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10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2022

☐ 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	Exact name of registrants as specified in their charters, address of principal executive offices and registrants' telephone number	I.R.S. Employer Identification No.
1-12579	OGE ENERGY CORP.	73-1481638
1-1097	OKLAHOMA GAS AND ELECTRIC COMPANY	73-0382390

321 North Harvey

P.O. Box 321

Oklahoma City, Oklahoma 73101-0321

405-553-3000

State or other jurisdiction of incorporation or organization: Oklahoma

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


Registrant	Title of each class	Trading Symbol(s)	Name of each exchange on which registered
OGE Energy Corp.	Common Stock	OGE	New York Stock Exchange
Oklahoma Gas and Electric Company	None	N/A	N/A

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.

OGE Energy Corp. ☑ Yes ☐ No Oklahoma Gas and Electric Company ☑ Yes ☐ No

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

OGE Energy Corp. ☐ Yes ☑ No Oklahoma Gas and Electric Company ☐ Yes ☑ 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.

OGE Energy Corp. ☑ Yes ☐ No Oklahoma Gas and Electric Company ☑ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

OGE Energy Corp. ☑ Yes ☐ No Oklahoma Gas and Electric Company ☑ Yes ☐ No

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


OGE Energy Corp.	Large Accelerated Filer	☑	Accelerated Filer	☐	Non-accelerated Filer	☐	Smaller reporting company	☐	Emerging growth company	☐
Oklahoma Gas and Electric Company	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 has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

OGE Energy Corp. ☑ Oklahoma Gas and Electric Company ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive oﬃcers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

OGE Energy Corp. ☐ Yes ☑ No Oklahoma Gas and Electric Company ☐ Yes ☑ No

At June 30, 2022, the last business day of OGE Energy Corp.'s most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $7,719,815,032 based on the number of shares held by non-affiliates (200,202,672) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $38.56.

At June 30, 2022, there was no voting or non-voting common equity of Oklahoma Gas and Electric Company held by non-affiliates.

At January 31, 2023, there were 200,229,215 shares of OGE Energy Corp.'s common stock, par value $0.01 per share, outstanding.

At January 31, 2023, there were 40,378,745 shares of Oklahoma Gas and Electric Company's common stock, par value $2.50 per share, outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.

DOCUMENTS INCORPORATED BY REFERENCE

The Proxy Statement for OGE Energy Corp.'s 2023 annual meeting of shareowners is incorporated by reference into Part III of this Form 10-K.

This combined Form 10-K represents separate filings by OGE Energy Corp. and Oklahoma Gas and Electric Company. Information contained herein related to an individual registrant is filed by such registrant on its own behalf. Oklahoma Gas and Electric Company makes no representations as to the information relating to OGE Energy Corp.'s other operations.

Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2022

TABLE OF CONTENTS


	Page
GLOSSARY OF TERMS	ii
FORWARD-LOOKING STATEMENTS	1

Part I
Item 1. Business	3
Item 1A. Risk Factors	13
Item 1B. Unresolved Staff Comments	21
Item 2. Properties	22
Item 3. Legal Proceedings	23
Item 4. Mine Safety Disclosures	23

Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6. [Reserved]	24
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	40
Item 8. Financial Statements and Supplementary Data	42
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	99
Item 9A. Controls and Procedures	99
Item 9B. Other Information	102
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	102

Part III
Item 10. Directors, Executive Officers and Corporate Governance	103
Item 11. Executive Compensation	103
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	103
Item 13. Certain Relationships and Related Transactions, and Director Independence	103
Item 14. Principal Accountant Fees and Services	103

Part IV
Item 15. Exhibit and Financial Statement Schedules	105
Item 16. Form 10-K Summary	110
Signatures	111

GLOSSARY OF TERMS

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


Abbreviation		Definition
2021 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2021
401(k) Plan		Qualified defined contribution retirement plan
APSC		Arkansas Public Service Commission
ASC		Financial Accounting Standards Board Accounting Standards Codification
ASU		Financial Accounting Standards Board Accounting Standards Update
CenterPoint		CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO2		Carbon dioxide
Code		Internal Revenue Code of 1986
COVID-19		Novel Coronavirus disease
Dry Scrubber		Dry flue gas desulfurization unit with spray dryer absorber
Enable		Enable Midstream Partners, LP, partnership formed to own and operate the midstream businesses of OGE Energy and CenterPoint (prior to December 2, 2021)
Energy Transfer		Energy Transfer LP, a Delaware limited partnership, collectively with its subsidiaries
EPA		U.S. Environmental Protection Agency
Federal Clean Water Act		Federal Water Pollution Control Act of 1972, as amended
FERC		Federal Energy Regulatory Commission
FIP		Federal Implementation Plan
GAAP		Accounting principles generally accepted in the U.S.
IRP		Integrated Resource Plan
ISO		Independent system operator
kV		Kilovolt
LIBOR		London Interbank Offered Rate
MW		Megawatt
MWh		Megawatt-hour
NAAQS		National Ambient Air Quality Standard
NERC		North American Electric Reliability Corporation
NGLs		Natural gas liquids, which are the hydrocarbon liquids contained within the natural gas stream
NOPR		Notice of proposed rulemaking
NOX		Nitrogen oxide
OCC		Oklahoma Corporation Commission
ODEQ		Oklahoma Department of Environmental Quality
OG&E		Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Energy		OGE Energy Corp., collectively with its subsidiaries, holding company and parent company of OG&E
OGE Holdings		OGE Enogex Holdings LLC, wholly-owned subsidiary of OGE Energy, parent company of Enogex Holdings LLC (prior to May 1, 2013) and 25.5 percent owner of Enable (prior to December 2, 2021)
ODFA		Oklahoma Development Finance Authority
OSHA		U.S. Department of Labor's Occupational Safety and Health Administration
Pension Plan		Qualified defined benefit retirement plan
Regional Haze		The EPA's Regional Haze Rule
Registrants		OGE Energy and OG&E
Restoration of Retirement Income Plan		Supplemental retirement plan to the Pension Plan
RTO		Regional transmission organization
SIP		State Implementation Plan
SO2		Sulfur dioxide
SOFR		Secured Overnight Funding Rate
SPP		Southwest Power Pool
System sales		Sales to OG&E's customers
U.S.		United States of America
USFWS		United States Fish and Wildlife Service
Winter Storm Uri		Unprecedented, prolonged extreme cold weather event in February 2021

FILING FORMAT

This combined Form 10-K is separately filed by OGE Energy and OG&E. Information in this combined Form 10-K relating to each individual Registrant is filed by such Registrant on its own behalf. OG&E makes no representation regarding information relating to any other companies affiliated with OGE Energy. Neither OGE Energy, nor any of OGE Energy's subsidiaries, other than OG&E, has any obligation in respect of OG&E's debt securities, and holders of such debt securities should not consider the financial resources or results of operations of OGE Energy nor any of OGE Energy's subsidiaries, other than OG&E (in relevant circumstances), in making a decision with respect to OG&E's debt securities. Similarly, none of OG&E nor any other subsidiary of OGE Energy has any obligation with respect to debt securities of OGE Energy. This combined Form 10-K should be read in its entirety. No one section of this combined Form 10-K deals with all aspects of the subject matter of this combined Form 10-K.

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," "forecast," "intend," "objective," "plan," "possible," "potential," "project," "target" 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, inflation rates and their impact on capital expenditures;

•

the ability of OGE Energy and OG&E 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, including through securitization, of items such as capital expenditures, fuel and purchased power costs, operating costs, transmission costs and deferred expenditures;

•

prices and availability of electricity, coal and natural gas;

•

competitive factors, including the extent and timing of the entry of additional competition in the markets served by the Registrants, potentially through deregulation;

•

the impact on demand for 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 and equipment 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 Registrants' markets;

•

environmental laws, safety laws or other regulations that may impact the cost of operations, restrict or change the way the Registrants' facilities are operated or result in stranded assets;

•

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, including losing control of our assets and potential ransoms, and other catastrophic events;

•

creditworthiness of suppliers, customers and other contractual parties, including large, new customers from emerging industries such as cryptocurrency;

•

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;

•

the impact of extraordinary external events, such as the pandemic health event resulting from COVID-19, and their collateral consequences;

•

national and global events that could adversely affect and/or exacerbate macroeconomic conditions, including inflationary pressures, rising interest rates, supply chain disruptions, economic recessions and uncertainty surrounding continued hostilities or sustained military campaigns;

•

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; and

•

other risk factors listed in the reports filed by the Registrants with the Securities and Exchange Commission, including those listed within "Item 1A. Risk Factors" herein.

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

PART I

Item 1. Business.

Introduction

OGE Energy is a holding company with investments in energy and energy services providers offering physical delivery and related services for electricity in Oklahoma and western Arkansas. Prior to September 30, 2022, OGE Energy also held investments in Enable and Energy Transfer, which offers natural gas, crude oil and NGL services. OGE Energy reports these activities through two business segments: (i) electric company operations and (ii) natural gas midstream operations. For periods prior to the December 2, 2021 closing of the Enable and Energy Transfer merger, OGE Energy accounted for its investment in Enable as an equity method investment and reported it within OGE Energy's natural gas midstream operations segment. For the period of December 2, 2021 through September 30, 2022, OGE Energy accounted for its investment in the Energy Transfer units it acquired in the merger as an investment in equity securities. As of the end of September 2022, OGE Energy had sold all of its Energy Transfer limited partner units, becoming primarily an electric company.

Electric Company Operations. OGE Energy's electric company operations are conducted through OG&E, which generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. OG&E's rates 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 OGE Energy. OG&E is the largest electric company 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.

Natural Gas Midstream Operations. For the period of December 2, 2021 to September 30, 2022, OGE Energy's natural gas midstream operations segment included OGE Energy's investment in Energy Transfer's equity securities acquired in the Enable/Energy Transfer merger. For the year ended December 31, 2022, this segment also includes legacy Enable seconded employee pension and postretirement costs. Prior to OGE Energy's sale of all Energy Transfer limited partner units, the investment in Energy Transfer's equity securities was held through wholly-owned subsidiaries and ultimately OGE Holdings. OGE Energy no longer has any ownership interest in natural gas midstream operations.

The Registrants' principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma, 73101-0321 (telephone 405-553-3000). OGE Energy's website address is www.oge.com. Through OGE Energy's website, OGE Energy makes available, free of charge, the Registrants' annual reports 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. OGE Energy'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.

Strategy

OGE Energy's purpose is to energize life, providing life-sustaining and life-enhancing products and services, while honoring its commitment to strengthen communities. Its business model is centered around growth and sustainability for employees (internally referred to as "members"), communities and customers and the owners of OGE Energy, its shareholders.

OGE Energy is focused on:

•

delivering top-quartile safety results, while enabling members to deliver improved value to their communities, customers and shareholders;

•

transforming the customer experience by centering decisions on customer impact that will drive customer operations, communications program and product development and the digital experience including increased personalization and self-service;

•

providing safe, reliable energy to the communities and customers it serves, with a particular focus on enhancing the value of the grid by improving reliability and resiliency;

•

leading economic development and job growth by attracting new and diverse businesses to improve the infrastructure of the communities in Oklahoma and Arkansas;

•

ensuring the necessary mix of generation resources to meet the long-term capacity needs of our customers, with a progressively cleaner generation portfolio;

•

maintaining customer rates that are some of the most affordable in the country by continuing focus on innovation, intellectual curiosity and execution with excellence;

•

delivering on earnings commitments to shareholders to enhance access to lower-cost debt and equity capital that is needed to deploy infrastructure for the long-term economic health of its communities;

•

having strong regulatory and legislative relationships, built on integrity, for the long-term benefit of our customers, communities, shareholders and members; and

•

developing and growing our members to be able to provide a greater contribution to the company's success, while also improving their own lives.

OGE Energy is focused on creating long-term shareholder value by targeting the consistent growth of earnings per share of five to seven percent at the electric company, supported by strong load growth enabled by low customer rates and a strategy of investing in lower risk infrastructure projects that improve the economic vitality of the communities it serves in Oklahoma and Arkansas. In the next five years, OGE Energy expects to continue to grow the dividend, targeting a dividend payout ratio of 65 to 70 percent. Over the next several years, OGE Energy expects earnings per share growth to exceed the dividend growth rate to help achieve this target. OGE Energy's financial objectives also include maintaining investment grade credit ratings and providing a strong and reliable dividend for shareholders.

OGE Energy's long-term sustainability is predicated on providing exceptional customer experiences, investing in grid improvements and increasingly cleaner generation resources, environmental stewardship, strong governance practices and caring for and supporting its members and communities.

