Operation and maintenance expense and General and administrative expense associated with product sales is immaterial.

Environmental Costs

The Partnership expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Partnership expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Partnership records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. There are no material amounts accrued at December 31, 2019 or 2018.

Depreciation and Amortization Expense

Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Amortization of intangible assets is computed using the straight-line method over the respective lives of the intangible assets.

The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets at the time the assets are placed in service. As circumstances warrant, useful lives are adjusted when changes in planned use, changes in estimated production lives of affiliated natural gas basins or other factors indicate that a different life would be more appropriate. Such changes could materially impact future depreciation expense. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The computation of amortization expense on intangible assets requires judgment regarding the amortization method used. Intangible assets are amortized on a straight-line basis over their useful lives using a method of amortization that reflects the pattern in which the economic benefits of the intangible asset are consumed.

Income Taxes

The Partnership’s earnings are not subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) and are taxable at the individual partner level. For more information, see Note 18.

We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense.

Cash and Cash Equivalents

The Partnership considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase. The Consolidated Balance Sheets have $4 million and $8 million of cash and cash equivalents as of December 31, 2019 and 2018, respectively.

10

Exhibit 99.01

Restricted Cash

Restricted cash consists of cash which is restricted by agreements with third parties. The Consolidated Balance Sheets have $0 and $14 million of restricted cash as of December 31, 2019 and 2018, respectively.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, we evaluate our customers’ financial strength based on aging of accounts receivable, payment history and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due. Based on this review, management determined that a $2 million allowance for doubtful accounts was required at each of the years ended December 31, 2019 and 2018.

Inventory

Materials and supplies inventory is valued at cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership recorded no write-downs to net realizable value related to materials and supplies inventory disposed or identified as excess or obsolete for each of the years ended December 31, 2019 and 2018, and $1 million for the year ended December 31, 2017. Materials and supplies are recorded to inventory when purchased and, as appropriate, subsequently charged to operation and maintenance expense on the Consolidated Statements of Income or capitalized to property, plant and equipment on the Consolidated Balance Sheets when installed.

Natural gas inventory is held, through the transportation and storage reportable segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing reportable segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value. During the years ended December 31, 2019, 2018 and 2017, the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $8 million, $4 million and $2 million, respectively. The cost of gas associated with sales of natural gas and natural gas liquids inventory is presented in Cost of natural gas and natural gas liquids, excluding depreciation and amortization on the Consolidated Statements of Income.

	December 31,
	2019		2018
	(In millions)
Materials and supplies	$	32	$	31
Natural gas and natural gas liquids	14		19
Total Inventory	$	46	$	50

Gas Imbalances

Gas imbalances occur when the actual amounts of natural gas delivered from or received by the Partnership’s pipeline systems differ from the amounts scheduled to be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or natural gas depending on contractual terms. The Partnership values all imbalances at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value.

Long-Lived Assets (including Intangible Assets)

The Partnership records property, plant and equipment and intangible assets at historical cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and capitalized interest. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and charged to Accumulated depreciation. For assets that do not

11

Exhibit 99.01

belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Operation and maintenance expense. The Partnership expenses repair and maintenance costs as incurred. Repair, removal and maintenance costs are included in the Consolidated Statements of Income as Operation and maintenance expense.

Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. For more information, see Note 14.

The Partnership assesses its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. The Partnership utilizes the market or income approaches to estimate the fair value of the reporting unit, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the reporting unit is then compared to the carrying amount of the reporting unit and an impairment charge is recorded to goodwill for the difference. The Partnership performs its goodwill impairment testing at the reporting unit, which is one level below the transportation and storage and gathering and processing reportable segment level. For more information, see Note 10.

Regulatory Assets and Liabilities

The Partnership applies the guidance for accounting for regulated operations to portions of the transportation and storage reportable segment. The Partnership’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of each of December 31, 2019 and 2018, these removal costs of $24 million and $23 million, respectively, are classified as Regulatory liabilities in the Consolidated Balance Sheets.

Capitalization of Interest and Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates for entities that apply guidance for accounting for regulated operations. Capitalized interest represents the approximate net composite interest cost of borrowed funds used for construction. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. For the years ended December 31, 2019, 2018 and 2017, the Partnership capitalized interest and AFUDC of $2 million, $6 million and $1 million, respectively.

Derivative Instruments

The Partnership is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. At times, the Partnership utilizes commodity derivative instruments such as physical forward contracts, financial futures and swaps to mitigate the impact of changes in commodity prices on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value unless the Partnership elects hedge accounting or the normal purchase and sales exemption for qualified physical transactions. For commodity derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized in Product sales in the Consolidated Statements of Income. A commodity derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

At times, the Partnership utilizes interest rate derivative instruments such as swaps to mitigate the impact of changes in interest rates on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period in which the hedged transaction is recognized in earnings.

12

Exhibit 99.01

The Partnership’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

Fair Value Measurements

The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, the Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy included in current accounting guidance. The Partnership generally applies the market approach to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

Equity-Based Compensation

The Partnership awards equity-based compensation to officers, directors and employees under the Long-Term Incentive Plan. All equity-based awards to officers, directors and employees under the Long-Term Incentive Plan, including grants of performance units, time-based phantom units (phantom units) and time-based restricted units (restricted units) are recognized in the Consolidated Statements of Income based on their fair values. The fair value of the phantom units and restricted units are based on the closing market price of the Partnership’s common unit on the grant date. The fair value of the performance units is estimated on the grant date using a lattice-based valuation model that factors in information, including the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the phantom unit and restricted unit awards is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a vesting period. The vesting of the performance unit awards is also contingent upon the probable outcome of the market condition. Depending on forfeitures and actual vesting, the compensation expense recognized related to the awards could increase or decrease.

Employee Benefit Plans

On January 1, 2015, the Partnership adopted the 401(k) Savings Plan, covering all full-time employees. Participant contributions are discretionary, and can be up to 70% of compensation, as pre-tax, Roth, and /or after-tax contributions, subject to certain limits. We match 100% of employee contributions up to 6% of each participant’s eligible annual compensation, subject to certain limits. Matching contributions provided by the Partnership are immediately vested. The Partnership may also make discretionary profit sharing contributions. Allocations of such profit sharing contributions are based on the proportion of each participant’s eligible compensation of the plan year to the total of all participants’ eligible compensation, as defined. A participant must be employed on the last day of the Plan year in order to receive an allocation of profit sharing contributions. Profit sharing contributions must be approved by the Board of Directors annually. For the years ended December 31, 2019, 2018 and 2017, the Partnership contributed $20 million, $19 million and $18 million, respectively.

During the years ended December 31, 2019, 2018 and 2017, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. For the years ended December 31, 2019, 2018 and 2017, the Partnership reimbursed OGE Energy $3 million, $3 million and $5 million, respectively, for these benefits. See Note 16 for further information related to our related party transactions.

Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP

On November 14, 2017, the General Partner adopted the Fifth Amended and Restated Agreement of Limited Partnership (the Partnership Agreement), to implement certain changes to the Internal Revenue Code enacted by the Bipartisan Budget Act of 2015 relating to partnership audit and adjustment procedures. The Partnership Agreement also removed references to the subordinated units (all of which previously converted into common units) and related provisions.

(2) New Accounting Pronouncements

Accounting Standards to be Adopted in Future Periods

13

Exhibit 99.01

Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires 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. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other

In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This standard requires entities to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Partnership elected to adopt the guidance in ASU 2017-04 effective October 1, 2019, and as a result applied the new guidance to its annual goodwill impairment test performed as of October 1, 2019. The impairment resulting from the October 1, 2019 annual impairment test was based upon the amount by which the carrying amount exceeded the reporting unit’s fair value up to the actual amount of goodwill recorded for the Anadarko Basin reporting unit.

Fair Value Measurement—Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement

In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement” which focuses on improving the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by U.S. GAAP that is most important to users of each entity’s financial statements. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other—Internal-Use Software

In August 2018, the FASB issued ASU No. 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract,” which aims to reduce complexity in the accounting for costs of implementing a cloud computing service arrangement. ASU No. 2018-15 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. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Collaborative Arrangements

In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606.” This standard resolves the diversity in practice concerning the manner in which entities account for transactions on the basis of their view of the economics of the collaborative arrangement. The amendments (1) clarify that certain transactions between collaborative participants should be accounted for as revenue under topic 606 when the collaborative participant is a customer in the context of the unit of account; (2) add unit-of-account guidance in Topic 808 to align with the guidance in Topic 606; and (3) clarify that in a transaction that is not directly related to sales to third parties, presenting the transaction as revenue would be precluded if the collaborative participant counterparty was not a customer. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

14

Exhibit 99.01

Codification Improvements

In April 2019, the FASB issued ASU No. 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments,” which clarifies and improves areas of guidance related to recently issued standards on credit losses, hedging and recognition and measurement. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

In November 2019, FASB issued ASU No. 2019-11, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses,” which introduced an expected credit loss model for the impairment of financial assets measured at amortized cost basis to replace the probable, incurred loss model for those assets. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

(3) Revenues

The Partnership adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (ASC 606) on January 1, 2018 using the modified retrospective method. Upon adoption, the Partnership did not recognize a material cumulative adjustment to Partners’ Equity and there were no material changes in the timing of revenue recognition or our accounting policies. The Partnership has applied the standard only to contracts that were not expired as of January 1, 2018.

The following tables disaggregate total revenues by major source from contracts with customers and the gain on derivative activity for the years ended December 31, 2019 and 2018.

	Year Ended December 31, 2019
	Gathering and Processing		Transportation and Storage		Eliminations		Total
	(In millions)
Revenues:
Product sales:
Natural gas	$	368	$	464	$	(384)	$	448
Natural gas liquids	943		19		(19)		943
Condensate	126		—		—		126
Total revenues from natural gas, natural gas liquids, and condensate	1,437		483		(403)		1,517
Gain on derivative activity	12		4		—		16
Total Product sales	$	1,449	$	487	$	(403)	$	1,533
Service revenues:
Demand revenues	$	274	$	489	$	—	$	763
Volume-dependent revenues	615		62		(13)		664
Total Service revenues	$	889	$	551	$	(13)	$	1,427
Total Revenues	$	2,338	$	1,038	$	(416)	$	2,960

15

Exhibit 99.01

	Year Ended December 31, 2018
	Gathering and Processing		Transportation and Storage		Eliminations		Total
	(In millions)
Revenues:
Product sales:
Natural gas	$	480	$	590	$	(506)	$	564
Natural gas liquids	1,405		30		(30)		1,405
Condensate	126		—		—		126
Total revenues from natural gas, natural gas liquids, and condensate	2,011		620		(536)		2,095
Gain on derivative activity	5		5		1		11
Total Product sales	$	2,016	$	625	$	(535)	$	2,106
Service revenues:
Demand revenues	$	252	$	472	$	—	$	724
Volume-dependent revenues	550		65		(14)		601
Total Service revenues	$	802	$	537	$	(14)	$	1,325
Total Revenues	$	2,818	$	1,162	$	(549)	$	3,431

Product Sales

Natural Gas, NGLs or Condensate

We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue at the point in time when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index-based price received.

Gain (Loss) on Derivative Activity

Included in Product sales are gains and losses on natural gas, natural gas liquids, and crude oil (for condensate) derivatives that are accounted for under guidance in ASC 815. See Note 13 for further discussion of our derivative and hedging activity.

Service Revenues

Service revenues include demand revenues and volume-dependent revenues, both of which include contracts with customers that typically contain a series of distinct services performed on discrete volumes. For these types of contracts with customers, we typically have a right to consideration from our customers in an amount that corresponds directly with the value to the customer of our performance completed to date and recognize service revenues in accordance with our election to use the right to invoice practical expedient.

Demand revenues

Our demand revenue arrangements are generally structured in one of the following ways:

•Under a firm arrangement, a customer agrees to pay a fixed fee for a contractually agreed upon pipeline or storage capacity, which results in performance obligations for each individual period of reservation. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized.

•Under a minimum volume commitment arrangement, a customer agrees to pay the contractually agreed upon gathering, compressing and treating fees for a minimum volume of natural gas or crude oil irrespective of whether or not the minimum volume of natural gas or crude oil is delivered, which results in performance obligations for each individual unit of volume. If the actual volumes exceed the minimum volume of natural gas or crude oil, the customer pays the contractually agreed upon gathering, compressing and treating fees for the excess volumes in addition to the fees paid for the minimum volume of natural gas or crude oil. Once the services have been completed, or the customer no longer has the ability to utilize the services, the performance

16

Exhibit 99.01

obligation is met, and revenue is recognized. In addition, when certain minimum volume commitment fee arrangements include commitments of one year or more, significant judgment is used in interim commitment periods in which a customer’s actual volumes are deficient in relation to the minimum volume commitment. Revenue is recognized in proportion to the pattern of past performance exercised by the customer or when the likelihood of the customer meeting the minimum volume commitment becomes remote.

Volume-dependent revenues

Our volume-dependent revenues primarily consist of gathering, compressing, treating, processing, transportation or storage services fees on contracts that exceed their contractually committed volume or do not have firm arrangements or minimum volume commitment arrangements. These revenues are generally variable because the volumes are dependent on throughput by third-party customers for which the service provided is only specified on a daily or monthly basis. Our other fee revenue arrangements typically recognize revenue as the service is performed and have pricing terms that are generally structured in one of the following ways: (1) Contractually agreed upon monetary fee for service or (2) contractually agreed upon consideration received in the form of natural gas or natural gas liquids, which are valued at the current month index-based price, which approximates fair value.

Accounts Receivable

Payments for all types of revenues are typically received within 30 days of invoice. Invoices for all revenue types are sent on at least a monthly basis, except for the shortfall provisions under certain minimum volume commitment arrangements, which are typically invoiced annually. Accounts receivable includes accrued revenues associated with certain minimum volume commitments that will be invoiced at the conclusion of the measurement period specified under the respective contracts.

The following table summarizes the components of accounts receivable:

	December 31, 2019		December 31, 2018
	(In millions)
Accounts Receivable:
Customers	$	239	$	297
Contract assets (1)	18		6
Non-customers	12		6
Total Accounts Receivable (2)	$	269	$	309

____________________

(1)Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include $6 million of contract assets related to firm transportation contracts with tiered rates, which are reflected in Other Assets.

(2)Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.

Contract Liabilities

Our contract liabilities primarily consist of the following prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment:

•Under certain firm arrangements, customers pay their demand fee prior to the month of contracted capacity. These fees are applied to the subsequent month’s activity and are included in other current liabilities on the Consolidated Balance Sheets.

•Under certain demand and volume dependent arrangements, customers make contributions of aid in construction payments. For payments that are related to contracts under ASC 606, the payment is deferred and amortized over the life of the associated contract and the unamortized balance is included in other current or long-term liabilities on the Consolidated Balance Sheets.

17

Exhibit 99.01

The table below summarizes the change in the contract liabilities for the year ended December 31, 2019:

	December 31, 2019		December 31, 2018		Amounts recognized in revenues
	(In millions)
Deferred revenues (1)	$	48	$	48	$	24

The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2019:

	2020		2021		2022		2023		2024 and After
	(In millions)
Deferred revenues (1)	$	25	$	6	$	6	$	5	$	6

____________________

(1)Deferred revenues includes deferred revenue—affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities.

Remaining Performance Obligations

We apply certain practical expedients as permitted by ASC 606, in which we are not required to disclose information regarding remaining performance obligations associated with agreements with original expected durations of one year or less, agreements in which we have elected to recognize revenue in the amount to which we have the right to invoice, and agreements where the variable consideration is allocated entirely to wholly unsatisfied performance obligations that generally do not get resolved until actual volumes are delivered and the prices are known. However, certain agreements do not qualify for practical expedients, which consist primarily of firm arrangements and minimum volume commitment arrangements. Upon completion of the performance obligations associated with these arrangements, revenue is recognized as Service revenues in the Consolidated Statements of Income.

The table below summarizes the timing of recognition of the remaining performance obligations as of December 31, 2019:

	2020		2021		2022		2023		2024 and After
	(In millions)
Transportation and Storage (1)	$	461	$	298	$	238	$	225	$	699
Gathering and Processing	137		121		123		121		313
Total remaining performance obligations	$	598	$	419	$	361	$	346	$	1,012

____________________

(1)The remaining performance obligations include certain obligations for MRT, which are calculated based on rates that are subject to FERC rate case approval.

(4) Leases

On January 1, 2019, the Partnership adopted ASU 2016-02, “Leases (ASC 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership has applied the standard only to contracts that were not expired as of January 1, 2019.

The Partnership elected the optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership’s adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership elected the optional transition practical expedient to not reassess whether any expired or existing contracts are or contain leases, the lease classification for any expired or existing leases and initial direct costs for any existing leases. Upon adoption, we increased our asset and liability balances on the Consolidated Balance Sheets by approximately $35 million due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that were classified as

18

Exhibit 99.01

operating leases. The Partnership did not recognize a material cumulative adjustment to the Consolidated Statement of Partners’ Equity and we did not have any material changes in the timing of expense recognition or our accounting policies.

Our lease obligations are primarily comprised of rentals of field equipment and buildings, which are recorded as Operation and maintenance and General and administrative expenses in the Partnership’s Consolidated Statements of Income. Other than the contractual terms for each lease obligation, the key inputs for our calculations of the initial right-of-use assets and corresponding lease liabilities are the expected remaining life and applicable discount rate. Field equipment has an expected lease term of three to five years, with contractual base terms of one to three years followed by month-to-month renewals. Field equipment rental arrangements do not generally contain any significant variable lease payments. While certain arrangements may include lower standby rates, field equipment is generally anticipated to be in use for all of its expected lease term. Buildings have an expected lease term of seven to ten years, which is currently the same as the contractual base term. Building rental arrangements contain market-based renewal options of up to 15 years. Variable lease payments for buildings are generally comprised of costs for utilities, maintenance and building management services. Variable lease payments due under building rental arrangements began July 1, 2019, with amounts due monthly. The Partnership is generally not aware of the implicit rate for either field equipment or building rental arrangements, so discount rates are based upon the expected term of each arrangement and the Partnership’s uncollateralized borrowing rate associated with the expected term at the time of lease inception. As of December 31, 2019, the weighted average remaining lease term is 6.4 years and the weighted average discount rate is 5.40%.

As of December 31, 2019, we have right-of-use assets of $37 million recorded as Other Assets, $9 million of corresponding obligations recorded as Other Current Liabilities and $31 million of corresponding obligations recorded as Other Liabilities on the Partnership’s Consolidated Balance Sheet. All lease obligations outstanding during the year ended December 31, 2019 were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities. Total lease costs comprised of field equipment rentals and buildings rentals were $29 million and $7 million in the Consolidated Statements of Income during the year ended December 31, 2019, respectively.

The table below summarizes lease cost for the year ended December 31, 2019:

	Year Ended December 31, 2019
	Gathering and Processing		Transportation and Storage		Total
	(In millions)
Lease Cost:
Operating lease cost	$	11	$	—	$	11
Short-term lease cost	22		2		24
Variable lease cost	1		—		1
Total Lease Cost	$	34	$	2	$	36

Under ASC 842, as of December 31, 2019, the Partnership has operating lease obligations expiring at various dates. The $4 million difference between undiscounted cash flows for operating leases and our $40 million of lease obligations is due to the impact of the applicable discount rate. Undiscounted cash flows for operating lease liabilities are as follows:

	Year Ended December 31,
	2020		2021		2022		2023		2024		2025 and After		Total
	(In millions)
Noncancellable operating leases	$	11	$	7	$	6	$	6	$	4	$	10	$	44

Description of Lease Contracts

The Partnership occupied 162,053 square feet of office space at its former principle executive offices under a lease that expired June 30, 2019. The lease payments were $19 million over the lease term, which began April 1, 2012. These lease costs are included in General and administrative expense in the Consolidated Statements of Income.

During 2017, the Partnership entered into a lease to occupy 48,642 square feet of office space in Houston, Texas, which

19

Exhibit 99.01

ends December 31, 2025. The lease payments are $4 million over the lease term, as well as a proportionate percentage of facility expenses. These lease costs are included in General and administrative expense in the Consolidated Statements of Income.

On August 28, 2018, the Partnership entered into a lease to occupy 154,584 feet of office space for its principle executive offices in Oklahoma City, Oklahoma, which expires June 30, 2029. The lease payments commenced on July 1, 2019, and total $25 million over the lease term, as well as a proportionate percentage of facility expenses. The Partnership relocated its headquarters to the new location during the second quarter of 2019. Minimum lease payments were $1 million in 2019 and are expected to be $2 million per year from 2020 through 2023.

The Partnership currently has 86 compression service agreements, of which 71 agreements are on a month-to-month basis and 15 agreements will expire in 2020. The Partnership also has nine gas treating lease agreements, of which seven are on a month-to-month basis, one agreement will expire in 2021 and one agreement will expire in 2022. These lease costs are reflected in Operation and maintenance expense in the Consolidated Statements of Income.

ASC 840 Lease Accounting

Under ASC 840 rental expense was $35 million and $27 million during the years ended December 31, 2018 and 2017, respectively.

As of December 31, 2018, the Partnership had the following future minimum payments for operating lease obligations as follows:

	Year Ended December 31,
	2019		2020-2021		2022-2023		After 2023		Total
	(In millions)
Noncancellable operating leases	$	14	$	6	$	6	$	14	$	40

(5) Acquisitions

EOCS Acquisition

On November 1, 2018, the Partnership acquired all of the equity interests in Velocity Holdings, LLC, now EOCS, which owns and operates a crude oil and condensate gathering system in the SCOOP and STACK plays of the Anadarko Basin, for approximately $444 million in cash. The acquisition was accounted for as a business combination and was funded with borrowings under the commercial paper program. During the fourth quarter of 2018, the Partnership finalized the purchase price allocation as of November 1, 2018.

The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date:

Purchase price allocation (in millions):
Assets acquired:
Cash	$	1
Current Assets	3
Property, plant and equipment	124
Intangibles	259
Goodwill	86
Liabilities assumed:
Current liabilities	1
Less: Noncontrolling interest at fair value	28
Total identifiable net assets	$	444

20

Exhibit 99.01

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Anadarko Basin and is allocated to the gathering and processing reportable segment. Included within the acquisition was 60% of a 26-mile pipeline system joint venture with a third party which owns and operates a refinery connected to the EOCS system. This joint venture’s financials have been consolidated within the Partnership’s financial statements resulting in $28 million in non-controlling interest. The Partnership incurred approximately $6 million of acquisition costs associated with this transaction, which were included in General and administrative expense in the Consolidated Statements of Income. The Partnership determined not to include pro forma consolidated financial statements for the periods presented as the impact would not be material.

ETGP Acquisition

On October 4, 2017, the Partnership acquired all of the equity interests in Align Midstream, LLC, now ETGP, a midstream service provider with natural gas gathering and processing facilities in the Cotton Valley and Haynesville plays of the Ark-La-Tex Basin, for approximately $298 million in cash. The acquisition was accounted for as a business combination and funded with borrowings under the Revolving Credit Facility. During the fourth quarter of 2017, the Partnership finalized the purchase price allocation as of October 4, 2017.

The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date:

Purchase price allocation (in millions):
Assets acquired:
Accounts receivable	$	5
Property, plant and equipment	111
Intangibles	176
Goodwill	12
Liabilities assumed:
Current liabilities	6
Total identifiable net assets	$	298

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Ark-La-Tex Basin and is allocated to the gathering and processing reportable segment. The Partnership incurred approximately $2 million of acquisition costs associated with this transaction, which are included in General and administrative expense in the Consolidated Statements of Income. The Partnership determined not to include pro forma consolidated financial statements for the periods presented as the impact would not be material.

(6) Earnings Per Limited Partner Unit

Basic and diluted earnings per limited partner unit is calculated by dividing net income allocable to common and subordinated units by the weighted average number of common and subordinated units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding. The dilutive effect of the unit-based awards discussed in Note 19 was $0.01 per unit during the years ended December 31, 2019 and 2018 and less than $0.01 per unit during the year ended December 31, 2017.

21

Exhibit 99.01

The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units:

	Year Ended December 31,
	2019		2018		2017
	(In millions, except per unit data)
Net income	$	400	$	523	$	437
Net income attributable to noncontrolling interests	4		2		1
Series A Preferred Unit distributions	36		36		36
General partner interest in net income	—		—		—
Net income available to common and subordinated units	$	360	$	485	$	400
Net income allocable to common units	$	360	$	485	$	273
Net income allocable to subordinated units	—		—		127
Net income available to common and subordinated units	$	360	$	485	$	400
Net income allocable to common units	$	360	$	485	$	273
Dilutive effect of Series A Preferred Unit distribution	—		—		—
Diluted net income allocable to common units	360		485		273
Diluted net income allocable to subordinated units	—		—		127
Total	$	360	$	485	$	400
Basic weighted average number of outstanding
Common units (1)	436		434		296
Subordinated units	—		—		137
Total	436		434		433
Basic earnings per unit
Common units	$	0.83	$	1.12	$	0.92
Subordinated units	$	—	$	—	$	0.93
Basic weighted average number of outstanding common units (1)	436		434		296
Dilutive effect of Series A Preferred Units	—		—		—
Dilutive effect of performance units	1		2		1
Diluted weighted average number of outstanding common units	437		436		297
Diluted weighted average number of outstanding subordinated units	—		—		137
Total	437		436		434
Diluted earnings per unit
Common units	$	0.82	$	1.11	$	0.92
Subordinated units	$	—	$	—	$	0.93

____________________

(1)Basic weighted average number of outstanding common units for the years ended December 31, 2019, 2018, and 2017 includes approximately one million time-based phantom units.

See Note 7 for discussion of the expiration of the subordination period.

(7) Partners’ Equity

The Partnership Agreement requires that, within 60 days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.

22

Exhibit 99.01

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2019, 2018 and 2017 (in millions, except for per unit amounts):

Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2019
December 31, 2019 (1)	February 18, 2020	February 25, 2020	$	0.3305	$	144
September 30, 2019	November 19, 2019	November 26, 2019	$	0.3305	$	144
June 30, 2019	August 20, 2019	August 27, 2019	$	0.3305	$	144
March 31, 2019	May 21, 2019	May 29, 2019	$	0.318	$	138
2018
December 31, 2018	February 19, 2019	February 26, 2019	$	0.318	$	138
September 30, 2018	November 16, 2018	November 29, 2018	$	0.318	$	138
June 30, 2018	August 21, 2018	August 28, 2018	$	0.318	$	138
March 31, 2018	May 22, 2018	May 29, 2018	$	0.318	$	138
2017
December 31, 2017	February 20, 2018	February 27, 2018	$	0.318	$	138
September 30, 2017	November 14, 2017	November 21, 2017	$	0.318	$	138
June 30, 2017	August 22, 2017	August 29, 2017	$	0.318	$	138
March 31, 2017	May 23, 2017	May 30, 2017	$	0.318	$	137

_____________________

(1)The Board of Directors declared a $0.3305 per common unit cash distribution on February 7, 2020, to be paid on February 25, 2020, to common unitholders of record at the close of business on February 18, 2020.

23

Exhibit 99.01

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2019, 2018, and 2017 (in millions, except for per unit amounts):

Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2019
December 31, 2019 (1)	February 7, 2020	February 14, 2020	$	0.625	$	9
September 30, 2019	November 5, 2019	November 14, 2019	$	0.625	$	9
June 30, 2019	August 2, 2019	August 14, 2019	$	0.625	$	9
March 31, 2019	April 29, 2019	May 15, 2019	$	0.625	$	9
2018
December 31, 2018	February 8, 2019	February 14, 2019	$	0.625	$	9
September 30, 2018	November 6, 2018	November 14, 2018	$	0.625	$	9
June 30, 2018	August 1, 2018	August 14, 2018	$	0.625	$	9
March 31, 2018	May 1, 2018	May 15, 2018	$	0.625	$	9
2017
December 31, 2017	February 9, 2018	February 15, 2018	$	0.625	$	9
September 30, 2017	October 31, 2017	November 14, 2017	$	0.625	$	9
June 30, 2017	July 31, 2017	August 14, 2017	$	0.625	$	9
March 31, 2017	May 2, 2017	May 12, 2017	$	0.625	$	9

_____________________

(1)The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 7, 2020, to be paid on February 14, 2020 to Series A Preferred unitholders of record at the close of business on February 7, 2020.

General Partner Interest and Incentive Distribution Rights

Enable GP owns a non-economic general partner interest in the Partnership and, except as provided below with respect to incentive distribution rights, will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from operating surplus (as defined in the Partnership Agreement) in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units that they own.

Expiration of Subordination Period

Prior to the expiration of the subordination period, CenterPoint Energy and OGE Energy held 139,704,916 and 68,150,514 subordinated units, respectively. The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units converted into common units on a one-for-one basis on August 30, 2017. The conversion of the subordinated units did not change the aggregate amount of outstanding units, and the conversion of the subordinated units did not impact the amount of cash available for distribution by the Partnership.

Series A Preferred Units

The Partnership has 14,520,000 Series A Preferred Units, representing limited partner interests in the Partnership, which were issued at a price of $25.00 per Series A Preferred Unit.

Pursuant to the Partnership Agreement, the Series A Preferred Units:

•rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;

•have no stated maturity;

•are not subject to any sinking fund; and

24

Exhibit 99.01

•will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.

Holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis if and when declared by the General Partner, and subject to certain adjustments, equal to an annual rate of: 10% on the stated liquidation preference of $25.00 from the date of original issue to, but not including, the five year anniversary of the original issue date; and thereafter a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5%.

At any time on or after February 18, 2021, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. Following changes of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units. If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement. If under certain circumstances the Series A Preferred Units are not eligible for trading on the New York Stock Exchange, the Series A Preferred Units are required to be redeemed by the Partnership.

In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units at any time following a reduction by any of the ratings agencies in the amount of equity content attributed to the Series A Preferred Units. On July 30, 2019, S&P announced that it was reclassifying the Series A Preferred Units from having 50% equity content to having minimal equity content. S&P’s announcement followed a revision of its criteria for evaluating the amount of equity credit attributable to hybrid securities. As a result the reduction of equity content attributed to the Series A Preferred Units by S&P, the Partnership may redeem the Series A Preferred Units at any time, upon not less than 30 days’ nor more than 60 days’ notice, at a price of $25.50 per Series A Preferred Unit plus an amount equal to all unpaid distributions thereon from the issuance date through the redemption date.

Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law.

Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the Series B Preferred Units) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid.

At the closing of the private placement of Series A Preferred Units, the Partnership entered into a registration rights agreement with CenterPoint Energy, pursuant to which, among other things, CenterPoint Energy has certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units.

ATM Program

On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement in connection with an ATM Program. Pursuant to the ATM Program, the Partnership may issue and sell common units having an aggregate offering price of up to $200 million, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. For the year ended December 31, 2019, the Partnership did not sell any common units under the ATM Program. For the year ended December 31, 2018, the Partnership sold an aggregate of 140,920 common units under the ATM Program, which generated proceeds of approximately $2 million (net of approximately $25,000 of commissions). The proceeds were used for general partnership purposes. As of December 31, 2019, approximately $197 million of common units of aggregate offering price remained available for issuance through the ATM Program.

25

Exhibit 99.01

(8) Property, Plant and Equipment

The Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage reportable segments. Effective January 1, 2019, the new depreciation rates have been applied prospectively as a change in accounting estimate. The new depreciation rates did not result in a material change in depreciation expense or results of operations.

Property, plant and equipment includes the following:

	Weighted Average Useful Lives (Years)	December 31,
		2019		2018
		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	33	$	8,252	$	8,011
Transportation and Storage	39	4,778		4,740
Construction work-in-progress		131		148
Total		$	13,161	$	12,899
Accumulated depreciation:
Gathering and Processing		1,252		1,063
Transportation and Storage		1,039		965
Total accumulated depreciation		2,291		2,028
Property, plant and equipment, net		$	10,870	$	10,871

The Partnership recorded depreciation expense of $371 million, $351 million and $335 million during the years ended December 31, 2019, 2018 and 2017, respectively.

(9) Intangible Assets, Net

The Partnership has intangible assets associated with customer relationships related to the acquisitions of Enogex LLC, Monarch Natural Gas, LLC, ETGP and EOCS as follows:

	December 31,
	2019		2018
	(In millions)
Customer relationships:
Total intangible assets (1)	$	840	$	840
Accumulated amortization	239		177
Net intangible assets	$	601	$	663

____________________

(1)See Note 5 for discussion of the acquisition of EOCS and ETGP during the years ended December 31, 2018 and 2017, respectively.

Intangible assets related to customer relationships have a weighted average useful life of 14 years. Intangible assets do not have any significant residual value or renewal options of existing terms. There are no intangible assets with indefinite useful lives.

The Partnership recorded amortization expense of $62 million, $47 million and $31 million during the years ended December 31, 2019, 2018 and 2017, respectively. The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years:

26

Exhibit 99.01

	2020		2021		2022		2023		2024
	(In millions)
Expected amortization of intangible assets	$	62	$	62	$	62	$	62	$	62

(10) Goodwill

In the fourth quarter of 2017, as a result of the acquisition of ETGP, the Partnership recorded $12 million of goodwill associated with the Ark-La-Tex Basin reporting unit, included in the gathering and processing reportable segment. In the fourth quarter of 2018, as a result of the acquisition of EOCS, the Partnership recorded $86 million of goodwill associated with the Anadarko Basin reporting unit, included in the gathering and processing reportable segment.