Electric Operations - OG&E

General

OG&E provides retail electric utility service to approximately 889,000 customers in Oklahoma and western Arkansas. The service area covers 30,000 square miles including Oklahoma City, the largest city in Oklahoma, Fort Smith, Arkansas, the third largest city in that state, and other large communities with their contiguous rural and suburban areas throughout Oklahoma and western Arkansas. OG&E derived 92 percent of its total electric operating revenues in 2022 from sales in Oklahoma and the remainder from sales in Arkansas. OG&E does not currently serve wholesale customers in either state.

In 2022, OG&E's system control area peak demand was 7,301 MWs on July 19, 2022, and OG&E's load responsibility peak demand was 6,498 MWs on July 19, 2022. The following table presents system sales and variations in system sales for 2022, 2021 and 2020.


Year Ended December 31	2022		2022 vs. 2021	2021		2021 vs. 2020	2020
System sales (Millions of MWh)		30.0	8.3%		27.7	2.6%		27.0

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. OG&E's ability to maintain relatively low cost, efficient and reliable operations is a significant determinant of its competitiveness.

OKLAHOMA GAS AND ELECTRIC COMPANY

CERTAIN OPERATING STATISTICS


Year Ended December 31	2022			2021			2020
ELECTRIC ENERGY (Millions of MWh)
Generation (exclusive of station use)		13.6			16.3			17.5
Purchased		19.0			14.6			12.9
Total generated and purchased		32.6			30.9			30.4
OG&E use, free service and losses		(1.5	)		(1.6	)		(1.4	)
Electric energy sold		31.1			29.3			29.0
ELECTRIC ENERGY SOLD (Millions of MWh)
Residential		10.4			9.6			9.5
Commercial		7.9			6.8			6.3
Industrial		4.2			4.2			4.2
Oilfield		4.4			4.2			4.2
Public authorities and street light		3.1			2.9			2.8
System sales		30.0			27.7			27.0
Integrated market		1.1			1.6			2.0
Total sales		31.1			29.3			29.0
ELECTRIC OPERATING REVENUES (In millions)
Residential	$	1,307.0		$	1,342.1		$	869.0
Commercial		825.6			766.9			479.4
Industrial		322.4			328.2			197.3
Oilfield		306.7			316.8			172.3
Public authorities and street light		298.9			289.5			176.9
System sales revenues		3,060.6			3,043.5			1,894.9
Provision for rate refund		(1.2	)		—			3.8
Integrated market		163.8			468.9			49.6
Transmission		131.7			140.2			143.3
Other		20.8			1.1			30.7
Total operating revenues	$	3,375.7		$	3,653.7		$	2,122.3
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential		756,751			749,091			740,174
Commercial		105,018			103,337			100,200
Industrial		2,464			2,585			2,710
Oilfield		6,791			6,804			6,822
Public authorities and street light		17,735			17,630			17,483
Total customers		888,759			879,447			867,389

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 2022, 88 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and four percent to the FERC.

The OCC and the APSC require that, among other things, (i) OGE Energy permits the OCC and the APSC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E; (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers; and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the FERC has access to the books and records of OGE Energy 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 14 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, the Green Power Wind Rider and the Utility Solar Program are rate options that make renewable energy resources available as a voluntary option to all OG&E 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 those OG&E commercial and industrial customers who enroll with the opportunity to curtail usage on a voluntary basis when power delivery system conditions merit curtailment action. Large customers greater than 50 MWs who enroll in the program are also required to participate in Direct Load Control, giving OG&E direct control over the curtailable portion of the customer's load. Customers that curtail their usage will receive credit for their curtailment response.

•

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.

In addition to specific rate structures, OG&E provides customers with other programs such as Average Monthly Billing which helps to make the customer's bill more predictable on a monthly basis. Similarly, OG&E has energy efficiency programs which provide qualified customers with programs such as in-home weatherization and opportunities to lower their monthly bill. OG&E also has a Low Income Assistance Program and a Senior Citizen Discount, which provide qualified customers with a monthly bill credit.

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 its 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 was 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 was obtained from the APSC. As further described in Note 14 within “Item 8. Financial Statements and Footnotes,” in September 2022, the APSC denied OG&E's extension request for the formula rate rider, as the APSC and OG&E did not agree on the APSC's approved debt-to-equity ratio for OG&E. Despite the denial of the extension request, the APSC ruled on January 20, 2023 that OG&E is able to undertake two more true-up updates to its formula rate rider with adjustments to rates occurring in April 2023 and April 2024. Subsequent to the April 2024 update, the formula rate rider will continue until new rates are set in a future general rate review.

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 and the Universal Solar Program are rate options that make renewable energy resources available as a voluntary option to all OG&E Arkansas 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 and receive a billing credit when OG&E's system conditions merit curtailment action.

•

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 a price signal received from OG&E. The day-ahead price and flex price rate options are based on OG&E's projected next day hourly operating costs.

In addition to specific rate structures, OG&E provides customers with other programs such as Levelized Billing Plan which helps to make the customer's bill more predictable on a monthly basis. Similarly, OG&E has energy efficiency programs which provide qualified customers with programs such as in-home weatherization and opportunities to lower their monthly bill.

Fuel Supply and Generation

The following table presents the OG&E-generated energy produced and purchased, by type, for the last three years.


	Generation Mix (A)
	2022			2021			2020
Natural gas		60	%		48	%		62	%
Coal		30	%		40	%		25	%
Renewable		10	%		12	%		13	%
Total		100	%		100	%		100	%

(A)

Generation mix calculated as a percent of net MWhs generated and includes purchased power agreements.

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 generally recoverable through fuel adjustment clauses.

The following table presents the weighted-average cost of fuel used, by type, for the last three years.


	Fuel Cost (A) (In cents/Kilowatt-Hour)
	2022		2021		2020
Natural gas		7.032		11.907		2.077
Coal		3.253		1.935		1.821
Renewable		—		—		—
Total		5.480		6.833		1.863

(A)

Total fuel and purchased power weighted-average cost was 5.096, 6.892 and 2.117 cents per kilowatt-hour in 2022, 2021 and 2020, respectively.

The changes in the weighted average cost of fuel in 2022 compared to 2021 and in 2021 compared to 2020 were primarily due to inflated fuel costs in 2021 during Winter Storm Uri. Fuel costs are generally recoverable through OG&E's fuel adjustment clauses that are approved by the OCC and the APSC, with the exception of Winter Storm Uri fuel costs in 2021 which were recovered in Oklahoma in 2022 through securitization and which are being recovered in Arkansas over 10 years through a regulatory asset mechanism. See Notes 1 and 14 within "Item 8. Financial Statements and Supplementary Data" for further discussion.

Of OG&E's 7,240 total MWs of generation capability reflected in the table within "Item 2. Properties," 4,904 MWs, or 67.7 percent, are from natural gas generation, 1,534 MWs, or 21.2 percent, are from coal generation, 321 MWs, or 4.4 percent, are from dual-fuel generation (coal/gas), 449 MWs, or 6.2 percent, are from wind generation and 32 MWs, or 0.5 percent, are from solar generation.

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. In 2022, OG&E expanded its physical storage capacity by entering into two storage service contracts. These two contracts provide OG&E security in both volume and price to further help protect customers against volatile natural gas prices.

Coal

OG&E's coal-fired units are designed to burn primarily low sulfur western sub-bituminous coal. The combination of all 2022 coal purchased had a weighted average sulfur content of 0.25 percent. Based on the average sulfur content and EPA-certified data, OG&E's coal units have an approximate emission rate of 0.2 lbs. of SO2 per MMBtu.

For 2023 through 2025, OG&E has coal supply agreements for 100 percent of its expected coal requirements for both the Sooner and River Valley facilities. For the Muskogee facility, OG&E has a majority of its expected 2023 coal requirements met through a coal supply agreement and will fill any additional coal needs through term agreements, spot purchases and the use of existing inventory. In 2022, OG&E purchased 3.1 million tons of coal from its sub-bituminous suppliers and 0.011 million tons from its bituminous suppliers. 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.

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 presented in the following table.


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

OG&E currently owns and operates the solar sites presented in the following table.


Name	Location	Year Completed	Photovoltaic Panels		MWs
Mustang	Oklahoma City, OK	2015		9,867		2.5
Covington	Covington, OK	2018		38,000		9.7
Choctaw Nation	Durant, OK	2020		15,344		5.0
Chickasaw Nation	Davis, OK	2020		15,344		5.0
Branch	Branch, AR	2021		15,444		5.0
Durant 2	Durant, OK	2022		15,471		5.0

OG&E issued a request for proposals for solar in 2022 based on generation needs established in its October 2021 IRP. OG&E will continue to evaluate the need to add additional solar sites to its generation portfolio based on customer demand, cost and reliability.

Environmental Matters

The activities of OG&E are subject to numerous stringent and complex federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact the Registrants' 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 the Registrants' operations are in substantial compliance with current federal, state and local environmental standards.

President Biden's Administration has taken a number of actions that adopt policies and affect environmental regulations, including issuance of executive orders that instruct the EPA and other executive agencies to review certain rules that affect OG&E with a view to achieving nationwide reductions in greenhouse gas emissions. OG&E is monitoring these actions which are in various stages of being implemented. At this point in time, the impacts of these actions on the Registrants' results of operations, if any, cannot be determined with any certainty. In the meantime, the Registrants continue to have obligations to take or complete action under current environmental rules.

Management continues to evaluate the Registrants' compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market but at the current time, based on existing rules, does not expect capital expenditures for environmental control facilities to be material for 2023 or 2024. For further discussion of environmental matters and capital expenditures related to environmental factors that may affect the Registrants, see "2022 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."

Human Capital Management

Our company fulfills a critical role in the nation's electric utility infrastructure. In order to do so, we believe we need to attract, retain, motivate and develop a high quality, diverse workforce and provide a safe, inclusive and productive work environment for everyone. Our company's core values are teamwork, transparency, respect, integrity, public service, and individual safety and well-being. Our company's core beliefs are unleash potential, live safely, achieve together, create shared trust, value diversity and inclusion, take charge and values matter. We believe that our company's values and beliefs serve as a foundation for our relationships with our employees, who we refer to internally as "members" of the Registrants. These core values and beliefs are reinforced to all employees at the time of hire, annually through a review of our Code of Ethics and periodically through small and large group meetings. We believe the efforts described herein, among others, contribute to our members' sense of purpose for the work we perform and result in the retention of our members. This belief is supported by OGE Energy being named by Forbes as the #2 Best Employer in Oklahoma for

2022 based on safety of work environment, competitiveness of compensation, opportunities for advancement, openness to telecommuting and how likely members would be to recommend OGE Energy as an employer. At December 31, 2022, OGE Energy had 2,237 employees, of which 1,861 are OG&E employees.

Total Rewards

To help us attract and retain the most qualified individuals for our businesses, we provide a combination of strong compensation and comprehensive benefit offerings, including healthcare, health savings and flexible spending accounts, short-term and long-term incentive plans, retirement savings plans with company matching contributions, disability coverage, paid time off, parental leave and employee assistance programs. We also have a defined benefit pension plan that covers certain employees hired on or before December 1, 2009. Our employees are also offered two days of paid volunteer leave every year, which is intended to further enrich both their lives and the lives of others in the communities we serve.

Employee Recruiting, Development and Engagement

We make it a priority to attract, retain, motivate and develop a high-quality workforce. Our recruitment efforts begin with industry and career awareness efforts directed toward learning institutions, parents and students. We have built partnerships with universities, state career tech systems, state education departments, technical learning/trade schools, military bases and local school districts to increase awareness of the employment opportunities we provide and the total rewards packages that are tied to those opportunities. We build these relationships to create talent pipelines that will funnel qualified individuals back to our organization and the workforce needs we have identified.

We provide our employees with a variety of opportunities for career growth and development. Many of the positions in our company are highly specialized, so having appropriate training and succession planning is critical to business continuity and competitiveness. We provide leadership, career development and skill-building opportunities, including internal and external training as well as tuition reimbursement, to invest in the next generation of leaders for our company. The number of annual hours of training per employee that we target, and historically average, aligns with the benchmark published annually by the American Society of Training and Development.

OGE Energy, like many utilities across the country, is planning for and managing the effects of turnover of our workforce due to a significant number of retirements occurring now and expected during the next five to ten years, which is a period that will be impacted by major transformation of our business through technology investments, regulatory changes to our electric generation portfolio and upgrades to our distribution infrastructure. Management engages in ongoing succession planning discussions, which includes the annual involvement of OGE Energy's Board of Directors as it relates to officer succession planning.

OGE Energy conducts and/or participates in employee engagement surveys to seek feedback from its employees on a variety of topics, including understanding of and alignment with the company's strategy, objectives, values and beliefs, management practices, operational performance and the employee value proposition. OGE Energy shares the survey results with employees, and senior management incorporates the results of the surveys into their action plans in order to respond to the feedback and further enhance employee engagement.

Safety

At OGE Energy, safety is more than a priority; it is a value and is paramount in the work we perform. Our safety principles are core to who we are and what we do. These principles are communicated, demonstrated and embraced at all levels of the company and supported by our core belief to "Live Safely." To us, "Live Safely" means we protect ourselves and others from injury by constant engagement, "always living safely." Our goal is to have zero safety incidents every year, and we educate all employees on our incident and injury-free workplace vision through extensive training on safety culture and task specific training to perform their work safely.

To further our vision of safety excellence, our health and safety professionals, supervisors and Safety Task Force teams conduct routine work observations to verify employees and contractors are following safety protocols and procedures and provide coaching, if necessary. To further drive improvements in our safety performance, we report and analyze all near misses and incidents to understand the causal factors and associated corrective actions necessary to reduce the likelihood of recurrence. We share what we have learned company-wide to provide real-time learning opportunities for all employees. We continue to analyze trends and engage in discussions with our employees, creating a dialogue to enhance safety performance and work toward our incident and injury-free workplace. Our focus on safety has contributed to each of the last seven years being the safest in our 120-year history.

Since the inception of our safety principle that all incidents and injuries are preventable and embracing our incident and injury free vision, we have seen a sustained decline in our injury rate. We have reduced our 5-year averages for OSHA recordable injuries by

73 percent and our Days Away, Restricted, Transfer Rate ("DART") by 78 percent since our 2011 baseline. The DART rate is an OSHA calculation that determines how safe businesses have been in a calendar year in reference to particular types of worker compensation injuries.

OG&E is subject to a number of federal, state and local regulations, which are administered by a variety of agencies. These agencies cover areas such as health and safety, transportation and the environment. OG&E has processes and procedures for these areas, and we believe we are in material compliance with all applicable regulations.

Diversity and Inclusion

Within our overall recruitment efforts, we are focused on diversity with the over-arching goal for the company's workforce to look like the communities we serve. Several of the talent pipeline partnerships referenced above are with organizations and trade schools whose student populations are diverse or raised in underrepresented communities. The company continues working with others to recruit diverse students to their programs, which can lead to potential employment for our positions. We have also formed relationships with universities to provide scholarships to students with diverse backgrounds and have focused on hiring individuals transitioning out of the military. For our workforce as a whole, the hiring percentage of members representing gender, racial and ethnically diverse communities has been trending upward for the past three years, and we expect that trend to continue. The retirement of our more tenured employees creates opportunities to promote or attract and hire additional individuals with diverse backgrounds.

We strive to reinforce the belief that our members are one of our greatest assets by creating a culture of respect throughout the company. One of our core beliefs is to "Value Diversity and Inclusion," which to us means that we embrace the uniqueness of each individual to make us a stronger and more resourceful organization, which enables us to serve and support the diverse communities where we live and work. We do this by, among other things, encouraging employees to treat others justly and considering their views in the decisions we make.

The company currently has eight employee-led Member Resource Groups ("MRGs") supporting Asian American & Pacific Islander, Black, Hispanic, LGBTQ+, Veteran and Women members along with new members and those dedicated to public service. All groups are voluntary and inclusive. Each MRG selects an officer of the company to serve as its Executive Sponsor. These MRGs are intended to foster a sense of belonging for all employees, inspire conversation, introduce new ways of thinking about issues, drive innovation among our diverse population of members and provide an opportunity for professional development, community involvement and recruitment.

Information About the Registrants' Executive Officers

The following table presents the names, titles and business experience for the most recent five years for those persons serving as Executive Officers of the Registrants as of February 22, 2023:


Name	Age	Current Title and Business Experience
Sean Trauschke	55	2018 - Present:	Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp.
W. Bryan Buckler	50	2021 - Present:	Chief Financial Officer of OGE Energy Corp.
		2019 - 2020:	Vice President of Investor Relations - Duke Energy Corporation
		2018 - 2019:	Director of Financial Planning and Analysis - Duke Energy Corporation
Sarah R. Stafford	41	2018 - Present:	Controller and Chief Accounting Officer of OGE Energy Corp.
		2018:	Accounting Research Officer of OGE Energy Corp.
Scott A. Briggs	51	2020 - Present:	Vice President - Human Resources of OG&E
		2019 - 2020:	Managing Director Human Resources of OG&E
		2018:	Chief Operating Officer of The Oklahoma Publishing Co., d/b/a The Oklahoma Media Company
Robert J. Burch	60	2020 - Present:	Vice President - Utility Technical Services of OG&E
		2018 - 2020:	Managing Director Utility Technical Services of OG&E
		2018:	Director Power Supply Services of OG&E
Andrea M. Dennis	46	2019 - Present:	Vice President - Transmission and Distribution Operations of OG&E
		2019:	Managing Director Transmission and Distribution Operations of OG&E
		2018 - 2019:	Director System Operations of OG&E
Keith E. Erickson	49	2022 - Present:	Vice President - Sales and Customer Operations of OG&E
		2018 - 2022:	Director of Sales and Business Development of OG&E
Donnie O. Jones	56	2019 - Present:	Vice President - Utility Operations of OG&E
		2018 - 2019:	Vice President - Power Supply Operations of OG&E
Cristina F. McQuistion	58	2020 - Present:	Vice President - Corporate Responsibility and Stewardship of OGE Energy Corp.
		2018 - 2020:	Vice President - Chief Information Officer of OG&E
Kenneth A. Miller	56	2019 - Present:	Vice President - Public and Regulatory Affairs of OG&E
		2018:	State Treasurer of Oklahoma
David A. Parker	46	2020 - Present:	Vice President - Technology, Data and Security of OG&E
		2019 - 2020:	Director Enterprise Security & Risk of OGE Energy Corp.
		2018 - 2019:	Director of Internal Audit of OGE Energy Corp.
Matthew J. Schuermann	44	2020 - Present:	Vice President - Power Supply Operations of OG&E
		2019 - 2020:	Managing Director Power Plant Operations of OG&E
		2018 - 2019:	Special Projects Director of OG&E
William H. Sultemeier	55	2022 - Present:	General Counsel, Corporate Secretary and Chief Compliance Officer of OGE Energy Corp.
		2018 - 2022:	General Counsel and Chief Compliance Officer of OGE Energy Corp.
Charles B. Walworth	48	2018 - Present:	Treasurer of OGE Energy Corp.
Johnny W. Whitfield, Jr.	46	2022 - Present:	Vice President - Business Intelligence and Supply Chain of OG&E
		2019 - 2022:	Director of Business Intelligence of OG&E
		2018 - 2019:	Sr. Manager of Resource Coordination of OG&E
Christine O. Woodworth	52	2021 - Present:	Vice President - Marketing and Communications of OG&E
		2018 - 2021:	Vice President of Public Relations - Sonic Drive-In, a fast-food restaurant chain

No family relationship exists between any of the Executive Officers of the Registrants. Messrs. Trauschke, Buckler, Sultemeier, Walworth and Mses. McQuistion and Stafford are also officers of OG&E. Each Executive Officer is to hold office until the next annual election of officers by the Board of Directors which is typically accomplished at the first regular board meeting following the Annual Meeting of Shareholders, currently scheduled for May 18, 2023.

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 Registrants. 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.

The Registrants are subject to a variety of risks which can be classified as regulatory, operational, financial and general. Risk factors of OG&E are also risk factors of OGE Energy.

REGULATORY RISKS

The Registrants' profitability depends to a large extent on the ability of OG&E to fully recover its costs, including its cost of capital, 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, including its cost of capital, 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, such as the Oklahoma and Arkansas fuel clause under recovery amounts as disclosed in Note 1 within "Item 8. Financial Statements and Footnotes." The utility commissions in the states where OG&E operates regulate many aspects of its electric operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the electric operations is dependent on OG&E's ability to fully recover costs related to providing electricity and power 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 and purchased power costs through rates without a general rate review, subject to a later determination that such costs were prudently incurred. If the state regulatory commissions determine that such 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.

The Registrants are unable to predict the impact on their operating results from future regulatory activities of any of the agencies that regulate OG&E. Changes in regulations, legislation or the imposition of additional regulations or legislation could have an adverse impact on the Registrants' 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 company. 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, 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.

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 laws and regulations to which we must adhere change, and the Biden Administration's agenda includes a significant shift in environmental and energy policy, focusing on reducing greenhouse gas emissions and addressing climate change issues. Together, these actions reflect climate change issues and greenhouse gas emission reductions as central areas of focus for domestic and international regulations, orders and policies. In addition, a parallel focus on reducing greenhouse gas emissions is reflected in legislation introduced in Congress. For example, the Infrastructure Investment and Jobs Act and Inflation Reduction Act were passed into law in 2022. These laws present opportunities for federal grants and tax incentives intended to hasten the future economy-wide deployment of various greenhouse gas emission reducing technologies and approaches. These initiatives could lead to new and revised energy and environmental laws and regulations, including tax reforms relating to energy and environmental issues. Any such changes, as well as any enforcement actions or judicial decisions regarding those laws and regulations, could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Such changes also could affect the manner in which we conduct our business and could require us to make substantial additional capital expenditures or abandon certain projects.

There is inherent risk of the incurrence of environmental costs and liabilities in our operations and historical industry 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. The Biden Administration has suggested that it will enact stricter laws, regulations and enforcement policies that could significantly increase compliance costs and the cost of any remediation that may become necessary. If regulations are enacted regarding any of our generating units, as listed in "Item 2. Properties," it could potentially result in stranded assets.

In addition, we may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.

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

We are subject to financial risks associated with climate change and the transition to a lower carbon economy.

In addition to the potential for physical risk related to climate change (discussed below), climate change, and the risks related to our transition to a lower-carbon economy, creates financial risk. Transition risks represent those risks related to the social and economic changes needed to shift toward a lower carbon future. These risks are often interconnected, representing policy and regulatory changes, technology and market risks, and risks to our reputation and financial performance.

Potential regulation associated with climate change legislation could pose financial risks to OGE Energy and its affiliates. The U.S. is a party to the United Nations' "Paris Agreement" on climate change, and the Agreement along with other potential legislation and regulation discussed above, could result in enforceable greenhouse gas emission reduction requirements that could lead to increased compliance costs for OGE Energy and its affiliates. For example, in September 2022, the EPA created a non-rulemaking docket for public input related to the EPA's efforts to reduce emissions of greenhouse gases from new and existing fossil fuel-fired electric generating units under the Clean Air Act Section 111.

As we expand our cleaner energy generation asset mix, the ability to integrate renewable technologies into our operations and maintain reliability and affordability is key. The intermittency of renewables remains a critical challenge particularly as cost-efficient energy storage is still in development. Other technology risks include the need for significant upfront financial investments, lengthy development timelines, and the uncertainty of integration and scalability across our entire service territory.

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 costs, CO2 taxes or imposed costs, OGE Energy and its affiliates may be adversely impacted. There are also increasing risks for energy companies 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 investors and lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable investing and 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 financial risks from private party litigation relating to greenhouse gas emissions. 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 may not be able to recover the costs of our substantial investments in capital improvements and additions.

Our business plan calls for extensive investments in capital improvements and additions in OG&E, 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. As discussed above, the Infrastructure Investment and Jobs Act and Inflation Reduction Act present opportunities for federal grants and tax incentives intended to hasten the future economy-wide deployment of various greenhouse gas emission reducing technologies and approaches. While we plan to pursue opportunities through the Infrastructure Investment and Jobs Act, we expect to typically be responsible for 50 percent of the dollars spent on investments related to this Act. 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 the Registrants' 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. Our 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 efforts to restructure utility and energy markets or deregulation could have a significant financial and load growth impact on us and consequently impact our revenue and affordability of services.

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. 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. Further, we regularly engage in negotiations on renewals of franchise agreements with municipal governments within our service territories. Any such restructuring could have a significant impact on our financial position, results of operations and cash flows. Further, our load growth could be impacted, which could result in an impact on the affordability of our services. 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 financial position, results of operations or cash flows.

We are subject to substantial utility regulation by governmental agencies. Compliance with current and future utility 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. As 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 to fuel supply or the electric grid that are beyond our control.

We are exposed to risks related to performance of contractual obligations by our suppliers and transporters. 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 and transportation contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply and transport coal and natural gas to us. The suppliers and transporters under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers and transporters under these agreements may not be required to provide the commodity or service 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, availability of equipment and labor shortages. Failure or delay by our suppliers and transporters of coal and natural gas 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 financial position, results of operations and cash flows.

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 purchased 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, fuel transportation, purchased power and purchased capacity 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;

•

intentional destruction of electric grid equipment; 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 or if insurance is not available, could have a material effect on our 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 is a vertically integrated electric company and primarily generates electricity at large central facilities. We believe this method is the most efficient and cost-effective method for power delivery, as it typically results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, wind turbines 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 electric company 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.

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 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.