The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. During 2019, the crude oil and natural gas industry was impacted by current and forward commodity price declines. Amid such crude oil, natural gas and NGL price declines, producers have been cutting back spending and shifting their focus from emphasizing reserves growth, to increasing net cash flows and reducing outstanding debt, which consequently resulted in a decrease in rig count and in forecasted producer activity in the Anadarko Basin reporting unit during the fourth quarter of 2019. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations have dropped to their lowest levels in the last three years. Due to the continuing decrease in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Anadarko Basin reporting unit would more likely than not be impaired. As a result, the Partnership performed a quantitative test for our annual goodwill impairment analysis as of October 1, 2019, and determined that the carrying value of the Anadarko Basin reporting unit exceeded its fair value and that goodwill associated with the Anadarko Basin reporting unit was completely impaired in the amount of $86 million. The impairment is included in Impairments on the Consolidated Statements of Income for the year ended December 31, 2019.

While the fair value of the Ark-La-Tex Basin reporting unit exceeded its carrying value as of December 31, 2019, a lower fair value estimate and an impairment of the Partnership’s $12 million of goodwill could result from sustained commodity price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions, such as decreased prices in market-based transactions for similar assets. The change in carrying amount of goodwill in each of our reportable segments is as follows:

	Gathering and Processing		Transportation and Storage		Total
	(in millions)
Balance as of December 31, 2017	$	12	$	—	$	12
EOCS Acquisition (1)	86		—		86
Balance as of December 31, 2018	$	98	$	—	$	98
Goodwill impairment	$	(86)	$	—	$	(86)
Balance as of December 31, 2019	$	12	$	—	$	12

_____________________

(1)See Note 5 for further discussion.

(11) Investment in Equity Method Affiliate

The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.

SESH is owned 50% by Enbridge Inc. and 50% by the Partnership for the years ended December 31, 2019 and 2018. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its limited partner interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Enbridge Inc. may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions.

27

Exhibit 99.01

The Partnership shares operations of SESH with Enbridge Inc. under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. During the years ended December 31, 2019, 2018 and 2017, the Partnership billed SESH $17 million, $18 million and $17 million, respectively, associated with these service agreements.

The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017.

SESH:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Equity in Earnings of Equity Method Affiliate	$	17	$	26	$	28
Distributions from Equity Method Affiliate (1)	25		33		33

____________________ 

(1)Distributions from equity method affiliate includes a $17 million, $26 million and $28 million return on investment and a $8 million, $7 million and $5 million return of investment for the years ended December 31, 2019, 2018 and 2017, respectively.

Summarized financial information of SESH:

	December 31,
	2019		2018
	(In millions)
Balance Sheets:
Current assets	$	49	$	30
Property, plant and equipment, net	1,060		1,078
Total assets	$	1,109	$	1,108
Current liabilities	$	30	$	13
Long-term debt	398		397
Members’ equity	681		698
Total liabilities and members’ equity	$	1,109	$	1,108
Reconciliation:
Investment in SESH	$	309	$	317
Less: Capitalized interest on investment in SESH	(1)		(1)
Add: Basis differential, net of amortization	33		33
The Partnership’s share of members’ equity	$	341	$	349

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Income Statements:
Revenues	$	109	$	112	$	113
Operating income	50		67		72
Net income	33		50		54

28

Exhibit 99.01

(12) Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2019 and 2018.

	December 31, 2019						December 31, 2018
	Outstanding Principal		Premium (Discount)(1)		Total Debt		Outstanding Principal		Premium (Discount)(1)		Total Debt
	(In millions)
Commercial Paper	$	155	$	—	$	155	$	649	$	—	$	649
Revolving Credit Facility	—		—		—		250		—		250
2019 Term Loan Agreement	800		—		800		—		—		—
2019 Notes	—		—		—		500		—		500
2024 Notes	600		—		600		600		—		600
2027 Notes	700		(2)		698		700		(2)		698
2028 Notes	800		(5)		795		800		(6)		794
2029 Notes	550		(1)		549		—		—		—
2044 Notes	550		—		550		550		—		550
EOIT Senior Notes	250		1		251		250		7		257
Total debt	$	4,405	$	(7)	$	4,398	$	4,299	$	(1)	$	4,298
Less: Short-term debt (2)					155						649
Less: Current portion of long-term debt (3)					251						500
Less: Unamortized debt expense (4)					23						20
Total long-term debt					$	3,969					$	3,129

___________________

(1)Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.

(2)Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018, respectively.

(3)As of December 31, 2019, Current portion of long-term debt includes the $251 million outstanding balance of the EOIT Senior Notes due March 15, 2020. At December 31, 2018, Current portion of long-term debt included the $500 million outstanding balance of the 2019 Notes due May 15, 2019.

(4)As of December 31, 2019 and 2018, there was an additional $4 million and $6 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.

Maturities of outstanding debt, excluding unamortized premiums (discounts), are as follows (in millions):

2020	$	405
2021	—
2022	800
2023	—
2024	600
Thereafter	$	2,600

Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were $155 million and $649 million outstanding under our commercial paper program at December 31, 2019 and December 31, 2018, respectively. The weighted average interest rate for the outstanding commercial paper was 2.29% as of December 31, 2019.

29

Exhibit 99.01

Revolving Credit Facility

On April 6, 2018, the Partnership amended and restated its Revolving Credit Facility. As amended and restated, the Revolving Credit Facility is a $1.75 billion, five-year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $875 million. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an extension option, which could be exercised two times to extend the term of the Revolving Credit facility, in each case, for an additional one-year term. As of December 31, 2019, there were no principal advances and $3 million in letters of credit outstanding under the restated Revolving Credit Facility.

The Revolving Credit Facility provides that outstanding borrowings bear interest at LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of December 31, 2019, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit ratings. As of December 31, 2019, the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Consolidated Statements of Income.

The Revolving Credit Facility contains a financial covenant requiring us to maintain a ratio of consolidated funded debt to consolidated EBITDA as defined under the Revolving Credit Facility as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for any three fiscal quarters including and following any fiscal quarter in which the aggregate value of one or more acquisitions by us or certain of our subsidiaries with a purchase price of at least $25 million in the aggregate, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00.

The Revolving Credit Facility also contains covenants that restrict us and certain subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the Revolving Credit Facility), restricted payments, changes in the nature of their respective businesses and entering into certain restrictive agreements. Borrowings under the Revolving Credit Facility are subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured money judgments in excess of $100 million and the occurrence of certain ERISA and bankruptcy events, subject where applicable to specified cure periods.

2019 Term Loan Agreement

On January 29, 2019, the Partnership entered into an unsecured term loan agreement with Bank of America, N.A., as administrative agent, and the several lenders thereto. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to two times, to extend the maturity date for an additional one-year term, subject to lender approval. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of December 31, 2019, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was 1.25% based on the Partnership’s credit ratings. As of December 31, 2019, the weighted average interest rate of the 2019 Term Loan Agreement was 3.10%.

Prior to the expiration of the availability period for advances on July 26, 2019, the Partnership drew $1 billion in advances under the Term Loan Agreement, which were used for general partnership purposes and repayment of the 2019 Notes. Advances under the 2019 Term Loan Agreement can be prepaid, in whole or in part, at any time without premium or penalty, other than usual and customary LIBOR breakage costs, if applicable. On September 16, 2019, the Partnership prepaid $200 million of the advances under the Term Loan Agreement, the repayment of which was not subject to LIBOR breakage costs. As of December 31, 2019, there was $800 million outstanding under the 2019 Term Loan Agreement.

The 2019 Term Loan Agreement contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to consolidated EBITDA as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for a certain period time following an acquisition by the Partnership or certain of its subsidiaries with a purchase price that when combined with the aggregate purchase price for all other such acquisitions in any rolling 12-month period, is

30

Exhibit 99.01

equal to or greater than $25 million, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00.

The 2019 Term Loan Agreement also contains covenants that restrict the Partnership and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the 2019 Term Loan Agreement), restricted payments, changes in the nature of their respective business and entering into certain restrictive agreements. The 2019 Term Loan Agreement is subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured judgments in excess of $100 million, and the occurrence of certain ERISA and bankruptcy events, subject, where applicable, to specified cure periods.

Senior Notes

On September 13, 2019, the Partnership completed the public offering of $550 million aggregate principal amount of its 4.150% Senior Notes due 2029. The Partnership received net proceeds of approximately $544 million, after deducting the underwriting discount and offering expenses. The net proceeds were used to repay $200 million of borrowings outstanding under the 2019 Term Loan Agreement, to repay amounts outstanding under the commercial paper program, and for general partnership purposes. The 2029 Notes had an unamortized discount of $1 million and unamortized debt expense of $5 million at December 31, 2019, resulting in an effective interest rate of 4.31% from the issue date through December 31, 2019.

As of December 31, 2019, the Partnership’s debt also included the 2024 Notes, 2027 Notes, 2028 Notes and 2044 Notes, which had $7 million of unamortized discount and $18 million of unamortized debt expense at December 31, 2019, resulting in effective interest rates of 4.01%, 4.57%, 5.20% and 5.08%, respectively, during the year ended December 31, 2019. In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement.

The indenture governing the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes contains certain restrictions, including, among others, limitations on our ability and the ability of our principal subsidiaries to: (i) consolidate or merge and sell all or substantially all of our and our subsidiaries’ assets and properties; (ii) create, or permit to be created or to exist, any lien upon any of our or our principal subsidiaries’ principal property, or upon any shares of stock of any principal subsidiary, to secure any debt; and (iii) enter into certain sale-leaseback transactions. These covenants are subject to certain exceptions and qualifications.

As of December 31, 2019, the Partnership’s debt included EOIT’s Senior Notes. The EOIT Senior Notes had $1 million of unamortized premium at December 31, 2019, resulting in an effective interest rate of 3.84% during the year ended December 31, 2019. These senior notes do not contain any financial covenants other than a limitation on liens. This limitation on liens is subject to certain exceptions and qualifications.

As of December 31, 2019, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

(13) Derivative Instruments and Hedging Activities

The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivative instruments are commodity price and interest rate risks. The Partnership is also exposed to credit risk in its business operations.

Commodity Price Risk

The Partnership uses forward physical contracts, commodity price swap contracts and commodity price option features to manage its commodity price risk exposures. Commodity derivative instruments used by the Partnership are as follows:

•NGL put options, NGL futures and swaps, and WTI crude oil futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;

•natural gas futures and swaps, natural gas options, natural gas swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas price exposure associated with its gathering, processing, transportation and storage assets, contracts and asset management activities.

31

Exhibit 99.01

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by its gathering and processing business.

The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and are recorded as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement.

As of December 31, 2019 and 2018, the Partnership had no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Interest Rate Risk

The Partnership uses interest rate swap contracts to manage its interest rate risk exposures. The Partnership recognizes its interest rate derivative instruments as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. The Partnership’s interest rate swap contracts are designated as cash flow hedging instruments for accounting purposes. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized currently in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period the hedged transaction affects earnings. As of December 31, 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes. As of December 31, 2018, the Partnership had no outstanding interest rate derivative instruments.

Credit Risk

Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may seek or be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.

Derivatives Not Designated as Hedging Instruments

Derivative instruments not designated as hedging instruments for accounting purposes are utilized to manage the Partnership’s exposure to commodity price risk. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments Not Designated as Hedging Instruments

The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments.

32

Exhibit 99.01

As of December 31, 2019 and 2018, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

	December 31, 2019		December 31, 2018
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps	10	19	16	28
Financial basis futures/swaps	11	30	18	29
Financial swaptions (2)	—	2	—	1
Physical purchases/sales	—	6	—	11
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	—	990	—	945
Financial swaptions (2)	—	225	—	30
Natural gas liquids— MBbl (4)
Financial futures/swaps	2,490	2,415	270	2,535

____________________

(1)As of December 31, 2019December 31, 2019, 86.6% of the natural gas contracts had durations of one year or less and 13.4% had durations of more than one year and less than two years. As of December 31, 2018, 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more than two years.

(2)The notional value contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.

(3)As of December 31, 2019, 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% had durations of more than one year and less than two years. As of December 31, 2018, 76.9% of the crude oil (for condensate) contracts had durations of one year or less and 23.1% had durations of more than one year and less than two years.

(4)As of December 31, 2019, 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years. As of December 31, 2018, 86.1% of the natural gas liquids contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years.

Derivatives Designated as Hedging Instruments

Derivative instruments designated as hedging instruments for accounting purposes are utilized in managing the Partnership’s interest rate risk exposures.

Quantitative Disclosures Related to Derivative Instruments Designated as Hedging Instruments

The derivative instruments designated as hedges for accounting purposes are interest rate derivative instruments priced on monthly interest rates.

As of December 31, 2019 and December 31, 2018, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:

	December 31, 2019		December 31, 2018
	Gross Notional Value
	(In millions)
Interest rate swaps	$	300	$	—

33

Exhibit 99.01

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets at December 31, 2019 and 2018 that were not designated as hedging instruments for accounting purposes are as follows:

		December 31, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	7	$	5	$	3	$	5
Financial futures/swaps	Other	—		1		—		2
Physical purchases/sales	Other Current	5		—		3		—
Physical purchases/sales	Other	—		—		4		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	1		19		9		3
Financial futures/swaps	Other	—		8		2		—
Natural gas liquids
Financial futures/swaps	Other Current	25		3		10		1
Financial futures/swaps	Other	11		2		2		—
Total gross derivatives (1)		$	49	$	38	$	33	$	11

_____________________

(1)See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018.

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018 that were designated as hedging instruments for accounting purposes are as follows:

		December 31, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Interest rate swaps	Other Current	$	—	$	1	$	—	$	—
Interest rate swaps	Other	—		2		—		—
Total gross interest rate derivatives (1)		$	—	$	3	$	—	$	—

_____________________

(1)All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2019.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017:

34

Exhibit 99.01

	Amounts Recognized in Income
	Year Ended December 31,
	2019		2018		2017
	(In millions)
Natural Gas
Financial futures/swaps gains (losses)	$	13	$	(8)	$	20
Physical purchases/sales gains	2		7		9
Crude oil (for condensate)
Financial futures/swaps (losses) gains	(41)		6		(1)
Natural gas liquids
Financial futures/swaps gains (losses)	42		6		(9)
Total	$	16	$	11	$	19

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2019, 2018 and 2017 are reported in Product sales. For derivatives designated as hedges, amounts recognized in income and reported in Interest expense for the year ended December 31, 2019 were approximately zero.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017: 

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Change in fair value of derivatives	$	(11)	$	26	$	28
Realized gain (loss) on derivatives	27		(15)		(9)
Gain on derivative activity	$	16	$	11	$	19

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s or S&P were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters or credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of December 31, 2019, under these obligations, the Partnership has posted no cash collateral related to natural gas swaps and swaptions, crude oil swaps and swaptions, and NGL swaps and no additional collateral would be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating. In certain situations where the Partnership’s credit rating is lowered by Moody’s or S&P, the Partnership could be subject to an early termination event related to certain derivative instruments, which could result in a cash settlement of the instruments at market values on the date of such early termination.

(14) Fair Value Measurements

Certain assets and liabilities are recorded at fair value in the Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on either the NYMEX or the ICE and settled through either a NYMEX or ICE clearing broker.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 generally include over-the-counter natural gas swaps, natural gas swaptions, natural gas basis swaps and natural gas

35

Exhibit 99.01

purchase and sales transactions in markets such that the pricing is closely related to the NYMEX or the ICE pricing, over-the-counter WTI crude oil swaps and swaptions for condensate sales, and over-the-counter interest rate swaps traded in observable markets with less volume and transaction frequency than active markets. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.

The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX, ICE or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX or ICE published market prices may be considered Level 1 if they are settled through a NYMEX or ICE clearing broker account with daily margining. Over-the-counter derivatives with NYMEX, ICE or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. Certain derivatives with option features may be classified as Level 2 if valued using an industry standard Black-Scholes option pricing model that contain observable inputs in the marketplace throughout the term of the derivative instrument. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3. As of December 31, 2019, there were no contracts classified as Level 3.

The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the year ended December 31, 2019, there were no transfers between levels.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on S& P’s and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at December 31, 2019 and 2018:

	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$	—	$	—	$	250	$	250
2019 Term Loan Agreement (Level 2)	800		800		—		—
2019 Notes (Level 2)	—		—		500		497
2024 Notes (Level 2)	600		614		600		571
2027 Notes (Level 2)	698		698		698		642
2028 Notes (Level 2)	795		811		794		764
2029 Notes (Level 2)	549		526		—		—
2044 Notes (Level 2)	550		506		550		445
EOIT Senior Notes (Level 2)	251		252		257		256

______________________

36

Exhibit 99.01

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $155 million and $649 million of commercial paper was outstanding as of December 31, 2019 and 2018, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2019 Notes, 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes, 2044 Notes, and EOIT Senior Notes, is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of December 31, 2019, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

Based upon review of forecasted undiscounted cash flows as of December 31, 2019, all of the asset groups were considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions could reduce forecasted undiscounted cash flows.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

As of December 31, 2019, the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments. The following tables summarize the Partnership’s other assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2019 and December 31, 2018:

December 31, 2019	Commodity Contracts				Gas Imbalances (1)
	Assets		Liabilities		Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	5	$	31	$	—	$	—
Significant other observable inputs (Level 2)	44		7		14		11
Unobservable inputs (Level 3)	—		—		—		—
Total fair value	49		38		14		11
Netting adjustments	(37)		(37)		—		—
Total	$	12	$	1	$	14	$	11

December 31, 2018	Commodity Contracts				Gas Imbalances (1)
	Assets		Liabilities		Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	4	$	9	$	—	$	—
Significant other observable inputs (Level 2)	29		2		18		17
Unobservable inputs (Level 3)	—		—		—		—
Total fair value	33		11		18		17
Netting adjustments	(9)		(9)		—		—
Total	$	24	$	2	$	18	$	17

37

Exhibit 99.01

______________________

(1)The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. There were no netting adjustments as of December 31, 2019 and 2018.

(2)Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $21 million and $11 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(3)Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $8 million and $5 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Changes in Level 3 Fair Value Measurements

The following tables provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented. Transfers out of Level 3 represent liabilities that were previously classified as Level 3 for which the inputs became observable for classification in Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Partnership’s derivative contracts is subject to change.

	Commodity Contracts
	Natural gas liquids financial futures/swaps
	(In millions)
Balance as of December 31, 2017	$	(5)
Losses included in earnings	(23)
Settlements	7
Transfers out of Level 3	21
Balance as of December 31, 2018	$	—

For the year ended December 31, 2019, there were no Level 3 commodity contracts.

(15)Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	185	$	148	$	114
Income taxes, net of refunds	1		3		—
Non-cash transactions:
Accounts payable related to capital expenditures	10		54		39
Lease liabilities arising from the application of ASC 842	45		—		—

38

Exhibit 99.01

The following table reconciles cash and cash equivalents and restricted cash on the Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows:

	December 31,
	2019		2018
	(In millions)
Cash and cash equivalents	$	4	$	8
Restricted cash	—		14
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows	$	4	$	22

As of December 31, 2018, Restricted cash included $14 million of cash collateral which was provided by a third party as credit assurance. The cash collateral was released in 2019.

39

Exhibit 99.01

(16) Related Party Transactions

The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.

Transportation and Storage Agreements

Transportation and Storage Agreements with CenterPoint Energy

EGT provides natural gas transportation and storage services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas under a combination of contracts that include the following types of services: firm transportation, firm transportation with seasonal demand, firm storage, firm no-notice transportation with storage and maximum rate firm transportation. The term of these contracts is through March 31, 2021. MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. Contracts for these services are in effect through May 15, 2023 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.

The Partnership may agree to reimburse the costs that its customers incur to make required modifications for the repair and maintenance of pipelines that impact customer delivery points. For the years ended December 31, 2019 and 2018, we reimbursed CenterPoint Energy’s LDCs $2 million and $1 million, respectively, in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines and in connection with a reimbursement associated with an unplanned pipeline outage. For the year ended December 31, 2017, we reimbursed CenterPoint Energy’s LDCs $1 million in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines.

Transportation and Storage Agreement with OGE Energy

EOIT provides no-notice load-following transportation and storage services to four of OGE Energy’s generating facilities. Service is provided to three generating facilities under a transportation agreement with a primary term of April 1, 2019 through May 1, 2024, which will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. Service is provided to one additional generating facility in Muskogee, Oklahoma under a transportation agreement with a primary term of December 1, 2018 through December 1, 2038. EOIT has agreed to pay OGE Energy $2 million and to waive $5 million of demand fee charges as a result of damage that occurred to the Muskogee facility during commissioning as a result of the failure of certain filters on the connected transportation pipeline, which is included in the Partnership’s results of operations as of December 31, 2019.

Gas Sales and Purchases Transactions

The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchases natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices.

The Partnership’s revenues from affiliated companies accounted for 6%, 5% and 5% of total revenues during the years ended December 31, 2019, 2018 and 2017, respectively. Amounts of total revenues from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$	108	$	111	$	110
Natural gas product sales — CenterPoint Energy	8		11		6
Gas transportation and storage service revenues — OGE Energy	41		37		35
Natural gas product sales — OGE Energy	10		4		2
Total revenues — affiliated companies	$	167	$	163	$	153

40

Exhibit 99.01

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	3	$	1
Cost of natural gas purchases — OGE Energy	33		23		19
Total cost of natural gas purchases — affiliated companies	$	33	$	26	$	20

Corporate services, operating lease expense and seconded employee

The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate these services agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2019 are $1 million and $1 million, respectively.

The Partnership leased office and data center space from an affiliate of CenterPoint Energy in Shreveport, Louisiana. The term of the lease was effective on October 1, 2016 and ended on December 31, 2019.

During the years ended December 31, 2019, 2018 and 2017, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of $5 million in 2019 and thereafter, unless and until secondment is terminated.

Amounts charged to the Partnership by affiliates for corporate services, operating lease and seconded employees, are primarily included in Operation and maintenance expenses and General and administrative expenses in the Partnership’s Consolidated Statements of Income are as follows:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Corporate Services — CenterPoint Energy	$	—	$	1	$	3
Operating Lease — CenterPoint Energy	1		1		1
Seconded Employee Costs — OGE Energy	18		29		31
Corporate Services — OGE Energy	—		1		3
Total corporate services, operating lease and seconded employee expense	$	19	$	32	$	38

(17) Commitments and Contingencies

Commercial Obligations

On January 1, 2017, the Partnership entered into a 10-year gathering and processing agreement, which became effective on July 1, 2018, with an affiliate of Energy Transfer, LP for 400 MMcf/d of deliveries to the Godley Plant in Johnson County, Texas. As of December 31, 2019, the Partnership estimates the remaining associated minimum volume commitment fee to be $192 million in the aggregate. Minimum volume commitment fees are expected to be $23 million per year from 2020 through 2027 and $11 million in 2028.

On September 13, 2018, the Partnership executed a precedent agreement for the development of the Gulf Run Pipeline, an interstate natural gas transportation project. On January 30, 2019, a final investment decision was made by Golden Pass LNG,

41

Exhibit 99.01

the cornerstone shipper for the LNG facility to be served by the Gulf Run Pipeline project. Subject to approval of the project by FERC, the Partnership will be required to construct a large-diameter pipeline from northern Louisiana to Gulf Coast markets. In addition, the Partnership may transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project would be as much as $500 million and the project is backed by a 20-year firm transportation service. The Gulf Run Pipeline connects natural gas producing regions in the U.S., including the Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in 2022.

On September 23, 2019, the Partnership entered into an agreement to sell its undivided 1/12th interest in the Bistineau Storage Facility in Louisiana for approximately $19 million. Until such time as the sale closes, the Partnership will continue to utilize this facility to provide storage services to its customers. On January 27, 2020, FERC approved the sale. The Partnership anticipates closing the sale on April 1, 2020.

Legal, Regulatory and Other Matters

The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

(18) Income Taxes

The Partnership’s earnings are generally not subject to income tax ( and are taxable at the individual partner level. The Partnership and its non-corporate subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the consolidated financial statements. Consequently, the Consolidated Statements of Income do not include an income tax provision (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary). On December 22, 2017, the act known as the “Tax Cuts and Jobs Act,” was signed into law which lowered the corporate tax rate from 35% to 21% for tax years beginning after December 31, 2017. As a result of this new law, the Partnership’s corporate subsidiaries re-valued their deferred income tax assets and liabilities as of December 31, 2017, which resulted in recording a federal deferred income tax benefit of $1 million for the year ended December 31, 2017.

The items comprising income tax expense are as follows:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Provision for current income taxes
Federal	$	—	$	—	$	1
State	—		—		1
Total provision for current income taxes	—		—		2
Benefit for deferred income taxes, net
Federal	$	(1)	$	(1)	$	(2)
State	—		—		(1)
Total benefit for deferred income taxes, net	(1)		(1)		(3)
Total income tax benefit	$	(1)	$	(1)	$	(1)

42

Exhibit 99.01

The components of Deferred Income Taxes as of December 31, 2019 and 2018 were as follows:

	December 31,
	2019		2018
	(In millions)
Deferred tax liabilities, net:
Non-current:
Intercompany management fee	$	17	$	16
Depreciation	6		5
Accrued compensation	(19)		(16)
Total deferred tax liabilities, net	$	4	$	5

Uncertain Income Tax Positions

There were no unrecognized tax benefits as of December 31, 2019, 2018 and 2017.

Tax Audits and Settlements

The federal income tax return of the Partnership has been audited through the 2013 tax year.

(19) Equity-Based Compensation

Enable GP has adopted the Enable Midstream Partners, LP Long Term Incentive Plan (LTIP) for officers, directors and employees of the Partnership and its affiliates, including any individual who provides services to the Partnership as a seconded employee. The LTIP provides for the following types of awards: restricted units, phantom units, appreciations rights, option rights, cash incentive awards, performance units, distribution equivalent rights, and other awards denominated in, payable in, valued in or otherwise based on or related to common units.

The LTIP is administered by the Compensation Committee of the Board of Directors. With respect to any grant of equity as long-term incentive awards to our independent directors and our officers subject to reporting under Section 16 of the Exchange Act, the Compensation Committee makes recommendations to the Board of Directors and any such awards will only be effective upon the approval of the Board of Directors. The LTIP limits the number of units that may be delivered pursuant to vested awards to 13,100,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units cancelled, forfeited, expired or cash settled are available for delivery pursuant to other awards.

The Board of Directors may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made, including amending the long-term incentive plan to increase the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would be adverse to the participant without the consent of the participant.

Performance unit, restricted unit and phantom unit awards are classified as equity on the Partnership’s Consolidated Balance Sheet. The following table summarizes the Partnership’s equity-based compensation expense for the years ended December 31, 2019, 2018 and 2017 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Performance units	$	9	$	9	$	10
Restricted units	—		1		2
Phantom units	7		6		3
Total equity-based compensation expense	$	16	$	16	$	15

43

Exhibit 99.01

Performance Units

Awards of performance based phantom units (performance units) have been made under the LTIP in 2019, 2018 and 2017 to certain officers and employees providing services to the Partnership. Subject to the achievement of performance goals, the performance unit awards cliff vest three years from the grant date, with distribution equivalent rights paid at vesting. The performance goals for 2019, 2018 and 2017 awards are based on total unitholder return over a three-calendar year performance cycle. Total unitholder return is based on the relative performance of the Partnership’s common units against a peer group. The performance unit awards have a payout from zero to 200% of the target based on the level of achievement of the performance goal. Performance unit awards are paid out in common units, with distribution equivalent rights paid in cash at vesting. Any unearned performance units are cancelled. Pay out requires the confirmation of the achievement of the performance level by the Compensation Committee. Prior to vesting, performance units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control. In the event of retirement, a participant will receive a prorated payment based on the target performance or a prorated payment based on the actual performance of the performance goals during the award cycle, based on the grant year.

The fair value of each performance unit award was estimated on the grant date using a lattice-based valuation model. The valuation information factored into the model includes the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition over the expected life of the performance units. Equity-based compensation expense for each performance unit award is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Distributions are accumulated and paid at vesting and, therefore, are included in the fair value calculation of the performance unit award. The expected price volatility for the awards granted in 2019, 2018 and 2017 is based on three years of daily stock price observations, to determine the total unitholder return ranking. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. There are no post-vesting restrictions related to the Partnership’s performance units.

The number of performance units granted based on total unitholder return and the assumptions used to calculate the grant date fair value of the performance units based on total unitholder return are shown in the following table.

	2019			2018			2017
Number of units granted	638,798			551,742			468,626
Fair value of units granted	$	19.95		$	17.70		$	19.27
Expected price volatility	34.2		%	44.2		%	47.3		%
Risk-free interest rate	2.54		%	2.36		%	1.57		%
Distribution yield	8.38		%	8.56		%	9.10		%
Expected life of units (in years)	3			3			3

Phantom Units

Awards of phantom units have been made under the LTIP in 2019, 2018 and 2017 to certain officers and employees providing services to the Partnership. Except for Phantom units granted to retirement eligible employees, which vest in annual tranches, phantom units cliff-vest on the first, second or third anniversary of the grant date with distribution equivalent rights paid during the vesting period. Phantom unit awards are paid out in common units, with distribution equivalent rights paid in cash. Any unearned phantom units are cancelled. Prior to vesting, phantom units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control.

The fair value of the phantom units was based on the closing market price of the Partnership’s common unit on the grant date. Equity-based compensation expense for the phantom unit is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over the vesting period. Distributions on phantom units are paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the phantom unit is based on the applicable vesting period. The number of phantom units granted and the grant date fair value are shown in the following table.

	2019	2018	2017
Phantom units granted	695,486	546,708	392,338
Fair value of phantom units granted	$8.95 - $15.04	$13.74 - $17.00	$15.44 - $16.93

44

Exhibit 99.01

Other Awards

In 2019, 2018 and 2017, the Board of Directors granted common units to the independent directors of Enable GP, for their service as directors, which vested immediately. The fair value of the common units was based on the closing market price of the Partnership’s common unit on the grant date.

	2019		2018		2017
Common units granted	28,221		16,335		16,653
Fair value of common units granted	$	10.43	$	14.94	$	15.03

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 2019 and changes during 2019 are shown in the following table.

	Performance Units				Phantom Units
	Number of Units		Weighted Average Grant-Date Fair Value, Per Unit		Number of Units		Weighted Average Grant-Date Fair Value, Per Unit
	(In millions, except unit data)
Units outstanding at 12/31/2018	2,109,835		$	14.33	1,447,590		$	12.38
Granted (1)	638,798		19.95		695,486		14.26
Vested (2)(3)	(1,174,597)		11.09		(608,755)		8.71
Forfeited	(180,707)		18.96		(141,761)		14.89
Units outstanding at 12/31/2019	1,393,329		19.04		1,392,560		14.65
Aggregate intrinsic value of units outstanding at December 31, 2019	$	14			$	14

_____________________

(1)For performance units, this represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.

(2)Performance units vested as of December 31, 2019 include 1,097,846 and 26,986 units from 2016 grants, which were approved by the Board of Directors in 2016 and paid out at 200%, or 2,195,692 units on March 1, 2019 and 53,972 units on September 6, 2019, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2016 through December 31, 2018.

(3)Performance units outstanding as of December 31, 2019 include 378,109 units from the 2017 annual grants, which were approved by the Board of Directors in 2017 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2017 through December 31, 2019, will not vest. The decrease in outstanding units for a payout percentage of an amount other than 100% is not reflected above until the vesting date.

A summary of the Partnership’s performance, restricted and phantom units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for each of the years ended December 31, 2019, 2018 and 2017 are shown in the following tables.

	Year Ended December 31, 2019
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate intrinsic value of units vested	$	34	$	—	$	9
Fair value of units vested	13		—		5

	Year Ended December 31, 2018
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate intrinsic value of units vested	$	11	$	3	$	1
Fair value of units vested	7		4		—

45

Exhibit 99.01

	Year Ended December 31, 2017
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate intrinsic value of units vested	$	5	$	2	$	—
Fair value of units vested	10		4		—

Unrecognized Compensation Expense

A summary of the Partnership’s unrecognized compensation expense for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

	December 31, 2019
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	12	1.32
Phantom Units	9		1.24
Total	$	21

As of December 31, 2019, there were 6,353,205 units available for issuance under the long-term incentive plan.

(20) Reportable Segments

The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies described in Note 1. The Partnership uses operating income as the measure of profit or loss for its reportable segments.

The Partnership’s assets and operations are organized into two

Financial data for reportable segments are as follows:

Year Ended December 31, 2019	Gathering and Processing		Transportation and Storage (1)		Eliminations		Total
	(In millions)
Product sales	$	1,449	$	487	$	(403)	$	1,533
Service revenues	889		551		(13)		1,427
Total Revenues	2,338		1,038		(416)		2,960
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately	1,203		491		(415)		1,279
Operation and maintenance, General and administrative	320		207		(1)		526
Depreciation and amortization	308		125		—		433
Impairments	86		—		—		86
Taxes other than income tax	41		26		—		67
Operating Income	$	380	$	189	$	—	$	569
Total Assets	$	9,739	$	5,886	$	(3,359)	$	12,266
Capital expenditures	$	314	$	118	$	—	$	432

46

Exhibit 99.01

Year Ended December 31, 2018	Gathering and Processing		Transportation and Storage (1)		Eliminations		Total
	(In millions)
Product sales	$	2,016	$	625	$	(535)	$	2,106
Service revenues	802		537		(14)		1,325
Total Revenues	2,818		1,162		(549)		3,431
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately	1,741		628		(550)		1,819
Operation and maintenance, General and administrative	312		189		—		501
Depreciation and amortization	263		135		—		398
Impairments	—		—		—		—
Taxes other than income tax	38		27		—		65
Operating Income	$	464	$	183	$	1	$	648
Total Assets	$	9,874	$	5,805	$	(3,235)	$	12,444
Capital expenditures, including acquisitions	$	981	$	190	$	—	$	1,171

Year Ended December 31, 2017	Gathering and Processing		Transportation and Storage (1)		Eliminations		Total
	(In millions)
Product sales	$	1,538	$	621	$	(506)	$	1,653
Service revenues	632		525		(7)		1,150
Total Revenues	2,170		1,146		(513)		2,803
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately	1,285		604		(508)		1,381
Operation and maintenance, General and administrative	289		179		(4)		464
Depreciation and amortization	232		134		—		366
Impairments	—		—		—		—
Taxes other than income tax	37		27		—		64
Operating Income	$	327	$	202	$	(1)	$	528
Total Assets	$	9,079	$	5,616	$	(3,102)	$	11,593
Capital expenditures	$	601	$	113	$	—	$	714

_____________________

(1)Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income and is not included in the table above. See Note 11 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage reportable segment for the years ended December 31, 2019, 2018 and 2017.