Physical risks from climate can be considered in both acute (event-driven) and chronic (longer-term shifts in climate patterns) terms. The effects of climate change could exacerbate physical changes in weather and the extreme weather events discussed above, including prolonged droughts, rise in temperatures and more extreme weather events like wildfires and ice storms, among other weather impacts. We have observed some of these events in recent years, and the trend could continue. OG&E can incur significant restoration costs as a result of these weather events. 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.

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 financial position, results of operations or cash flows.

We have a Pension Plan that covers certain employees hired before December 1, 2009. We also have defined benefit postretirement plans that cover certain 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. We expect to make future contributions to maintain required funding levels as necessary, and 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 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 financial position, results of operations or liquidity.

OGE Energy is a holding company with its primary asset being its subsidiary, OG&E.

OGE Energy is a holding company and thus its primary asset is its subsidiary, OG&E. Substantially all of OGE Energy's operations are conducted by its subsidiary. Consequently, OGE Energy's operating cash flow and its ability to pay dividends and service its indebtedness are dependent upon the operating cash flow of OG&E and the payment of funds by OG&E to OGE Energy in the form of dividends or distributions. At December 31, 2022, OGE Energy and OG&E had outstanding indebtedness and other liabilities of $8.1 billion. OG&E is a separate legal entity that has no obligation to pay any amounts due on OGE Energy's indebtedness or to make any funds available for that purpose, whether by dividends or distributions. In addition, OG&E's ability to pay dividends or distributions to OGE Energy depends on any statutory and contractual restrictions that may be applicable to the entity, which may include requirements to maintain minimum levels of working capital and other assets. Claims of creditors, including general creditors, of OG&E on its assets will generally have priority over OGE Energy claims (except to the extent that OGE Energy may be a creditor and its claims are recognized) and claims by OGE Energy 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 OGE Energy, it could adversely affect its ability to continue to pay dividends.

GENERAL RISKS

Governmental and market reactions to events involving other public companies or other energy companies that are beyond our control may have negative impacts on our business, financial position, results of operations, cash flows and access to capital.

Accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities and political contributions, could lead to public and regulatory scrutiny and suspicion for public companies, including those in the regulated and unregulated utility business. Accounting irregularities could cause 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 could increase 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 any of these types of events may have on our business, 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 financial position, results of operations and cash flows.

Economic conditions, including inflationary pressures and supply chain disruptions, could negatively impact our business and our results of operations.

Our operations have been and are affected by local, national and worldwide economic conditions. National and global events could adversely affect and/or exacerbate macroeconomic conditions, including inflationary pressures, rising interest rates, supply chain disruptions and economic recessions, which in turn affect our operations and our customers. The Registrants have experienced rising costs to produce electricity through increased fuel prices, raw material inflation, logistical challenges and certain component shortages. We are dependent upon others, such as fuel suppliers and transporters and suppliers for our capital projects, to help execute our operations. Supply chain disruption has resulted, and may continue to result, in delays in construction activities and equipment deliveries related to our capital projects.

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 and general inflation 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 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 results of operations and cash flows.

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

In the regular course of our business, 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 due to theft, ransomware, viruses, denial of service, hacking, acts of war or terrorism or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our 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 respond to security breaches or repair system damage. 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 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 controls and monitoring 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 cyber and 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.

The failure of our technology infrastructure, or the failure to enhance existing technology infrastructure and implement new technology, could adversely affect our business.

Our operations are dependent upon the proper functioning of our internal systems, including the technology and network infrastructure that support our underlying business processes. Any significant failure or malfunction of such technology infrastructure may result in disruptions of our operations. In the ordinary course of business, we rely on technology infrastructure, including the internet and third-party hosted services, to support a variety of business processes and activities and to store sensitive data. Our technology infrastructure is dependent upon global communications and cloud service providers, as well as their respective vendors, many of whom have at some point experienced significant system failures and outages in the past and may experience such failures and outages in the future. These providers' systems are susceptible to cybersecurity and data breaches, outages from fire, floods, power loss, telecommunications failures, physical attack and similar events. Failure to prevent or mitigate data loss from system failures or outages could materially adversely affect our results of operations, financial position and cash flows.

In addition to maintaining our current technology infrastructure, we believe the digital transformation of our business is key to driving internal efficiencies as well as providing additional capabilities to customers. Our technology infrastructure is critical to cost-effective, reliable daily operations and our ability to effectively serve our customers. We expect our customers to continue to demand more sophisticated technology-driven solutions, and we must enhance or replace our technology infrastructure in response. This involves significant development and implementation costs to keep pace with changing technologies and customer demand. If we fail to successfully implement critical technology infrastructure, or if it does not provide the anticipated benefits or meet customer demands,

such failure could materially adversely affect our business strategy as well as impact our results of operations, financial position and cash flows.

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

In late 2022, physical attacks on electric equipment owned by other electric utility companies in the U.S. resulted in the loss of power for a period of time. Authorities have indicated they believe these attacks may have been carried out by domestic extremists, as the U.S. electric grid is noted as being highly vulnerable to domestic terrorism. While the Registrants have experienced physical attacks on their electric equipment, these incidents have not been material to their operations. The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility 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.

Health epidemics and other outbreaks could adversely impact economic activity and conditions worldwide, which could have a material adverse effect on our results of operations and financial condition.

Health epidemics and other outbreaks, such as the COVID-19 pandemic, could adversely impact economic activity and conditions worldwide, by, among other things, leading to shutdowns, disrupting supply chains, increasing unemployment, resulting in customer slow payment or non-payment and decreasing commercial and industrial load. In response to health epidemics and other outbreaks, an extended slowdown of the United States' economic growth, demand for commodities and/or material changes in governmental policy could result in lower economic growth and lower demand for electricity in our key markets as well as the ability of various customers, contractors, suppliers and other business partners to fulfill their obligations, which could have a material adverse effect on our results of operations, financial condition and prospects.

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 higher than the national average. Over the next three years, 23.4 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 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 OGE Energy or OG&E 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 the current credit ratings of the Registrants 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.

The Registrants recently amended their credit facilities to switch from eurodollar loans based on LIBOR to term SOFR loans. SOFR is a relatively new reference rate, and its composition and characteristics are not the same as LIBOR. It is not possible to predict what effect the change to SOFR may have on our interest rates.

As indicated above, SOFR is a relatively new reference rate. Any failure of SOFR to gain market acceptance could cause the SOFR to be modified or discontinued. The Registrants' current credit facilities provide a mechanism for determining an alternative rate of interest upon the occurrence of certain events related to the discontinuance of SOFR. The change to SOFR or transition to other alternative rates, whether in connection with borrowings under the current credit facilities, or borrowings under replacement facilities or lines of credit, could expose the Registrants' future borrowings to less favorable rates. If the change to SOFR, or other alternative rates, results in increased alternative interest rates or if the Registrants' lenders have increased costs due to such phase out or changes, then the Registrants' debt that uses benchmark rates could be affected and, in turn, the Registrants' cash flows and interest expense could be adversely impacted.

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. In December 2022, OGE Energy entered into an amendment to its revolving credit facility that increased the permitted maximum debt to capitalization ratio from 65 percent to 70 percent. OG&E’s credit facility has a financial covenant requiring it to maintain a maximum debt to capitalization ratio of 65 percent. 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 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.

We have seen increased interest for electric service from emerging industries such as crypto mining and hydrogen production, which are both large consumers of electricity. If this continues, these types of customers could represent a significant portion of our revenues.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included 17 generating stations with an aggregate capability of 7,240 MWs at December 31, 2022. The following table presents information with respect to OG&E's electric generating facilities. Unless otherwise indicated, these electric generating facilities are located in Oklahoma.


Station & Unit			Year Installed	Unit Design Type	Fuel Capability	2022 Capacity Factor (A)			Unit Capability (MW)		Station Capability (MW)
Seminole	1		1971	Steam-Turbine	Gas		10.5	%		500
	2		1973	Steam-Turbine	Gas		13.2	%		510
	3		1975	Steam-Turbine	Gas		10.9	%		498		1,508
Muskogee	4		1977	Steam-Turbine	Gas		17.2	%		487
	5		1978	Steam-Turbine	Gas		11.7	%		488
	6		1984	Steam-Turbine	Coal		22.6	%		503		1,478
Sooner	1		1979	Steam-Turbine	Coal		29.4	%		516
	2		1980	Steam-Turbine	Coal		30.2	%		515		1,031
Horseshoe Lake	5A	(B)	1971	Combustion-Turbine	Gas/Jet Fuel		4.0	%		33
	5B	(B)	1971	Combustion-Turbine	Gas/Jet Fuel		3.9	%		31
	6		1958	Steam-Turbine	Gas		16.5	%		170
	7		1963	Steam-Turbine	Gas		1.4	%		211
	8		1969	Steam-Turbine	Gas		3.0	%		377
	9		2000	Combustion-Turbine	Gas		28.6	%		45
	10		2000	Combustion-Turbine	Gas		27.1	%		43		910
Redbud (C)	1		2003	Combined Cycle	Gas		37.1	%		154
	2		2003	Combined Cycle	Gas		35.6	%		154
	3		2003	Combined Cycle	Gas		32.5	%		152
	4		2003	Combined Cycle	Gas		35.9	%		153		613
Mustang	6		2018	Combustion-Turbine	Gas		19.4	%		57
	7		2018	Combustion-Turbine	Gas		34.8	%		56
	8		2017	Combustion-Turbine	Gas		1.5	%		58
	9		2018	Combustion-Turbine	Gas		14.4	%		57
	10		2018	Combustion-Turbine	Gas		19.2	%		57
	11		2018	Combustion-Turbine	Gas		38.0	%		57
	12		2018	Combustion-Turbine	Gas		37.0	%		57		399
McClain (D)	1		2001	Combined Cycle	Gas		50.1	%		378		378
Frontier	1		1989	Combined Cycle	Gas		40.4	%		121		121
River Valley	1		1991	Steam-Turbine	Coal/Gas		35.0	%		161
	2		1991	Steam-Turbine	Coal/Gas		16.2	%		160		321
Total Generating Capability (all stations, excluding renewable)												6,759

(A)

2022 Capacity Factor = 2022 Net Actual Generation / (2022 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)). Capacity Factors are impacted by events that reduce Net Actual Generation such as outages.

(B)

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

(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.


Renewable					2022
Station	Year Installed	Location	Number of Units	Fuel Capability	Capacity Factor (A)			Unit Capability (MW)		Station Capability (MW)
Crossroads	2011	Canton, OK	98	Wind		18.6	%		2.3		228
Centennial	2007	Laverne, OK	80	Wind		16.5	%		1.5		120
OU Spirit	2009	Woodward, OK	44	Wind		15.5	%		2.3		101
Mustang	2015	Oklahoma City, OK	90	Solar		26.4	%	< 0.1			2
Covington	2018	Covington, OK	4	Solar		18.1	%		2.5		10
Choctaw Nation	2020	Durant, OK	2	Solar		23.6	%		2.5		5
Chickasaw Nation	2020	Davis, OK	2	Solar		25.4	%		2.5		5
Branch	2021	Branch, AR	2	Solar		22.6	%		2.5		5
Durant 2	2022	Durant, OK	2	Solar		10.4	%		2.5		5
Total Generating Capability (renewable)											481

(A)

At December 31, 2022, OG&E's transmission system included: (i) 54 substations with a total capacity of 14.1 million kV-amps and 5,190 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.9 million kV-amps and 347 structure miles of lines in Arkansas. At December 31, 2022, OG&E's distribution system included: (i) 350 substations with a total capacity of 10.8 million kV-amps, 29,544 structure miles of overhead lines, 3,544 miles of underground conduit and 11,183 miles of underground conductors in Oklahoma and (ii) 30 substations with a total capacity of 1.0 million kV-amps, 2,801 structure miles of overhead lines, 360 miles of underground conduit and 660 miles of underground conductors in Arkansas.

During the three years ended December 31, 2022, both Registrants' gross property, plant and equipment (excluding construction work in progress) additions were $2.2 billion, and gross retirements were $299.4 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 15.2 percent of gross property, plant and equipment (excluding construction work in progress) for both Registrants at December 31, 2022.

Item 3. Legal Proceedings.

In the normal course of business, the Registrants are 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 Registrants have 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 Registrants' financial statements. At the present time, based on currently available information, the Registrants believe 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 their financial statements and would not have a material adverse effect on the Registrants' financial position, results of operations or cash flows.

Item 4. Mine Safety Disclosures.

Not Applicable.

PART II

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

OGE Energy's common stock is listed for trading on the New York Stock Exchange under the ticker symbol "OGE." At December 31, 2022, there were 12,222 holders of record of OGE Energy's common stock.

Currently, all of OG&E's outstanding common stock is held by OGE Energy. Therefore, there is no public trading market for OG&E's common stock.

Performance Graph

The below graph shows a five-year comparison of cumulative total returns for OGE Energy's common stock, the S&P 500 Index and the S&P 1500 Composite Utilities Sector Index. The graph assumes that the value of the investment in OGE Energy's common stock and each index was $100 as of December 31, 2017, and that all dividends were reinvested.

The above graph and related information should not be deemed "soliciting material" or to be "filed" with the Securities Exchange Commission, nor should such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that OGE Energy specifically incorporates such information by reference into such a filing. The graph and information are included for historical comparative purposes only and should not be considered indicative of future stock performance.

Issuer Purchases of Equity Securities

None.

Item 6. [Reserved]

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

The following combined discussion is separately filed by OGE Energy and OG&E. However, OG&E does not make any representations as to information related solely to OGE Energy or the subsidiaries of OGE Energy other than itself.

Overview

OGE Energy is a holding company with investments in energy and energy services providers offering physical delivery and related services for electricity in Oklahoma and western Arkansas. Prior to September 30, 2022, OGE Energy also held investments in Enable and Energy Transfer, which offered natural gas, crude oil and NGL services. OGE Energy reports these activities through two business segments: (i) electric company and (ii) natural gas midstream operations. The accounts of OGE Energy and its wholly-owned subsidiaries, including OG&E, are included in OGE Energy's consolidated financial statements. All intercompany transactions and balances are eliminated in such consolidation. For periods prior to the December 2, 2021 closing of the Enable and Energy Transfer merger, OGE Energy accounted for its investment in Enable as an equity method investment and reported it within OGE Energy's natural gas midstream operations segment. For the period of December 2, 2021 through September 30, 2022, OGE Energy accounted for its investment in the Energy Transfer units it acquired in the merger as an investment in equity securities. As of the end of September 2022, OGE Energy had sold all of its Energy Transfer limited partner units, becoming primarily an electric company.

Recent Developments

Oklahoma Fuel Cost Adjustment Show Cause

On September 29, 2022, the OCC Public Utility Division Staff initiated a cause to determine the appropriate methodology to recover OG&E's $424.0 million fuel clause under recovery balance as of August 31, 2022 and how OG&E's fuel factors should be set going forward. The Staff requested that OG&E explain how it arrived at the noted under recovery balance, explain its fuel forecasting process, justify its amortization period of 24 months and explain the adequacy of its resource mix and fuel supply plans. Updated fuel factors were implemented by OG&E on October 1, 2022 to recover the balance from customers over 24 months. The Staff did not oppose OG&E's implementation of updated fuel factors on an interim basis and subject to refund. Despite several public deliberations, the OCC has not issued a final order in this proceeding. On January 1, 2023, OG&E implemented its annual redetermination of its fuel factors, without further action or opposition from the OCC.

Global Macroeconomic Pressures

Geopolitical events, and related governmental and business responses, continue to have an impact on the Registrants' operations, supply chains and end-user customers, including our end-user customers' ability to pay for electric service. The Registrants have experienced raw material inflation, logistical challenges and certain component shortages. Supply chain disruption has resulted, and may continue to result, in delays in construction activities and equipment deliveries related to OGE Energy's capital projects. The timing and extent of the financial impact from these events are still uncertain, and the Registrants cannot predict the magnitude of the impact to the results of their business and results of operations.

OG&E's Regulatory Matters

Completed regulatory matters affecting current period results are discussed in Note 14 within "Item 8. Financial Statements and Supplementary Data."

Summary of OGE Energy 2022 Operating Results Compared to 2021

OGE Energy's net income was $665.7 million, or $3.32 per diluted share, in 2022 as compared to $737.3 million, or $3.68 per diluted share, in 2021. The decrease in net income of $71.6 million, or $0.36 per diluted share, in 2022 as compared to 2021 is further discussed below.

•

An increase in net income at OG&E of $79.5 million, or $0.39 per diluted share of OGE Energy's common stock, was primarily due to higher operating revenues driven by more favorable weather and revenues from the recovery of capital investments (excluding impacts of recoverable fuel, purchased power and direct transmission expense not impacting earnings), partially offset by higher depreciation and amortization expense due to an increase in depreciation rates resulting from the Oklahoma general rate review order received in September 2022 and additional assets being placed into service, as well as higher income taxes and higher other operation and maintenance expense.

•

A decrease in net loss of other operations (holding company) of $2.6 million, or $0.01 per diluted share of OGE Energy's common stock, was primarily due to higher other income, partially offset by an increase in net interest expense due to the long-term debt issuance in May 2021.

•

A decrease in net income at OGE Holdings (Natural Gas Midstream Operations) of $153.7 million, or $0.76 per diluted share of OGE Energy's common stock, was primarily due to a prior year $344.4 million pre-tax gain on the Enable/Energy Transfer merger and the elimination of OGE Energy's equity in earnings of Enable in 2022, which were driven by the merger closing in December 2021, partially offset by a $282.1 million pre-tax gain on OGE Energy's investment in Energy Transfer's equity securities in 2022, distributions received from Energy Transfer of $34.0 million and lower income tax expense.

A more detailed discussion regarding the financial performance for the year ended December 31, 2022 as compared to December 31, 2021 can be found under "Results of Operations" below. A discussion of the financial performance for the year ended December 31, 2021 compared to December 31, 2020 for OGE Energy and OG&E can be found within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the Registrants' 2021 Form 10-K.

2023 Outlook

Key assumptions for the Registrants' 2023 outlook are discussed below.

Consolidated OGE Energy

OGE Energy is projected to earn approximately $387 million to $416 million, or $1.93 to $2.07 per average diluted share, with a midpoint of $402 million, or $2.00 per average diluted share, in 2023 and is based on the assumptions listed below. As a result of OGE Energy's sales of all Energy Transfer limited partner units in 2022, OGE Energy will not report earnings, and therefore guidance, for a natural gas midstream operations segment beginning in 2023.

OG&E (Electric Company)

OG&E is projected to earn approximately $400 million to $421 million, or $1.99 to $2.09 per average diluted share, with a midpoint of $411 million, or $2.04 per average diluted share, in 2023 and is based on the following assumptions:

•

normal weather patterns are experienced for the year;

•

operating revenues growth driven by total retail load growth (weather normalized) of approximately 4 to 5 percent, or approximately 2.5 to 3.5 percent assuming an equivalent level of datamining load in 2023 as existed at the end of 2022;

•

operating expenses of approximately $1.101 billion to $1.109 billion, with operation and maintenance expenses comprising approximately 45 percent of the total;

•

net interest expense of approximately $204 million to $210 million which assumes a $4 million allowance for borrowed funds used during construction reduction to interest expense and assumes a debt issuance at OG&E of up to $400 million in 2023 in addition to the $450 million that was issued in January 2023;

•

other income of approximately $32 million including $10 million of allowance for equity funds used during construction; and

•

an effective tax rate of approximately 15 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.

Other Operations (Primarily Holding Company)

A loss of $9 million, or $0.04 per average diluted share, is expected at the holding company, within a range of a loss of $5 million to $13 million, or $0.02 to $0.06 per average diluted share.

Other consolidated assumptions include:

•

approximately 201.0 million average diluted shares outstanding; and

•

an effective tax rate of approximately 14 percent.

Results of Operations

The following discussion and analysis presents factors that affected the Registrants' results of operations for the years ended December 31, 2022 and 2021 and the Registrants' financial positions at December 31, 2022 and 2021. The following information should be read in conjunction with the financial statements and notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.


OGE Energy	Year Ended December 31,
(In millions except per share data)	2022		2021
Net income	$	665.7	$	737.3
Basic average common shares outstanding		200.2		200.1
Diluted average common shares outstanding		200.8		200.3
Basic earnings per average common share	$	3.33	$	3.68
Diluted earnings per average common share	$	3.32	$	3.68
Dividends declared per common share	$	1.64820	$	1.62500

Results by Business Segment


	Year Ended December 31,
(In millions)	2022			2021
Net income (loss):
OG&E (Electric Company)	$	439.5		$	360.0
OGE Holdings (Natural Gas Midstream Operations) (A)		231.3			385.0
Other operations (B)		(5.1	)		(7.7	)
OGE Energy net income	$	665.7		$	737.3

(A)

Net income for the year ended December 31, 2021 includes the $344.4 million gain ($264.8 million after tax) recognized for the Enable merger transaction, as further discussed in Note 1 within "Item 8. Financial Statements and Supplementary Data."

(b)

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

The following discussion of results of operations by business segment includes intercompany transactions that are eliminated in OGE Energy's consolidated financial statements.

OG&E (Electric Company)


Year Ended December 31 (Dollars in millions)	2022			2021
Operating revenues	$	3,375.7		$	3,653.7
Fuel, purchased power and direct transmission expense		1,662.4			2,127.6
Other operation and maintenance		491.9			464.7
Depreciation and amortization		460.9			416.0
Taxes other than income		98.0			99.3
Operating income		662.5			546.1
Allowance for equity funds used during construction		6.9			6.7
Other net periodic benefit income (expense)		1.2			(4.3	)
Other income		6.5			7.1
Other expense		3.4			1.8
Interest expense		157.8			152.0
Income tax expense		76.4			41.8
Net income	$	439.5		$	360.0
Operating revenues by classification:
Residential	$	1,307.0		$	1,342.1
Commercial		825.6			766.9
Industrial		322.4			328.2
Oilfield		306.7			316.8
Public authorities and street light		298.9			289.5
System sales revenues		3,060.6			3,043.5
Provision for rate refund		(1.2	)		—
Integrated market		163.8			468.9
Transmission		131.7			140.2
Other		20.8			1.1
Total operating revenues	$	3,375.7		$	3,653.7
MWh sales by classification (In millions)
Residential		10.4			9.6
Commercial		7.9			6.8
Industrial		4.2			4.2
Oilfield		4.4			4.2
Public authorities and street light		3.1			2.9
System sales		30.0			27.7
Integrated market		1.1			1.6
Total sales		31.1			29.3
Number of customers		888,759			879,447
Weighted-average cost of energy per kilowatt-hour (In cents)
Natural gas (A)		7.032			11.907
Coal		3.253			1.935
Total fuel (A)		5.480			6.833
Total fuel and purchased power (A)		5.096			6.892
Degree days (B)
Heating - Actual		3,652			3,281
Heating - Normal		3,568			3,452
Cooling - Actual		2,385			1,896
Cooling - Normal		1,893			1,912

(A)

Decreased primarily due to both elevated pricing from Winter Storm Uri and higher market prices related to increased natural gas prices in 2021.

(b)

Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period. The calculation of heating and cooling degree normal days is based on a 30-year average and updated every ten years, which most recently occurred in mid-2021.

OG&E's net income increased $79.5 million, or 22.1 percent, in 2022 as compared to 2021. The following section discusses the primary drivers for the increase in net income in 2022 as compared to 2021.

Operating revenues decreased $278.0 million, or 7.6 percent, primarily driven by the below factors.


(In millions)	$ Change
Fuel, purchased power and direct transmission expense (A)	$	(465.2	)
Wholesale transmission revenue		(4.2	)
Other		(2.8	)
Industrial and oilfield sales		5.0
Non-residential demand and related revenues		10.2
New customer growth		13.0
Guaranteed Flat Bill program (B)		16.3
Quantity impacts (primarily weather) (C)		68.0
Price variance (D)		81.7
Change in operating revenues	$	(278.0	)

(A)

These expenses are generally recoverable from customers through regulatory mechanisms and are offset in Fuel, Purchased Power and Direct Transmission Expense in the statements of income, as further described below. The primary drivers of the changes in fuel, purchased power and direct transmission expense during the period are further detailed in the table below.

(B)

Increased primarily due to the loss from the Guaranteed Flat Bill program in 2021 related to Winter Storm Uri. The Guaranteed Flat Bill program allows qualifying customers the opportunity to purchase their electricity needs at a set monthly price for an entire year which can result in variances when actual fuel and purchased power prices differ from what is included in Guaranteed Flat Bill Program rates.

(C)

Increased primarily due to a 25.8 percent increase in cooling degree days and an 11.3 percent increase in heating degree days.

(D)

Increased primarily due to the Oklahoma general rate review order received in September 2022 that approved new rates effective July 1, 2022, the impact of the Arkansas Formula Rate Plan and increased recovery through rider mechanisms, such as the Storm Cost Recovery Rider and energy efficiency riders.

Fuel, purchased power and direct transmission expense for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. As described above, the actual cost of fuel used in electric generation and certain purchased power costs are generally recoverable from 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 fuel, purchased power and direct transmission expense decreased $465.2 million, or 21.9 percent, primarily driven by the below factors.


(In millions)	$ Change			% Change
Fuel expense (A)	$	(369.6	)		(33.2	)%
Purchased power costs:
Purchases from SPP (B)		(94.2	)		(10.8	)%
Wind		2.2			3.9	%
Other		(0.3	)		(2.8	)%
Transmission expense		(3.3	)		(4.3	)%
Change in fuel, purchased power and direct transmission expense	$	(465.2	)

(A)

Decreased primarily due to inflated fuel costs in 2021 during Winter Storm Uri.