47

Exhibit 99.01

(21) Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2019 and 2018 are as follows:

	Quarters Ended
	March 31, 2019		June 30, 2019		September 30, 2019		December 31, 2019
	(in millions, except per unit data)
Total Revenues	$	795	$	735	$	699	$	731
Cost of natural gas and natural gas liquids	378		317		263		321
Operating income (1)	165		167		175		62
Net income	123		124		133		20
Net income attributable to limited partners	122		124		132		18
Net income attributable to common units	113		115		123		9
Basic earnings per unit
Common units	$	0.26	$	0.26	$	0.28	$	0.02
Diluted earnings per unit
Common units	$	0.26	$	0.26	$	0.28	$	0.02
	Quarters Ended
	March 31, 2018		June 30, 2018		September 30, 2018		December 31, 2018
	(in millions, except per unit data)
Total Revenues	$	748	$	805	$	928	$	950
Cost of natural gas and natural gas liquids	375		444		516		484
Operating income	139		126		171		212
Net income	114		95		139		175
Net income attributable to limited partners	114		95		138		174
Net income attributable to common units	105		86		129		165
Basic earnings per unit
Common Units	$	0.24	$	0.20	$	0.30	$	0.38
Diluted earnings per unit
Common Units	$	0.24	$	0.20	$	0.30	$	0.38

_____________________

(1)The Partnership recorded an impairment to goodwill of $86 million during the fourth quarter related to the Anadarko Basin reporting unit, included in the gathering and processing reportable segment. See Note 10 for further information.

48

XML

Income Taxes

12 Months Ended

Dec. 31, 2019

Income Taxes [Abstract]

Income Tax Disclosure [Text Block]

Income Taxes

Income Tax Expense (Benefit)

The items comprising income tax expense (benefit) are as follows: 

Year Ended December 31 (In millions)	2019		2018		2017
Provision (benefit) for current income taxes:
Federal	$	(6.4)	$	(1.9)	$	4.9
State	5.1		(4.4)		(4.2)
Total provision (benefit) for current income taxes	(1.3)		(6.3)		0.7
Provision (benefit) for deferred income taxes, net:
Federal	48.5		74.7		(75.9)
State	(17.4)		3.7		26.0
Total provision (benefit) for deferred income taxes, net	31.1		78.4		(49.9)
Deferred federal investment tax credits, net	—		0.1		(0.1)
Total income tax expense (benefit)	$	29.8	$	72.2	$	(49.3)

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal tax or state and local examinations by tax authorities for years prior to 2016. 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. Additionally, OG&E earns federal tax credits associated with production from its wind facilities. Oklahoma production and investment state tax credits are also earned on investments in electric and solar generating facilities which further reduce OG&E's effective tax rate.

The following schedule reconciles the statutory tax rates to the effective income tax rate:

Year Ended December 31	2019		2018		2017
Statutory federal tax rate	21.0	%	21.0	%	35.0	%
Executive compensation limitation	0.2		0.2		—
Federal renewable energy credit (A)	(6.0)		(5.1)		(4.8)
Amortization of net unfunded deferred taxes	(4.5)		(2.1)		0.7
State income taxes, net of federal income tax benefit	(1.2)		0.4		2.0
Stock-based compensation	(1.2)		—		—
Remeasurement of state deferred tax liabilities	(0.8)		(0.4)		0.4
Other	(0.7)		0.4		(0.1)
401(k) dividends	(0.4)		(0.3)		(0.5)
Federal deferred tax revaluation	—		0.4		(41.2)
Federal investment tax credits, net	—		—		(0.1)
Effective income tax rate	6.4	%	14.5	%	(8.6)	%

(A)Represents credits associated with the production from OG&E's wind farms.

The deferred tax provisions are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E. The components of Deferred Income Taxes at December 31, 2019 and 2018 were as follows:

December 31 (In millions)	2019		2018
Deferred income tax liabilities, net:
Accelerated depreciation and other property related differences	$	1,656.8	$	1,605.3
Investment in Enable	478.2		469.9
Regulatory assets	28.4		17.4
Company Pension Plan	4.1		7.6
Bond redemption-unamortized costs	2.2		2.4
Derivative instruments	1.6		1.7
Other	0.4		1.1
Federal tax credits	(238.0)		(237.8)
Income taxes recoverable from customers, net	(229.9)		(239.6)
State tax credits	(185.8)		(156.0)
Regulatory liabilities	(68.1)		(78.8)
Postretirement medical and life insurance benefits	(23.3)		(23.6)
Asset retirement obligations	(19.2)		(21.5)
Net operating losses	(16.6)		(20.2)
Accrued liabilities	(10.7)		(12.5)
Accrued vacation	(2.1)		(2.3)
Deferred federal investment tax credits	(1.8)		(1.8)
Uncollectible accounts	(0.4)		(0.4)
Total deferred income tax liabilities, net	$	1,375.8	$	1,310.9

As of December 31, 2019, the Company has classified $16.4 million of unrecognized tax benefits as a reduction of deferred tax assets recorded. Management is currently unaware of any issues under review that could result in significant additional payments, accruals or other material deviation from this amount.

Following is a reconciliation of the Company's total gross unrecognized tax benefits as of the years ended December 31, 2019, 2018 and 2017.

(In millions)	2019		2018		2017
Balance at January 1	$	20.7	$	20.7	$	20.7
Tax positions related to current year:
Additions	—		—		—
Balance at December 31	$	20.7	$	20.7	$	20.7

As of each of December 31, 2019, 2018 and 2017, there were $16.4 million of unrecognized tax benefits that, if recognized, would affect the annual effective tax rate.

Where applicable, the Company classifies income tax-related interest and penalties as interest expense and other expense, respectively. During the year ended December 31, 2019, there were no income tax-related interest or penalties recorded with regard to uncertain tax positions.

The Company sustained federal and state tax operating losses through 2012 caused primarily by bonus depreciation and other book versus tax temporary differences. As a result, the Company had accrued federal and state income tax benefits carrying into 2017, when the remaining federal net operating loss was utilized. State operating losses are being carried forward for utilization in future years. In addition to the tax operating losses, the Company was unable to utilize the various tax credits that were generated during these years. These tax losses and credits are being carried as deferred tax assets and will be utilized in future periods. Under current law, the Company anticipates future taxable income will be sufficient to utilize remaining losses and credits before they begin to expire after 2020. The following table summarizes these carry forwards:

(In millions)	Carry Forward Amount		Deferred Tax Asset		Earliest Expiration Date
State operating loss	$	371.6	$	16.6	2030
Federal tax credits	$	238.0	$	238.0	2032
State tax credits:
Oklahoma investment tax credits	$	183.9	$	145.3	N/A
Oklahoma capital investment board credits	$	12.4	$	12.4	N/A
Oklahoma zero emission tax credits	$	34.9	$	28.0	2020
Louisiana inventory credits	$	0.2	$	0.1	2020

N/A - not applicable

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Summary of Significant Accounting Policies

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 Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.

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

The natural gas midstream operations segment represents the Company's investment in Enable through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is 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. Enable's 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.

The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and Enable are assigned as such. Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method. The "Distrigas" method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. The Company adopted this method as a result of a recommendation by the OCC Staff. The Company believes this method provides a reasonable basis for allocating common expenses.

Use of Estimates

In preparing the 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 Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Changes to these assumptions and estimates could have a material effect on the Company's 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 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.

Cash and Cash Equivalents

For purposes of the Consolidated Financial Statements, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.

Allowance for Uncollectible Accounts Receivable

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate, which is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable in the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense in the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $1.5 million and $1.7 million at December 31, 2019 and 2018, respectively.

New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers whose outside credit scores indicate an elevated risk are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored, and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.

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 December 31, 2019 as presented in Note 14. 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 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 Consolidated Statements of Cash Flows.

Allowance for Funds Used During Construction

Allowance for funds used during construction, a non-cash item, is reflected as an increase to Net Other Income and a reduction to Interest Expense in the Consolidated Statements of Income and as an increase to Construction Work in Progress in the Consolidated Balance Sheets. Allowance for funds used during construction is calculated according to the FERC requirements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction rates, compounded semi-annually, were 7.6 percent, 7.6 percent and 8.2 percent for the years ended December 31, 2019, 2018 and 2017, respectively.

Collection of Sales Tax

In the normal course of its operations, OG&E collects sales tax from its customers. OG&E records a current liability for sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. OG&E excludes the sales tax collected from its operating revenues.

Revenue Recognition

General

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

Integrated Market and Transmission

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

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

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

Other Revenues

Revenues from Alternative Revenue Programs

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

Fuel Adjustment Clauses

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.

LeasesThe Company evaluates all contracts under ASC 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 ASC 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.

Income Taxes

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. 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. The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company recognizes interest related to unrecognized tax benefits in Interest Expense and recognizes penalties in Other Expense in the Consolidated Statements of Income.

Accrued Vacation

The Company accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned but not taken.

Comprehensive Income (Loss) Note [Text Block]

Accumulated Other Comprehensive Income (Loss)

The following tables summarize changes in the components of accumulated other comprehensive income (loss) attributable to the Company during 2018 and 2019. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan		Postretirement Benefit Plans
(In millions)	Net Gain  (Loss)		Net Gain (Loss)		Prior Service Cost (Credit)		Other Comprehensive Loss from Unconsolidated Affiliates		Total
Balance at December 31, 2017	$	(32.7)	$	2.5	$	7.0	$	—	$	(23.2)
Other comprehensive income (loss) before reclassifications	(14.1)		2.1		—		—		(12.0)
Amounts reclassified from accumulated other comprehensive income (loss)	3.3		—		(1.7)		—		1.6
Settlement cost	4.7		—		—		—		4.7
Net current period other comprehensive income (loss)	(6.1)		2.1		(1.7)		—		(5.7)
Balance at December 31, 2018	(38.8)		4.6		5.3		—		(28.9)
Other comprehensive income (loss) before reclassifications	(8.3)		(0.2)		—		(0.6)		(9.1)
Amounts reclassified from accumulated other comprehensive income (loss)	3.4		(0.2)		(1.7)		—		1.5
Settlement cost	8.6		—		—		—		8.6
Net current period other comprehensive income (loss)	3.7		(0.4)		(1.7)		(0.6)		1.0
Balance at December 31, 2019	$	(35.1)	$	4.2	$	3.6	$	(0.6)	$	(27.9)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the years ended December 31, 2019 and 2018.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)				Affected Line Item in the Consolidated Statements of Income
	Year Ended December 31,
(In millions)	2019		2018
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses	$	(4.5)	$	(4.4)	(A)
Settlement cost	(11.3)		(6.3)		(A)
	(15.8)		(10.7)		Income Before Taxes
	(3.8)		(2.7)		Income Tax Expense
	$	(12.0)	$	(8.0)	Net Income
Amortization of postretirement benefit plans items:
Prior service credit	$	2.3	$	2.3	(A)
Actuarial gains	0.2		—		(A)
	2.5		2.3		Income Before Taxes
	0.6		0.6		Income Tax Expense
	$	1.9	$	1.7	Net Income
Total reclassifications for the period, net of tax	$	(10.1)	$	(6.3)	Net Income

(A)These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 13 for additional information).

The amounts in accumulated other comprehensive loss (gain) at December 31, 2019 that are expected to be recognized into earnings in 2020 are as follows:

(In millions)
Pension Plan and Restoration of Retirement Income Plan:
Net gain	$	(4.2)
Postretirement Benefit Plans:
Net loss	0.2
Prior service cost	2.3
Total, net of tax	$	(1.7)

Asset Retirement Obligation Disclosure [Text Block]

OG&E has asset retirement obligations primarily associated with the removal of company-owned wind turbines on leased land, as well as the removal of asbestos from certain power generating stations. The Company has recorded asset retirement obligations that are being accreted over their respective lives ranging from ten to 68 years. 

The following table summarizes changes to the Company's asset retirement obligations during the years ended December 31, 2019 and 2018.

(In millions)	2019		2018
Balance at January 1	$	83.9	$	75.1
Accretion expense	1.0		3.4
Revisions in estimated cash flows (A)	(2.4)		6.8
Liabilities settled (B)	(9.0)		(1.4)
Balance at December 31	$	73.5	$	83.9

(A)Assumptions changed related to the estimated cost of the removal of wind turbine assets and asbestos removal at OG&E's generating facilities.

(B)Asset retirement obligations were settled for asbestos removal and for the closure of an ash pond at OG&E's generating facilities.

Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost. The Company had $18.7 million and $23.4 million in accrued environmental liabilities at December 31, 2019 and 2018, respectively, which are included in the Company's asset retirement obligations.

Property, Plant and Equipment Disclosure [Text Block]

Property, Plant and Equipment

All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances, and the cost of such property net of any salvage proceeds is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation, and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Other Expense. Repair and replacement of minor items of property are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense.

The tables below present OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant, such as fuel, maintenance expense and other operating expenses, are included in the applicable financial statement captions in the Consolidated Statements of Income.

December 31, 2019 (In millions)	Percentage Ownership		Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
McClain Plant (A)	77	%	$	254.4	$	83.5	$	170.9
Redbud Plant (A)(B)	51	%	$	529.9	$	159.0	$	370.9

(A)Construction work in progress was $0.2 million and $1.4 million for the McClain and Redbud Plants, respectively.

(B)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.

December 31, 2018 (In millions)	Percentage Ownership		Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
McClain Plant (A)	77	%	$	227.2	$	78.2	$	149.0
Redbud Plant (A)(B)	51	%	$	493.9	$	145.3	$	348.6

(A)Construction work in progress was $0.2 million and $0.9 million for the McClain and Redbud Plants, respectively.

(B)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.

The Company's property, plant and equipment and related accumulated depreciation are divided into the following major classes: 

December 31, 2019 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
OGE Energy:
Property, plant and equipment	$	6.1	$	—	$	6.1
OGE Energy property, plant and equipment	6.1		—		6.1
OG&E:
Distribution assets	4,468.6		1,381.1		3,087.5
Electric generation assets (A)	4,838.6		1,601.0		3,237.6
Transmission assets (B)	2,901.1		565.5		2,335.6
Intangible plant	225.2		145.4		79.8
Other property and equipment	473.1		175.1		298.0
OG&E property, plant and equipment	12,906.6		3,868.1		9,038.5
Total property, plant and equipment	$	12,912.7	$	3,868.1	$	9,044.6

(A)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.

(B)This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.8 million.

December 31, 2018 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
OGE Energy:
Property, plant and equipment	$	6.1	$	—	$	6.1
OGE Energy property, plant and equipment	6.1		—		6.1
OG&E:
Distribution assets	4,229.4		1,324.5		2,904.9
Electric generation assets (A)	4,657.2		1,572.8		3,084.4
Transmission assets (B)	2,846.7		534.2		2,312.5
Intangible plant	187.6		135.1		52.5
Other property and equipment	444.2		160.8		283.4
OG&E property, plant and equipment	12,365.1		3,727.4		8,637.7
Total property, plant and equipment	$	12,371.2	$	3,727.4	$	8,643.8

(A)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.

(B)This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.7 million.

OG&E's unamortized computer software costs, included in intangible plant above, were $71.3 million and $44.3 million at December 31, 2019 and 2018, respectively.

The following table summarizes the Company's amortization expense for computer software costs.

Year Ended December 31 (In millions)	2019		2018		2017
OGE Energy	$	—	$	—	$	0.2
OG&E	11.0		9.6		8.8
Total	$	11.0	$	9.6	$	9.0

Depreciation and Amortization

The provision for depreciation, which was 2.7 percent of the average depreciable utility plant for both 2019 and 2018, is calculated using the straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant and is based on the average life group method. In 2020, the provision for depreciation is projected to be 2.7 percent of the average depreciable utility plant.

Amortization of intangible assets is calculated using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2019, 98.9 percent will be amortized over 10.4 years with the remaining 1.1 percent of the intangible plant balance at December 31, 2019 being amortized over 23.7 years.  

Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired assets. Plant acquisition adjustments include $148.3 million for the Redbud Plant, which is being amortized over a 27 year life and $3.3 million for certain transmission substation facilities in OG&E's service territory, which are being amortized over a 37 to 59 year period.

Inventory Disclosure [Text Block]

Fuel Inventories

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was $46.3 million and $57.6 million at December 31, 2019 and 2018, respectively.

Summary of Significant Accounting Policies [Text Block]

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.

December 31 (In millions)	2019		2018
REGULATORY ASSETS
Current:
Fuel clause under recoveries	$	39.5	$	2.0
Production tax credit rider over credit (A)	1.7		6.9
Oklahoma demand program rider under recovery (A)	—		6.4
Other (A)	7.5		3.2
Total current regulatory assets	$	48.7	$	18.5
Non-current:
Benefit obligations regulatory asset	$	167.2	$	188.2
Deferred storm expenses	65.5		36.5
Sooner Dry Scrubbers	20.6		4.5
Smart Grid	18.4		25.6
Unamortized loss on reacquired debt	10.6		11.4
Arkansas deferred pension expenses	8.0		6.8
Pension tracker	2.3		—
Other	13.4		12.8
Total non-current regulatory assets	$	306.0	$	285.8
REGULATORY LIABILITIES
Current:
Reserve for tax refund and interim surcharge (B)	$	12.7	$	15.4
Fuel clause over recoveries	4.8		0.3
SPP cost tracker over recovery (B)	2.6		16.8
Oklahoma demand program rider over recovery (B)	2.0		—
Transmission cost recovery rider over recovery (B)	—		2.7
Other (B)	6.9		1.4
Total current regulatory liabilities	$	29.0	$	36.6
Non-current:
Income taxes refundable to customers, net	$	899.2	$	937.1
Accrued removal obligations, net	318.5		308.1
Pension tracker	—		18.7
Other	5.8		6.8
Total non-current regulatory liabilities	$	1,223.5	$	1,270.7

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

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

Fuel clause under and over recoveries are generated from OG&E's customers when OG&E's cost of fuel either exceeds or is less than the amount billed to its customers, respectively. OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.

As approved by the OCC, OG&E utilizes a rider separate from base rates to credit customers for production tax credits.

OG&E recovers program costs related to the Demand and Energy Efficiency Program in Oklahoma through the Demand Program Rider, which operates on a three-year program cycle. The current program cycle, which runs through 2021,

includes recovery of (i) energy efficiency program costs, (ii) lost revenues associated with certain achieved energy efficiency and demand savings, (iii) performance-based incentives and (iv) costs associated with research and development investments.

The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost. These expenses are recorded as a regulatory asset as OG&E historically has recovered and currently recovers pension and postretirement benefit plan expense in its electric rates. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the benefit obligations regulatory asset balance to be reclassified to accumulated other comprehensive income.

The following table is a summary of the components of the benefit obligations regulatory asset:

December 31 (In millions)	2019		2018
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	160.5	$	185.3
Postretirement Benefit Plans:
Net loss	23.3		25.6
Prior service cost	(16.6)		(22.7)
Total	$	167.2	$	188.2

The following amounts in the benefit obligations regulatory asset at December 31, 2019 are expected to be recognized as components of net periodic benefit cost in 2020: 

(In millions)
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	11.4
Postretirement Benefit Plans:
Net loss	2.8
Prior service cost	(6.1)
Total	$	8.1

OG&E includes in expense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million annually and defers to a regulatory asset any additional expenses incurred over $2.7 million. OG&E expects to recover the amounts deferred each year over a five-year period in accordance with historical practice.

As approved by the OCC in June 2018, OG&E deferred the non-fuel incremental operation and maintenance expenses, depreciation, debt cost associated with the capital investment and related ad valorem taxes for the Dry Scrubbers at Sooner Units 1 and 2 as a regulatory asset. As approved by the OCC, these costs are being recovered over 25 years.

OG&E deferred to a regulatory asset the incremental and stranded costs that were accumulated during Smart Grid deployment, including (i) costs for web portal access, (ii) costs for education and home energy reports and (iii) stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters. As approved by the OCC and APSC, these costs are being recovered over a six-year period.

Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt. These amounts are recorded in interest expense and are being amortized over the term of the long-term debt which replaced the previous long-term debt. The unamortized loss on reacquired debt is recovered as a part of OG&E's cost of capital.

Arkansas includes a certain level of pension expense in base rates. When the Pension Plan experiences a settlement, which represents an acceleration of future pension costs, OG&E defers to a regulatory asset the Arkansas jurisdictional portion of each settlement, which historically was recovered from customers over the average life of the remaining plan participants. A portion of these settlements is being recovered in current rates, and recovery of additional amounts will be requested as additional settlements occur. For additional information related to settlements, see Note 13.

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 regulatory asset in the table above.

As a result of 2018 filings with the OCC, APSC and FERC, OG&E established mechanisms to refund to customers the amount of excess taxes received through rates, with an ongoing adjustment for any excess accumulated deferred income taxes resulting from the 2017 Tax Act. Additional amounts due to customers will be refunded in accordance with agreements in each jurisdiction.

OG&E recovers certain SPP costs related to base plan charges from its customers and refunds certain SPP revenues received to its customers in Oklahoma through the SPP cost tracker and in Arkansas through the transmission cost recovery rider.

Income taxes refundable to customers, net, represents the reduction in accumulated deferred income taxes resulting from the reduction in the federal income tax rate as part of the 2017 Tax Act and includes income taxes recoverable from customers that represent income tax benefits previously used to reduce OG&E's revenues (treated as regulatory assets). These liabilities will be returned to customers in varying amounts over approximately 80 years, and the assets will be amortized over the estimated remaining life of the assets to which they relate, as the temporary differences that generated the income tax benefits turn around.

Accrued removal obligations, net represents asset retirement costs previously recovered from ratepayers for other than legal obligations. 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.

Reclassifications [Text Block]

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

XML

Investment in Unconsolidated Affiliate and Related Party Transactions

12 Months Ended

Dec. 31, 2019

Schedule of Equity Method Investments [Line Items]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

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 December 31, 2019, the Company owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units. On December 31, 2019, Enable's common unit price closed at $10.03. The Company recorded equity in earnings of unconsolidated affiliates of $113.9 million, $152.8 million and $131.2 million for the years ended December 31, 2019, 2018 and 2017, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex LLC and its underlying equity in the net assets of Enable. The basis difference is being amortized, 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 as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017.

	December 31,
Balance Sheet	2019		2018
(In millions)
Current assets	$	389	$	449
Non-current assets	$	11,877	$	11,995
Current liabilities	$	780	$	1,615
Non-current liabilities	$	4,077	$	3,211

	Year Ended December 31,
Income Statement	2019		2018		2017
(In millions)
Total revenues	$	2,960	$	3,431	$	2,803
Cost of natural gas and NGLs	$	1,279	$	1,819	$	1,381
Operating income	$	569	$	648	$	528
Net income	$	360	$	485	$	400

The following table reconciles OGE Energy's equity in earnings of unconsolidated affiliates for the years ended December 31, 2019, 2018 and 2017.

	Year Ended December 31,
(In millions)	2019			2018			2017
Enable net income	$	360.0		$	485.3		$	400.3
OGE Energy's percent ownership at period end	25.5		%	25.6		%	25.7		%
OGE Energy's portion of Enable net income	$	91.8		$	124.4		$	102.7
Amortization of basis difference and dilution recognition (A)	22.1			28.4			28.5
Equity in earnings of unconsolidated affiliates	$	113.9		$	152.8		$	131.2

(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 December 31, 2019.

(In millions)
Basis difference at December 31, 2018	$	680.3
Amortization of basis difference (A)	(27.8)
Basis difference at December 31, 2019	$	652.5

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

On February 7, 2020, 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 $144.0 million, $141.2 million and $141.2 million during the years ended December 31, 2019, 2018 and 2017, 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 $0.5 million, $0.6 million and $2.3 million for December 31, 2019, 2018 and 2017, respectively.

Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of December 31, 2019, 80 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $23.2 million, $27.5 million and $29.5 million in 2019, 2018 and 2017, respectively, under the seconding agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by $17.3 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 $0.8 million and $1.7 million as of December 31, 2019 and 2018, which are included in Accounts Receivable in the Company's Consolidated Balance Sheets.

OG&E and Enable

Enable provides gas transportation services to OG&E pursuant to an agreement, which expires in May 2024, 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. Further, an additional gas transportation services contract with Enable became effective in December 2018 related to the project to convert Muskogee Units 4 and 5 from coal to natural gas. The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2019, 2018 and 2017.

	Year Ended December 31,
(In millions)	2019		2018		2017
Operating revenues:
Electricity to power electric compression assets	$	15.9	$	16.3	$	14.0
Cost of sales:
Natural gas transportation services	$	41.2	$	37.9	$	35.0
Natural gas (sales) purchases	$	(6.0)	$	(3.2)	$	(2.1)

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

The following table presents information about investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments. Cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds are also presented in the table.

Year Ended December 31 (In millions)	2019		2018		2017
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement	$	28.9	$	(9.2)	$	(2.6)
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of interest capitalized) (A)	$	152.2	$	153.8	$	139.6
Income taxes (net of income tax refunds)	$	5.5	$	2.8	$	(16.0)

(A)Net of interest capitalized of $2.8 million, $11.7 million and $18.0 million in 2019, 2018 and 2017, respectively.

XML

Leases, Codification Topic 842 (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Lease, Cost

The following table presents amounts recognized for operating leases in the Company's 2019 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.

(In millions)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	5.6
Right-of-use assets obtained in exchange for new operating lease liabilities	$	10.7
(Dollars in millions)	December 31, 2019
Right-of-use assets at period end (A)	$	40.9
Operating lease liabilities at period end (B)	$	45.8
Operating lease weighted-average remaining lease term (in years)	13.1
Operating lease weighted-average discount rate	3.9		%

	December 31,
Future minimum operating lease payments as of:	2019		2018(C)(D)
(In millions)
2019	$	—	$	22.1
2020	6.2		3.9
2021	5.8		3.5
2022	5.2		2.9
2023	5.2		2.9
2024	3.1		3.0
Thereafter	34.7		34.6
Total future minimum lease payments	60.2		$	72.9
Less: Imputed interest	14.4
Present value of net minimum lease payments	$	45.8

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

(B) Included in Other Deferred Credits and Other Liabilities in the 2019 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.

XML

Summary of Significant Accounting Policies Enviromental Costs (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Accrued Environmental Loss Contingencies, Noncurrent	$ 18.7	$ 23.4

XML

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer, Excluding Assessed Tax	$ 2,175.5	$ 2,211.7	$ 0.0
Provision for Rate Refund [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	(0.9)	(6.0)
Integrated Market [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	38.4	48.7
Transmission [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	148.0	147.4
Other Contracts with Customers [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	29.1	27.1
Residential [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	865.8	877.8
Commercial [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	486.6	500.0
Industrial [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	217.8	228.9
Oilfield [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	200.4	190.4
Public Authority [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	190.3	197.4
Total Retail Customer [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,960.9	$ 1,994.5