(B)

Decreased primarily due to higher market prices in 2021 during Winter Storm Uri.

Other operation and maintenance expense increased $27.2 million, or 5.9 percent, primarily driven by the below factors.


(In millions)	$ Change		% Change
Contract technical and construction services (A)	$	6.7		12.8	%
Materials and supplies (B)		4.1		15.5	%
Other		3.9		1.3	%
Vegetation management		3.8		9.9	%
Fees, permits and licenses		3.3		15.7	%
Fleet transportation (C)		2.9		35.3	%
Contract professional services		2.5		12.8	%
Change in other operation and maintenance expense	$	27.2

(A)

Increased primarily due to higher equipment maintenance which included additional Arkansas storm restoration.

(B)

Increased primarily due to inflationary increases throughout the supply chain.

(C)

Increased primarily due to higher fuel prices, including diesel which supports the majority of company fleet.

Depreciation and amortization expense increased $44.9 million, or 10.8 percent, primarily due to an increase in depreciation rates effective as of July 1, 2022 resulting from the Oklahoma general rate review order received in September 2022, additional assets being placed into service and increased amortization of the regulatory asset related to storms.

Other net periodic benefit income changed $5.5 million, primarily due to lower pension expense driven by changes to the level of pension expense included in base rates, effective July 1, 2022, as approved in the Oklahoma general rate review order received in September 2022.

Income tax expense increased $34.6 million, or 82.8 percent, reflecting additional income taxes primarily related to higher pretax income and decreased federal and state tax credit generation, partially offset by higher amortization of net unfunded deferred taxes.

OGE Holdings (Natural Gas Midstream Operations)

On December 2, 2021, Energy Transfer completed its previously announced acquisition of Enable. Prior to the Energy Transfer and Enable merger closing, OGE Energy's natural gas midstream operations segment included its equity method investment in Enable, and from December 2, 2021 to September 30, 2022, this segment included OGE Energy's investment in Energy Transfer's equity securities. Legacy Enable seconded employee pension and postretirement costs are also included for the year ended December 31, 2022. Therefore, results of operations for the natural gas midstream operations segment are not comparable for the year ended December 31, 2022 compared to the year ended December 31, 2021. See "Investment in Equity Securities of Energy Transfer" in Note 1 within "Item 8. Financial Statements and Supplementary Data" for further discussion of the net proceeds from sales of Energy Transfer's equity securities, realized gain/loss on Energy Transfer's equity securities and dividend income recognized by OGE Energy. See OGE Energy's 2021 Form 10-K for discussion of the primary drivers of Enable's income statement information for the period of January 1, 2021 through December 2, 2021.

OGE Holdings' income tax expense decreased $52.9 million, or 52.4 percent, primarily due to lower pre-tax income and tax adjustments from the sale of Energy Transfer limited partner units, partially offset by state deferred tax adjustments related to OGE Energy's midstream investment in Energy Transfer subsequent to the acquisition of Enable.

Liquidity and Capital Resources

Cash Flows

OGE Energy


Year Ended December 31 (In millions)	2022			2021			$ Change			% Change
Net cash provided from (used in) operating activities (A)	$	843.1		$	(313.3	)	$	1,156.4		*
Net cash provided from (used in) investing activities (B)	$	12.9		$	(749.1	)	$	762.0		*
Net cash (used in) provided from financing activities (C)	$	(767.9	)	$	1,061.3		$	(1,829.2	)	*

* Change is greater than 100 percent.

(A)

Changed primarily due to an increase in cash received from customers, the receipt of securitization funds from the ODFA and a decrease in vendor payments, including payments for fuel and purchased power costs related to Winter Storm Uri in 2021, partially offset by additional income tax payments primarily relating to the sale of Energy Transfer's limited partner units in 2022.

(B)

Changed primarily due to proceeds from the sale of Energy Transfer's limited partner units, partially offset by increased investment in power delivery projects at OG&E.

(C)

Changed primarily due to decreased proceeds from long-term debt reflective of the debt issuance in May 2021 and decreased short-term debt, which was used to provide additional liquidity for the fuel and purchased power costs incurred by OG&E related to Winter Storm Uri in 2021.

Working Capital

Working capital is defined as the difference in current assets and current liabilities. OGE Energy'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 OG&E's customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries. The following discussion addresses changes in OGE Energy's working capital balances at December 31, 2022 compared to December 31, 2021.

Cash and Cash Equivalents increased $88.1 million, primarily due to proceeds received from OGE Energy's sales of Energy Transfer limited partner units and OG&E's receipt of securitization funds from the ODFA, which OGE Energy intends to utilize to help fund the repayment of the senior notes due in May 2023.

Accounts Receivable and Accrued Unbilled Revenues increased $97.0 million, or 42.7 percent, primarily due to an increase in billings to OG&E's retail customers reflecting higher usage and new rates as approved in the Oklahoma general rate review order received in September 2022, as well as increased fuel prices.

Income Taxes Receivable increased $18.1 million, primarily due to the timing of cash payments to tax authorities.

Fuel Inventories increased $68.2 million, primarily due to higher prices and volumes of coal and gas purchases.

Materials and Supplies, at Average Cost increased $62.6 million, or 53.1 percent, primarily due to increased inventory which is partly a result of the ongoing supply chain and inflation impacts of the current economic environment.

Fuel Clause Under Recoveries increased $363.0 million, primarily due to lower recoveries from OG&E retail customers as compared to the actual cost of fuel and purchased power. OG&E has implemented updated fuel factors to address recovery of the fuel under recovery balance, as further discussed in Note 14 within "Item 8. Financial Statements and Supplementary Data."

Other Current Assets increased $30.2 million, or 41.2 percent, primarily due to an increase in SPP deposits, partially offset by a decrease in under recovered riders.

Short-term Debt decreased $486.9 million, or 100.0 percent, primarily due to the repayment of short-term borrowings used for general operating needs. OGE Energy borrows on a short-term basis, as necessary, by the issuance of commercial paper and borrowings under its revolving credit agreements and term credit agreements.

Accounts Payable increased $174.9 million, or 63.8 percent, primarily due to timing of vendor payments.

Long-Term Debt Due Within One Year increased $999.9 million, due to the reclassification of long-term debt that will mature in May 2023.

Other Current Liabilities increased $15.5 million, or 45.5 percent, primarily due to an increase in SPP projected payables as well as changes in amounts of taxes due.

2022 Capital Requirements, Sources of Financing and Financing Activities

OGE Energy's total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $1,051.0 million, and contractual obligations, net of recoveries through fuel adjustment clauses, were $0.5 million, resulting in total net capital requirements and contractual obligations of $1,051.5 million in 2022. This compares to net capital requirements of $778.6 million and net contractual obligations of $1.0 million totaling $779.6 million in 2021.

In 2022, OGE Energy's primary sources of capital were cash generated from operations, proceeds from the issuance of long- and short-term debt, sales of Energy Transfer's limited partner units and distributions received from Energy Transfer. Changes in working capital reflect the seasonal nature of OGE Energy'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.

Future Material Cash Requirements

OGE Energy's primary, material cash requirements 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 recoveries and other general corporate purposes. Further, working capital requirements can be seasonal. OGE Energy generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.

Capital Expenditures

The following table presents OGE Energy's estimates of capital expenditures for the years 2023 through 2027. These capital investments are customer-focused and targeted to maintain and improve the safety, resiliency and reliability of OG&E's distribution and transmission grid and generation fleet, enhance the ability of OG&E's system to perform during extreme weather events and to serve OG&E's growing customer base.


(In millions)	2023		2024		2025		2026		2027		Total
Transmission	$	125	$	145	$	160	$	160	$	160	$	750
Oklahoma distribution & grid advancement		490		490		550		550		550		2,630
Arkansas distribution		20		20		20		20		20		100
Generation		115		115		120		120		120		590
Other (A)		200		180		100		100		100		680
Total	$	950	$	950	$	950	$	950	$	950	$	4,750

(A)

Estimated capital expenditures associated with OG&E's enterprise resource planning system project are included in 2023 and 2024.

Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities, will be evaluated based upon the requirements of OG&E's power supply, transmission and distribution operational teams and the expected resultant customer benefits. The investments above do not include amounts related to new generation capacity needs as outlined in OG&E's October 2021 IRP and recent changes to the SPP's planning reserve margin and resource capacity accreditation. OG&E intends to file for approval of the generation capacity investments and would expect to update its capital plan based on a final order. The annual level of investments in the transmission and distribution system could vary depending on the amount and timing of incremental generation capacity investments. Supply chain disruption may increase the risk of delays in construction activities and equipment deliveries related to OGE Energy's capital projects.

Contractual Obligations

The following table presents OGE Energy's total contractual obligations for the next five years at December 31, 2022. For further detail of OGE Energy's contractual obligations, which include operating leases, long-term debt and purchase obligations and commitments (including information for maturities beyond the next five years), see Notes 4, 9 and 13, respectively, within "Item 8. Financial Statements and Supplementary Data."


(In millions)	2023			2024			2025			2026			2027			Total
Total contractual obligations	$	1,174.4		$	167.0		$	259.0		$	102.0		$	290.1		$	1,992.5
Amounts recoverable through fuel adjustment clause (A)		(168.8	)		(149.5	)		(123.8	)		(81.9	)		(82.3	)		(606.3	)
Total contractual obligations, net	$	1,005.6		$	17.5		$	135.2		$	20.1		$	207.8		$	1,386.2

(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 in Note 4 within "Item 8. Financial Statements and Supplementary Data") 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 in Notes 4 and 13, respectively, within "Item 8. Financial Statements and Supplementary Data" may increase capital requirements, such costs are generally 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. Otherwise, as discussed above, OGE Energy expects to meet these cash requirement needs through cash generated from operations, short-term borrowings and permanent financings.

Pension and Postretirement Benefit Plans

At December 31, 2022, 24.5 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in corporate fixed income and other securities, U.S. Treasury notes and bonds and mutual funds as presented in Note 11 within "Item 8. Financial Statements and Supplementary Data." During 2022, the actual return on the Pension Plan was a loss of $82.2 million, compared to an expected return on plan assets of $25.4 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. OGE Energy did not make any contribution to its Pension Plan in 2022 and made a contribution of $40.0 million in 2021. OGE Energy does not expect it will need to make any contributions to the Pension Plan in 2023. OGE Energy 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 OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 2022 and 2021. 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 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 statements of income in future periods.


	Pension Plan						Restoration of Retirement Income Plan						Postretirement Benefit Plans
December 31 (In millions)	2022			2021			2022			2021			2022			2021
Benefit obligations	$	358.5		$	502.9		$	5.8		$	5.9		$	101.9		$	137.3
Fair value of plan assets		293.0			486.0			—			—			32.8			44.3
Funded status at end of year	$	(65.5	)	$	(16.9	)	$	(5.8	)	$	(5.9	)	$	(69.1	)	$	(93.0	)

Common Stock Dividends

OGE Energy'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. Prior to the approval of a change in the dividend in 2022, the Board of Directors reviewed a recommendation from management of an increase in the quarterly dividend to $0.4141 per share from $0.41 per share and subsequently approved the recommendation to become effective with the dividend payment in October 2022.

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 OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. OGE Energy 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. In January 2023, OG&E issued $450.0 million of Senior Notes due January 15, 2033, as further discussed within "Long-Term Debt" below.

Short-Term Debt and Credit Facilities

OGE Energy borrows on a short-term basis, as necessary, by issuance of commercial paper and borrowings under its revolving credit agreements and term credit agreements maturing in one year or less.

OGE Energy has unsecured five-year revolving credit facilities totaling $1.1 billion ($550.0 million for OGE Energy and $550.0 million for OG&E), which can also be used as letter of credit facilities. As further discussed below, in May 2022, OGE Energy entered into a $100.0 million floating rate unsecured three-year credit agreement, of which $50.0 million is considered a revolving loan. The following table presents information about OGE Energy's revolving credit agreements as of December 31, 2022.


(Dollars in millions)	December 31, 2022
Balance of outstanding supporting letters of credit	$	0.4
Weighted-average interest rate of outstanding supporting letters of credit		1.15	%
Net available liquidity under revolving credit agreements, commercial paper borrowings and letters of credit	$	1,149.6
Balance of cash and cash equivalents	$	89.3

The following table presents information about OGE Energy's total short-term debt activity for the year ended December 31, 2022.


(Dollars in millions)	Year Ended December 31, 2022
Average balance of short-term debt	$	337.3
Weighted-average interest rate of average balance of short-term debt		0.97	%
Maximum month-end balance of short-term debt	$	731.5

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 $1.0 billion in short-term borrowings at any one time for a two-year period beginning January 1, 2023 and ending December 31, 2024.

Long-Term Debt

In May 2022, OGE Energy entered into a $100.0 million floating rate unsecured three-year credit agreement, of which $50.0 million is considered a revolving loan and $50.0 million is considered a term loan, and borrowed the full $50.0 million term loan, in order to preserve general financial flexibility within the company. Advances under this agreement were used to refinance existing indebtedness and for working capital and general corporate purposes of OGE Energy. The credit agreement, under certain circumstances, may be increased to a maximum commitment limit of $135.0 million and contains substantially the same covenants as OGE Energy's existing $550.0 million revolving credit agreement. The credit agreement is scheduled to terminate on May 24, 2025. At December 31, 2022, the weighted-average interest rate for the amount drawn on the term loan under this credit agreement was 3.48 percent.

In January 2023, OG&E issued $450.0 million of 5.40% Senior Notes due January 15, 2033. The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to help fund the repayment of its $500.0 million 0.553% Senior Notes, Series due May 26, 2023 and the funding of its capital investment program and working capital needs.

OG&E expects to issue up to $400.0 million of long-term debt to support its current year capital investment plan and for the repayment of maturing debt.

Securitization of Oklahoma Winter Storm Uri Extreme Purchase Costs

As further discussed in Note 14 within "Item 8. Financial Statements and Supplementary Data," on July 20, 2022, the ODFA issued securitization bonds, and OG&E received proceeds of approximately $750 million for the sale of securitization property to the ODFA. OG&E used these proceeds to fund the Oklahoma Winter Storm Uri regulatory asset by recovering the authorized extreme, extraordinary fuel and purchased power costs incurred during Winter Storm Uri, as well as carrying costs.

Security Ratings


	Moody's Investors Service		S&P's Global Ratings		Fitch Ratings
	Rating	Outlook	Rating	Outlook	Rating	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 OGE Energy'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 OGE Energy's short-term borrowings, but a reduction in OGE Energy'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 OGE Energy 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.

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

OGE Energy does not expect to issue any common stock in 2023 from its Automatic Dividend Reinvestment and Stock Purchase Plan. See Note 8 within "Item 8. Financial Statements and Supplementary Data" for a discussion of OGE Energy's common stock activity.

Distributions by Enable and Energy Transfer

During the year ended December 31, 2022, OGE Energy received distributions of $34.0 million from Energy Transfer. During the years ended December 31, 2021 and 2020, OGE Energy received distributions of $73.4 million and $91.7 million, respectively, from Enable.

Sale of Energy Transfer's Equity Securities

As previously disclosed, OGE Energy intended to become primarily an electric company by exiting its investment in Energy Transfer's equity securities. As of the end of September 2022, OGE Energy had sold all of its 95.4 million Energy Transfer limited partner units, resulting in pre-tax net proceeds of $1,067.2 million. OGE Energy intends to use these proceeds to help repay the $1.0 billion in senior notes due in May 2023 and for general corporate purposes.

Critical Accounting Policies and Estimates

The financial statements and notes thereto contain information that is pertinent to management's discussion and analysis. In preparing the 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 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 Registrants' financial statements. However, the Registrants believe they have taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Registrants that could result if actual results vary from the assumptions and estimates.

In management's opinion, the areas where the most significant judgment is exercised include the determination of pension and postretirement plan assumptions, income taxes, contingency reserves, asset retirement obligations, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Audit Committee of OGE Energy's Board of Directors. The Registrants discuss their 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."

Pension and Postretirement Plan Assumptions

OGE Energy has a Pension Plan that covers certain employees, including OG&E's employees, hired before December 1, 2009. Effective December 1, 2009, OGE Energy's Pension Plan is no longer being offered to employees hired on or after December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover certain employees, including OG&E's 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 11 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 presents the sensitivity of the Pension Plan funded status to these variables.


	Change	Impact on Funded Status
Actual plan asset returns	+/- 1 percent	+/- $2.9 million
Discount rate	+/- 0.25 percent	+/- $5.6 million
Contributions	+/- $10 million	+/- $10.0 million

Income Taxes

The Registrants use 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 Registrants recognized in their financial statements. Tax positions taken by the Registrants on their 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.

Contingency Reserves

Asset Retirement Obligations

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

Regulatory Assets and Liabilities

Unbilled Revenues

OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E measures its customers' metered usage 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 balance sheets and in Revenues from Contracts with Customers in the 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. At December 31, 2022 and 2021, Accrued Unbilled Revenues were $74.2 million and $65.0 million, respectively.

At December 31, 2022, 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.

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 generally 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 and is adjusted for current conditions and supportable forecasts as necessary. To the extent the historical collection rates, when incorporating forecasted conditions, 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 balance sheets and is included in Other Operation and Maintenance Expense in the statements of income. The allowance for uncollectible accounts receivable was $1.9 million and $2.4 million at December 31, 2022 and 2021, respectively.

At December 31, 2022, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of $0.2 million.

Accounting Pronouncements

See Note 2 within "Item 8. Financial Statements and Supplementary Data" for further discussion of recently adopted accounting standards and recently issued accounting standards that are not yet effective that could have a material impact on the Registrants' financial position, results of operations or cash flows upon adoption.

Commitments and Contingencies

In the normal course of business, the Registrants are 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 Registrants have 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 financial statements. At the present time, based on currently available information, the Registrants believe 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 their financial statements and would not have a material adverse effect on their financial position, results of operations or cash flows. See Notes 13 and 14 within "Item 8. Financial Statements and Supplementary Data" and "Item 3. Legal Proceedings" for further discussion of the Registrants' commitments and contingencies.

Environmental Laws and Regulations

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

OG&E's operations are subject to the Federal Clean Air Act of 1970, 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.

OG&E is working cooperatively with federal and state environmental agencies to create emission limits for OG&E's operations that are consistent with legal requirements for protecting health and the environment while being cost effective for OG&E to implement. Although various court proceedings are pending that challenge the validity or stringency of rules issued by federal and state environmental agencies, OG&E is not currently a party to any of these proceedings. At this time, OG&E does not anticipate additional material capital expenditures for compliance with the existing rules.

The EPA revised the NAAQS for ozone in 2015. Although Oklahoma complies with the revised standard, the Federal Clean Air Act of 1970, as amended, requires states to submit to the EPA for approval a SIP to prohibit in-state sources from contributing

significantly to nonattainment of the NAAQS in another state. On October 28, 2018, Oklahoma submitted its SIP to the EPA related to these "Good Neighbor" requirements. On January 31, 2023, the EPA disapproved the SIPs of 19 states, including Oklahoma. In response to litigation, on April 6, 2022, the EPA also published a proposed FIP related to the "Good Neighbor" requirements intended to reduce interstate NOx emissions contributions. The proposed FIP, which includes Oklahoma among 24 other states, proposes to limit the current Oklahoma NOx emissions budgets over four years for certain generating units including OG&E's units beginning in 2023. It is anticipated the EPA will finalize the FIP by mid-March of 2023. OG&E filed comments to the proposed FIP with the EPA on June 21, 2022. OG&E is closely monitoring these issues; however, it is unknown at this time what, if any, potential material impacts will result from the EPA actions.

On January 27, 2023, the EPA published a proposed rule in the Federal Register to reconsider the primary (health-based) and secondary (welfare-based) NAAQS for Particulate Matter ("PM NAAQS"). The EPA is proposing to lower the primary annual PM2.5 to a level ranging from approximately 17 percent to 25 percent below the current standard and is proposing to retain the other PM NAAQS at their current levels. Particulate matter ("PM") is not a single pollutant but rather is a mixture of chemicals, solids and aerosols composed of small droplets of liquid, dry solid fragments and solid cores with liquid coatings. PM varies widely in size, shape and chemical composition and is defined by diameter for air quality regulatory purposes: PM10 and PM2.5. The EPA expects to issue a final decision on the PM standards in 2024. The EPA will determine which areas of the country meet the standards, such as making initial attainment/nonattainment designations, no later than two years after new standards are issued. States must develop and submit attainment plans no later than 18 months after the EPA finalizes nonattainment designations. This proposed rule could impact regional air quality goals and emission limits for emission sources; however, it is unknown at this time what, if any, potential material impacts to OG&E individual operating permit emission limits will result from the EPA actions.

In July 2020, the ODEQ notified OG&E that the Horseshoe Lake generating units would be included in Oklahoma's second Regional Haze implementation period evaluation of visibility impairment impacts to the Wichita Mountains. OG&E submitted an analysis of all potential control measures for NOx on these units to the ODEQ. The ODEQ submitted a revised SIP to the EPA on August 12, 2022. It is unknown at this time what the outcome, or any potential material impacts, if any, will be from the evaluations by OG&E, the ODEQ and the EPA.

OG&E monitors possible changes in legal standards for emissions of greenhouse gases, including CO2, sulfur hexafluoride and methane, including President Biden Administration's target of a 50 to 52 percent reduction in economy-wide net greenhouse gas emissions from 2005 levels by 2030 with full decarbonization of the electric power industry by 2035 and the September 2022 EPA non-rulemaking docket for public input related to the EPA's efforts to reduce emissions of greenhouse gases from new and existing fossil fuel-fired electric generating units under Clean Air Act Section 111. If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of CO2 and other greenhouse gases at OG&E's facilities, this could result in significant additional compliance costs that would affect OG&E's future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

OG&E has reduced carbon dioxide emissions by over 40 percent compared to 2005 levels, and during the same period, emissions of ozone-forming NOx have been reduced by approximately 80 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 rules, 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.

In October 2021, OG&E issued its most recent IRP to the OCC and APSC that proposes to expand its renewable generation fleet, including the development of additional solar resources. 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.

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 OG&E conducts operations, or if additional species in those areas become subject to protection, OG&E's operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or OG&E could be required to implement expensive mitigation measures.

On November 9, 2021, the USFWS published a proposed rule to list the Alligator Snapping Turtle as threatened under the Endangered Species Act, along with a 4(d) rule that would provide conservation of the species. The habitat located within the OG&E service territory is limited to eastern Oklahoma and western Arkansas; however, the USFWS is proposing to exempt incidental take by industry for operation and maintenance and other routine activities that are conducted by using best management practices that reduce incidental take and conserve the habitat. The final rule for the listing decision was expected to occur in November 2022.

On September 14, 2022, the USFWS published a proposal to list the Tricolored Bat as endangered under the Endangered Species Act. According to the proposal, the current known range of the Tricolored Bat extends to 36 states, including Oklahoma and Arkansas.

On September 30, 2022, the USFWS proposed a voluntary permitting rule that would cover incidental take of bald and golden eagles from allowed activities by instituting voluntary mitigation actions. Some of the voluntary actions include retrofitting 11 non-electrocution-safe poles or 1/2 mile of non-electrocution-safe circuit to electrocution-safe as a result of eagle take or injury, retrofitting 10 percent of non-electrocution-safe infrastructure to electrocution-safe within the five-year term of the permit and incorporating an eagle shooting response strategy to investigate shootings near power line infrastructure. It is unknown at this time whether the voluntary permitting program will become a requirement. OG&E currently maintains an avian protection plan to help mitigate eagle impacts and has adopted the best management practices of the Avian Power Line Interaction Committee, of which OG&E is a member.

OG&E is closely monitoring each of these issues due to possible future impacts; however, it is unknown at this time what, if any, material impacts will result from the USFWS action.

On November 25, 2022, the USFWS published a final rule to list two distinct population segments of the Lesser Prairie Chicken; the southern distinct population segment located in west Texas and eastern New Mexico is proposed as endangered status, and the northern distinct population located in northwest Texas, northwest Oklahoma, Kansas and Colorado is proposed to be listed as threatened status with a 4(d) rule which would prohibit take of the chicken, such as destroying its habitat by building a transmission line or substation, without a permit or special authorization from the USFWS. At this time, OG&E expects this rule will not impact any current OG&E infrastructure and should allow for construction in areas that are considered previously disturbed.

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.

During 2022, approximately 95 percent of the ash from OG&E's River Valley, Muskogee and Sooner facilities was recovered and reused in various ways, including soil stabilization, landfill cover, road base construction and cement and concrete production. Reusing fly ash reduces the need to manufacture cement resulting in reductions in greenhouse gas emissions from cement and concrete production. Based on estimates from the American Coal Ash Association, OG&E fly ash reuse helped avoid over three million tons of CO2 emissions in the last 15 years.

OG&E has sought and will continue to seek pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2022, OG&E obtained refunds of $2.9 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.

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 October 13, 2020, the EPA published a final rule to revise the technology-based effluent limitations for flue gas desulfurization waste water and bottom ash transport water. On August 3, 2021, the EPA published notice in the Federal Register that it will undertake a supplemental rulemaking to revise the effluent limitation guidelines rule after completing its review of the October 2020 rule. The existing effluent limitation guidelines will remain in effect while the EPA undertakes this new rulemaking. 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 permit requirements from the State of Oklahoma.