XML

Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match		200.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay		5.00%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Employer contributions		$ 20.0		$ 15.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Effect of One Percentage Point Increase on Service and Interest Cost Components		0.0		0.0		$ 0.0
Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation		0.1		0.1		0.1
Effect of One Percentage Point Decrease on Service and Interest Cost Components		0.0		0.0		0.0
Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		0.3		0.3		0.3
Expected Future Benefit Payments, Next Twelve Months		58.4
Expected Future Benefit Payments, Year Two		56.8
Expected Future Benefit Payments, Year Three		56.2
Expected Future Benefit Payments, Year Four		55.7
Expected Future Benefit Payments, Year Five		56.6
Expected Future Benefit Payments, Five Fiscal Years Thereafter		249.4
Defined Contribution Plan, Cost		14.4		13.2		13.2
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		(14.6)		(14.6)
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		0.0		0.0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		615.9		687.5
Service cost		12.9		14.9		15.5
Interest cost		20.7		23.8		26.2
Plan settlements		(83.1)		(73.7)
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		0.0		0.0
Actuarial losses (gains)		64.3		(22.0)
Benefit Obligation, Ending		616.1		615.9		687.5
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		522.8		635.3
Actual return on plans' assets		85.2		(39.2)
Employer contributions		20.0		15.0
Plan settlements		(83.1)		(73.7)
Fair Value of Plan Assets, Ending		530.3		522.8		635.3
Funded Status of Plan		(85.8)		(93.1)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		12.9		14.9		15.5
Interest cost		20.7		23.8		26.2
Expected return on plan assets		(36.1)		(44.1)		(42.6)
Defined Benefit Plan, Amortization of Gain (Loss)		(17.3)		(16.2)		(17.4)
Amortization of unrecognized prior service cost	[1]	0.0		0.0		(0.1)
Settlement cost		27.6		25.1		15.3
Net periodic benefit cost		42.4		35.9		31.7
Amount paid by unconsolidated affiliates		2.9		2.5		4.3
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		39.5		33.4		27.4
Plan settlements		(83.1)		(73.7)
Capitalized Portion of Net Periodic Benefit Cost		$ 3.6		$ 3.8		$ 4.4
Assumptions Used Calculating Benefit Obligation, Discount Rate		3.15%		4.20%		3.60%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		7.50%		7.50%		7.50%
Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		4.20%		4.20%		4.20%
Fair Value of Plan Assets, Beginning		$ 522.8		$ 635.3
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		0.0		0.0
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(14.6)		(14.6)
Pension Plans, Defined Benefit [Member] | OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Settlement cost	[2]	17.9		22.1		$ 13.2
Additional Pension Expense to Meet State Requirements	[2]	(16.1)		(14.1)		(2.3)
Pension Plans, Defined Benefit [Member] | ARKANSAS
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Settlement cost	[2]	1.7		2.1		1.1
Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Restoration of Retirement Income Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		0.0		0.0
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		0.3		0.0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		9.6		8.1
Service cost		0.5		0.4		0.3
Interest cost		0.4		0.3		0.3
Plan settlements		(1.2)		(2.0)
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		0.0		0.0
Actuarial losses (gains)		0.7		2.8
Benefit Obligation, Ending		10.3		9.6		8.1
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0		0.0
Actual return on plans' assets		0.0		0.0
Employer contributions		1.2		2.0
Plan settlements		(1.2)		(2.0)
Fair Value of Plan Assets, Ending		0.0		0.0		0.0
Funded Status of Plan		(10.3)		(9.6)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.5		0.4		0.3
Interest cost		0.4		0.3		0.3
Expected return on plan assets		0.0		0.0		0.0
Defined Benefit Plan, Amortization of Gain (Loss)		(0.5)		(0.7)		(0.4)
Amortization of unrecognized prior service cost	[1]	0.0		0.1		0.1
Settlement cost		0.5		1.0		0.0
Net periodic benefit cost		1.9		2.5		1.1
Amount paid by unconsolidated affiliates		0.1		0.1		0.0
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		1.8		2.4		1.1
Plan settlements		(1.2)		(2.0)
Fair Value of Plan Assets, Beginning		0.0		0.0
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		0.0		0.0
Defined Benefit Plan, Benefit Obligation, Benefits Paid		0.0		0.0
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		(12.1)		(13.5)
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		0.0		0.0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		135.8		149.4
Service cost		0.2		0.3		0.6
Interest cost		5.6		5.4		7.2
Plan settlements		0.0		0.0
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		(4.1)		(3.8)
Actuarial losses (gains)		2.9		(9.6)
Benefit Obligation, Ending		136.5		135.8		149.4
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		45.3		50.2
Actual return on plans' assets		4.6		(0.6)
Employer contributions		5.1		5.4
Plan settlements		0.0		0.0
Fair Value of Plan Assets, Ending		47.0		45.3		50.2
Funded Status of Plan		(89.5)		(90.5)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.2		0.3		0.6
Interest cost		5.6		5.4		7.2
Expected return on plan assets		(1.9)		(2.0)		(2.2)
Defined Benefit Plan, Amortization of Gain (Loss)		(2.0)		(3.8)		(2.0)
Amortization of unrecognized prior service cost	[1]	(8.4)		(8.4)		(3.5)
Settlement cost		0.0		0.0		0.6
Net periodic benefit cost		(2.5)		(0.9)		4.7
Amount paid by unconsolidated affiliates		(0.6)		(0.5)		0.3
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		(1.9)		(0.4)		4.4
Plan settlements		0.0		0.0
Capitalized Portion of Net Periodic Benefit Cost		$ 0.2		$ 0.2		$ 1.2
Assumptions Used Calculating Benefit Obligation, Discount Rate		3.25%		4.30%		3.70%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		4.00%		4.00%		4.00%
Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase						4.20%
Health Care Cost Trend Rate Assumed for Next Fiscal Year				7.00%
Fair Value of Plan Assets, Beginning		$ 45.3		$ 50.2
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		4.1		3.8
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(12.1)		(13.5)
Other Postretirement Benefits Plan [Member] | OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Additional Pension Expense to Meet State Requirements	[3]	1.0		4.4		$ 6.2
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		9.8
Fair Value of Plan Assets, Ending		12.1		9.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		9.8
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		36.0
Fair Value of Plan Assets, Ending		34.8		36.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		36.0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		45.8
Fair Value of Plan Assets, Ending		46.9		45.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		$ 45.8
Less Than 90% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income		50.00%
Projected Benefit Obligation Funded Status Thresholds Equity		50.00%
Projected Benefit Obligation Funded Status Thresholds		100.00%
95% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income		58.00%
Projected Benefit Obligation Funded Status Thresholds Equity		42.00%
Projected Benefit Obligation Funded Status Thresholds		100.00%
100% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income		65.00%
Projected Benefit Obligation Funded Status Thresholds Equity		35.00%
Projected Benefit Obligation Funded Status Thresholds		100.00%
105% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income		73.00%
Projected Benefit Obligation Funded Status Thresholds Equity		27.00%
Projected Benefit Obligation Funded Status Thresholds		100.00%
110% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income		80.00%
Projected Benefit Obligation Funded Status Thresholds Equity		20.00%
Projected Benefit Obligation Funded Status Thresholds		100.00%
115% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income		85.00%
Projected Benefit Obligation Funded Status Thresholds Equity		15.00%
Projected Benefit Obligation Funded Status Thresholds		100.00%
120% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income		90.00%
Projected Benefit Obligation Funded Status Thresholds Equity		10.00%
Projected Benefit Obligation Funded Status Thresholds		100.00%
Domestic All-Cap/Large Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		40.00%
Domestic Mid-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		15.00%
Domestic Small-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		25.00%
International Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		20.00%
Minimum [Member] | Domestic All-Cap/Large Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		35.00%
Minimum [Member] | Domestic Mid-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		5.00%
Minimum [Member] | Domestic Small-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		5.00%
Minimum [Member] | International Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		10.00%
Maximum [Member] | Domestic All-Cap/Large Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		60.00%
Maximum [Member] | Domestic Mid-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		25.00%
Maximum [Member] | Domestic Small-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		30.00%
Maximum [Member] | International Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		30.00%
Group Retiree Medical Insurance Contract [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		$ 36.0
Fair Value of Plan Assets, Ending		34.8		36.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		36.0
Group Retiree Medical Insurance Contract [Member] | Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Group Retiree Medical Insurance Contract [Member] | Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		36.0
Fair Value of Plan Assets, Ending		34.8		36.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		36.0
U.S. common stocks [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		169.3
Fair Value of Plan Assets, Ending		202.0		169.3
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		169.3
U.S. common stocks [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		169.3
Fair Value of Plan Assets, Ending		202.0		169.3
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		169.3
U.S. common stocks [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
U.S. treasury notes and bonds [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4],[6]	0.0	[5],[7]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[7]	137.9
Fair Value of Plan Assets, Ending	[7]	134.8		137.9
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[7]	137.9
U.S. treasury notes and bonds [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[7]	137.9
Fair Value of Plan Assets, Ending	[7]	134.8		137.9
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[7]	137.9
U.S. treasury notes and bonds [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[7]	0.0
Fair Value of Plan Assets, Ending	[7]	0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[7]	0.0
Mortgage-backed securities | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		65.9
Fair Value of Plan Assets, Ending		45.8		65.9
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		65.9
Mortgage-backed securities | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Mortgage-backed securities | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		65.9
Fair Value of Plan Assets, Ending		45.8		65.9
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		65.9
Corporate fixed income and other securities [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		143.2
Fair Value of Plan Assets, Ending		130.5		143.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		143.2
Corporate fixed income and other securities [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Corporate fixed income and other securities [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		143.2
Fair Value of Plan Assets, Ending		130.5		143.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		143.2
Commingled fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		23.9	[4],[8]	19.7	[5],[9]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[9]	19.7
Fair Value of Plan Assets, Ending	[9]	23.9		19.7
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[9]	19.7
Commingled fund [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[9]	0.0
Fair Value of Plan Assets, Ending	[9]	0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[9]	0.0
Commingled fund [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[9]	0.0
Fair Value of Plan Assets, Ending	[9]	0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[9]	0.0
Foreign government bonds [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		4.4
Fair Value of Plan Assets, Ending		3.0		4.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		4.4
Foreign government bonds [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Foreign government bonds [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		4.4
Fair Value of Plan Assets, Ending		3.0		4.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		4.4
Municipal bonds [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.6
Fair Value of Plan Assets, Ending		1.1		0.6
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.6
Municipal bonds [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Municipal bonds [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.6
Fair Value of Plan Assets, Ending		1.1		0.6
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.6
Money market funds [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		7.5	[4]	0.3	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.3
Fair Value of Plan Assets, Ending		7.5		0.3
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.3
Money market funds [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Money market funds [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Money market funds [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		1.2
Money market funds [Member] | Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		1.2
Money market funds [Member] | Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		0.0
Mutual fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		8.0
Fair Value of Plan Assets, Ending		2.4		8.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		8.0
Mutual fund [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		8.0
Fair Value of Plan Assets, Ending		2.4		8.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		8.0
Mutual fund [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Treasury futures, receivable [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		27.0
Fair Value of Plan Assets, Ending		22.9		27.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		27.0
Treasury futures, receivable [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Treasury futures, receivable [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		27.0
Fair Value of Plan Assets, Ending		22.9		27.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		27.0
Treasury futures, payable [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		(20.4)
Fair Value of Plan Assets, Ending		(10.9)		(20.4)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		(20.4)
Treasury futures, payable [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Treasury futures, payable [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		(20.4)
Fair Value of Plan Assets, Ending		(10.9)		(20.4)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		(20.4)
Cash collateral [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.7
Fair Value of Plan Assets, Ending		0.6		0.7
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.7
Cash collateral [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.7
Fair Value of Plan Assets, Ending		0.6		0.7
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.7
Cash collateral [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Receivable (foreign currency) [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		0.0	[4]	0.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.1
Fair Value of Plan Assets, Ending		0.1		0.1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.1
Receivable (foreign currency) [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0		0.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.0
Receivable (foreign currency) [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.1
Fair Value of Plan Assets, Ending		0.1		0.1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.1
Preferred stocks (foreign) [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[4]	0.0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		0.7
Preferred stocks (foreign) [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		0.7
Preferred stocks (foreign) [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		0.0
Total Plan investments [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment		31.4	[4]	20.0	[5]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		556.7
Fair Value of Plan Assets, Ending		564.4		556.7
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		556.7
Total Plan investments [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		315.9
Fair Value of Plan Assets, Ending		340.5		315.9
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		315.9
Total Plan investments [Member] | Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		220.8
Fair Value of Plan Assets, Ending		192.5		220.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		220.8
Interest and dividends receivable [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		3.0
Fair Value of Plan Assets, Ending		2.4		3.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		3.0
Payable to broker for securities purchased [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		(36.9)
Fair Value of Plan Assets, Ending		(36.5)		(36.9)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		(36.9)
Total Plan assets [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		522.8
Fair Value of Plan Assets, Ending		530.3		$ 522.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		$ 522.8

[1] 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.

[2] Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

[3] Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

[4] GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

[5] GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

[6] This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.

[7] This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.

[8] This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

[9] This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

XML

Common Equity Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount																	0.0		0.0		0.0
Net income attributable to OGE Energy	$ 35.4		$ 250.9		$ 100.2		$ 47.1		$ 54.7		$ 205.1		$ 110.7		$ 55.0		$ 433.6		$ 425.5		$ 619.0
Basic Average Common Shares Outstanding																	200.1		199.7		199.7
Contingently Issuable Shares (Performance and Restricted Stock Units)																	0.6		0.8		0.3
Diluted Average Common Shares Outstanding																	200.7		200.5		200.0
Earnings Per Share, Basic and Diluted [Abstract]
Basic earnings per average common share attributable to OGE Energy common shareholders	$ 0.18	[1]	$ 1.25	[1]	$ 0.50	[1]	$ 0.24	[1]	$ 0.27	[1]	$ 1.03	[1]	$ 0.55	[1]	$ 0.28	[1]	$ 2.17	[1]	$ 2.13	[1]	$ 3.10
Diluted earnings per average common share attributable to OGE Energy common shareholders	$ 0.18	[1]	$ 1.25	[1]	$ 0.50	[1]	$ 0.24	[1]	$ 0.27	[1]	$ 1.02	[1]	$ 0.55	[1]	$ 0.27	[1]	$ 2.16	[1]	$ 2.12	[1]	$ 3.10
Retained Earnings [Member]
Net income attributable to OGE Energy																	$ 433.6		$ 425.5		$ 619.0

[1] Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

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Schedule II (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Beginning Balance		$ 1.7	$ 1.5	$ 1.5
Valuation Allowances and Reserves, Charged to Cost and Expense		2.2	3.4	2.6
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	[1]	2.4	3.2	2.6
Valuation Allowances and Reserves, Ending Balance		$ 1.5	$ 1.7	$ 1.5

[1] Uncollectible accounts receivable written off, net of recoveries.

XML

Rate Matters and Regulation (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 5.2
Customer Refund Liability, Current		4.8	$ 0.3
Regulatory Assets, Current		48.7	18.5
Public Utilities, Amount Requested for Acquisition		53.5
Estimated Refund to SPP		13.0
Investment in Grid Enhancement		800.0
Impact to Company [Member]
Estimated Refund to SPP		5.0
Customer Impact [Member]
Estimated Refund to SPP		$ 8.0
Oklahoma Corporation Commission [Member]
OG&E's Jurisdictional Revenues		86.00%
Arkansas Public Service Commission [Member]
OG&E's Jurisdictional Revenues		8.00%
Federal Energy Regulatory Commission [Member]
OG&E's Jurisdictional Revenues		6.00%
OKLAHOMA
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 77.6
ARKANSAS
Public Utilities, Approved Rate Increase (Decrease), Amount		(3.3)
Oklahoma demand program rider under recovery [Member]
Regulatory Assets, Current	[1]	$ 0.0	$ 6.4
FERC [Member]
Recommended Common Equity Percentage		7.85%
Public Utilities, Approved Return on Equity, Percentage		10.60%

[1] Included in Other Current Assets in the Consolidated Balance Sheets.

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 433.6	$ 425.5	$ 619.0
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	355.0	321.6	283.5
Deferred income taxes and investment tax credits, net	27.6	78.5	(50.0)
Equity in earnings of unconsolidated affiliates	(113.9)	(152.8)	(131.2)
Distributions from unconsolidated affiliates	125.5	141.2	131.2
Allowance for equity funds used during construction	(4.5)	(23.8)	(39.7)
Stock-based compensation expense	13.9	13.4	9.1
Regulatory assets	47.1	10.8	(3.7)
Regulatory liabilities	(45.6)	(16.5)	(3.7)
Other assets	(3.8)	6.2	(0.7)
Other liabilities	19.2	1.0	(65.5)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	18.8	19.8	(21.8)
Income taxes receivable	(1.0)	(4.1)	13.6
Fuel, materials and supplies inventories	4.2	27.3	(3.6)
Fuel recoveries	(33.0)	(3.4)	53.0
Other current assets	5.1	25.1	27.2
Accounts payable	(34.5)	29.7	27.1
Other current liabilities	(38.0)	73.2	(66.7)
Net cash provided from operating activities	681.5	951.1	784.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(635.5)	(573.6)	(824.1)
Investment in unconsolidated affiliates	(7.7)	(2.5)	(8.5)
Return of capital - unconsolidated affiliates	18.5	0.0	10.0
Proceeds from sale of assets	0.0	0.1	0.7
Net cash used in investing activities	(624.7)	(576.0)	(821.9)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase (decrease) in short-term debt	112.0	(168.4)	(67.8)
Proceeds from long-term debt	296.5	396.0	592.1
Payment of long-term debt	(250.1)	(250.1)	(225.1)
Dividends paid on common stock	(299.2)	(272.2)	(247.6)
Cash paid for employee equity-based compensation and expense of common stock	(10.3)	(0.5)	(0.1)
Net cash provided from (used in) financing activities	(151.1)	(295.2)	51.5
NET CHANGE IN CASH AND CASH EQUIVALENTS	(94.3)	79.9	14.1
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	94.3	14.4	0.3
CASH AND CASH EQUIVALENTS AT END OF YEAR	$ 0.0	$ 94.3	$ 14.4

XML

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2019	Jun. 30, 2019
Document Information [Line Items]
Entity Registrant Name	OGE ENERGY CORP.
Entity Central Index Key	0001021635
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	200,177,358	200,175,812
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float		$ 8,519,482,559
Entity Incorporation, State or Country Code	OK
Entity Tax Identification Number	73-1481638
Entity Address, Address Line One	321 North Harvey
Entity Address, Address Line Two	P.O. Box 321
Trading Symbol	OGE
Security Exchange Name	NYSE
Entity Interactive Data Current	Yes
City Area Code	405
Local Phone Number	553-3000
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73101-0321
Entity File Number	1-12579
Title of 12(b) Security	Common Stock
Entity Address, City or Town	Oklahoma City
Share Price		$ 42.56
Document Transition Report	false
Document Annual Report	true

XML

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	450.0	450.0
Common Stock, Shares, Outstanding	200.1	199.7
Debt Instrument, Maturity Date	Mar. 15, 2030
Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument, Maturity Date	Jan. 01, 2025
Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument, Maturity Date	Jan. 01, 2025
Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument, Maturity Date	Jun. 01, 2027
Senior Notes [Member] | Series Due January 15, 2019 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jan. 15, 2019
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Senior Notes [Member] | Series Due July 15, 2027 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jul. 15, 2027
Debt Instrument, Interest Rate, Stated Percentage	6.65%
Senior Notes [Member] | Series Due April 15, 2028 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Apr. 15, 2028
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Senior Notes [Member] | Series Due August 15, 2028 [Member] [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Aug. 15, 2028
Debt Instrument, Interest Rate, Stated Percentage	3.80%
Senior Notes [Member] | Series Due March 15, 2030 | OG&E [Member]
Debt Instrument, Maturity Date	Mar. 15, 2030
Debt Instrument, Interest Rate, Stated Percentage	3.30%
Senior Notes [Member] | Series Due January 15, 2036 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jan. 15, 2036
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Senior Notes [Member] | Series Due February 1, 2038 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Feb. 01, 2038
Debt Instrument, Interest Rate, Stated Percentage	6.45%
Senior Notes [Member] | Series Due June 1, 2040 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jun. 01, 2040
Debt Instrument, Interest Rate, Stated Percentage	5.85%
Senior Notes [Member] | Series Due May 15, 2041 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	May 15, 2041
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Senior Notes [Member] | Series Due May 1, 2043 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	May 01, 2043
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Senior Notes [Member] | Series Due March 15, 2044 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Mar. 15, 2044
Debt Instrument, Interest Rate, Stated Percentage	4.55%
Senior Notes [Member] | Series Due December 15, 2044 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Dec. 15, 2044
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Senior Notes [Member] | Series due April 1, 2047 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Apr. 01, 2047
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Senior Notes [Member] | Series due August 15, 2047 [Member] [Domain] | OG&E [Member]
Debt Instrument, Maturity Date	Aug. 15, 2047
Debt Instrument, Interest Rate, Stated Percentage	3.85%
Long-term Debt [Member] | Due August 31, 2062 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Aug. 31, 2062
Debt Instrument, Interest Rate, Stated Percentage	3.80%
Minimum [Member] | Debentures Subject to Mandatory Redemption [Member] | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.20%
Minimum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.19%
Minimum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.20%
Maximum [Member] | Debentures Subject to Mandatory Redemption [Member] | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Maximum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.35%
Maximum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.48%

XML

Summary of Significant Accounting Policies Regulated Operations (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause under recoveries		$ 39.5	$ 2.0
Fuel clause over recoveries		4.8	0.3
Regulatory Assets, Current		48.7	18.5
Regulatory Assets, Noncurrent		306.0	285.8
Regulatory Liability, Current		29.0	36.6
Regulatory Liability, Noncurrent		1,223.5	1,270.7
SPP Cost Tracker Rider Over Recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	2.6	16.8
Reserve for Tax Refund [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	12.7	15.4
Transmission Cost Recovery Rider [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	0.0	2.7
Income taxes recoverable from customers, net [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Noncurrent		899.2	937.1
Accrued removal obligations [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Noncurrent		318.5	308.1
Pension tracker [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Noncurrent		0.0	18.7
Other Regulatory Liabilities [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	6.9	1.4
Regulatory Liability, Noncurrent		5.8	6.8
Oklahoma demand program rider over recovery
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	2.0	0.0
Production Tax Credit Rider [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[2]	1.7	6.9
Oklahoma demand program rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[2]	0.0	6.4
Benefit obligations regulatory asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		167.2	188.2
Deferred storm expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		65.5	36.5
Smart Grid [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		18.4	25.6
Unamortized loss on reacquired debt [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		10.6	11.4
Deferred Pension Expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		8.0	6.8
Dry Scrubber Regulatory Asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		20.6	4.5
Other Regulatory Assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[2]	7.5	3.2
Regulatory Assets, Noncurrent		13.4	12.8
Pension tracker [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		$ 2.3	$ 0.0

[1] Included in Other Current Liabilities in the Consolidated Balance Sheets.

[2] Included in Other Current Assets in the Consolidated Balance Sheets.

XML

Report of Business Segments (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The following tables summarize the results of the Company's business segments for the years ended December 31, 2019, 2018 and 2017.

2019	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,231.6	$	—	$	—	$	—	$	2,231.6
Cost of sales	786.9		—		—		—		786.9
Other operation and maintenance	492.5		2.8		(3.5)		—		491.8
Depreciation and amortization	355.0		—		—		—		355.0
Taxes other than income	89.5		0.4		3.7		—		93.6
Operating income (loss)	507.7		(3.2)		(0.2)		—		504.3
Equity in earnings of unconsolidated affiliates	—		113.9		—		—		113.9
Other income (expense)	3.1		(8.6)		2.2		(3.6)		(6.9)
Interest expense	140.5		—		11.0		(3.6)		147.9
Income tax expense (benefit)	20.1		20.7		(11.0)		—		29.8
Net income	$	350.2	$	81.4	$	2.0	$	—	$	433.6
Investment in unconsolidated affiliates	$	—	$	1,132.9	$	18.6	$	—	$	1,151.5
Total assets	$	10,076.6	$	1,135.4	$	107.0	$	(294.7)	$	11,024.3
Capital expenditures	$	635.5	$	—	$	—	$	—	$	635.5

2018	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,270.3	$	—	$	—	$	—	$	2,270.3
Cost of sales	892.5		—		—		—		892.5
Other operation and maintenance	473.8		1.4		(0.6)		—		474.6
Depreciation and amortization	321.6		—		—		—		321.6
Taxes other than income	88.2		0.6		3.2		—		92.0
Operating income (loss)	494.2		(2.0)		(2.6)		—		489.6
Equity in earnings of unconsolidated affiliates	—		152.8		—		—		152.8
Other income (expense)	25.6		(4.9)		(3.4)		(6.0)		11.3
Interest expense	151.8		—		10.2		(6.0)		156.0
Income tax expense (benefit)	40.0		37.1		(4.9)		—		72.2
Net income (loss)	$	328.0	$	108.8	$	(11.3)	$	—	$	425.5
Investment in unconsolidated affiliates	$	—	$	1,166.6	$	10.9	$	—	$	1,177.5
Total assets	$	9,704.5	$	1,169.8	$	184.8	$	(310.5)	$	10,748.6
Capital expenditures	$	573.6	$	—	$	—	$	—	$	573.6

2017	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,261.1	$	—	$	—	$	—	$	2,261.1
Cost of sales	897.6		—		—		—		897.6
Other operation and maintenance	469.8		(0.8)		(10.3)		—		458.7
Depreciation and amortization	280.9		—		2.6		—		283.5
Taxes other than income	84.8		1.0		3.6		—		89.4
Operating income (loss)	528.0		(0.2)		4.1		—		531.9
Equity in earnings of unconsolidated affiliates	—		131.2		—		—		131.2
Other income (expense)	57.7		(1.0)		(5.4)		(0.9)		50.4
Interest expense	138.4		—		6.3		(0.9)		143.8
Income tax expense (benefit) (A)	141.8		(195.2)		4.1		—		(49.3)
Net income (loss)	$	305.5	$	325.2	$	(11.7)	$	—	$	619.0
Investment in unconsolidated affiliates	$	—	$	1,151.9	$	8.5	$	—	$	1,160.4
Total assets	$	9,255.6	$	1,155.3	$	109.1	$	(107.3)	$	10,412.7
Capital expenditures	$	824.1	$	—	$	—	$	—	$	824.1

(A)The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act.

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Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) - Automatic Dividend Reinvestment and Stock Purchase Plan [Member]	12 Months Ended
	Dec. 31, 2019 shares
Stock Issued During Period, Shares, Dividend Reinvestment Plan and Stock Purchase Plan	0
Shares Held in Reserve Related to Dividend Reinvestment Plan and Stock Purchase Plan	4,774,442

XML

Investment in Unconsolidated Affiliate and Related Party Transactions Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Summarized Financial Information of Equity Method Investment [Line Items]
Current assets	$ 389.0	$ 449.0
Non-current assets	11,877.0	11,995.0
Current liabilities	780.0	1,615.0
Non-current liabilities	$ 4,077.0	$ 3,211.0

XML

Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	$ 3,195.2	$ 3,146.9
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	3,050.3	3,001.9
Long-Term Debt, Fair Value	3,500.4	3,178.2
OG&E Industrial Authority Bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	135.4	135.4
Long-Term Debt, Fair Value	135.4	135.4
OG&E Tinker Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	9.5	9.6
Long-Term Debt, Fair Value	10.0	$ 8.7
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0.0

XML

Retirement Plans and Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2019

Retirement Plans and Postretirement Benefit Plans [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Retirement Plans and Postretirement Benefit Plans

Pension Plan and Restoration of Retirement Income Plan

It is the Company's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by the Company's actuarial consultants. Such contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. The Company made a $20.0 million and $15.0 million contribution to its Pension Plan in 2019 and 2018, respectively. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2020. Any contribution to the Pension Plan during 2020 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. The Company could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.

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 2019, 2018 and 2017, 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 plan settlement charges as presented in the net periodic benefit cost table below. The pension settlement charges did not require a cash outlay by the Company and did not increase the Company's total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.

The Company provides a Restoration of Retirement Income Plan to those participants in the Company's Pension Plan whose benefits are subject to certain limitations of the Code. Participants in the Restoration of Retirement Income Plan receive the same benefits that they would have received under the Company's Pension Plan in the absence of limitations imposed by the federal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan.

Obligations and Funded Status

The following table presents the status of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 2019 and 2018. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E's portion, which is recorded as a regulatory asset as discussed in Note 1) in the Company's Consolidated Balance Sheets. The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods. The benefit obligation for the Company's Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for the Company's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2019 was $563.3 million and $8.1 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2018 was $561.9 million and $7.8 million, respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Consolidated Balance Sheets are included in the following table.

	Pension Plan				Restoration of Retirement Income Plan				Postretirement Benefit Plans
December 31 (In millions)	2019		2018		2019		2018		2019		2018
Change in benefit obligation
Beginning obligations	$	615.9	$	687.5	$	9.6	$	8.1	$	135.8	$	149.4
Service cost	12.9		14.9		0.5		0.4		0.2		0.3
Interest cost	20.7		23.8		0.4		0.3		5.6		5.4
Plan settlements	(83.1)		(73.7)		(1.2)		(2.0)		—		—
Plan amendments	—		—		0.3		—		—		—
Participants' contributions	—		—		—		—		4.1		3.8
Actuarial losses (gains)	64.3		(22.0)		0.7		2.8		2.9		(9.6)
Benefits paid	(14.6)		(14.6)		—		—		(12.1)		(13.5)
Ending obligations	$	616.1	$	615.9	$	10.3	$	9.6	$	136.5	$	135.8
Change in plans' assets
Beginning fair value	$	522.8	$	635.3	$	—	$	—	$	45.3	$	50.2
Actual return on plans' assets	85.2		(39.2)		—		—		4.6		(0.6)
Employer contributions	20.0		15.0		1.2		2.0		5.1		5.4
Plan settlements	(83.1)		(73.7)		(1.2)		(2.0)		—		—
Participants' contributions	—		—		—		—		4.1		3.8
Benefits paid	(14.6)		(14.6)		—		—		(12.1)		(13.5)
Ending fair value	$	530.3	$	522.8	$	—	$	—	$	47.0	$	45.3
Funded status at end of year	$	(85.8)	$	(93.1)	$	(10.3)	$	(9.6)	$	(89.5)	$	(90.5)

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 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 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 Consolidated Statements of Income.

	Pension Plan						Restoration of Retirement Income Plan						Postretirement Benefit Plans
Year Ended December 31 (In millions)	2019		2018		2017		2019		2018		2017		2019		2018		2017
Service cost	$	12.9	$	14.9	$	15.5	$	0.5	$	0.4	$	0.3	$	0.2	$	0.3	$	0.6
Interest cost	20.7		23.8		26.2		0.4		0.3		0.3		5.6		5.4		7.2
Expected return on plan assets	(36.1)		(44.1)		(42.6)		—		—		—		(1.9)		(2.0)		(2.2)
Amortization of net loss	17.3		16.2		17.4		0.5		0.7		0.4		2.0		3.8		2.0
Amortization of unrecognized prior service cost (A)	—		—		(0.1)		—		0.1		0.1		(8.4)		(8.4)		(3.5)
Settlement cost	27.6		25.1		15.3		0.5		1.0		—		—		—		0.6
Total net periodic benefit cost	42.4		35.9		31.7		1.9		2.5		1.1		(2.5)		(0.9)		4.7
Less: Amount paid by unconsolidated affiliates	2.9		2.5		4.3		0.1		0.1		—		(0.6)		(0.5)		0.3
Net periodic benefit cost	$	39.5	$	33.4	$	27.4	$	1.8	$	2.4	$	1.1	$	(1.9)	$	(0.4)	$	4.4

(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 recognized, as presented in the table above, for the Pension and Restoration of Retirement Income Plans in 2019, 2018 and 2017, the Company recognized the following:

Year Ended December 31 (In millions)	2019		2018		2017
Decrease of pension expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	(16.1)	$	(14.1)	$	(2.3)
Deferral of pension expense related to pension settlement charges:
Oklahoma jurisdiction (A)	$	17.9	$	22.1	$	13.2
Arkansas jurisdiction (A)	$	1.7	$	2.1	$	1.1

(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

In addition to the net periodic benefit income and cost amounts recognized, as presented in the table above, for the postretirement benefit plans in 2019, 2018 and 2017, the Company recognized the following:

Year Ended December 31 (In millions)	2019		2018		2017
Increase of postretirement expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	1.0	$	4.4	$	6.2

(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

(In millions)	2019		2018		2017
Capitalized portion of net periodic pension benefit cost	$	3.6	$	3.8	$	4.4
Capitalized portion of net periodic postretirement benefit cost	$	0.2	$	0.2	$	1.2

Rate Assumptions

	Pension Plan and Restoration of Retirement Income Plan						Postretirement Benefit Plans
Year Ended December 31	2019		2018		2017		2019		2018		2017
Assumptions to determine benefit obligations:
Discount rate	3.15	%	4.20	%	3.60	%	3.25	%	4.30	%	3.70	%
Rate of compensation increase	4.20	%	4.20	%	4.20	%	N/A		N/A		N/A
Assumptions to determine net periodic benefit cost:
Discount rate	3.63	%	3.73	%	4.00	%	4.30	%	3.70	%	4.20	%
Expected return on plan assets	7.50	%	7.50	%	7.50	%	4.00	%	4.00	%	4.00	%
Rate of compensation increase	4.20	%	4.20	%	4.20	%	N/A		N/A		4.20	%

N/A - not applicable

The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The discount rate used to determine net benefit cost for the current year is the same discount rate used to determine the benefit obligation as of the previous year's balance sheet date, unless a plan settlement occurs during the current year that requires an updated discount rate for net periodic cost measurement. For 2019 and 2018, the Pension Plan discount rates used to determine net periodic benefit cost are disclosed on a weighted-average basis.

The overall expected rate of return on plan assets assumption was 7.50 percent in both 2019 and 2018, which was used in determining net periodic benefit cost due to recent returns on the Company's long-term investment portfolio. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans' current and expected asset allocation.

The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 7.00 percent in 2020 with the rates trending downward to 4.50 percent by 2030. The effects of a one-percentage point change in the assumed health care cost trend rate are presented in the following tables. 

ONE-PERCENTAGE POINT INCREASE
Year Ended December 31 (In millions)	2019		2018		2017
Effect on aggregate of the service and interest cost components	$	—	$	—	$	—
Effect on accumulated postretirement benefit obligations	$	0.1	$	0.1	$	0.1

ONE-PERCENTAGE POINT DECREASE
Year Ended December 31 (In millions)	2019		2018		2017
Effect on aggregate of the service and interest cost components	$	—	$	—	$	—
Effect on accumulated postretirement benefit obligations	$	0.3	$	0.3	$	0.3

Pension Plan

Pension Plan Investments, Policies and Strategies

The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability-driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.

Projected Benefit Obligation Funded Status Thresholds	<90%	95%	100%	105%	110%	115%	120%
Fixed income	50%	58%	65%	73%	80%	85%	90%
Equity	50%	42%	35%	27%	20%	15%	10%
Total	100%	100%	100%	100%	100%	100%	100%

Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below.

Asset Class	Target Allocation	Minimum	Maximum
Domestic Large Cap Equity	40%	35%	60%
Domestic Mid-Cap Equity	15%	5%	25%
Domestic Small-Cap Equity	25%	5%	30%
International Equity	20%	10%	30%

The Company has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of the Company's members and the Company's Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager's respective portfolio. 

The portfolio is rebalanced at least on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust's exposure to any asset class to exceed or fall below the established allowable guidelines.

To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:

Asset Class	Comparative Benchmark(s)
Active Duration Fixed Income	Bloomberg Barclays Aggregate
Long Duration Fixed Income	Duration blended Barclays Long Government/Credit & Barclays Universal
Equity Index	Standard & Poor's 500 Index
Mid-Cap Equity	Russell Midcap Index
	Russell Midcap Value Index
Small-Cap Equity	Russell 2000 Index
	Russell 2000 Value Index
International Equity	Morgan Stanley Capital International ACWI ex-U.S.

The fixed income managers are expected to use discretion over the asset mix of the trust assets in their efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies or its instrumentalities (which have no limits), is limited to five percent of the fixed income portfolio as measured by market value. At

least 75 percent of the invested assets must possess an investment-grade rating at or above Baa3 or BBB- by Moody's Investors Service, S&P's Global Ratings or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 15 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. The purchase of any of the Company's equity, debt or other securities is prohibited.

The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index. The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-U.S. Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-U.S. Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the U.S. All of the equities which are purchased for the international portfolio are thoroughly researched. All securities are freely traded on a recognized stock exchange, and there are no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).

For all domestic equity investment managers, no more than five percent can be invested in any one stock at the time of purchase and no more than 10 percent after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval of the Company's Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of the Company's equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager's organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.

Pension Plan Investments

The following tables summarize the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2019 and 2018. There were no Level 3 investments held by the Pension Plan at December 31, 2019 and 2018. 

(In millions)	December 31, 2019		Level 1		Level 2		Net Asset Value (A)
Common stocks	$	202.0	$	202.0	$	—	$	—
U.S. Treasury notes and bonds (B)	134.8		134.8		—		—
Mortgage- and asset-backed securities	45.8		—		45.8		—
Corporate fixed income and other securities	130.5		—		130.5		—
Commingled fund (C)	23.9		—		—		23.9
Foreign government bonds	3.0		—		3.0		—
U.S. municipal bonds	1.1		—		1.1		—
Money market fund	7.5		—		—		7.5
Mutual fund	2.4		2.4		—		—
Preferred stocks	0.7		0.7		—		—
Futures:
U.S. Treasury futures (receivable)	22.9		—		22.9		—
U.S. Treasury futures (payable)	(10.9)		—		(10.9)		—
Cash collateral	0.6		0.6		—		—
Forward contracts:
Receivable (foreign currency)	0.1		—		0.1		—
Total Pension Plan investments	564.4		$	340.5	$	192.5	$	31.4
Interest and dividends receivable	2.4
Payable to broker for securities purchased	(36.5)
Total Pension Plan assets	$	530.3

(A)GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

(B)This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.

(C)This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

(In millions)	December 31, 2018		Level 1		Level 2		Net Asset Value (A)
Common stocks	$	169.3	$	169.3	$	—	$	—
U.S. Treasury notes and bonds (B)	137.9		137.9		—		—
Mortgage- and asset-backed securities	65.9		—		65.9		—
Corporate fixed income and other securities	143.2		—		143.2		—
Commingled fund (C)	19.7		—		—		19.7
Foreign government bonds	4.4		—		4.4		—
U.S. municipal bonds	0.6		—		0.6		—
Money market fund	0.3		—		—		0.3
Mutual fund	8.0		8.0		—		—
Futures:
U.S. Treasury futures (receivable)	27.0		—		27.0		—
U.S. Treasury futures (payable)	(20.4)		—		(20.4)		—
Cash collateral	0.7		0.7		—		—
Forward contracts:
Receivable (foreign currency)	0.1		—		0.1		—
Total Pension Plan investments	556.7		$	315.9	$	220.8	$	20.0
Interest and dividends receivable	3.0
Payable to broker for securities purchased	(36.9)
Total Pension Plan assets	$	522.8

(A)GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

(B)This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.

(C)This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

As defined in the fair value hierarchy, Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan 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 Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

Expected Benefit Payments

The following table summarizes the benefit payments the Company expects to pay related to OGE Energy's Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure the Company's benefit obligation at the end of the year and include benefits attributable to estimated future employee service. 

(In millions)	Projected Benefit Payments
2020	$	58.4
2021	$	56.8
2022	$	56.2
2023	$	55.7
2024	$	56.6
After 2024	$	249.4

Postretirement Benefit Plans

In addition to providing pension benefits, the Company provides certain medical and life insurance benefits for eligible retired members. Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained at least age 55 with 10 or more years of service at the time of retirement are entitled to postretirement medical benefits, while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Eligible retirees must contribute such amount as the Company specifies from time to time toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. OG&E charges postretirement benefit costs to expense and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.

The Company's contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level, and the Company covers future annual medical inflationary cost increases up to five percent. Increases in excess of five percent annually are covered by the pre-65 aged retiree in the form of premium increases. The Company provides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to a Company-sponsored health reimbursement arrangement. Medicare-eligible retirees are able to purchase individual insurance policies supplemental to Medicare through a third-party administrator and use their health reimbursement arrangement funds for reimbursement of medical premiums and other eligible medical expenses.

Postretirement Plans Investments

The following tables summarize the postretirement benefit plans' investments that are measured at fair value on a recurring basis at December 31, 2019 and 2018. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2019 and 2018.

(In millions)	December 31, 2019		Level 1		Level 3
Group retiree medical insurance contract	$	34.8	$	—	$	34.8
Mutual funds	10.9		10.9		—
Money market fund	1.2		1.2		—
Total plan investments	$	46.9	$	12.1	$	34.8

(In millions)	December 31, 2018		Level 1		Level 3
Group retiree medical insurance contract	$	36.0	$	—	$	36.0
Mutual funds	8.9		8.9		—
Cash	0.9		0.9		—
Total plan investments	$	45.8	$	9.8	$	36.0

The group retiree medical insurance contract invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans' pro-rata share of the total assets in the contract.

The following table summarizes the postretirement benefit plans' investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

Year Ended December 31 (In millions)	2019
Group retiree medical insurance contract:
Beginning balance	$	36.0
Claims paid	(3.8)
Investment fees	(0.1)
Net unrealized gains related to instruments held at the reporting date	1.4
Interest income	0.8
Dividend income	0.5
Ending balance	$	34.8

Medicare Prescription Drug, Improvement and Modernization Act of 2003

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs. The following table summarizes the gross benefit payments the Company expects to pay related to its postretirement benefit plans, including prescription drug benefits.

(In millions)	Gross Projected Postretirement Benefit Payments
2020	$	11.2
2021	$	11.2
2022	$	11.1
2023	$	9.5
2024	$	9.4
After 2024	$	42.3

Post-Employment Benefit Plan

Disabled employees receiving benefits from the Company's Group Long-Term Disability Plan are entitled to continue participating in the Company's Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in the Company's Group Long-Term Disability Plan and their dependents, as defined in the Company's Medical Plan.

The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from the Company's Group Long-Term Disability Plan due to death, recovery from disability or eligibility for retiree medical benefits. The Company's post-employment benefit obligation was $2.1 million and $1.9 million at December 31, 2019 and 2018, respectively.

401(k) Plan

The Company provides a 401(k) Plan, and each regular full-time employee of the Company or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of the Company or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have reached age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof, (ii) a contribution made on a non-Roth after-tax basis or (iii) a Roth contribution. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have their future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, the Company contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation.

No Company contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, the Company's contribution may be directed to any available investment option in the 401(k) Plan. The Company match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their Company contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan requirements, in the event of their termination

due to death or permanent disability or upon attainment of age 65 while employed by the Company or its affiliates. The Company contributed $14.4 million, $13.2 million and $13.2 million in 2019, 2018 and 2017, respectively, to the 401(k) Plan.

Deferred Compensation Plan

The Company provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of the Company and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace.

Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers. The Company matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of the Company or termination of the plan. Deferrals, plus any Company match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2019, those investment options included a Company Common Stock fund, whose value was determined based on the stock price of the Company's common stock. The Company accounts for the contributions related to the Company's executive officers in this plan as Accrued Benefit Obligations, and the Company accounts for the contributions related to the Company's directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in the Consolidated Balance Sheets. The appreciation of these investments is accounted for as Other Income, and the increase in the liability under the plan is accounted for as Other Expense in the Consolidated Statements of Income.

Supplemental Executive Retirement Plan

The Company provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of the Company's Board of Directors who may not otherwise qualify for a sufficient level of benefits under the Company's Pension Plan and Restoration of Retirement Income Plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limitations of the Code. For the actuarial equivalence calculations, the supplemental executive retirement plan provides that (i) mortality rates shall be based on the unisex mortality table issued under Internal Revenue Service 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 (ii) the interest rate shall be five percent.

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Quarterly Financial Data

12 Months Ended

Dec. 31, 2019

Quarterly Financial Data [Abstract]

Quarterly Financial Information [Text Block]

Quarterly Financial Data (Unaudited)

Due to the seasonal fluctuations and other factors of the Company's businesses, the operating results for interim periods are not necessarily indicative of the results that may be expected for the year. In the Company's opinion, the following quarterly financial data includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present such amounts. Summarized consolidated quarterly unaudited financial data is as follows:

Quarter Ended (In millions, except per share data)		March 31		June 30		September 30		December 31		Total
Operating revenues	2019	$	490.0	$	513.7	$	755.4	$	472.5	$	2,231.6
	2018	$	492.7	$	567.0	$	698.8	$	511.8	$	2,270.3
Operating income	2019	$	49.7	$	110.0	$	274.3	$	70.3	$	504.3
	2018	$	66.6	$	137.7	$	227.3	$	58.0	$	489.6
Net income	2019	$	47.1	$	100.2	$	250.9	$	35.4	$	433.6
	2018	$	55.0	$	110.7	$	205.1	$	54.7	$	425.5
Basic earnings per average common share (A)	2019	$	0.24	$	0.50	$	1.25	$	0.18	$	2.17
	2018	$	0.28	$	0.55	$	1.03	$	0.27	$	2.13
Diluted earnings per average common share (A)	2019	$	0.24	$	0.50	$	1.25	$	0.18	$	2.16
	2018	$	0.27	$	0.55	$	1.02	$	0.27	$	2.12

(A)Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Common stock, par value $0.01 per share; authorized 450.0 shares; and outstanding 200.1 shares and 199.7 shares, respectively	$ 2.0	$ 2.0
Premium on common stock	1,129.3	1,125.7
Retained earnings	3,036.1	2,906.3
Accumulated other comprehensive loss, net of tax	(27.9)	(28.9)
Total stockholders' equity	4,139.5	4,005.1
Unamortized debt expense	(24.2)	(22.9)
Total long-term debt	3,195.2	3,146.9
Less: long-term debt due within one year	0.0	(250.0)
Total long-term debt (excluding long-term debt due within one year)	3,195.2	2,896.9
Total capitalization (including long-term debt due within one year)	7,334.7	7,152.0
Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount	(10.5)	(10.2)
Senior Notes [Member] | Series Due January 15, 2019 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 0.0	250.0
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Senior Notes [Member] | Series Due July 15, 2027 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 125.0	125.0
Debt Instrument, Interest Rate, Stated Percentage	6.65%
Senior Notes [Member] | Series Due April 15, 2028 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 100.0	100.0
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Senior Notes [Member] | Series Due August 15, 2028 [Member] [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 400.0	400.0
Debt Instrument, Interest Rate, Stated Percentage	3.80%
Senior Notes [Member] | Series Due March 15, 2030 | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 300.0	0.0
Debt Instrument, Interest Rate, Stated Percentage	3.30%
Senior Notes [Member] | Series Due January 15, 2036 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 110.0	110.0
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Senior Notes [Member] | Series Due February 1, 2038 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 200.0	200.0
Debt Instrument, Interest Rate, Stated Percentage	6.45%
Senior Notes [Member] | Series Due June 1, 2040 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250.0	250.0
Debt Instrument, Interest Rate, Stated Percentage	5.85%
Senior Notes [Member] | Series Due May 15, 2041 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250.0	250.0
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Senior Notes [Member] | Series Due May 1, 2043 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250.0	250.0
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Senior Notes [Member] | Series Due March 15, 2044 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250.0	250.0
Debt Instrument, Interest Rate, Stated Percentage	4.55%
Senior Notes [Member] | Series Due December 15, 2044 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250.0	250.0
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Senior Notes [Member] | Series due August 15, 2047 [Member] [Domain] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 300.0	300.0
Debt Instrument, Interest Rate, Stated Percentage	3.85%
Senior Notes [Member] | Series due April 1, 2047 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 300.0	300.0
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Long-term Debt [Member] | Due August 31, 2062 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 9.5	9.6
Debt Instrument, Interest Rate, Stated Percentage	3.80%
Debentures Subject to Mandatory Redemption [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Total long-term debt	$ 135.4
Debentures Subject to Mandatory Redemption [Member] | Garfield Industrial Authority Bond [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	47.0	47.0
Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority Bond Due 2025 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	32.4	32.4
Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority Bond Due 2027 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 56.0	$ 56.0

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Summary of Significant Accounting Policies Accounting Records (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets, Current	$ 48.7	$ 18.5
Regulatory Assets, Noncurrent	306.0	285.8
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	(1.7)
Deferred Storm and Property Reserve Deficiency, Current	2.7
Regulatory Liability, Current	29.0	36.6
Pension Plans, Defined Benefit [Member] | Defined Benefit Plans Income Loss [Member]
Components of Benefit Obligation Regulatory Asset	160.5	185.3
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	11.4
Other Postretirement Benefit Plans, Defined Benefit [Member] | Defined Benefit Plans Income Loss [Member]
Components of Benefit Obligation Regulatory Asset	23.3	25.6
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	2.8
Other Postretirement Benefit Plans, Defined Benefit [Member] | Prior Service Cost [Member]
Components of Benefit Obligation Regulatory Asset	(16.6)	$ (22.7)
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	(6.1)
Regulatory Asset [Member]
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	$ 8.1

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

The Company's future purchase obligations and commitments estimated for the next five years are as follows: 

(In millions)	2020		2021		2022		2023		2024		Total
Purchase obligations and commitments:
Minimum purchase commitments	$	82.6	$	55.1	$	50.4	$	50.4	$	32.9	$	271.4
Expected wind purchase commitments	55.7		56.0		56.4		56.8		57.5		282.4
Long-term service agreement commitments	2.4		2.4		2.4		13.8		32.1		53.1
Environmental compliance plan expenditures	0.4		—		—		—		—		0.4
Total purchase obligations and commitments	$	141.1	$	113.5	$	109.2	$	121.0	$	122.5	$	607.3

Schedule of Wind Power Purchases [Table Text Block]

The following table summarizes OG&E's wind power purchase contracts.

Company	Location	Original Term of Contract	Expiration of Contract	MWs
CPV Keenan	Woodward County, OK	20 years	2030	152.0
Edison Mission Energy	Dewey County, OK	20 years	2031	130.0
NextEra Energy	Blackwell, OK	20 years	2032	60.0

The following table summarizes OG&E's wind power purchases for the years ended December 31, 2019, 2018 and 2017. 

Year Ended December 31 (In millions)	2019		2018		2017
CPV Keenan	$	27.2	$	27.0	$	29.0
Edison Mission Energy	23.1		21.7		22.1
NextEra Energy	7.4		6.8		7.4
FPL Energy (A)	—		2.1		2.6
Total wind power purchased	$	57.7	$	57.6	$	61.1

(A)OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $1.1, $1.1 and $1.4, respectively	$ 1.1	$ 1.1	$ 1.4
Net gain (loss) arising during the period, net of tax of $(2.6), ($4.7) and $0.2, respectively	(2.6)	(4.7)	0.2
Amortization of prior service credit, net of tax of $0.0, $0.0 and $0.0, respectively	0.0	0.0	0.0
Postretirement plans:
Prior service cost arising during the period, net of tax of $0.0, $0.0 and $4.0, respectively	0.0	0.0	4.0
Amortization of deferred net gain, net of tax of $0.0, $0.0 and $0.0, respectively	0.0	0.0	0.0
Net gain (loss) arising during the period, net of tax of ($0.1), $0.7 and ($0.2), respectively	(0.1)	0.7	(0.2)
Amortization of prior service credit, net of tax of ($0.6), ($0.6) and ($0.3), respectively	(0.6)	(0.6)	(0.3)
Amortization of deferred interest rate swap hedging losses, net of tax of $0, $0 and $0.0, respectively	0.0	0.0	0.0
Pension Plans [Member]
Pension Plan and Restoration of Retirement Income Plan:
Settlement cost, net of tax of $2.7, $1.6 and $1.4, respectively	2.7	1.6	1.4
Other Postretirement Benefits Plan [Member]
Pension Plan and Restoration of Retirement Income Plan:
Settlement cost, net of tax of $2.7, $1.6 and $1.4, respectively	$ 0.0	$ 0.0
Postretirement plans:
Settlement cost, net of tax of $0.0, $0.0 and $0.2, respectively			$ 0.2

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Investment in Unconsolidated Affiliate and Related Party Transactions Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Expected Settlement Charge	$ 17.3
Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	15.9	$ 16.3	$ 14.0
Operating Costs Charged [Member] | OGE Energy [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	0.5	0.6	2.3
Natural Gas Transportation [Member] | Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	41.2	37.9	35.0
Natural Gas Purchases [Member] | Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	(6.0)	(3.2)	(2.1)
Employment Costs [Member] | OGE Energy [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	23.2	27.5	$ 29.5
Excluding Fuel Purchases [Member]
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 0.8	$ 1.7

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Investment in Unconsolidated Affiliate and Related Party Transactions Reconciliation of Basis Difference (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Basis Difference [Line Items]
Amortization of basis difference	[1]	$ 22.1	$ 28.4	$ 28.5
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		652.5	$ 680.3
OGE Energy [Member]
Reconciliation of Basis Difference [Line Items]
Amortization of basis difference	[2]	$ 27.8

[1] Includes loss on dilution, net of proportional basis difference recognition.

[2] Includes proportional basis difference recognition due to dilution.

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Income Taxes (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Regulatory Liability, Noncurrent		$ 1,223.5	$ 1,270.7
Current Federal Tax Expense (Benefit)		(6.4)	(1.9)	$ 4.9
Current State and Local Tax Expense (Benefit)		5.1	(4.4)	(4.2)
Current Income Tax Expense (Benefit)		(1.3)	(6.3)	0.7
Deferred Federal Income Tax Expense (Benefit)		48.5	74.7	(75.9)
Deferred State and Local Income Tax Expense (Benefit)		(17.4)	3.7	26.0
Deferred Income Tax Expense (Benefit)		31.1	78.4	(49.9)
Investment Tax Credit		0.0	0.1	(0.1)
Income Tax Expense (Benefit)		$ 29.8	$ 72.2	$ (49.3)	[1]
Statutory federal tax rate		21.00%	21.00%	35.00%
Federal deferred tax revaluation		0.00%	0.40%	(41.20%)
Federal renewable energy credit (A)	[2]	(6.00%)	(5.10%)	(4.80%)
Remeasurement of state deferred tax liabilities		(0.80%)	(0.40%)	0.40%
401(k) dividends		(0.40%)	(0.30%)	(0.50%)
Federal investment tax credits, net		0.00%	0.00%	(0.10%)
State income taxes, net of federal income tax benefit		(1.20%)	0.40%	2.00%
Effective Income Tax Rate Reconciliation, Executive Compensation Limitation, Percent		0.20%	0.20%	0.00%
Amortization of net unfunded deferred taxes		(4.50%)	(2.10%)	0.70%
Other		(0.70%)	0.40%	(0.10%)
Effective income tax rate		6.40%	14.50%	(8.60%)
Accrued liabilities		$ (10.7)	$ (12.5)
Accrued vacation		(2.1)	(2.3)
Uncollectible accounts		(0.4)	(0.4)
Accelerated depreciation and other property related differences		1,656.8	1,605.3
Investment in Enable		478.2	469.9
Regulatory assets		28.4	17.4
Income taxes recoverable from customers, net		(229.9)	(239.6)
Company Pension Plan		4.1	7.6
Bond redemption-unamortized costs		2.2	2.4
Derivative instruments		1.6	1.7
Federal tax credits		(238.0)	(237.8)
State tax credits		(185.8)	(156.0)
Postretirement medical and life insurance benefits		(23.3)	(23.6)
Net operating losses		(16.6)	(20.2)
Regulatory liabilities		(68.1)	(78.8)
Asset retirement obligations		(19.2)	(21.5)
Deferred federal investment tax credits		(1.8)	(1.8)
Other		0.4	1.1
Total deferred income tax liabilities, net		1,375.8	1,310.9
Unrecognized Tax Benefits		20.7	20.7	$ 20.7		$ 20.7
Current year additions		0.0	0.0	$ 0.0
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		0.0
Tax Credit Carryforward, Deferred Tax Asset		$ 238.0	$ 237.8
Stock-based compensation		(1.20%)	0.00%	0.00%
State operating loss [Member]
Operating Loss Carryforwards		$ 371.6
Deferred Tax Assets, Operating Loss Carryforwards, State and Local		16.6
Federal tax credits [Member]
Federal tax credits		(238.0)
Tax Credit Carryforward, Amount		238.0
Tax Credit Carryforward, Deferred Tax Asset		238.0
Oklahoma investment tax credits [Member]
State tax credits		(145.3)
Tax Credit Carryforward, Amount		183.9
Oklahoma capital investment board credits [Member]
State tax credits		(12.4)
Tax Credit Carryforward, Amount		12.4
Oklahoma zero emission tax credits [Member]
State tax credits		(28.0)
Tax Credit Carryforward, Amount		34.9
Louisiana inventory credits
State tax credits		(0.1)
Tax Credit Carryforward, Amount		0.2
Og and E [Member]
Unrecognized Tax Benefits		$ 16.4	$ 16.4	$ 16.4

[1] The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act.

[2] Represents credits associated with the production from OG&E's wind farms.

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Short-Term Debt and Credit Facilities

12 Months Ended

Dec. 31, 2019

Short-term Debt [Abstract]

Short-Term Debt and Credit Facilities

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 agreement. As of December 31, 2019, the Company had $112.0 million 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 December 31, 2019.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
	(In millions)
OGE Energy (B)	$	450.0	$	112.0	2.06	%	(D)	March 8, 2023
OG&E (C)	450.0		0.3		1.00	%	(D)	March 8, 2023
Total	$	900.0	$	112.3	2.06	%

(A)Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 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 and OG&E's credit facilities each have a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent, as defined in each such facility. The Company and OG&E's facilities each also contain covenants which restrict the respective borrower and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. The Company and OG&E's facilities are each subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facilities, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in each such facility), nonpayment of uninsured judgments in excess of $100.0 million and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods.

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.

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Rate Matters and Regulation

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Rate Matters and Regulation

Rate Matters and Regulation

Regulation and Rates

OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2019, 86 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and six percent to the FERC.

The OCC and the APSC require that, among other things, (i) the Company permits the OCC and the APSC access to the books and records of the Company and its affiliates relating to transactions with OG&E; (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers; and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions. In addition, the FERC has access to the books and records of the Company and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

Completed Regulatory Matters

Arkansas 2018 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 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 finding that the plants to be acquired were used and useful and that the acquisition of the plants was in the public interest. The APSC also approved the depreciation rates to be applied to the acquired plants. The cost OG&E paid for the acquired plants was reviewed by the APSC in OG&E's 2019 Formula Rate Plan filing, and parties reached a settlement agreement requesting the APSC to approve the cost of the acquisitions. OG&E is awaiting a final decision from the APSC.

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.

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. On December 12, 2019, the OCC issued an order deeming OG&E's electric generation, purchased power and fuel procurement costs were prudent.

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. On November 21, 2019, the FERC approved the settlement agreement.

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 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 required SPP to charge for these upgrades beginning in 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 companies that were net payers of Z2 charges 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 Circuit. In July 2018, that court 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 November 2017 rehearing denial, ruled that SPP violated its tariff to charge for the 2008 - 2015 period in 2016, held that the SPP tariff provision that prohibited those charges could not be waived 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 that SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement and of the applicable tariff. 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. SPP's response to OG&E's filing agreed that OG&E should be entitled to keep its Z2 payments and argued that SPP should not be held responsible for those payments if refunds are ordered. Further, SPP has requested the FERC to

negotiate a global settlement with all impacted parties, including other project sponsors who, like OG&E, have also filed complaints at FERC contending that the payments they have received cannot properly be unwound.

On February 20, 2020, the FERC denied OG&E's request for rehearing of its February 28, 2019 order, denying the waiver and ruling that SPP must seek refunds from project sponsors for Z2 payments for the 2008 - 2015 period and pay them back to transmission owners. The FERC also denied SPP's request for a stay and for institution of settlement procedures. The FERC stated it would not institute settlement procedures unless parties on both sides of the matter requested them. The FERC did not rule on OG&E's complaint or the complaints of other project sponsors, or consider SPP's refund plan. The FERC thus has not set any date for payment of refunds. The FERC's order denying the waiver and requiring refunds is now appealable, and OG&E intends to file a timely appeal.

The Company cannot predict the outcome of this proceeding based on currently available information, and as of December 31, 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.

SPP has recently proposed eliminating Attachment Z2 revenue crediting and replacing it with a different mechanism that would provide project sponsors such as OG&E the same level of recovery they would receive if payments continued under Attachment Z2. The FERC rejected that proposal to the extent it would limit recovery to the amount of the upgrade sponsor's directly assigned upgrade costs with interest, finding that providing the possibility of recovering greater than the cost of the investment could serve as an incentive for entities to build merchant transmission projects. The SPP can resubmit a proposal without that cap.

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 was held on December 17, 2019. The primary question before the APSC is whether a company can utilize an environmental compliance plan rider while also regulated under a formula rate plan. OG&E is awaiting a final decision from the APSC.

Arkansas 2019 Formula Rate Plan Filing

OG&E filed its second evaluation report under its Formula Rate Plan in October 2019. On January 29, 2020, OG&E, the General Staff of the APSC and the Office of the Arkansas Attorney General filed a settlement agreement requesting the APSC approve a $5.2 million revenue increase, with rates effective April 1, 2020. The settling parties agreed that the Series I grid modernization projects are prudent in both action and cost and that the Series II grid modernization projects are prudent in action only and the determination of prudence of costs will be reserved until the actual historical costs are reviewed. The settling parties also agreed that OG&E will no longer use projections for the remaining initial term or extension of its current Formula Rate Plan and that all costs will be included for recovery for the first time in the historical year. A hearing was held on February 5, 2020, and OG&E is awaiting a final decision from the APSC.

Oklahoma Grid Enhancement Plan

On February 24, 2020, OG&E filed an application with the OCC for approval of a mechanism that allows for interim recovery of the costs associated with its grid enhancement plan. The plan includes approximately $800 million of strategic, data-driven investments, over five years, covering grid resiliency, grid automation, communication systems and technology platforms and applications. A procedural schedule has not been set by the OCC.

Oklahoma Retail Electric Supplier Certified Territory Act Causes

Certain rural electric cooperative electricity suppliers have filed complaints with the OCC alleging that OG&E has violated the Oklahoma Retail Electric Supplier Certified Territory Act. OG&E believes it is lawfully serving customers specifically exempted from this act and has presented evidence and testimony to the OCC supporting its position. If the OCC were to ultimately find that some or all of the customers being served are not exempted, then OG&E would have to evaluate the recoverability of some plant investment made to serve these customers. OG&E may also be required to reimburse certified territory suppliers for an amount of lost revenue.

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Common Stock, Shares, Outstanding		199.7
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0.0
Balance at Dec. 31, 2016	$ 3,443.8	$ 2.0	$ 1,103.8	$ 2,367.3	$ (29.3)
Comprehensive income (loss)
Net income	619.0	$ 0.0	0.0	619.0	0.0
Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification, Number of Shares		0.0
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0.0
Other comprehensive income, net of tax	10.6	$ 0.0	0.0	0.0	10.6
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Net Income	22.3	$ 0.0	0.0	26.8	(4.5)
Dividends, Common Stock, Cash, Number of Shares		0.0
Dividends declared on common stock	(253.6)	$ 0.0	0.0	(253.6)	0.0
Stock Issued During Period, Shares, New Issues		0.0
Expense of common stock	(0.1)	$ 0.0	(0.1)	0.0	0.0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0.0
Stock-based compensation	9.1	$ 0.0	9.1	0.0	0.0
Balance at Dec. 31, 2017	$ 3,851.1	$ 2.0	1,112.8	2,759.5	(23.2)
Comprehensive income (loss)
DIVIDENDS DECLARED PER COMMON SHARE	$ 1.2700
Common Stock, Shares, Outstanding		199.7
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0.0
Net income	$ 425.5	$ 0.0	0.0	425.5	0.0
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0.0
Other comprehensive income, net of tax	(5.7)	$ 0.0	0.0	0.0	(5.7)
Dividends, Common Stock, Cash, Number of Shares		0.0
Dividends declared on common stock	(278.7)	$ 0.0	0.0	(278.7)	0.0
Stock Issued During Period, Shares, New Issues		0.0
Expense of common stock	(0.1)	$ 0.0	(0.1)	0.0	0.0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0.0
Stock-based compensation	13.0	$ 0.0	13.0	0.0	0.0
Balance at Dec. 31, 2018	$ 4,005.1	$ 2.0	1,125.7	2,906.3	(28.9)
Comprehensive income (loss)
DIVIDENDS DECLARED PER COMMON SHARE	$ 1.3950
Common Stock, Shares, Outstanding	199.7	199.7
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0.0
Net income	$ 433.6	$ 0.0	0.0	433.6	0.0
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0.0
Other comprehensive income, net of tax	1.0	$ 0.0	0.0	0.0	1.0
Dividends, Common Stock, Cash, Number of Shares		0.0
Dividends declared on common stock	(303.8)	$ 0.0	0.0	(303.8)	0.0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0.4
Stock-based compensation	3.6	$ 0.0	3.6	0.0	0.0
Balance at Dec. 31, 2019	$ 4,139.5	$ 2.0	$ 1,129.3	$ 3,036.1	$ (27.9)
Comprehensive income (loss)
DIVIDENDS DECLARED PER COMMON SHARE	$ 1.5050
Common Stock, Shares, Outstanding	200.1	200.1

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Leases, Codification Topic 842

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases of Lessee Disclosure

Leases

Based on its evaluation of all contracts under ASC 842, as described in Note 1, 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

OG&E 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 $6.0 million, $4.9 million and $6.2 million for the years ended December 31, 2019, 2018 and 2017, respectively. The following table presents amounts recognized for operating leases in the Company's 2019 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.

(In millions)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	5.6
Right-of-use assets obtained in exchange for new operating lease liabilities	$	10.7
(Dollars in millions)	December 31, 2019
Right-of-use assets at period end (A)	$	40.9
Operating lease liabilities at period end (B)	$	45.8
Operating lease weighted-average remaining lease term (in years)	13.1
Operating lease weighted-average discount rate	3.9		%

	December 31,
Future minimum operating lease payments as of:	2019		2018(C)(D)
(In millions)
2019	$	—	$	22.1
2020	6.2		3.9
2021	5.8		3.5
2022	5.2		2.9
2023	5.2		2.9
2024	3.1		3.0
Thereafter	34.7		34.6
Total future minimum lease payments	60.2		$	72.9
Less: Imputed interest	14.4
Present value of net minimum lease payments	$	45.8

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

(B) Included in Other Deferred Credits and Other Liabilities in the 2019 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.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Information [Abstract]

Cash Flow, Supplemental Disclosures [Text Block]

Supplemental Cash Flow Information

The following table presents information about investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments. Cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds are also presented in the table.

Year Ended December 31 (In millions)	2019		2018		2017
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement	$	28.9	$	(9.2)	$	(2.6)
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of interest capitalized) (A)	$	152.2	$	153.8	$	139.6
Income taxes (net of income tax refunds)	$	5.5	$	2.8	$	(16.0)

(A)Net of interest capitalized of $2.8 million, $11.7 million and $18.0 million in 2019, 2018 and 2017, respectively.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Taxes [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The items comprising income tax expense (benefit) are as follows: 

Year Ended December 31 (In millions)	2019		2018		2017
Provision (benefit) for current income taxes:
Federal	$	(6.4)	$	(1.9)	$	4.9
State	5.1		(4.4)		(4.2)
Total provision (benefit) for current income taxes	(1.3)		(6.3)		0.7
Provision (benefit) for deferred income taxes, net:
Federal	48.5		74.7		(75.9)
State	(17.4)		3.7		26.0
Total provision (benefit) for deferred income taxes, net	31.1		78.4		(49.9)
Deferred federal investment tax credits, net	—		0.1		(0.1)
Total income tax expense (benefit)	$	29.8	$	72.2	$	(49.3)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The following schedule reconciles the statutory tax rates to the effective income tax rate:

Year Ended December 31	2019		2018		2017
Statutory federal tax rate	21.0	%	21.0	%	35.0	%
Executive compensation limitation	0.2		0.2		—
Federal renewable energy credit (A)	(6.0)		(5.1)		(4.8)
Amortization of net unfunded deferred taxes	(4.5)		(2.1)		0.7
State income taxes, net of federal income tax benefit	(1.2)		0.4		2.0
Stock-based compensation	(1.2)		—		—
Remeasurement of state deferred tax liabilities	(0.8)		(0.4)		0.4
Other	(0.7)		0.4		(0.1)
401(k) dividends	(0.4)		(0.3)		(0.5)
Federal deferred tax revaluation	—		0.4		(41.2)
Federal investment tax credits, net	—		—		(0.1)
Effective income tax rate	6.4	%	14.5	%	(8.6)	%

(A)Represents credits associated with the production from OG&E's wind farms.

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

The components of Deferred Income Taxes at December 31, 2019 and 2018 were as follows:

December 31 (In millions)	2019		2018
Deferred income tax liabilities, net:
Accelerated depreciation and other property related differences	$	1,656.8	$	1,605.3
Investment in Enable	478.2		469.9
Regulatory assets	28.4		17.4
Company Pension Plan	4.1		7.6
Bond redemption-unamortized costs	2.2		2.4
Derivative instruments	1.6		1.7
Other	0.4		1.1
Federal tax credits	(238.0)		(237.8)
Income taxes recoverable from customers, net	(229.9)		(239.6)
State tax credits	(185.8)		(156.0)
Regulatory liabilities	(68.1)		(78.8)
Postretirement medical and life insurance benefits	(23.3)		(23.6)
Asset retirement obligations	(19.2)		(21.5)
Net operating losses	(16.6)		(20.2)
Accrued liabilities	(10.7)		(12.5)
Accrued vacation	(2.1)		(2.3)
Deferred federal investment tax credits	(1.8)		(1.8)
Uncollectible accounts	(0.4)		(0.4)
Total deferred income tax liabilities, net	$	1,375.8	$	1,310.9

Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]

Following is a reconciliation of the Company's total gross unrecognized tax benefits as of the years ended December 31, 2019, 2018 and 2017.

(In millions)	2019		2018		2017
Balance at January 1	$	20.7	$	20.7	$	20.7
Tax positions related to current year:
Additions	—		—		—
Balance at December 31	$	20.7	$	20.7	$	20.7

Summary of Tax Credit Carryforwards [Table Text Block]

The following table summarizes these carry forwards:

(In millions)	Carry Forward Amount		Deferred Tax Asset		Earliest Expiration Date
State operating loss	$	371.6	$	16.6	2030
Federal tax credits	$	238.0	$	238.0	2032
State tax credits:
Oklahoma investment tax credits	$	183.9	$	145.3	N/A
Oklahoma capital investment board credits	$	12.4	$	12.4	N/A
Oklahoma zero emission tax credits	$	34.9	$	28.0	2020
Louisiana inventory credits	$	0.2	$	0.1	2020

N/A - not applicable

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Investment in Unconsolidated Affiliate and Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Summarized Balance Sheet Financial Information, Equity Method Investment [Table Text Block]

Summarized unaudited financial information for 100 percent of Enable is presented below as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017.

	December 31,
Balance Sheet	2019		2018
(In millions)
Current assets	$	389	$	449
Non-current assets	$	11,877	$	11,995
Current liabilities	$	780	$	1,615
Non-current liabilities	$	4,077	$	3,211

Summarized Income Statement Financial Information, Equity Method Investment [Table Text Block]

	Year Ended December 31,
Income Statement	2019		2018		2017
(In millions)
Total revenues	$	2,960	$	3,431	$	2,803
Cost of natural gas and NGLs	$	1,279	$	1,819	$	1,381
Operating income	$	569	$	648	$	528
Net income	$	360	$	485	$	400

Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Table Text Block]

The following table reconciles OGE Energy's equity in earnings of unconsolidated affiliates for the years ended December 31, 2019, 2018 and 2017.

	Year Ended December 31,
(In millions)	2019			2018			2017
Enable net income	$	360.0		$	485.3		$	400.3
OGE Energy's percent ownership at period end	25.5		%	25.6		%	25.7		%
OGE Energy's portion of Enable net income	$	91.8		$	124.4		$	102.7
Amortization of basis difference and dilution recognition (A)	22.1			28.4			28.5
Equity in earnings of unconsolidated affiliates	$	113.9		$	152.8		$	131.2

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

Reconciliation of Basis Difference [Table Text Block]

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 December 31, 2019.

(In millions)
Basis difference at December 31, 2018	$	680.3
Amortization of basis difference (A)	(27.8)
Basis difference at December 31, 2019	$	652.5

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

Schedule of Related Party Transactions [Table Text Block]

The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2019, 2018 and 2017.

	Year Ended December 31,
(In millions)	2019		2018		2017
Operating revenues:
Electricity to power electric compression assets	$	15.9	$	16.3	$	14.0
Cost of sales:
Natural gas transportation services	$	41.2	$	37.9	$	35.0
Natural gas (sales) purchases	$	(6.0)	$	(3.2)	$	(2.1)

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Summary of Significant Accounting Policies Asset Retirement Obligation (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1		$ 83.9	$ 75.1
Accretion expense		1.0	3.4
Revisions in estimated cash flows	[1]	(2.4)	6.8
Liabilities settled	[2]	(9.0)	(1.4)
Balance at December 31		$ 73.5	$ 83.9

[1] Assumptions changed related to the estimated cost of the removal of wind turbine assets and asbestos removal at OG&E's generating facilities.

[2] Asset retirement obligations were settled for asbestos removal and for the closure of an ash pond at OG&E's generating facilities.

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Accounting Pronouncements New Accounting Pronouncement (Details) - USD ($) $ in Millions	Dec. 31, 2019		Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Lease, Right-of-Use Asset	$ 40.9	[1]	$ 34.5
Operating Lease, Liability	$ 45.8	[2]	$ 39.1

[1] Included in Property, Plant and Equipment in the 2019 Consolidated Balance Sheet.

[2] Included in Other Deferred Credits and Other Liabilities in the 2019 Consolidated Balance Sheet.

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Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Operating revenues	$ 472.5		$ 755.4		$ 513.7		$ 490.0		$ 511.8		$ 698.8		$ 567.0		$ 492.7		$ 2,231.6		$ 2,270.3		$ 2,261.1
Operating income	70.3		274.3		110.0		49.7		58.0		227.3		137.7		66.6		504.3		489.6		531.9
Net income	$ 35.4		$ 250.9		$ 100.2		$ 47.1		$ 54.7		$ 205.1		$ 110.7		$ 55.0		$ 433.6		$ 425.5		$ 619.0
Basic earnings per average common share attributable to OGE Energy common shareholders	$ 0.18	[1]	$ 1.25	[1]	$ 0.50	[1]	$ 0.24	[1]	$ 0.27	[1]	$ 1.03	[1]	$ 0.55	[1]	$ 0.28	[1]	$ 2.17	[1]	$ 2.13	[1]	$ 3.10
Diluted earnings per average common share attributable to OGE Energy common shareholders	$ 0.18	[1]	$ 1.25	[1]	$ 0.50	[1]	$ 0.24	[1]	$ 0.27	[1]	$ 1.02	[1]	$ 0.55	[1]	$ 0.27	[1]	$ 2.16	[1]	$ 2.12	[1]	$ 3.10

[1] Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

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Retirement Plans and Postretirement Benefit Plans Postretirement Benefit Plans (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019		Dec. 31, 2018
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Employer contributions		$ 20.0	$ 15.0
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Level 3 Asset Value, Beginning of Period		36.0
Interest income		0.8
Dividend income		0.5
Unrealized gains		1.4
Administrative expenses and charges		(0.1)
Claims paid		(3.8)
Level 3 Asset Value, End of Period		34.8	36.0
Postretirement Plan, Expected Future Benefit Payments, Next Twelve Months					$ 11.2
Postretirement Plan, Expected Future Benefit Payments, Year Two					11.2
Postretirement Plan, Expected Future Benefit Payments, Year Three					11.1
Postretirement Plan, Expected Future Benefit Payments in Year Four					9.5
Postretirement Plan, Expected Future Benefit Payments, Year Five					9.4
Postretirement Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter					42.3
Postemployment Benefits Liability					2.1		$ 1.9
Defined Contribution Plan, Cost		$ 14.4	13.2	$ 13.2
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay		5.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Match		200.00%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value		$ 34.8	36.0		34.8		36.0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Claims Paid		3.8
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Administrative Expenses and Charges		0.1
Unrealized gains		1.4
Interest income		0.8
Dividend income		0.5
Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.9
Fair Value of Plan Assets, Ending			0.9
Fair Value, Inputs, Level 1 [Member] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.9
Fair Value of Plan Assets, Ending			0.9
Fair Value, Inputs, Level 3 [Member] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending			0.0
Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		615.9	687.5
Service cost		12.9	14.9	15.5
Interest cost		20.7	23.8	26.2
Plan settlements		(83.1)	(73.7)
Actuarial losses (gains)		64.3	(22.0)
Benefit Obligation, Ending		616.1	615.9	687.5
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		522.8	635.3
Actual return on plans' assets		85.2	(39.2)
Employer contributions		20.0	15.0
Plan settlements		(83.1)	(73.7)
Fair Value of Plan Assets, Ending		530.3	522.8	635.3
Funded Status of Plan					$ (85.8)		$ (93.1)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		12.9	14.9	15.5
Interest cost		20.7	23.8	26.2
Expected return on plan assets		(36.1)	(44.1)	(42.6)
Amortization of unrecognized prior service cost	[1]	0.0	0.0	(0.1)
Settlement cost		27.6	25.1	15.3
Net periodic benefit cost		42.4	35.9	31.7
Amount paid by unconsolidated affiliates		2.9	2.5	4.3
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		39.5	33.4	27.4
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Capitalized Portion of Net Periodic Benefit Cost		$ 3.6	$ 3.8	$ 4.4
Assumptions Used Calculating Benefit Obligation, Discount Rate				3.60%	3.15%		4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.63%	3.73%	4.00%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		7.50%	7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				4.20%	4.20%		4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		4.20%	4.20%	4.20%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ (14.6)	$ (14.6)
Defined Benefit Plan, Plan Assets, Benefits Paid		14.6	14.6
Accumulated Benefit Obligation					$ 563.3		$ 561.9
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		0.0	0.0
Pension Plan [Member] | Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[2]	19.7
Fair Value of Plan Assets, Ending	[2]	23.9	19.7
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Alternative Investment					23.9	[3],[4]	19.7	[2],[5]
Pension Plan [Member] | Money market funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.3
Fair Value of Plan Assets, Ending		7.5	0.3
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Alternative Investment					7.5	[3]	0.3	[5]
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[2]	0.0
Fair Value of Plan Assets, Ending	[2]	0.0	0.0
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Money market funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0	0.0
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[2]	0.0
Fair Value of Plan Assets, Ending	[2]	0.0	0.0
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Money market funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0	0.0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0	0.0
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		135.8	149.4
Service cost		0.2	0.3	$ 0.6
Interest cost		5.6	5.4	7.2
Plan settlements		0.0	0.0
Actuarial losses (gains)		2.9	(9.6)
Benefit Obligation, Ending		136.5	135.8	149.4
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		45.3	50.2
Actual return on plans' assets		4.6	(0.6)
Employer contributions		5.1	5.4
Plan settlements		0.0	0.0
Fair Value of Plan Assets, Ending		47.0	45.3	50.2
Funded Status of Plan					$ (89.5)		$ (90.5)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.2	0.3	0.6
Interest cost		5.6	5.4	7.2
Expected return on plan assets		(1.9)	(2.0)	(2.2)
Amortization of unrecognized prior service cost	[1]	(8.4)	(8.4)	(3.5)
Settlement cost		0.0	0.0	0.6
Net periodic benefit cost		(2.5)	(0.9)	4.7
Amount paid by unconsolidated affiliates		(0.6)	(0.5)	0.3
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		(1.9)	(0.4)	4.4
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Capitalized Portion of Net Periodic Benefit Cost		$ 0.2	$ 0.2	$ 1.2
Assumptions Used Calculating Benefit Obligation, Discount Rate				3.70%	3.25%		4.30%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.30%	3.70%	4.20%
Health Care Cost Trend Rate Assumed for Next Fiscal Year							7.00%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		4.00%	4.00%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase				4.20%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ (12.1)	$ (13.5)
Defined Benefit Plan, Plan Assets, Benefits Paid		12.1	13.5
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		0.0	0.0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Group Retiree Medical Insurance Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		36.0
Fair Value of Plan Assets, Ending		34.8	36.0
Other Postretirement Benefit Plans, Defined Benefit [Member] | U.S. Equity Mutual Funds Investment [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		8.9
Fair Value of Plan Assets, Ending		10.9	8.9
Other Postretirement Benefit Plans, Defined Benefit [Member] | Money market funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		1.2
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		9.8
Fair Value of Plan Assets, Ending		12.1	9.8
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Group Retiree Medical Insurance Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0	0.0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | U.S. Equity Mutual Funds Investment [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		8.9
Fair Value of Plan Assets, Ending		10.9	8.9
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Money market funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		1.2
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0	0.0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		36.0
Fair Value of Plan Assets, Ending		34.8	36.0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Group Retiree Medical Insurance Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		36.0
Fair Value of Plan Assets, Ending		34.8	36.0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | U.S. Equity Mutual Funds Investment [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0
Fair Value of Plan Assets, Ending		0.0	0.0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Money market funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		0.0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		45.8
Fair Value of Plan Assets, Ending		46.9	45.8
Other Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		9.6	8.1
Service cost		0.5	0.4	$ 0.3
Interest cost		0.4	0.3	0.3
Plan settlements		(1.2)	(2.0)
Actuarial losses (gains)		0.7	2.8
Benefit Obligation, Ending		10.3	9.6	8.1
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.0	0.0
Actual return on plans' assets		0.0	0.0
Employer contributions		1.2	2.0
Plan settlements		(1.2)	(2.0)
Fair Value of Plan Assets, Ending		0.0	0.0	0.0
Funded Status of Plan					$ (10.3)		$ (9.6)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.5	0.4	0.3
Interest cost		0.4	0.3	0.3
Expected return on plan assets		0.0	0.0	0.0
Amortization of unrecognized prior service cost	[1]	0.0	0.1	0.1
Settlement cost		0.5	1.0	0.0
Net periodic benefit cost		1.9	2.5	1.1
Amount paid by unconsolidated affiliates		0.1	0.1	0.0
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		1.8	2.4	1.1
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Benefits Paid		0.0	0.0
Defined Benefit Plan, Plan Assets, Benefits Paid		0.0	0.0
Accumulated Benefit Obligation					$ 8.1		$ 7.8
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		0.3	0.0
OKLAHOMA | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Settlement cost	[6]	$ 17.9	$ 22.1	$ 13.2

[1] 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.

[2] This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

[3] GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

[4] This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

[5] GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

[6] Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

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Common Equity Dividends Restriction (Details) shares in Millions, $ in Millions	Dec. 31, 2019 USD ($) shares
Preferred Stock, Shares Outstanding | shares	0.0
OGE Energy [Member]
Ratio of Consolidated Debt to Consolidated Capitalization	65.00%
Retained Earnings, Restricted	$ 661.4
Retained Earnings, Unrestricted	$ 2,400.0
Og and E [Member]
Ratio of Consolidated Debt to Consolidated Capitalization	65.00%
Retained Earnings, Restricted	$ 694.9
Retained Earnings, Unrestricted	$ 2,200.0

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Investment in Unconsolidated Affiliate and Related Party Transactions Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment, Summarized Financial Information, Revenue	$ 2,960.0	$ 3,431.0	$ 2,803.0
Equity Method Investment, Summarized Financial Information, Cost of Sales	1,279.0	1,819.0	1,381.0
Equity Method Investment, Summarized Financial Information, Operating Income	569.0	648.0	528.0
Net income	$ 360.0	$ 485.3	$ 400.3

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Stock Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized		7,400,000
Tax Benefit from Compensation Expense		$ 3.6		$ 3.4	$ 3.5
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Minimum payout range		0.00%
Maximum payout range		200.00%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Total Compensation Cost Not yet Recognized		$ 11.0
Performance Units Related to Earnings Per Share [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		0	[1]	87,308	86,857
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 0		$ 31.03	$ 34.83
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number		155,171		251,825
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		0	[1]	87,308	86,857
Equity Instruments Other than Options, Converted in Period	[2]	(91,356)
Equity Instruments Other than Options, Forfeited in Period		(5,298)
Awards Other than Options, Fully Vested		74,053
Equity Instruments Other than Options, Converted, Aggregrate Intrinsic Value		$ 7.2
Equity Instruments Other than Options, Vested in Period, Aggregate Intrinsic Value		6.6
Equity Instruments Other than Options, Outstanding, Aggregrate Intrinsic Value		11.5
Equity Instruments Other than Options, Fully Vested, Aggregrate Intrinsic Value		$ 4.7
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Equity Instruments Other than Options, Nonvested, Number, Beginning Balance		160,469
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		0	[1]	87,308	86,857
Equity Instruments Other than Options, Vested in Period		(74,053)
Equity Instruments Other than Options, Forfeited in Period		(5,298)
Equity Instruments Other than Options, Nonvested, Number, Ending Balance		81,118		160,469
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 31.03		$ 32.82
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		0		$ 31.03	$ 34.83
Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		34.83
Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 32.07
Awards Other than Options, Vested and Expected to Vest, Outstanding	[3]	77,617
Fair Value of Vested Performance Units and Restricted Stock		$ 5.2		$ 4.9	$ 1.2
Total Compensation Cost Not yet Recognized		$ 0.8
Total Compensation Cost Not yet Recognized, Period for Recognition		1 year
Total Shareholder Return [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		208,647	[1]	261,916	260,570
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 47.00		$ 36.86	$ 41.77
Expected Dividend Rate		4.00%		3.60%	3.80%
Expected Volatility Rate		17.00%		19.00%	19.90%
Risk Free Interest Rate		2.47%		2.38%	1.44%
Expected Term		2 years 10 months 9 days		2 years 10 months 9 days	2 years 9 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number		664,817		755,480
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		208,647	[1]	261,916	260,570
Equity Instruments Other than Options, Converted in Period	[2]	(274,078)
Equity Instruments Other than Options, Forfeited in Period		(25,232)
Awards Other than Options, Fully Vested		222,163
Equity Instruments Other than Options, Converted, Aggregrate Intrinsic Value		$ 19.8
Equity Instruments Other than Options, Vested in Period, Aggregate Intrinsic Value		11.5
Equity Instruments Other than Options, Outstanding, Aggregrate Intrinsic Value		35.4
Equity Instruments Other than Options, Fully Vested, Aggregrate Intrinsic Value		$ 22.8
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Equity Instruments Other than Options, Nonvested, Number, Beginning Balance		481,402
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		208,647	[1]	261,916	260,570
Equity Instruments Other than Options, Vested in Period		(222,163)
Equity Instruments Other than Options, Forfeited in Period		(25,232)
Equity Instruments Other than Options, Nonvested, Number, Ending Balance		442,654		481,402
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 41.43		$ 39.17
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		47.00		$ 36.86	$ 41.77
Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		41.76
Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 41.45
Awards Other than Options, Vested and Expected to Vest, Outstanding	[3]	418,331
Fair Value of Vested Performance Units and Restricted Stock		$ 9.3		$ 5.9	$ 6.3
Total Compensation Cost Not yet Recognized		$ 8.7
Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 8 months 1 day
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 13.0		13.3	9.0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Total Compensation Cost Not yet Recognized		9.5
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 0.9		$ 0.1	$ 0.1
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		75,929		826	3,145
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 41.71		$ 36.28	$ 34.96
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number		72,880		2,711
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		75,929		826	3,145
Equity Instruments Other than Options, Forfeited in Period		(3,599)
Equity Instruments Other than Options, Vested in Period, Aggregate Intrinsic Value		$ 0.1
Equity Instruments Other than Options, Outstanding, Aggregrate Intrinsic Value		3.2
Equity Instruments Other than Options, Fully Vested, Aggregrate Intrinsic Value		$ 2.4
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Equity Instruments Other than Options, Nonvested, Number, Beginning Balance		2,711
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		75,929		826	3,145
Equity Instruments Other than Options, Vested in Period		(2,161)
Equity Instruments Other than Options, Forfeited in Period		(3,599)
Equity Instruments Other than Options, Nonvested, Number, Ending Balance		72,880		2,711
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 41.66		$ 35.00
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		41.71		$ 36.28	$ 34.96
Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		34.66
Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 41.78
Awards Other than Options, Vested and Expected to Vest, Outstanding	[3]	54,102
Fair Value of Vested Performance Units and Restricted Stock		$ 0.1		$ 0.1	$ 0.1
Total Compensation Cost Not yet Recognized		$ 1.5
Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 11 months 23 days
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense, Net of Unconsolidated Affiliates		$ 13.9		13.4	9.1
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		4.3		5.1	1.4
Total Shareholder Return [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 8.7		$ 8.2	$ 7.6
Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures		443,900		26,211	2,298

[1] For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.

[2] These amounts represent performance units that vested at December 31, 2018 which were settled in February 2019.

[3] The intrinsic value of the performance units based on total shareholder return and earnings per share is $22.8 million and $4.7 million, respectively. The intrinsic value of restricted stock units is $2.4 million.

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Schedule II (Tables)

9 Months Ended

Sep. 30, 2019

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II Valuation and Qualifying Accounts [Table Text Block]

SCHEDULE II - Valuation and Qualifying Accounts

			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (A)		Balance at End of Period
(In millions)
Balance at December 31, 2017
Reserve for Uncollectible Accounts	$	1.5	$	2.6	$	2.6	$	1.5
Balance at December 31, 2018
Reserve for Uncollectible Accounts	$	1.5	$	3.4	$	3.2	$	1.7
Balance at December 31, 2019
Reserve for Uncollectible Accounts	$	1.7	$	2.2	$	2.4	$	1.5

(A)Uncollectible accounts receivable written off, net of recoveries.

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Retirement Plans and Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2019

Retirement Plans and Postretirement Benefit Plans [Abstract]

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]

The following table presents the status of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 2019 and 2018. These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E's portion, which is recorded as a regulatory asset as discussed in Note 1) in the Company's Consolidated Balance Sheets. The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods. The benefit obligation for the Company's Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for the Company's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2019 was $563.3 million and $8.1 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2018 was $561.9 million and $7.8 million, respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Consolidated Balance Sheets are included in the following table.

	Pension Plan				Restoration of Retirement Income Plan				Postretirement Benefit Plans
December 31 (In millions)	2019		2018		2019		2018		2019		2018
Change in benefit obligation
Beginning obligations	$	615.9	$	687.5	$	9.6	$	8.1	$	135.8	$	149.4
Service cost	12.9		14.9		0.5		0.4		0.2		0.3
Interest cost	20.7		23.8		0.4		0.3		5.6		5.4
Plan settlements	(83.1)		(73.7)		(1.2)		(2.0)		—		—
Plan amendments	—		—		0.3		—		—		—
Participants' contributions	—		—		—		—		4.1		3.8
Actuarial losses (gains)	64.3		(22.0)		0.7		2.8		2.9		(9.6)
Benefits paid	(14.6)		(14.6)		—		—		(12.1)		(13.5)
Ending obligations	$	616.1	$	615.9	$	10.3	$	9.6	$	136.5	$	135.8
Change in plans' assets
Beginning fair value	$	522.8	$	635.3	$	—	$	—	$	45.3	$	50.2
Actual return on plans' assets	85.2		(39.2)		—		—		4.6		(0.6)
Employer contributions	20.0		15.0		1.2		2.0		5.1		5.4
Plan settlements	(83.1)		(73.7)		(1.2)		(2.0)		—		—
Participants' contributions	—		—		—		—		4.1		3.8
Benefits paid	(14.6)		(14.6)		—		—		(12.1)		(13.5)
Ending fair value	$	530.3	$	522.8	$	—	$	—	$	47.0	$	45.3
Funded status at end of year	$	(85.8)	$	(93.1)	$	(10.3)	$	(9.6)	$	(89.5)	$	(90.5)

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

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 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 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 Consolidated Statements of Income.

	Pension Plan						Restoration of Retirement Income Plan						Postretirement Benefit Plans
Year Ended December 31 (In millions)	2019		2018		2017		2019		2018		2017		2019		2018		2017
Service cost	$	12.9	$	14.9	$	15.5	$	0.5	$	0.4	$	0.3	$	0.2	$	0.3	$	0.6
Interest cost	20.7		23.8		26.2		0.4		0.3		0.3		5.6		5.4		7.2
Expected return on plan assets	(36.1)		(44.1)		(42.6)		—		—		—		(1.9)		(2.0)		(2.2)
Amortization of net loss	17.3		16.2		17.4		0.5		0.7		0.4		2.0		3.8		2.0
Amortization of unrecognized prior service cost (A)	—		—		(0.1)		—		0.1		0.1		(8.4)		(8.4)		(3.5)
Settlement cost	27.6		25.1		15.3		0.5		1.0		—		—		—		0.6
Total net periodic benefit cost	42.4		35.9		31.7		1.9		2.5		1.1		(2.5)		(0.9)		4.7
Less: Amount paid by unconsolidated affiliates	2.9		2.5		4.3		0.1		0.1		—		(0.6)		(0.5)		0.3
Net periodic benefit cost	$	39.5	$	33.4	$	27.4	$	1.8	$	2.4	$	1.1	$	(1.9)	$	(0.4)	$	4.4

(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 recognized, as presented in the table above, for the Pension and Restoration of Retirement Income Plans in 2019, 2018 and 2017, the Company recognized the following:

Year Ended December 31 (In millions)	2019		2018		2017
Decrease of pension expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	(16.1)	$	(14.1)	$	(2.3)
Deferral of pension expense related to pension settlement charges:
Oklahoma jurisdiction (A)	$	17.9	$	22.1	$	13.2
Arkansas jurisdiction (A)	$	1.7	$	2.1	$	1.1

(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

In addition to the net periodic benefit income and cost amounts recognized, as presented in the table above, for the postretirement benefit plans in 2019, 2018 and 2017, the Company recognized the following:

Year Ended December 31 (In millions)	2019		2018		2017
Increase of postretirement expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	1.0	$	4.4	$	6.2

(A) Included in the pension regulatory asset or liability in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.

Schedule of Capitalized Pension and Postretirement Cost [Table Text Block]

(In millions)	2019		2018		2017
Capitalized portion of net periodic pension benefit cost	$	3.6	$	3.8	$	4.4
Capitalized portion of net periodic postretirement benefit cost	$	0.2	$	0.2	$	1.2

Schedule of Assumptions Used [Table Text Block]

Rate Assumptions

	Pension Plan and Restoration of Retirement Income Plan						Postretirement Benefit Plans
Year Ended December 31	2019		2018		2017		2019		2018		2017
Assumptions to determine benefit obligations:
Discount rate	3.15	%	4.20	%	3.60	%	3.25	%	4.30	%	3.70	%
Rate of compensation increase	4.20	%	4.20	%	4.20	%	N/A		N/A		N/A
Assumptions to determine net periodic benefit cost:
Discount rate	3.63	%	3.73	%	4.00	%	4.30	%	3.70	%	4.20	%
Expected return on plan assets	7.50	%	7.50	%	7.50	%	4.00	%	4.00	%	4.00	%
Rate of compensation increase	4.20	%	4.20	%	4.20	%	N/A		N/A		4.20	%

N/A - not applicable

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

The effects of a one-percentage point change in the assumed health care cost trend rate are presented in the following tables. 

ONE-PERCENTAGE POINT INCREASE
Year Ended December 31 (In millions)	2019		2018		2017
Effect on aggregate of the service and interest cost components	$	—	$	—	$	—
Effect on accumulated postretirement benefit obligations	$	0.1	$	0.1	$	0.1

ONE-PERCENTAGE POINT DECREASE
Year Ended December 31 (In millions)	2019		2018		2017
Effect on aggregate of the service and interest cost components	$	—	$	—	$	—
Effect on accumulated postretirement benefit obligations	$	0.3	$	0.3	$	0.3

Projected Benefit Obligation Funded Status Thresholds [Table Text Block]

The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability-driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.

Projected Benefit Obligation Funded Status Thresholds	<90%	95%	100%	105%	110%	115%	120%
Fixed income	50%	58%	65%	73%	80%	85%	90%
Equity	50%	42%	35%	27%	20%	15%	10%
Total	100%	100%	100%	100%	100%	100%	100%

Pension Plan Equity Asset Allocation Table [Table Text Block]

Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below.

Asset Class	Target Allocation	Minimum	Maximum
Domestic Large Cap Equity	40%	35%	60%
Domestic Mid-Cap Equity	15%	5%	25%
Domestic Small-Cap Equity	25%	5%	30%
International Equity	20%	10%	30%

Schedule of Allocation of Plan Assets [Table Text Block]

The following tables summarize the postretirement benefit plans' investments that are measured at fair value on a recurring basis at December 31, 2019 and 2018. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2019 and 2018.

(In millions)	December 31, 2019		Level 1		Level 3
Group retiree medical insurance contract	$	34.8	$	—	$	34.8
Mutual funds	10.9		10.9		—
Money market fund	1.2		1.2		—
Total plan investments	$	46.9	$	12.1	$	34.8

(In millions)	December 31, 2018		Level 1		Level 3
Group retiree medical insurance contract	$	36.0	$	—	$	36.0
Mutual funds	8.9		8.9		—
Cash	0.9		0.9		—
Total plan investments	$	45.8	$	9.8	$	36.0

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]

The following table summarizes the postretirement benefit plans' investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

Year Ended December 31 (In millions)	2019
Group retiree medical insurance contract:
Beginning balance	$	36.0
Claims paid	(3.8)
Investment fees	(0.1)
Net unrealized gains related to instruments held at the reporting date	1.4
Interest income	0.8
Dividend income	0.5
Ending balance	$	34.8

Schedule of Expected Benefit Payments [Table Text Block]

The following table summarizes the benefit payments the Company expects to pay related to OGE Energy's Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure the Company's benefit obligation at the end of the year and include benefits attributable to estimated future employee service. 

(In millions)	Projected Benefit Payments
2020	$	58.4
2021	$	56.8
2022	$	56.2
2023	$	55.7
2024	$	56.6
After 2024	$	249.4

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs. The following table summarizes the gross benefit payments the Company expects to pay related to its postretirement benefit plans, including prescription drug benefits.

(In millions)	Gross Projected Postretirement Benefit Payments
2020	$	11.2
2021	$	11.2
2022	$	11.1
2023	$	9.5
2024	$	9.4
After 2024	$	42.3

Defined Benefit Plan, Plan Assets, Category

The following tables summarize the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2019 and 2018. There were no Level 3 investments held by the Pension Plan at December 31, 2019 and 2018. 

(In millions)	December 31, 2019		Level 1		Level 2		Net Asset Value (A)
Common stocks	$	202.0	$	202.0	$	—	$	—
U.S. Treasury notes and bonds (B)	134.8		134.8		—		—
Mortgage- and asset-backed securities	45.8		—		45.8		—
Corporate fixed income and other securities	130.5		—		130.5		—
Commingled fund (C)	23.9		—		—		23.9
Foreign government bonds	3.0		—		3.0		—
U.S. municipal bonds	1.1		—		1.1		—
Money market fund	7.5		—		—		7.5
Mutual fund	2.4		2.4		—		—
Preferred stocks	0.7		0.7		—		—
Futures:
U.S. Treasury futures (receivable)	22.9		—		22.9		—
U.S. Treasury futures (payable)	(10.9)		—		(10.9)		—
Cash collateral	0.6		0.6		—		—
Forward contracts:
Receivable (foreign currency)	0.1		—		0.1		—
Total Pension Plan investments	564.4		$	340.5	$	192.5	$	31.4
Interest and dividends receivable	2.4
Payable to broker for securities purchased	(36.5)
Total Pension Plan assets	$	530.3

(A)GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

(B)This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.

(C)This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

(In millions)	December 31, 2018		Level 1		Level 2		Net Asset Value (A)
Common stocks	$	169.3	$	169.3	$	—	$	—
U.S. Treasury notes and bonds (B)	137.9		137.9		—		—
Mortgage- and asset-backed securities	65.9		—		65.9		—
Corporate fixed income and other securities	143.2		—		143.2		—
Commingled fund (C)	19.7		—		—		19.7
Foreign government bonds	4.4		—		4.4		—
U.S. municipal bonds	0.6		—		0.6		—
Money market fund	0.3		—		—		0.3
Mutual fund	8.0		8.0		—		—
Futures:
U.S. Treasury futures (receivable)	27.0		—		27.0		—
U.S. Treasury futures (payable)	(20.4)		—		(20.4)		—
Cash collateral	0.7		0.7		—		—
Forward contracts:
Receivable (foreign currency)	0.1		—		0.1		—
Total Pension Plan investments	556.7		$	315.9	$	220.8	$	20.0
Interest and dividends receivable	3.0
Payable to broker for securities purchased	(36.9)
Total Pension Plan assets	$	522.8

(A)GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

(B)This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.

(C)This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 0.0	$ 94.3
Accounts receivable, less reserve of $1.5 and $1.7, respectively	153.8	174.7
Accrued unbilled revenues	64.7	62.6
Income taxes receivable	10.9	9.9
Fuel inventories	46.3	57.6
Materials and supplies, at average cost	90.6	126.7
Fuel clause under recoveries	39.5	2.0
Other	24.4	29.5
Total current assets	430.2	557.3
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,151.5	1,177.5
Other	82.7	73.4
Total other property and investments	1,234.2	1,250.9
PROPERTY, PLANT AND EQUIPMENT
In service	12,771.1	11,994.8
Construction work in progress	141.6	376.4
Total property, plant and equipment	12,912.7	12,371.2
Less: accumulated depreciation	3,868.1	3,727.4
Net property, plant and equipment	9,044.6	8,643.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	306.0	285.8
Other	9.3	10.8
Total deferred charges and other assets	315.3	296.6
TOTAL ASSETS	11,024.3	10,748.6
CURRENT LIABILITIES
Short-term debt	112.0	0.0
Accounts payable	194.9	239.3
Dividends payable	77.6	72.9
Customer deposits	83.0	83.6
Accrued taxes	41.9	44.0
Accrued interest	37.9	44.5
Accrued compensation	40.6	47.8
Long-term debt due within one year	0.0	250.0
Fuel clause over recoveries	4.8	0.3
Other	65.2	87.0
Total current liabilities	657.9	869.4
LONG-TERM DEBT	3,195.2	2,896.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	225.0	225.7
Deferred income taxes	1,375.8	1,310.9
Accumulated Deferred Investment Tax Credit	7.1	7.2
Regulatory liabilities	1,223.5	1,270.7
Other	200.3	162.7
Total deferred credits and other liabilities	3,031.7	2,977.2
Total liabilities	6,884.8	6,743.5
COMMITMENTS AND CONTINGENCIES (NOTE 15)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,131.3	1,127.7
Retained earnings	3,036.1	2,906.3
Accumulated other comprehensive loss, net of tax	(27.9)	(28.9)
Total stockholders' equity	4,139.5	4,005.1
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 11,024.3	$ 10,748.6

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Summary of Significant Accounting Policies Fuel Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Other	$ 24.4	$ 29.5
Public Utilities, Inventory, Fuel [Member]
Public Utilities, Inventory	$ 46.3	$ 57.6

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Revenue from Contract with Customer, Excluding Assessed Tax	$ 2,175.5		$ 2,211.7		$ 0.0
Revenues from Alternative Revenue Programs	56.1		58.6		0.0
OPERATING REVENUES
Total operating revenues	2,231.6		2,270.3		2,261.1
Total cost of sales	786.9		892.5		897.6
OPERATING EXPENSES
Other operation and maintenance	491.8		474.6		458.7
Depreciation and amortization	355.0		321.6		283.5
Taxes other than income	93.6		92.0		89.4
Operating expenses	940.4		888.2		831.6
Operating income (loss)	504.3		489.6		531.9
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	113.9		152.8		131.2
Allowance for equity funds used during construction	4.5		23.8		39.7
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	(9.8)		(10.8)		(21.6)
Other income	21.9		21.7		46.4
Other expense	(23.5)		(23.4)		(14.1)
Net other income	107.0		164.1		181.6
INTEREST EXPENSE
Interest on long-term debt	138.3		157.4		153.6
Allowance for borrowed funds used during construction	(2.8)		(11.7)		(18.0)
Interest on short-term debt and other interest charges	12.4		10.3		8.2
Interest expense	147.9		156.0		143.8
INCOME BEFORE TAXES	463.4		497.7		569.7
INCOME TAX EXPENSE (BENEFIT)	29.8		72.2		(49.3)	[1]
NET INCOME	$ 433.6		$ 425.5		$ 619.0
BASIC AVERAGE COMMON SHARES OUTSTANDING	200.1		199.7		199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.7		200.5		200.0
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 2.17	[2]	$ 2.13	[2]	$ 3.10
DILUTED EARNINGS PER AVERAGE COMMON SHARE	2.16	[2]	2.12	[2]	3.10
DIVIDENDS DECLARED PER COMMON SHARE	$ 1.5050		$ 1.3950		$ 1.2700

[1] The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act.

[2] Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

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Schedule II

9 Months Ended

Sep. 30, 2019

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

SCHEDULE II - Valuation and Qualifying Accounts

			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (A)		Balance at End of Period
(In millions)
Balance at December 31, 2017
Reserve for Uncollectible Accounts	$	1.5	$	2.6	$	2.6	$	1.5
Balance at December 31, 2018
Reserve for Uncollectible Accounts	$	1.5	$	3.4	$	3.2	$	1.7
Balance at December 31, 2019
Reserve for Uncollectible Accounts	$	1.7	$	2.2	$	2.4	$	1.5

(A)Uncollectible accounts receivable written off, net of recoveries.

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Common Equity

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Common Equity

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 in 2019. The Company may, from time to time, issue shares under its Automatic Dividend Reinvestment and Stock Purchase Plan or purchase shares traded on the open market. At December 31, 2019, there were 4,774,442 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

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.

(In millions except per share data)	2019		2018		2017
Net income	$	433.6	$	425.5	$	619.0
Average common shares outstanding:
Basic average common shares outstanding	200.1		199.7		199.7
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.6		0.8		0.3
Diluted average common shares outstanding	200.7		200.5		200.0
Basic earnings per average common share	$	2.17	$	2.13	$	3.10
Diluted earnings per average common share	$	2.16	$	2.12	$	3.10
Anti-dilutive shares excluded from earnings per share calculation	—		—		—

Dividend Restrictions

The Company's Certificate of Incorporation places restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Before the Company can pay any dividends on its common stock, the holders of any of its preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. As there is no preferred stock outstanding, that restriction did not place any effective limit on the Company's ability to pay dividends to its shareholders.

The Company utilizes receipts from its equity investment in Enable and dividends from OG&E to pay dividends to its shareholders. Enable's partnership agreement requires that it distribute all "available cash," as defined as cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter.

Pursuant to the leverage restriction in the Company's revolving credit agreement, the Company must maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $661.4 million of the Company's retained earnings from being paid out in dividends. Accordingly, approximately $2.4 billion of the Company's retained earnings as of December 31, 2019 are unrestricted for the payment of dividends.

Pursuant to the Federal Power Act, OG&E is restricted from paying dividends from its capital accounts. Dividends are paid from retained earnings. Pursuant to the leverage restriction in OG&E's revolving credit agreement, OG&E must also maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $694.9 million of OG&E's retained earnings from being paid out in dividends. Accordingly, approximately $2.2 billion of OG&E's retained earnings as of December 31, 2019 are unrestricted for the payment of dividends.

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Report of Business Segments

12 Months Ended

Dec. 31, 2019

Segment Reporting Information [Line Items]

Report of Business Segments

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) natural gas midstream operations segment. Other operations primarily includes the operations of the holding company. 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 for the years ended December 31, 2019, 2018 and 2017.

2019	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,231.6	$	—	$	—	$	—	$	2,231.6
Cost of sales	786.9		—		—		—		786.9
Other operation and maintenance	492.5		2.8		(3.5)		—		491.8
Depreciation and amortization	355.0		—		—		—		355.0
Taxes other than income	89.5		0.4		3.7		—		93.6
Operating income (loss)	507.7		(3.2)		(0.2)		—		504.3
Equity in earnings of unconsolidated affiliates	—		113.9		—		—		113.9
Other income (expense)	3.1		(8.6)		2.2		(3.6)		(6.9)
Interest expense	140.5		—		11.0		(3.6)		147.9
Income tax expense (benefit)	20.1		20.7		(11.0)		—		29.8
Net income	$	350.2	$	81.4	$	2.0	$	—	$	433.6
Investment in unconsolidated affiliates	$	—	$	1,132.9	$	18.6	$	—	$	1,151.5
Total assets	$	10,076.6	$	1,135.4	$	107.0	$	(294.7)	$	11,024.3
Capital expenditures	$	635.5	$	—	$	—	$	—	$	635.5

2018	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,270.3	$	—	$	—	$	—	$	2,270.3
Cost of sales	892.5		—		—		—		892.5
Other operation and maintenance	473.8		1.4		(0.6)		—		474.6
Depreciation and amortization	321.6		—		—		—		321.6
Taxes other than income	88.2		0.6		3.2		—		92.0
Operating income (loss)	494.2		(2.0)		(2.6)		—		489.6
Equity in earnings of unconsolidated affiliates	—		152.8		—		—		152.8
Other income (expense)	25.6		(4.9)		(3.4)		(6.0)		11.3
Interest expense	151.8		—		10.2		(6.0)		156.0
Income tax expense (benefit)	40.0		37.1		(4.9)		—		72.2
Net income (loss)	$	328.0	$	108.8	$	(11.3)	$	—	$	425.5
Investment in unconsolidated affiliates	$	—	$	1,166.6	$	10.9	$	—	$	1,177.5
Total assets	$	9,704.5	$	1,169.8	$	184.8	$	(310.5)	$	10,748.6
Capital expenditures	$	573.6	$	—	$	—	$	—	$	573.6

2017	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,261.1	$	—	$	—	$	—	$	2,261.1
Cost of sales	897.6		—		—		—		897.6
Other operation and maintenance	469.8		(0.8)		(10.3)		—		458.7
Depreciation and amortization	280.9		—		2.6		—		283.5
Taxes other than income	84.8		1.0		3.6		—		89.4
Operating income (loss)	528.0		(0.2)		4.1		—		531.9
Equity in earnings of unconsolidated affiliates	—		131.2		—		—		131.2
Other income (expense)	57.7		(1.0)		(5.4)		(0.9)		50.4
Interest expense	138.4		—		6.3		(0.9)		143.8
Income tax expense (benefit) (A)	141.8		(195.2)		4.1		—		(49.3)
Net income (loss)	$	305.5	$	325.2	$	(11.7)	$	—	$	619.0
Investment in unconsolidated affiliates	$	—	$	1,151.9	$	8.5	$	—	$	1,160.4
Total assets	$	9,255.6	$	1,155.3	$	109.1	$	(107.3)	$	10,412.7
Capital expenditures	$	824.1	$	—	$	—	$	—	$	824.1

(A)The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act.

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Stock Based Compensation (Tables)

12 Months Ended

Dec. 31, 2019

Stock-Based Compensation [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the years ended December 31, 2019, 2018 and 2017 related to the Company's performance units and restricted stock units.

Year Ended December 31 (In millions)	2019		2018		2017
Performance units:
Total shareholder return	$	8.7	$	8.2	$	7.6
Earnings per share	4.3		5.1		1.4
Total performance units	13.0		13.3		9.0
Restricted stock units	0.9		0.1		0.1
Total compensation expense	$	13.9	$	13.4	$	9.1
Income tax benefit	$	3.6	$	3.4	$	3.5

Performance Units Total Shareholder Return Valuation Assumptions [Table Text Block]

The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table.

	2019			2018			2017
Number of units granted	208,647			261,916			260,570
Fair value of units granted	$	47.00		$	36.86		$	41.77
Expected dividend yield	4.0		%	3.6		%	3.8		%
Expected price volatility	17.0		%	19.0		%	19.9		%
Risk-free interest rate	2.47		%	2.38		%	1.44		%
Expected life of units (in years)	2.86			2.86			2.80

Performance Units Earnings Per Share Valuation Assumptions [Table Text Block]

In 2019, the Compensation Committee of the Company's Board of Directors voted to grant restricted stock units in lieu of performance units based on earnings per share. For 2018 and 2017, the number of performance units granted based on earnings per share and the grant date fair value are shown in the following table. 

	2018		2017
Number of units granted	87,308		86,857
Fair value of units granted	$	31.03	$	34.83

Restricted Stock Valuation Assumptions [Table Text Block]

The number of restricted stock units granted and the grant date fair value are shown in the following table. 

	2019		2018		2017
Restricted stock units granted	75,929		826		3,145
Fair value of restricted stock units granted	$	41.71	$	36.28	$	34.96

Share-based Compensation, Activity [Table Text Block]

A summary of the activity for the Company's performance units and restricted stock units at December 31, 2019 and changes in 2019 are shown in the following table.

	Performance Units								Restricted Stock Units
	Total Shareholder Return				Earnings Per Share
(Dollars in millions)	Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value		Number of Shares	Aggregate Intrinsic Value
Units/shares outstanding at 12/31/18	755,480				251,825				2,711
Granted	208,647	(A)			—				75,929
Converted	(274,078)	(B)	$	19.8	(91,356)	(B)	$	7.2	N/A
Vested	N/A				N/A				(2,161)	$	0.1
Forfeited	(25,232)				(5,298)				(3,599)
Units/shares outstanding at 12/31/19	664,817		$	35.4	155,171		$	11.5	72,880	$	3.2
Units/shares fully vested at 12/31/19	222,163		$	11.5	74,053		$	6.6

(A)For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.

(B)These amounts represent performance units that vested at December 31, 2018 which were settled in February 2019.

Schedule of Nonvested Share Activity [Table Text Block]

A summary of the activity for the Company's non-vested performance units and restricted stock units at December 31, 2019 and changes in 2019 are shown in the following table.

	Performance Units								Restricted Stock Units
	Total Shareholder Return				Earnings Per Share
	Number of Units		Weighted-Average Grant Date Fair Value		Number of Units		Weighted-Average Grant Date Fair Value		Number of Shares		Weighted-Average Grant Date Fair Value
Units/shares non-vested at 12/31/18	481,402		$	39.17	160,469		$	32.82	2,711		$	35.00
Granted	208,647	(A)	$	47.00	—		$	—	75,929		$	41.71
Vested	(222,163)		$	41.76	(74,053)		$	34.83	(2,161)		$	34.66
Forfeited	(25,232)		$	41.45	(5,298)		$	32.07	(3,599)		$	41.78
Units/shares non-vested at 12/31/19	442,654		$	41.43	81,118		$	31.03	72,880		$	41.66
Units/shares expected to vest	418,331	(B)			77,617	(B)			54,102	(B)

(A)For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.

(B)The intrinsic value of the performance units based on total shareholder return and earnings per share is $22.8 million and $4.7 million, respectively. The intrinsic value of restricted stock units is $2.4 million.

Fair Value of Vested Performance Units and Restricted Stock [Table Text Block]

A summary of the Company's fair value for its vested performance units and restricted stock units is shown in the following table.

Year Ended December 31 (In millions)	2019		2018		2017
Performance units:
Total shareholder return	$	9.3	$	5.9	$	6.3
Earnings per share	$	5.2	$	4.9	$	1.2
Restricted stock units	$	0.1	$	0.1	$	0.1

Schedule of Unrecognized Compensation Cost, Nonvested Awards [Table Text Block]

A summary of the Company's unrecognized compensation cost for its non-vested performance units and restricted stock units and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

December 31, 2019	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance units:
Total shareholder return	$	8.7	1.67
Earnings per share	0.8		1.00
Total performance units	9.5
Restricted stock units	1.5		1.98
Total unrecognized compensation cost	$	11.0

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Revenue from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

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 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

	Year Ended December 31,
(In millions)	2019		2018
Residential	$	865.8	$	877.8
Commercial	486.6		500.0
Industrial	217.8		228.9
Oilfield	200.4		190.4
Public authorities and street light	190.3		197.4
System sales revenues	1,960.9		1,994.5
Provision for rate refund	(0.9)		(6.0)
Integrated market	38.4		48.7
Transmission	148.0		147.4
Other	29.1		27.1
Revenues from contracts with customers	$	2,175.5	$	2,211.7

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

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 as follows:

Series			Date Due	Amount
				(In millions)
1.20%	-	2.50%	Garfield Industrial Authority, January 1, 2025	$	47.0
1.19%	-	2.35%	Muskogee Industrial Authority, January 1, 2025	32.4
1.20%	-	2.48%	Muskogee Industrial Authority, June 1, 2027	56.0
Total (redeemable during next 12 months)				$	135.4

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Accounting Pronouncements

12 Months Ended

Dec. 31, 2019

Accounting Pronouncement [Abstract]

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

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 ASC 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, ASC 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 ASC 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 ASC 842 land easements that exist or expired before the entity's adoption of ASC 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 ASC 842 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 ASC 840 disclosures for all periods that continue to be reported under ASC 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 Consolidated Balance Sheet. The new standard did not have a material impact on the Company's 2019 Consolidated Statement 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 ASC 842.

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 is applied utilizing a modified-retrospective approach. The Company determined the only financial instrument that the Company currently holds and is required to measure under ASU 2016-13 is its trade receivables. Upon adoption of this ASU, the Company considers forecasts of future economic conditions in addition to the historical data utilized prior to ASU 2016-13 when measuring the reserve for trade receivables. The Company evaluated its reserve for trade receivables in light of the new guidance and determined that no adjustment was necessary to the amount recorded as of January 1, 2020.

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. The Company adopted and prospectively applied the new guidance beginning in the first quarter of 2020, which did not have a material effect on the Consolidated Financial Statements upon adoption.

Issued Accounting Standards Not Yet Adopted

Simplifying the Accounting for Income Taxes. In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740)." The new guidance simplifies the accounting for income taxes by removing certain exceptions to the general principles in ASC 740 and improves consistent application of existing guidance. ASU 2019-12 will be effective for the Company as of January 1, 2021 and can be early adopted. The Company is currently assessing the impact of these rule changes on its Consolidated Financial Statements.

Investments - Equity Method and Joint Ventures. In January 2020, the FASB issued ASU 2020-01, "Investments - Equity Securities (Topic 321), Investments - Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815)." The new guidance makes targeted improvements to address certain aspects of accounting for financial instruments, clarifying the interaction of the accounting for equity securities under ASC 321 and investments accounted for under the equity method of accounting in ASC 323. ASU 2020-01 should be applied prospectively and will be effective for the

Company as of January 1, 2021. The Company is currently assessing the impact of these rule changes on its Consolidated Financial Statements.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

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

	2019				2018
December 31 (In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Classification
Long-term Debt (including Long-term Debt due within one year):
OG&E Senior Notes	$	3,050.3	$	3,500.4	$	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	$	9.5	$	10.0	$	9.6	$	8.7	Level 3

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Commitments and Contingencies (Details) $ in Millions		12 Months Ended
		Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months		$ 141.1
Operating Leases, Future Minimum Payments, Due in Two Years		113.5
Operating Leases, Future Minimum Payments, Due in Three Years		109.2
Operating Leases, Future Minimum Payments, Due in Four Years		121.0
Operating Leases, Future Minimum Payments, Due in Five Years		122.5
Operating Leases, Future Minimum Payments Due		607.3
Utilities Operating Expense, Purchased Power under Long-term Contracts		57.7	$ 57.6	$ 61.1
OG&E minimum fuel purchase commitments [Member]
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due		271.4
Purchase Obligation, Due in Next Twelve Months		82.6
Unrecorded Unconditional Purchase Obligation, Due within Two Years		55.1
Unrecorded Unconditional Purchase Obligation, Due within Three Years		50.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years		50.4
Unrecorded Unconditional Purchase Obligation, Due within Five Years		32.9
OG&E expected wind purchase commitments [Member]
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due		282.4
Purchase Obligation, Due in Next Twelve Months		55.7
Unrecorded Unconditional Purchase Obligation, Due within Two Years		56.0
Unrecorded Unconditional Purchase Obligation, Due within Three Years		56.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years		56.8
Unrecorded Unconditional Purchase Obligation, Due within Five Years		57.5
OG&E long-term service agreement commitments [Member]
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due		53.1
Purchase Obligation, Due in Next Twelve Months		2.4
Unrecorded Unconditional Purchase Obligation, Due within Two Years		2.4
Unrecorded Unconditional Purchase Obligation, Due within Three Years		2.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years		13.8
Unrecorded Unconditional Purchase Obligation, Due within Five Years		32.1
Environmental compliance plan expenditures [Member]
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due		0.4
Purchase Obligation, Due in Next Twelve Months		0.4
Unrecorded Unconditional Purchase Obligation, Due within Two Years		0.0
Unrecorded Unconditional Purchase Obligation, Due within Three Years		0.0
Unrecorded Unconditional Purchase Obligation, Due within Four Years		0.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years		0.0
OG&E total cogeneration payments [Member]
Loss Contingencies [Line Items]
Long-term Purchase Commitment, Amount		14.7	112.4	115.2
OG&E capacity payments [Member]
Loss Contingencies [Line Items]
Long-term Purchase Commitment, Amount		7.4	60.0	63.0
CPV Keenan [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts		27.2	27.0	29.0
Edison Mission Energy [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts		23.1	21.7	22.1
FPL Energy [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts	[1]	0.0	2.1	2.6
NextEra Energy [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts		$ 7.4	$ 6.8	$ 7.4
OG&E long-term service agreement commitments [Member] | McClain Plant [Member]
Loss Contingencies [Line Items]
Factored-Fired Hours		128,000
Factored-Fired Starts		4,800
OG&E long-term service agreement commitments [Member] | Redbud Plant [Member]
Loss Contingencies [Line Items]
Factored-Fired Hours		144,000
Factored-Fired Starts		4,500
Additional Factored-Fired Hours		24,000

[1] OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018.

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Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Short-term debt		$ 112.0	$ 0.0
Line of Credit Facility [Abstract]
Aggregate Commitment		900.0
Amount Outstanding	[1]	$ 112.3
Weighted Average Interest Rate		2.06%
OGE Energy [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[2]	$ 450.0
Line of Credit Facility [Abstract]
Amount Outstanding	[1],[2]	$ 112.0
Weighted Average Interest Rate	[2],[3]	2.06%
Maturity		Mar. 08, 2023
Ratio of Consolidated Debt to Consolidated Capitalization		65.00%
OG&E [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[4]	$ 450.0
Line of Credit Facility [Abstract]
Letters of Credit Outstanding, Amount	[1],[4]	$ 0.3
Weighted Average Interest Rate	[3],[4]	1.00%
Maturity		Mar. 08, 2023
Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt		2 years
Short Term Borrowing Capacity That Has Regulatory Approval		$ 800.0
Ratio of Consolidated Debt to Consolidated Capitalization		65.00%
Uninsured Judgements [Member] | OGE Energy [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		$ 100.0
Uninsured Judgements [Member] | OG&E [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		$ 100.0

[1] Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2019.

[2] 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.

[3] Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

[4] 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.

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Leases, Codification Topic 842 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017	Jan. 01, 2019
Leases [Abstract]
Lessee, Operating Lease, Contingent Liability	$ 6.8		$ 16.2
Operating Lease, Cost	6.0		4.9		$ 6.2
Operating Leased Assets [Line Items]
Cash Paid on Operating Leases	5.6
Operating Lease, Right-of-Use Asset	40.9	[1]				$ 34.5
Operating Lease, Liability	$ 45.8	[2]				$ 39.1
Operating Lease, Weighted Average Remaining Lease Term	13 years 1 month 6 days
Operating Lease, Weighted Average Discount Rate, Percent	3.90%
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 10.7
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	0.0		22.1	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	6.2		3.9	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due Year Two	5.8		3.5	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due Year Three	5.2		2.9	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due Year Four	5.2		2.9	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due Year Five	3.1		3.0	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due after Year Five	34.7		34.6	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due	60.2		72.9	[3],[4]
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	14.4
Lessee, Operating Lease, Contingent Liability	$ 6.8		$ 16.2

[1] Included in Property, Plant and Equipment in the 2019 Consolidated Balance Sheet.

[2] Included in Other Deferred Credits and Other Liabilities in the 2019 Consolidated Balance Sheet.

[3] Amounts included for comparability and accounted for in accordance with ASC 840, "Leases."

[4] 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.

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Summary of Significant Accounting Policies Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 12,912.7		$ 12,371.2
Accumulated Depreciation	3,868.1		3,727.4
Net property, plant and equipment	9,044.6		8,643.8
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments, Related Accumulated Depreciation	61.8		56.3
Capitalized Computer Software, Amortization	$ 11.0		$ 9.6		$ 9.0
McClain Plant [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	77.00%	[1]	77.00%	[2]
Property, Plant and Equipment, Gross	$ 254.4	[1]	$ 227.2	[2]
Accumulated Depreciation	83.5	[1]	78.2	[2]
Net property, plant and equipment	170.9	[1]	149.0	[2]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 0.2		$ 0.2
Redbud Plant [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	51.00%	[1],[3]	51.00%	[2],[4]
Property, Plant and Equipment, Gross	$ 529.9	[1],[3]	$ 493.9	[2],[4]
Accumulated Depreciation	159.0	[1],[3]	145.3	[2],[4]
Net property, plant and equipment	370.9	[1],[3]	348.6	[2],[4]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	1.4		0.9
Amount of Acquisition Adjustments	148.3		148.3
OGE Energy [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	6.1		6.1
Accumulated Depreciation	0.0		0.0
Net property, plant and equipment	6.1		6.1
Capitalized Computer Software, Amortization	0.0		0.0		0.2
OGE Energy [Member] | Total Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	6.1		6.1
Accumulated Depreciation	0.0		0.0
Net property, plant and equipment	6.1		6.1
OG&E [Member]
Property, Plant and Equipment [Line Items]
Capitalized Computer Software, Gross	71.3		44.3
Capitalized Computer Software, Amortization	11.0		9.6		$ 8.8
OG&E [Member] | Total Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	12,906.6		12,365.1
Accumulated Depreciation	3,868.1		3,727.4
Net property, plant and equipment	9,038.5		8,637.7
OG&E [Member] | Electric Transmission and Distribution [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	4,468.6		4,229.4
Accumulated Depreciation	1,381.1		1,324.5
Net property, plant and equipment	3,087.5		2,904.9
OG&E [Member] | Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	4,838.6	[5]	4,657.2	[6]
Accumulated Depreciation	1,601.0	[5]	1,572.8	[6]
Net property, plant and equipment	3,237.6	[5]	3,084.4	[6]
Amount of Acquisition Adjustments	148.3		148.3
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments, Related Accumulated Depreciation	61.8		56.3
OG&E [Member] | Electric Transmission [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,901.1	[7]	2,846.7	[8]
Accumulated Depreciation	565.5	[7]	534.2	[8]
Net property, plant and equipment	2,335.6	[7]	2,312.5	[8]
Amount of Acquisition Adjustments	3.3		3.3
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments, Related Accumulated Depreciation	0.8		0.7
OG&E [Member] | Finite-Lived Intangible Assets, Major Class Name [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	225.2		187.6
Accumulated Depreciation	145.4		135.1
Net property, plant and equipment	79.8		52.5
OG&E [Member] | Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	473.1		444.2
Accumulated Depreciation	175.1		160.8
Net property, plant and equipment	$ 298.0		$ 283.4

[1] Construction work in progress was $0.2 million and $1.4 million for the McClain and Redbud Plants, respectively.

[2] Construction work in progress was $0.2 million and $0.9 million for the McClain and Redbud Plants, respectively.

[3] This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.

[4] This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.

[5] This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.

[6] This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.

[7] This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.8 million.

[8] This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.7 million.

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Summary of Significant Accounting Policies Allowance for Funds Used During Construction (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Public Utilities, Allowance for Funds Used During Construction, Rate	7.60%	7.60%	8.20%

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Common Equity (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

The following table calculates basic and diluted earnings per share for the Company.

(In millions except per share data)	2019		2018		2017
Net income	$	433.6	$	425.5	$	619.0
Average common shares outstanding:
Basic average common shares outstanding	200.1		199.7		199.7
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.6		0.8		0.3
Diluted average common shares outstanding	200.7		200.5		200.0
Basic earnings per average common share	$	2.17	$	2.13	$	3.10
Diluted earnings per average common share	$	2.16	$	2.12	$	3.10
Anti-dilutive shares excluded from earnings per share calculation	—		—		—

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value, by Balance Sheet Grouping [Table Text Block]

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

	2019				2018
December 31 (In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Classification
Long-term Debt (including Long-term Debt due within one year):
OG&E Senior Notes	$	3,050.3	$	3,500.4	$	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	$	9.5	$	10.0	$	9.6	$	8.7	Level 3

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

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

December 31 (In millions)	2019		2018
REGULATORY ASSETS
Current:
Fuel clause under recoveries	$	39.5	$	2.0
Production tax credit rider over credit (A)	1.7		6.9
Oklahoma demand program rider under recovery (A)	—		6.4
Other (A)	7.5		3.2
Total current regulatory assets	$	48.7	$	18.5
Non-current:
Benefit obligations regulatory asset	$	167.2	$	188.2
Deferred storm expenses	65.5		36.5
Sooner Dry Scrubbers	20.6		4.5
Smart Grid	18.4		25.6
Unamortized loss on reacquired debt	10.6		11.4
Arkansas deferred pension expenses	8.0		6.8
Pension tracker	2.3		—
Other	13.4		12.8
Total non-current regulatory assets	$	306.0	$	285.8
REGULATORY LIABILITIES
Current:
Reserve for tax refund and interim surcharge (B)	$	12.7	$	15.4
Fuel clause over recoveries	4.8		0.3
SPP cost tracker over recovery (B)	2.6		16.8
Oklahoma demand program rider over recovery (B)	2.0		—
Transmission cost recovery rider over recovery (B)	—		2.7
Other (B)	6.9		1.4
Total current regulatory liabilities	$	29.0	$	36.6
Non-current:
Income taxes refundable to customers, net	$	899.2	$	937.1
Accrued removal obligations, net	318.5		308.1
Pension tracker	—		18.7
Other	5.8		6.8
Total non-current regulatory liabilities	$	1,223.5	$	1,270.7

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

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

Components of Benefit Obligation Regulatory Asset [Table Text Block]

The following table is a summary of the components of the benefit obligations regulatory asset:

December 31 (In millions)	2019		2018
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	160.5	$	185.3
Postretirement Benefit Plans:
Net loss	23.3		25.6
Prior service cost	(16.6)		(22.7)
Total	$	167.2	$	188.2

Schedule of Net Periodic Benefit Cost Not yet Recognized [Table Text Block]

The following amounts in the benefit obligations regulatory asset at December 31, 2019 are expected to be recognized as components of net periodic benefit cost in 2020: 

(In millions)
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	11.4
Postretirement Benefit Plans:
Net loss	2.8
Prior service cost	(6.1)
Total	$	8.1

Schedule of Jointly Owned Utility Plants [Table Text Block]

The tables below present OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant, such as fuel, maintenance expense and other operating expenses, are included in the applicable financial statement captions in the Consolidated Statements of Income.

December 31, 2019 (In millions)	Percentage Ownership		Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
McClain Plant (A)	77	%	$	254.4	$	83.5	$	170.9
Redbud Plant (A)(B)	51	%	$	529.9	$	159.0	$	370.9

(A)Construction work in progress was $0.2 million and $1.4 million for the McClain and Redbud Plants, respectively.

(B)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.

December 31, 2018 (In millions)	Percentage Ownership		Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
McClain Plant (A)	77	%	$	227.2	$	78.2	$	149.0
Redbud Plant (A)(B)	51	%	$	493.9	$	145.3	$	348.6

(A)Construction work in progress was $0.2 million and $0.9 million for the McClain and Redbud Plants, respectively.

(B)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.

Property, Plant and Equipment [Table Text Block]

The Company's property, plant and equipment and related accumulated depreciation are divided into the following major classes: 

December 31, 2019 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
OGE Energy:
Property, plant and equipment	$	6.1	$	—	$	6.1
OGE Energy property, plant and equipment	6.1		—		6.1
OG&E:
Distribution assets	4,468.6		1,381.1		3,087.5
Electric generation assets (A)	4,838.6		1,601.0		3,237.6
Transmission assets (B)	2,901.1		565.5		2,335.6
Intangible plant	225.2		145.4		79.8
Other property and equipment	473.1		175.1		298.0
OG&E property, plant and equipment	12,906.6		3,868.1		9,038.5
Total property, plant and equipment	$	12,912.7	$	3,868.1	$	9,044.6

(A)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $61.8 million.

(B)This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.8 million.

December 31, 2018 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
OGE Energy:
Property, plant and equipment	$	6.1	$	—	$	6.1
OGE Energy property, plant and equipment	6.1		—		6.1
OG&E:
Distribution assets	4,229.4		1,324.5		2,904.9
Electric generation assets (A)	4,657.2		1,572.8		3,084.4
Transmission assets (B)	2,846.7		534.2		2,312.5
Intangible plant	187.6		135.1		52.5
Other property and equipment	444.2		160.8		283.4
OG&E property, plant and equipment	12,365.1		3,727.4		8,637.7
Total property, plant and equipment	$	12,371.2	$	3,727.4	$	8,643.8

(A)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.

(B)This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.7 million.

Schedule of Computer Software Costs, Amortization [Table Text Block]

The following table summarizes the Company's amortization expense for computer software costs.

Year Ended December 31 (In millions)	2019		2018		2017
OGE Energy	$	—	$	—	$	0.2
OG&E	11.0		9.6		8.8
Total	$	11.0	$	9.6	$	9.0

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following table summarizes changes to the Company's asset retirement obligations during the years ended December 31, 2019 and 2018.

(In millions)	2019		2018
Balance at January 1	$	83.9	$	75.1
Accretion expense	1.0		3.4
Revisions in estimated cash flows (A)	(2.4)		6.8
Liabilities settled (B)	(9.0)		(1.4)
Balance at December 31	$	73.5	$	83.9

(A)Assumptions changed related to the estimated cost of the removal of wind turbine assets and asbestos removal at OG&E's generating facilities.

(B)Asset retirement obligations were settled for asbestos removal and for the closure of an ash pond at OG&E's generating facilities.

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following tables summarize changes in the components of accumulated other comprehensive income (loss) attributable to the Company during 2018 and 2019. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan		Postretirement Benefit Plans
(In millions)	Net Gain  (Loss)		Net Gain (Loss)		Prior Service Cost (Credit)		Other Comprehensive Loss from Unconsolidated Affiliates		Total
Balance at December 31, 2017	$	(32.7)	$	2.5	$	7.0	$	—	$	(23.2)
Other comprehensive income (loss) before reclassifications	(14.1)		2.1		—		—		(12.0)
Amounts reclassified from accumulated other comprehensive income (loss)	3.3		—		(1.7)		—		1.6
Settlement cost	4.7		—		—		—		4.7
Net current period other comprehensive income (loss)	(6.1)		2.1		(1.7)		—		(5.7)
Balance at December 31, 2018	(38.8)		4.6		5.3		—		(28.9)
Other comprehensive income (loss) before reclassifications	(8.3)		(0.2)		—		(0.6)		(9.1)
Amounts reclassified from accumulated other comprehensive income (loss)	3.4		(0.2)		(1.7)		—		1.5
Settlement cost	8.6		—		—		—		8.6
Net current period other comprehensive income (loss)	3.7		(0.4)		(1.7)		(0.6)		1.0
Balance at December 31, 2019	$	(35.1)	$	4.2	$	3.6	$	(0.6)	$	(27.9)

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the years ended December 31, 2019 and 2018.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)				Affected Line Item in the Consolidated Statements of Income
	Year Ended December 31,
(In millions)	2019		2018
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses	$	(4.5)	$	(4.4)	(A)
Settlement cost	(11.3)		(6.3)		(A)
	(15.8)		(10.7)		Income Before Taxes
	(3.8)		(2.7)		Income Tax Expense
	$	(12.0)	$	(8.0)	Net Income
Amortization of postretirement benefit plans items:
Prior service credit	$	2.3	$	2.3	(A)
Actuarial gains	0.2		—		(A)
	2.5		2.3		Income Before Taxes
	0.6		0.6		Income Tax Expense
	$	1.9	$	1.7	Net Income
Total reclassifications for the period, net of tax	$	(10.1)	$	(6.3)	Net Income

(A)These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 13 for additional information).

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]

The amounts in accumulated other comprehensive loss (gain) at December 31, 2019 that are expected to be recognized into earnings in 2020 are as follows:

(In millions)
Pension Plan and Restoration of Retirement Income Plan:
Net gain	$	(4.2)
Postretirement Benefit Plans:
Net loss	0.2
Prior service cost	2.3
Total, net of tax	$	(1.7)

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Revenue from Contracts with Customers (Notes)

9 Months Ended

Sep. 30, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

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 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

	Year Ended December 31,
(In millions)	2019		2018
Residential	$	865.8	$	877.8
Commercial	486.6		500.0
Industrial	217.8		228.9
Oilfield	200.4		190.4
Public authorities and street light	190.3		197.4
System sales revenues	1,960.9		1,994.5
Provision for rate refund	(0.9)		(6.0)
Integrated market	38.4		48.7
Transmission	148.0		147.4
Other	29.1		27.1
Revenues from contracts with customers	$	2,175.5	$	2,211.7

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Stock Based Compensation

12 Months Ended

Dec. 31, 2019

Stock-Based Compensation [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

Stock-Based Compensation

In 2013, the Company adopted, and its shareholders approved, the Stock Incentive Plan. Under the Stock Incentive Plan, restricted stock, restricted stock units, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of the Company and its subsidiaries. The Company has authorized the issuance of up to 7,400,000 shares under the Stock Incentive Plan.

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the years ended December 31, 2019, 2018 and 2017 related to the Company's performance units and restricted stock units.

Year Ended December 31 (In millions)	2019		2018		2017
Performance units:
Total shareholder return	$	8.7	$	8.2	$	7.6
Earnings per share	4.3		5.1		1.4
Total performance units	13.0		13.3		9.0
Restricted stock units	0.9		0.1		0.1
Total compensation expense	$	13.9	$	13.4	$	9.1
Income tax benefit	$	3.6	$	3.4	$	3.5

The Company has issued new shares of common stock to satisfy restricted stock unit grants and payouts of earned performance units. In 2019, 2018 and 2017, there were 443,900 shares, 26,211 shares and 2,298 shares, respectively, of new common stock issued pursuant to the Company's Stock Incentive Plan related to restricted stock unit grants and payouts of earned performance units.

Performance Units

Under the Stock Incentive Plan, the Company has issued performance units which represent the value of one share of the Company's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with the Company or a subsidiary prior to the end of the primarily three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle. The Company estimates expected forfeitures in accounting for performance unit compensation expense.

The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of the Company's common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a primarily three-year award cycle (i.e., three-year cliff vesting period) is dependent on the Company's total shareholder return ranking relative to a peer group of companies. The performance units granted based on earnings per share are contingently awarded and will be payable in shares of the Company's common stock based on the Company's earnings per share growth over a primarily three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of the Company's Board of Directors. All of these performance units are classified as equity in the Consolidated Balance Sheets. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of the Company's Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee.

Performance Units – Total Shareholder Return

The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the primarily three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends are accrued on a quarterly basis pending achievement of payout criteria and are included in the fair value calculations. Expected price volatility is based on the historical volatility of the Company's common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to the Company's performance units based on total shareholder return. The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table.

	2019			2018			2017
Number of units granted	208,647			261,916			260,570
Fair value of units granted	$	47.00		$	36.86		$	41.77
Expected dividend yield	4.0		%	3.6		%	3.8		%
Expected price volatility	17.0		%	19.0		%	19.9		%
Risk-free interest rate	2.47		%	2.38		%	1.44		%
Expected life of units (in years)	2.86			2.86			2.80

Performance Units – Earnings Per Share

The fair value of the performance units based on earnings per share is based on grant date fair value which is equivalent to the price of one share of the Company's common stock on the date of grant. The fair value of performance units based on earnings per share varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. The Company reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to the Company's performance units based on earnings per share. In 2019, the Compensation Committee of the Company's Board of Directors voted to grant restricted stock units in lieu of performance units based on earnings per share. For 2018 and 2017, the number of performance units granted based on earnings per share and the grant date fair value are shown in the following table. 

	2018		2017
Number of units granted	87,308		86,857
Fair value of units granted	$	31.03	$	34.83

Restricted Stock Units

Under the Stock Incentive Plan, the Company has issued restricted stock units to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace, and for the 2019 grant cycle, restricted stock units were granted in lieu of performance units based on earnings per share. The restricted stock units vest primarily in a three-year award cycle (i.e., three-year cliff vesting period). Prior to vesting, each restricted stock unit is subject to forfeiture if the recipient ceases to render substantial services to the Company or a subsidiary. These restricted stock units may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.

The fair value of the restricted stock units was based on the closing market price of the Company's common stock on the grant date. Compensation expense for the restricted stock units is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a primarily three-year vesting period. Also, for those restricted stock units that vest in one-third annual increments over a three-year cycle, the Company treats its restricted stock units as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period.

Dividends will only be paid on restricted stock unit awards that vest; therefore, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock units is based on the non-vested period since inception of the primarily three-year award cycle. There are no post-vesting restrictions related to the Company's restricted stock units. The number of restricted stock units granted and the grant date fair value are shown in the following table. 

	2019		2018		2017
Restricted stock units granted	75,929		826		3,145
Fair value of restricted stock units granted	$	41.71	$	36.28	$	34.96

Performance Units and Restricted Stock Units Activity

A summary of the activity for the Company's performance units and restricted stock units at December 31, 2019 and changes in 2019 are shown in the following table.

	Performance Units								Restricted Stock Units
	Total Shareholder Return				Earnings Per Share
(Dollars in millions)	Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value		Number of Shares	Aggregate Intrinsic Value
Units/shares outstanding at 12/31/18	755,480				251,825				2,711
Granted	208,647	(A)			—				75,929
Converted	(274,078)	(B)	$	19.8	(91,356)	(B)	$	7.2	N/A
Vested	N/A				N/A				(2,161)	$	0.1
Forfeited	(25,232)				(5,298)				(3,599)
Units/shares outstanding at 12/31/19	664,817		$	35.4	155,171		$	11.5	72,880	$	3.2
Units/shares fully vested at 12/31/19	222,163		$	11.5	74,053		$	6.6

(A)For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.

(B)These amounts represent performance units that vested at December 31, 2018 which were settled in February 2019.

A summary of the activity for the Company's non-vested performance units and restricted stock units at December 31, 2019 and changes in 2019 are shown in the following table.

	Performance Units								Restricted Stock Units
	Total Shareholder Return				Earnings Per Share
	Number of Units		Weighted-Average Grant Date Fair Value		Number of Units		Weighted-Average Grant Date Fair Value		Number of Shares		Weighted-Average Grant Date Fair Value
Units/shares non-vested at 12/31/18	481,402		$	39.17	160,469		$	32.82	2,711		$	35.00
Granted	208,647	(A)	$	47.00	—		$	—	75,929		$	41.71
Vested	(222,163)		$	41.76	(74,053)		$	34.83	(2,161)		$	34.66
Forfeited	(25,232)		$	41.45	(5,298)		$	32.07	(3,599)		$	41.78
Units/shares non-vested at 12/31/19	442,654		$	41.43	81,118		$	31.03	72,880		$	41.66
Units/shares expected to vest	418,331	(B)			77,617	(B)			54,102	(B)

(A)For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target.

(B)The intrinsic value of the performance units based on total shareholder return and earnings per share is $22.8 million and $4.7 million, respectively. The intrinsic value of restricted stock units is $2.4 million.

Fair Value of Vested Performance Units and Restricted Stock Units

A summary of the Company's fair value for its vested performance units and restricted stock units is shown in the following table.

Year Ended December 31 (In millions)	2019		2018		2017
Performance units:
Total shareholder return	$	9.3	$	5.9	$	6.3
Earnings per share	$	5.2	$	4.9	$	1.2
Restricted stock units	$	0.1	$	0.1	$	0.1

Unrecognized Compensation Cost

A summary of the Company's unrecognized compensation cost for its non-vested performance units and restricted stock units and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

December 31, 2019	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance units:
Total shareholder return	$	8.7	1.67
Earnings per share	0.8		1.00
Total performance units	9.5
Restricted stock units	1.5		1.98
Total unrecognized compensation cost	$	11.0

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Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Operating revenues	$ 472.5	$ 755.4	$ 513.7	$ 490.0	$ 511.8	$ 698.8	$ 567.0	$ 492.7	$ 2,231.6	$ 2,270.3	$ 2,261.1
Cost of sales									786.9	892.5	897.6
Other operation and maintenance									491.8	474.6	458.7
Depreciation and amortization									355.0	321.6	283.5
Taxes other than income									93.6	92.0	89.4
Operating income (loss)	70.3	274.3	110.0	49.7	58.0	227.3	137.7	66.6	504.3	489.6	531.9
Equity in earnings of unconsolidated affiliates									113.9	152.8	131.2
Other income (expense)									(6.9)	11.3	50.4
Interest expense									147.9	156.0	143.8
Income tax expense (benefit)									29.8	72.2	(49.3)	[1]
NET INCOME	35.4	$ 250.9	$ 100.2	$ 47.1	54.7	$ 205.1	$ 110.7	$ 55.0	433.6	425.5	619.0
Investment in unconsolidated affiliates	1,151.5				1,177.5				1,151.5	1,177.5	1,160.4
Total assets	11,024.3				10,748.6				11,024.3	10,748.6	10,412.7
Capital expenditures									635.5	573.6	824.1
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues									2,231.6	2,270.3	2,261.1
Cost of sales									786.9	892.5	897.6
Other operation and maintenance									492.5	473.8	469.8
Depreciation and amortization									355.0	321.6	280.9
Taxes other than income									89.5	88.2	84.8
Operating income (loss)									507.7	494.2	528.0
Equity in earnings of unconsolidated affiliates									0.0	0.0	0.0
Other income (expense)									3.1	25.6	57.7
Interest expense									140.5	151.8	138.4
Income tax expense (benefit)									20.1	40.0	141.8	[1]
NET INCOME									350.2	328.0	305.5
Investment in unconsolidated affiliates	0.0				0.0				0.0	0.0	0.0
Total assets	10,076.6				9,704.5				10,076.6	9,704.5	9,255.6
Capital expenditures									635.5	573.6	824.1
Natural Gas Midstream Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues									0.0	0.0	0.0
Cost of sales									0.0	0.0	0.0
Other operation and maintenance									2.8	1.4	(0.8)
Depreciation and amortization									0.0	0.0	0.0
Taxes other than income									0.4	0.6	1.0
Operating income (loss)									(3.2)	(2.0)	(0.2)
Equity in earnings of unconsolidated affiliates									113.9	152.8	131.2
Other income (expense)									(8.6)	(4.9)	(1.0)
Interest expense									0.0	0.0	0.0
Income tax expense (benefit)									20.7	37.1	(195.2)	[1]
NET INCOME									81.4	108.8	325.2
Investment in unconsolidated affiliates	1,132.9				1,166.6				1,132.9	1,166.6	1,151.9
Total assets	1,135.4				1,169.8				1,135.4	1,169.8	1,155.3
Capital expenditures									0.0	0.0	0.0
Other Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues									0.0	0.0	0.0
Cost of sales									0.0	0.0	0.0
Other operation and maintenance									(3.5)	(0.6)	(10.3)
Depreciation and amortization									0.0	0.0	2.6
Taxes other than income									3.7	3.2	3.6
Operating income (loss)									(0.2)	(2.6)	4.1
Equity in earnings of unconsolidated affiliates									0.0	0.0	0.0
Other income (expense)									2.2	(3.4)	(5.4)
Interest expense									11.0	10.2	6.3
Income tax expense (benefit)									(11.0)	(4.9)	4.1	[1]
NET INCOME									2.0	(11.3)	(11.7)
Investment in unconsolidated affiliates	18.6				10.9				18.6	10.9	8.5
Total assets	107.0				184.8				107.0	184.8	109.1
Capital expenditures									0.0	0.0	0.0
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues									0.0	0.0	0.0
Cost of sales									0.0	0.0	0.0
Other operation and maintenance									0.0	0.0	0.0
Depreciation and amortization									0.0	0.0	0.0
Taxes other than income									0.0	0.0	0.0
Operating income (loss)									0.0	0.0	0.0
Equity in earnings of unconsolidated affiliates									0.0	0.0	0.0
Other income (expense)									(3.6)	(6.0)	(0.9)
Interest expense									(3.6)	(6.0)	(0.9)
Income tax expense (benefit)									0.0	0.0	0.0	[1]
NET INCOME									0.0	0.0	0.0
Investment in unconsolidated affiliates	0.0				0.0				0.0	0.0	0.0
Total assets	$ (294.7)				$ (310.5)				(294.7)	(310.5)	(107.3)
Capital expenditures									$ 0.0	$ 0.0	0.0
Tax Benefit Due to Tax Law Change [Member]
Segment Reporting Information [Line Items]
Income tax expense (benefit)											245.2
Tax Expense Due to Tax Law Change [Member]
Segment Reporting Information [Line Items]
Income tax expense (benefit)											$ 10.5

[1] The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act.

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Long-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Total long-term debt	$ 3,195.2	$ 3,146.9
Percent of Principal Amount Subject to Optional Tender	100.00%
Date Due	Mar. 15, 2030
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 0.0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0.0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0.0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0.0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0.0
Debt Instrument, Face Amount	$ 300.0
Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Date Due	Jan. 01, 2025
Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Date Due	Jan. 01, 2025
Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Date Due	Jun. 01, 2027
Redeemable during the next 12 months
Debt Instrument [Line Items]
Total long-term debt	$ 135.4
OG&E [Member] | Redeemable during the next 12 months | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Long term debt, gross	47.0	47.0
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Long term debt, gross	32.4	32.4
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Long term debt, gross	56.0	56.0
Senior Notes [Member] | OG&E [Member] | Series Due March 15, 2030
Debt Instrument [Line Items]
Long term debt, gross	$ 300.0	$ 0.0
Debt Instrument, Interest Rate, Stated Percentage	3.30%
Date Due	Mar. 15, 2030
Minimum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.20%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.19%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.20%
Maximum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.35%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.48%

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Summary of Significant Accounting Policies Depreciation and Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Provision for Depreciation Rate	2.70%	2.70%
Projected provision for depreciation in next fiscal year	2.70%
Percent Of Intangible Plant Balance Amortizable	98.90%
Percent of Intangible Plant Balance Amortizable Thereafter	1.10%
Transmission Equipment [Member] | OG&E [Member]
Amount of Acquisition Adjustments	$ 3.3
Redbud Plant [Member]
Amount of Acquisition Adjustments	$ 148.3	$ 148.3

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Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive (income) loss		$ (27.9)	$ (28.9)	$ (23.2)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		(9.1)	(12.0)
Amounts reclassified from accumulated other comprehensive income (loss)		(3.4)	(3.3)	(2.5)
Amounts reclassified from accumulated other comprehensive income (loss)		1.5	1.6
Net current period other comprehensive income (loss)		1.0	(5.7)
Amounts Reclassified from Accumulated OCI, Net of Tax and Noncontrolling Interest		10.1	6.3
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		(1.7)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		(12.0)	(8.0)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, before Tax	[1]	(4.5)	(4.4)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	[1]	(11.3)	(6.3)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		(15.8)	(10.7)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		(3.8)	(2.7)
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		1.9	1.7
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, before Tax	[1]	0.2	0.0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, before Tax	[1]	2.3	2.3
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		2.5	2.3
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		0.6	0.6
Defined Benefit Plans Income Loss [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)		(35.1)	(38.8)	(32.7)
Other comprehensive income before reclassifications		(8.3)	(14.1)
Amounts reclassified from accumulated other comprehensive income (loss)		3.4	3.3
Net current period other comprehensive income (loss)		3.7	(6.1)
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		(4.2)
Defined Benefit Plans Income Loss [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)		4.2	4.6	2.5
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		(0.2)	2.1
Amounts reclassified from accumulated other comprehensive income (loss)		(0.2)	0.0
Net current period other comprehensive income (loss)		(0.4)	2.1
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		0.2
Defined Benefit Plan Prior Service Cost [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)		3.6	5.3	7.0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		0.0	0.0
Amounts reclassified from accumulated other comprehensive income (loss)		(1.7)	(1.7)
Net current period other comprehensive income (loss)		(1.7)	(1.7)
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		2.3
Settlement Cost [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		8.6	4.7
Settlement Cost [Member] | Defined Benefit Plans Income Loss [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		8.6	4.7
Settlement Cost [Member] | Defined Benefit Plans Income Loss [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		0.0	0.0
Settlement Cost [Member] | Defined Benefit Plan Prior Service Cost [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		0.0	0.0
Commodity Contract [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)			(0.6)	$ 0.0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			0.0
Amounts reclassified from accumulated other comprehensive income (loss)		0.0	0.0
Amounts reclassified from accumulated other comprehensive income (loss)		(0.6)	0.0
Net current period other comprehensive income (loss)		(0.6)	0.0
Amounts removed from accumulated other comprehensive income due to deconsolidation		$ 0.0	$ 0.0

[1] These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 13 for additional information).

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Investment in Unconsolidated Affiliate and Related Party Transactions (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	May 01, 2013
Schedule of Equity Method Investments [Line Items]
Limited Partner Units Owned	111.0
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.50%	25.60%	25.70%
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.33050
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 652.5	$ 680.3
Equity in earnings of unconsolidated affiliates	113.9	152.8	$ 131.2
Enable Midstream Partners [Member]
Schedule of Equity Method Investments [Line Items]
Distributions received	$ 144.0	141.2	141.2
Enogex LLC [Member]
Schedule of Equity Method Investments [Line Items]
Increase in fair value of net assets				$ 2,200.0
OGE Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.50%
OGE Energy [Member]
Schedule of Equity Method Investments [Line Items]
Percentage Share of Management Rights	50.00%
CenterPoint [Member]
Schedule of Equity Method Investments [Line Items]
Percentage Share of Management Rights	50.00%
Natural Gas Midstream Operations [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	$ 113.9	$ 152.8	$ 131.2

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Investment in Unconsolidated Affiliate and Related Party Transactions Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Enable net income		$ 360.0	$ 485.3	$ 400.3
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest		25.50%	25.60%	25.70%
Proportionate Unconsolidated Affiliate Net Income		$ 91.8	$ 124.4	$ 102.7
OGE Energy's portion of Enable net income				102.7
Amortization of basis difference and dilution recognition	[1]	22.1	28.4	28.5
Equity in earnings of unconsolidated affiliates		113.9	152.8	131.2
Natural Gas Midstream Operations [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates		$ 113.9	$ 152.8	$ 131.2
OGE Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest		25.50%
OGE Energy [Member]
Schedule of Equity Method Investments [Line Items]
Amortization of basis difference and dilution recognition	[2]	$ 27.8

[1] Includes loss on dilution, net of proportional basis difference recognition.

[2] Includes proportional basis difference recognition due to dilution.

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement		$ 28.9	$ (9.2)	$ (2.6)
SUPPLEMENTAL CASH FLOW INFORMATION
Interest (net of interest capitalized)	[1]	152.2	153.8	139.6
Income taxes (net of income tax refunds)		5.5	2.8	(16.0)
Interest costs capitalized		$ 2.8	$ 11.7	$ 18.0

[1] Net of interest capitalized of $2.8 million, $11.7 million and $18.0 million in 2019, 2018 and 2017, respectively.

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CONSOLIDATED BALANCE SHEETS Parenthetical - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Allowance for Doubtful Accounts Receivable	$ 1.5	$ 1.7

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Summary of Significant Accounting Policies Allowance for Uncollectible Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Allowance for Doubtful Accounts Receivable	$ 1.5	$ 1.7

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income	$ 433.6	$ 425.5	$ 619.0
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $1.1, $1.1 and $1.4, respectively	3.4	3.3	2.5
Amortization of prior service credit, net of tax of $0.0, $0.0 and $0.0, respectively	0.0	0.0	0.1
Net gain (loss) arising during the period, net of tax of $(2.6), ($4.7) and $0.2, respectively	(8.3)	(14.1)	0.4
Settlement cost, net of tax of $2.7, $1.6 and $1.4, respectively	8.6	4.7	2.2
Postretirement Benefit Plans:
Amortization of prior service credit, net of tax of ($0.6), ($0.6) and ($0.3), respectively	(1.7)	(1.7)	(0.6)
Amortization of deferred net gain, net of tax of $0.0, $0.0 and $0.0, respectively	(0.2)	0.0	0.0
Prior service cost arising during the period, net of tax of $0.0, $0.0 and $4.0, respectively	0.0	0.0	6.3
Net gain (loss) arising during the period, net of tax of ($0.1), $0.7 and ($0.2), respectively	(0.2)	2.1	(0.6)
Settlement cost, net of tax of $0.0, $0.0 and $0.2, respectively	0.0	0.0	0.5
Other comprehensive income (loss), net of tax	1.0	(5.7)	10.6
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest	0.6	0.0	0.0
Comprehensive income	$ 434.6	$ 419.8	$ 629.6

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Data [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

In the Company's opinion, the following quarterly financial data includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present such amounts. Summarized consolidated quarterly unaudited financial data is as follows:

Quarter Ended (In millions, except per share data)		March 31		June 30		September 30		December 31		Total
Operating revenues	2019	$	490.0	$	513.7	$	755.4	$	472.5	$	2,231.6
	2018	$	492.7	$	567.0	$	698.8	$	511.8	$	2,270.3
Operating income	2019	$	49.7	$	110.0	$	274.3	$	70.3	$	504.3
	2018	$	66.6	$	137.7	$	227.3	$	58.0	$	489.6
Net income	2019	$	47.1	$	100.2	$	250.9	$	35.4	$	433.6
	2018	$	55.0	$	110.7	$	205.1	$	54.7	$	425.5
Basic earnings per average common share (A)	2019	$	0.24	$	0.50	$	1.25	$	0.18	$	2.17
	2018	$	0.28	$	0.55	$	1.03	$	0.27	$	2.13
Diluted earnings per average common share (A)	2019	$	0.24	$	0.50	$	1.25	$	0.18	$	2.16
	2018	$	0.27	$	0.55	$	1.02	$	0.27	$	2.12

(A)Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

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Short-Term Debt and Credit Facilities (Tables)

12 Months Ended

Dec. 31, 2019

Short-term Debt [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

The following table provides information regarding the Company's revolving credit agreements at December 31, 2019.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
	(In millions)
OGE Energy (B)	$	450.0	$	112.0	2.06	%	(D)	March 8, 2023
OG&E (C)	450.0		0.3		1.00	%	(D)	March 8, 2023
Total	$	900.0	$	112.3	2.06	%

(A)Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 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.

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Long-Term Debt

12 Months Ended

Dec. 31, 2019

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

Long-Term Debt

A summary of the Company's long-term debt is included in the Consolidated Statements of Capitalization. The Company has no long-term debt maturing in the next five years. At December 31, 2019, the Company was in compliance with all of its debt agreements.

The Company has previously incurred costs related to debt refinancing. Unamortized loss on reacquired debt is classified as a Non-Current Regulatory Asset. Unamortized debt expense and unamortized premium and discount on long-term debt are classified as Long-Term Debt in the Consolidated Balance Sheets and are being amortized over the life of the respective debt.

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 as follows:

Series			Date Due	Amount
				(In millions)
1.20%	-	2.50%	Garfield Industrial Authority, January 1, 2025	$	47.0
1.19%	-	2.35%	Muskogee Industrial Authority, January 1, 2025	32.4
1.20%	-	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 Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

Issuance of Long-Term Debt

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

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Public Utility Regulatory Policy Act of 1978

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 power 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 16.

For the years ended December 31, 2019, 2018 and 2017, OG&E made total payments to cogenerators of $14.7 million, $112.4 million and $115.2 million, respectively, of which $7.4 million, $60.0 million and $63.0 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Consolidated Statements of Income as Cost of Sales.

Purchase Obligations and Commitments

The Company's future purchase obligations and commitments estimated for the next five years are as follows: 

(In millions)	2020		2021		2022		2023		2024		Total
Purchase obligations and commitments:
Minimum purchase commitments	$	82.6	$	55.1	$	50.4	$	50.4	$	32.9	$	271.4
Expected wind purchase commitments	55.7		56.0		56.4		56.8		57.5		282.4
Long-term service agreement commitments	2.4		2.4		2.4		13.8		32.1		53.1
Environmental compliance plan expenditures	0.4		—		—		—		—		0.4
Total purchase obligations and commitments	$	141.1	$	113.5	$	109.2	$	121.0	$	122.5	$	607.3

OG&E Minimum Purchase Commitments

OG&E has coal contracts for purchases through June 30, 2020 and May 31, 2021, whereby OG&E has the right but not the obligation to purchase a defined quantity of coal. OG&E purchases its coal through spot purchases on an as-needed basis. As a participant in the SPP Integrated Marketplace, OG&E purchases its natural gas supply through short-term agreements. OG&E relies on a combination of natural gas base load agreements and call agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP Integrated Marketplace.

OG&E has natural gas transportation service contracts with Enable and ONEOK, Inc. The contract with Enable ends in May 2024, and the contract with ONEOK, Inc. ends in August 2037. These transportation contracts grant Enable and ONEOK, Inc. the responsibility of delivering natural gas to OG&E's generating facilities.

OG&E Wind Purchase Commitments

The following table summarizes OG&E's wind power purchase contracts.

Company	Location	Original Term of Contract	Expiration of Contract	MWs
CPV Keenan	Woodward County, OK	20 years	2030	152.0
Edison Mission Energy	Dewey County, OK	20 years	2031	130.0
NextEra Energy	Blackwell, OK	20 years	2032	60.0

The following table summarizes OG&E's wind power purchases for the years ended December 31, 2019, 2018 and 2017. 

Year Ended December 31 (In millions)	2019		2018		2017
CPV Keenan	$	27.2	$	27.0	$	29.0
Edison Mission Energy	23.1		21.7		22.1
NextEra Energy	7.4		6.8		7.4
FPL Energy (A)	—		2.1		2.6
Total wind power purchased	$	57.7	$	57.6	$	61.1

(A)OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018.

OG&E Long-Term Service Agreement Commitments

OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant. In May 2013, a new contract was signed that is expected to run for the earlier of 128,000 factored-fired hours or 4,800 factored-fired starts. In December 2015, the McClain Long-Term Service Agreement was amended to define the terms and conditions for the exchange of spare rotors between OG&E and General Electric International, Inc. Based on historical usage and current expectations for future usage, this contract is expected to run until 2033. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.

OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional 24,000 factored-fired hours resulting in a maximum of the earlier of 144,000 factored-fired hours or 4,500 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2030. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.

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 or 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.

Affordable Clean Energy Rule

On July 8, 2019, the EPA published the Affordable Clean Energy rule. 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. The ultimate timing and impact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO₂ emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect the Company's future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

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 Consolidated Financial Statements. At the present time, based on currently available information, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation, Policy [Policy Text Block]

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 Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.

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

The natural gas midstream operations segment represents the Company's investment in Enable through wholly-owned subsidiaries and ultimately OGE Holdings. Enable is 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. Enable's 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.

Public Utilities, Policy [Policy Text Block]

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.

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.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

In preparing the 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 Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Changes to these assumptions and estimates could have a material effect on the Company's 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 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.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

For purposes of the Consolidated Financial Statements, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.

Allowance for Uncollectible Accounts Receivable, Policy

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate, which is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable in the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense in the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $1.5 million and $1.7 million at December 31, 2019 and 2018, respectively.

New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers whose outside credit scores indicate an elevated risk are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored, and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.

Inventory, Policy [Policy Text Block]

Fuel Inventories

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was $46.3 million and $57.6 million at December 31, 2019 and 2018, respectively.

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment

All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances, and the cost of such property net of any salvage proceeds is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation, and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Other Expense. Repair and replacement of minor items of property are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense.

Depreciation and Amortization, Policy [Policy Text Block]

Depreciation and Amortization

The provision for depreciation, which was 2.7 percent of the average depreciable utility plant for both 2019 and 2018, is calculated using the straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant and is based on the average life group method. In 2020, the provision for depreciation is projected to be 2.7 percent of the average depreciable utility plant.

Amortization of intangible assets is calculated using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2019, 98.9 percent will be amortized over 10.4 years with the remaining 1.1 percent of the intangible plant balance at December 31, 2019 being amortized over 23.7 years.  

Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired assets. Plant acquisition adjustments include $148.3 million for the Redbud Plant, which is being amortized over a 27 year life and $3.3 million for certain transmission substation facilities in OG&E's service territory, which are being amortized over a 37 to 59 year period.

Equity Method Investments [Policy Text Block]

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 December 31, 2019 as presented in Note 14. 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 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 Consolidated Statements of Cash Flows.

Asset Retirement Obligation [Policy Text Block]

Asset Retirement ObligationsOG&E has asset retirement obligations primarily associated with the removal of company-owned wind turbines on leased land, as well as the removal of asbestos from certain power generating stations. The Company has recorded asset retirement obligations that are being accreted over their respective lives ranging from ten to 68 years.

Allowance for Funds Used During Construction, Policy [Policy Text Block]

Allowance for Funds Used During Construction

Allowance for funds used during construction, a non-cash item, is reflected as an increase to Net Other Income and a reduction to Interest Expense in the Consolidated Statements of Income and as an increase to Construction Work in Progress in the Consolidated Balance Sheets. Allowance for funds used during construction is calculated according to the FERC requirements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction rates, compounded semi-annually, were 7.6 percent, 7.6 percent and 8.2 percent for the years ended December 31, 2019, 2018 and 2017, respectively.

Collection of Sales Tax, Policy [Policy Text Block]

Collection of Sales Tax

In the normal course of its operations, OG&E collects sales tax from its customers. OG&E records a current liability for sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. OG&E excludes the sales tax collected from its operating revenues.

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

General

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

Integrated Market and Transmission

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

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

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

Other Revenues

Revenues from Alternative Revenue Programs

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

Fuel Adjustment Clauses, Policy [Policy Text Block]

Fuel Adjustment Clauses

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.

Lessee, Leases

LeasesThe Company evaluates all contracts under ASC 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 ASC 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.

Income Taxes, Policy [Policy Text Block]

Income Taxes

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. 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. The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company recognizes interest related to unrecognized tax benefits in Interest Expense and recognizes penalties in Other Expense in the Consolidated Statements of Income.

Accrued Vacation, Policy [Policy Text Block]

Accrued Vacation

The Company accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned but not taken.

Environmental Costs, Policy [Policy Text Block]

Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost. The Company had $18.7 million and $23.4 million in accrued environmental liabilities at December 31, 2019 and 2018, respectively, which are included in the Company's asset retirement obligations.

Fair Value of Financial Instruments, Policy [Policy Text Block]

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 December 31, 2019 and 2018.

Share-based Compensation, Option and Incentive Plans, Policy [Policy Text Block]

Performance Units

Under the Stock Incentive Plan, the Company has issued performance units which represent the value of one share of the Company's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with the Company or a subsidiary prior to the end of the primarily three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle. The Company estimates expected forfeitures in accounting for performance unit compensation expense.

The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of the Company's common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a primarily three-year award cycle (i.e., three-year cliff vesting period) is dependent on the Company's total shareholder return ranking relative to a peer group of companies. The performance units granted based on earnings per share are contingently awarded and will be payable in shares of the Company's common stock based on the Company's earnings per share growth over a primarily three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of the Company's Board of Directors. All of these performance units are classified as equity in the Consolidated Balance Sheets. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of the Company's Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee.

Performance Units – Total Shareholder Return

The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the primarily three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends are accrued on a quarterly basis pending achievement of payout criteria and are included in the fair value calculations. Expected price volatility is based on the historical volatility of the Company's common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to the Company's performance units based on total shareholder return.Performance Units – Earnings Per ShareThe fair value of the performance units based on earnings per share is based on grant date fair value which is equivalent to the price of one share of the Company's common stock on the date of grant. The fair value of performance units based on earnings per share varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. The Company reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to the Company's performance units based on earnings per share.

Restricted Stock Units

Under the Stock Incentive Plan, the Company has issued restricted stock units to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace, and for the 2019 grant cycle, restricted stock units were granted in lieu of performance units based on earnings per share. The restricted stock units vest primarily in a three-year award cycle (i.e., three-year cliff vesting period). Prior to vesting, each restricted stock unit is subject to forfeiture if the recipient ceases to render substantial services to the Company or a subsidiary. These restricted stock units may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.

The fair value of the restricted stock units was based on the closing market price of the Company's common stock on the grant date. Compensation expense for the restricted stock units is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a primarily three-year vesting period. Also, for those restricted stock units that vest in one-third annual increments over a three-year cycle, the Company treats its restricted stock units as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period.

Dividends will only be paid on restricted stock unit awards that vest; therefore, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock units is based on the non-vested period since inception of the primarily three-year award cycle. There are no post-vesting restrictions related to the Company's restricted stock units.

Earnings Per Share, Policy [Policy Text Block]

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.

Pension and Other Postretirement Plans, Policy [Policy Text Block]

Pension Plan and Restoration of Retirement Income Plan

It is the Company's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by the Company's actuarial consultants. Such contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. The Company made a $20.0 million and $15.0 million contribution to its Pension Plan in 2019 and 2018, respectively. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2020. Any contribution to the Pension Plan during 2020 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. The Company could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.

The Company provides a Restoration of Retirement Income Plan to those participants in the Company's Pension Plan whose benefits are subject to certain limitations of the Code. Participants in the Restoration of Retirement Income Plan receive the same benefits that they would have received under the Company's Pension Plan in the absence of limitations imposed by the federal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan.As defined in the fair value hierarchy, Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan 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 Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

Postretirement Benefit Plans

In addition to providing pension benefits, the Company provides certain medical and life insurance benefits for eligible retired members. Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained at least age 55 with 10 or more years of service at the time of retirement are entitled to postretirement medical benefits, while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Eligible retirees must contribute such amount as the Company specifies from time to time toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. OG&E charges postretirement benefit costs to expense and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.

The group retiree medical insurance contract invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans' pro-rata share of the total assets in the contract.

Postemployment Benefit Plans, Policy [Policy Text Block]

Post-Employment Benefit Plan

Disabled employees receiving benefits from the Company's Group Long-Term Disability Plan are entitled to continue participating in the Company's Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in the Company's Group Long-Term Disability Plan and their dependents, as defined in the Company's Medical Plan.

The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from the Company's Group Long-Term Disability Plan due to death, recovery from disability or eligibility for retiree medical benefits. The Company's post-employment benefit obligation was $2.1 million and $1.9 million at December 31, 2019 and 2018, respectively.

Plan Investments, Policies and Strategies, Policy [Policy Text Block]

Pension Plan Investments, Policies and Strategies

The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability-driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.

Projected Benefit Obligation Funded Status Thresholds	<90%	95%	100%	105%	110%	115%	120%
Fixed income	50%	58%	65%	73%	80%	85%	90%
Equity	50%	42%	35%	27%	20%	15%	10%
Total	100%	100%	100%	100%	100%	100%	100%

Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below.

Asset Class	Target Allocation	Minimum	Maximum
Domestic Large Cap Equity	40%	35%	60%
Domestic Mid-Cap Equity	15%	5%	25%
Domestic Small-Cap Equity	25%	5%	30%
International Equity	20%	10%	30%

The Company has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of the Company's members and the Company's Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager's respective portfolio. 

The portfolio is rebalanced at least on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust's exposure to any asset class to exceed or fall below the established allowable guidelines.

To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:

Asset Class	Comparative Benchmark(s)
Active Duration Fixed Income	Bloomberg Barclays Aggregate
Long Duration Fixed Income	Duration blended Barclays Long Government/Credit & Barclays Universal
Equity Index	Standard & Poor's 500 Index
Mid-Cap Equity	Russell Midcap Index
	Russell Midcap Value Index
Small-Cap Equity	Russell 2000 Index
	Russell 2000 Value Index
International Equity	Morgan Stanley Capital International ACWI ex-U.S.

The fixed income managers are expected to use discretion over the asset mix of the trust assets in their efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies or its instrumentalities (which have no limits), is limited to five percent of the fixed income portfolio as measured by market value. At

least 75 percent of the invested assets must possess an investment-grade rating at or above Baa3 or BBB- by Moody's Investors Service, S&P's Global Ratings or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 15 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. The purchase of any of the Company's equity, debt or other securities is prohibited.

The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index. The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-U.S. Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-U.S. Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the U.S. All of the equities which are purchased for the international portfolio are thoroughly researched. All securities are freely traded on a recognized stock exchange, and there are no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).

For all domestic equity investment managers, no more than five percent can be invested in any one stock at the time of purchase and no more than 10 percent after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval of the Company's Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of the Company's equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager's organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.

Pension and Other Postretirement Plans, Nonpension Benefits, Policy [Policy Text Block]

401(k) Plan

The Company provides a 401(k) Plan, and each regular full-time employee of the Company or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of the Company or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have reached age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof, (ii) a contribution made on a non-Roth after-tax basis or (iii) a Roth contribution. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have their future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, the Company contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation.

No Company contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, the Company's contribution may be directed to any available investment option in the 401(k) Plan. The Company match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their Company contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan requirements, in the event of their termination

due to death or permanent disability or upon attainment of age 65 while employed by the Company or its affiliates. The Company contributed $14.4 million, $13.2 million and $13.2 million in 2019, 2018 and 2017, respectively, to the 401(k) Plan.

Deferred Compensation Plan

The Company provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of the Company and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace.

Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers. The Company matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of the Company or termination of the plan. Deferrals, plus any Company match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2019, those investment options included a Company Common Stock fund, whose value was determined based on the stock price of the Company's common stock. The Company accounts for the contributions related to the Company's executive officers in this plan as Accrued Benefit Obligations, and the Company accounts for the contributions related to the Company's directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in the Consolidated Balance Sheets. The appreciation of these investments is accounted for as Other Income, and the increase in the liability under the plan is accounted for as Other Expense in the Consolidated Statements of Income.