Since the purchase of the Redbud facility in 2008, OG&E made investments in the infrastructure that have led to OG&E's average use of approximately 2.5 billion gallons per year of treated municipal effluent for all of the needed cooling water at Redbud and McClain. 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 13 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 Registrants' exposure to changes in interest rates relates primarily to variable-rate debt, commercial paper and future long-term debt issuances. The Registrants are exposed to commodity prices in their operations to the extent any fuel price changes are not recovered in customer rates.

Risk Oversight Committee

The Registrants manage market risks using a risk committee structure. OGE Energy's Risk Oversight Committee, which consists of the Chief Financial Officer, other corporate officers and members of management, is responsible for the overall development, implementation and enforcement of strategies and policies for all significant risk management activities of the Registrants. In 2022, this committee and the Registrants' management applied a holistic perspective of risk assessment and application of its strategies and policies to manage the Registrants' overall financial performance. The Chief Financial Officer, acting in his role as the principal financial officer and as a member of the Risk Oversight Committee, reports periodically to the Audit Committee of OGE Energy's Board of Directors on the Registrants' risk profile affecting anticipated financial results, including any significant risk issues. The Audit Committee updates the Board of Directors regarding the company's risk management practices and the steps management has taken to monitor and control applicable risks.

Risk Policies

Management utilizes risk policies to control the amount of market risk exposure. These policies are designed to provide the Audit Committee of OGE Energy's Board of Directors and senior executives of the Registrants with confidence that the risks taken on by the Registrants' 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.

Interest Rate Risk

The Registrants' exposure to changes in interest rates primarily relates to variable-rate debt and commercial paper. The Registrants manage their interest rate exposure by monitoring and limiting the effects of market changes in interest rates. The Registrants 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 Registrants have no intent at this time to utilize interest rate derivatives.

The fair value of the Registrants' 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 Registrants' current borrowing rate. The following table presents the Registrants' long-term debt maturities and the weighted-average interest rates by maturity date.


Year Ended December 31 (Dollars in millions)	2023			2024			2025			2026			2027			Thereafter			Total			12/31/22 Fair Value
OGE Energy (holding company) fixed-rate debt (A):
Principal amount	$	500.0		$	—		$	—		$	—		$	—		$	—		$	500.0		$	491.2
Weighted-average interest rate		0.703	%		—	%		—	%		—	%		—	%		—	%		0.703	%
OGE Energy (holding company) variable-rate debt (A):
Principal amount	$	—		$	—		$	50.0		$	—		$	—		$	—		$	50.0		$	50.0
Weighted-average interest rate		—	%		—	%		5.375	%		—	%		—	%		—	%		5.375	%
OG&E fixed-rate debt (A):
Principal amount	$	500.0		$	—		$	—		$	—		$	125.0		$	3,269.3		$	3,894.3		$	3,484.4
Weighted-average interest rate		0.553	%		—	%		—	%		—	%		6.650	%		4.400	%		3.980	%
OG&E variable-rate debt (B):
Principal amount	$	—		$	—		$	79.4		$	—		$	56.0		$	—		$	135.4		$	135.4
Weighted-average interest rate		—	%		—	%		3.830	%		—	%		3.850	%		—	%		3.840	%

(A)

Prior to or when these debt obligations mature, the Registrants 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 OG&E would change interest expense by $1.4 million annually.

Item 8. Financial Statements and Supplementary Data.

OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME


Year Ended December 31 (In millions except per share data)	2022			2021			2020
OPERATING REVENUES
Revenues from contracts with customers	$	3,304.2		$	3,588.7		$	2,069.8
Other revenues		71.5			65.0			52.5
Operating revenues		3,375.7			3,653.7			2,122.3
FUEL, PURCHASED POWER AND DIRECT TRANSMISSION EXPENSE		1,662.4			2,127.6			644.6
OPERATING EXPENSES
Other operation and maintenance		501.4			463.1			462.8
Depreciation and amortization		460.9			416.0			391.3
Taxes other than income		101.5			102.8			101.4
Operating expenses		1,063.8			981.9			955.5
OPERATING INCOME		649.5			544.2			522.2
OTHER INCOME (EXPENSE)
Gain (loss) on equity securities (Note 1)		282.1			(8.6	)		—
Equity in earnings (losses) of unconsolidated affiliates		—			169.8			(668.0	)
Allowance for equity funds used during construction		6.9			6.7			4.8
Other net periodic benefit expense		(12.9	)		(6.1	)		(3.9	)
Other income		74.6			26.3			37.5
Gain on Enable/Energy Transfer transaction, net (Note 1)		—			344.4			—
Other expense		(44.6	)		(39.9	)		(35.2	)
Net other income (expense)		306.1			492.6			(664.8	)
INTEREST EXPENSE
Interest on long-term debt		162.1			154.8			152.8
Allowance for borrowed funds used during construction		(4.0	)		(3.5	)		(1.9	)
Interest on short-term debt and other interest charges		8.2			7.0			7.6
Interest expense		166.3			158.3			158.5
INCOME (LOSS) BEFORE TAXES		789.3			878.5			(301.1	)
INCOME TAX EXPENSE (BENEFIT)		123.6			141.2			(127.4	)
NET INCOME (LOSS)	$	665.7		$	737.3		$	(173.7	)
BASIC AVERAGE COMMON SHARES OUTSTANDING		200.2			200.1			200.1
DILUTED AVERAGE COMMON SHARES OUTSTANDING		200.8			200.3			200.1
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE	$	3.33		$	3.68		$	(0.87	)
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE	$	3.32		$	3.68		$	(0.87	)

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

OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


Year Ended December 31 (In millions)	2022			2021			2020
Net income (loss)	$	665.7		$	737.3		$	(173.7	)
Other comprehensive income (loss), net of tax:
Pension Plan and Restoration of Retirement Income Plan:
Amortization of prior service cost, net of tax of $0.1, $0.0 and $0.0, respectively		0.2			0.1			—
Amortization of deferred net loss, net of tax of $0.2, $0.9 and $1.2, respectively		1.4			1.6			3.9
Net gain (loss) arising during the period, net of tax of ($2.4), $0.0 and ($1.7), respectively		(7.6	)		1.4			(5.1	)
Prior service cost arising during the period, net of tax of $0.0, ($0.3) and $0.0, respectively		—			(1.1	)		—
Settlement cost, net of tax of $4.3, $2.7 and $0.7, respectively		13.6			6.0			2.2
Postretirement benefit plans:
Amortization of prior service credit, net of tax of ($0.1), ($0.4) and ($0.6), respectively		(0.2	)		(1.4	)		(1.7	)
Amortization of deferred net (gain) loss, net of tax of $0.0, $0.0 and $0.0, respectively		—			0.1			(0.1	)
Net gain (loss) arising during the period, net of tax of $1.7, ($0.2) and ($0.8), respectively		5.5			(0.7	)		(2.4	)
Curtailment cost, net of tax of $0.0, $0.0 and ($0.1), respectively		—			—			(0.3	)
Other comprehensive gain (loss) from unconsolidated affiliates, net of tax $0.0, $0.3 and ($0.2), respectively		—			1.3			(0.7	)
Other comprehensive income (loss), net of tax		12.9			7.3			(4.2	)
Comprehensive income (loss)	$	678.6		$	744.6		$	(177.9	)

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

OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS


Year Ended December 31 (In millions)	2022			2021			2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	665.7		$	737.3		$	(173.7	)
Adjustments to reconcile net income (loss) to net cash provided from (used in) operating activities:
Depreciation and amortization		460.9			416.0			391.3
Deferred income taxes and other tax credits, net		(154.0	)		125.9			(134.5	)
(Gain) loss on investment in equity securities (Note 1)		(282.1	)		8.6			—
Gain on Enable/Energy Transfer transaction (Note 1)		—			(353.0	)		—
Equity in (earnings) losses of unconsolidated affiliates		—			(169.8	)		668.0
Distributions from unconsolidated affiliates		—			73.4			91.7
Allowance for equity funds used during construction		(6.9	)		(6.7	)		(4.8	)
Stock-based compensation expense		9.7			9.8			9.8
Regulatory assets		702.2			(874.9	)		(112.0	)
Regulatory liabilities		(118.4	)		(71.2	)		(64.0	)
Other assets		18.9			(9.8	)		(9.2	)
Other liabilities		(6.6	)		(8.1	)		(26.3	)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net		(97.0	)		(1.9	)		3.1
Income taxes receivable		(18.1	)		5.5			2.8
Fuel, materials and supplies inventories		(130.1	)		(3.4	)		(8.9	)
Fuel recoveries		(363.0	)		(180.5	)		63.3
Other current assets		(30.2	)		(22.7	)		(16.8	)
Accounts payable		155.4			7.5			59.8
Other current liabilities		36.7			4.7			(26.8	)
Net cash provided from (used in) operating activities		843.1			(313.3	)		712.8
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)		(1,050.9	)		(778.5	)		(650.5	)
Proceeds from sales of equity securities		1,067.2			—			—
Cash received in Enable/Energy Transfer transaction (Note 1)		—			35.0			—
Other		(3.4	)		(5.6	)		(4.4	)
Net cash provided from (used in) investing activities		12.9			(749.1	)		(654.9	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		49.3			997.8			297.1
(Decrease) increase in short-term debt		(486.9	)		391.9			(17.0	)
Payment of long-term debt		(0.1	)		(0.1	)		(0.1	)
Dividends paid on common stock		(329.3	)		(324.9	)		(314.9	)
Cash paid for employee equity-based compensation and expense of common stock		(0.9	)		(3.4	)		(7.1	)
Purchase of treasury stock		—			—			(14.7	)
Other		—			—			(0.1	)
Net cash (used in) provided from financing activities		(767.9	)		1,061.3			(56.8	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		88.1			(1.1	)		1.1
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		—			1.1			—
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	88.1		$	—		$	1.1
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of interest capitalized of $4.0, $3.5 and $1.9, respectively)	$	164.0		$	156.4		$	153.4
Income taxes (net of income tax refunds)	$	276.0		$	8.7		$	3.9
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement	$	0.8		$	2.4		$	6.8
Investment in Energy Transfer's equity securities (Note 1)	$	—		$	793.7		$	—

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

OGE ENERGY CORP.

CONSOLIDATED BALANCE SHEETS


December 31 (In millions)	2022		2021
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	88.1	$	—
Accounts receivable, less reserve of $1.9 and $2.4, respectively		250.1		162.3
Accrued unbilled revenues		74.2		65.0
Income taxes receivable		20.7		2.6
Fuel inventories		108.8		40.6
Materials and supplies, at average cost		180.5		117.9
Fuel clause under recoveries		514.9		151.9
Other		103.5		73.3
Total current assets		1,340.8		613.6
OTHER PROPERTY AND INVESTMENTS
Equity securities investment in Energy Transfer		—		785.1
Other		105.8		120.0
Total other property and investments		105.8		905.1
PROPERTY, PLANT AND EQUIPMENT
In service		14,695.2		13,899.8
Construction work in progress		436.1		252.0
Total property, plant and equipment		15,131.3		14,151.8
Less: accumulated depreciation		4,584.5		4,318.9
Net property, plant and equipment		10,546.8		9,832.9
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets		524.3		1,230.8
Other		27.0		24.0
Total deferred charges and other assets		551.3		1,254.8
TOTAL ASSETS	$	12,544.7	$	12,606.4

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

OGE ENERGY CORP.

CONSOLIDATED BALANCE SHEETS (Continued)


December 31 (In millions)	2022			2021
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	—		$	486.9
Accounts payable		448.9			274.0
Dividends payable		82.9			82.1
Customer deposits		88.8			81.1
Accrued taxes		54.0			52.9
Accrued interest		41.1			40.8
Accrued compensation		37.0			37.7
Long-term debt due within one year		999.9			—
Other		49.6			34.1
Total current liabilities		1,802.2			1,089.6
LONG-TERM DEBT		3,548.7			4,496.4
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		176.9			159.8
Deferred income taxes		1,233.5			1,333.3
Deferred investment tax credits		12.0			12.8
Regulatory liabilities		1,147.1			1,231.1
Other		210.9			227.1
Total deferred credits and other liabilities		2,780.4			2,964.1
Total liabilities		8,131.3			8,550.1
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS' EQUITY
Common stockholders' equity		1,134.5			1,125.8
Retained earnings		3,290.9			2,955.4
Accumulated other comprehensive loss, net of tax		(11.9	)		(24.8	)
Treasury stock, at cost		(0.1	)		(0.1	)
Total stockholders' equity		4,413.4			4,056.3
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	12,544.7		$	12,606.4

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

OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF CAPITALIZATION


December 31 (In millions except per share data)		2022			2021
STOCKHOLDERS' EQUITY
Common stock, par value $0.01 per share; authorized 450.0 shares; and outstanding 200.2 shares and 200.1 shares, respectively		$	2.0		$	2.0
Premium on common stock			1,132.5			1,123.8
Retained earnings			3,290.9			2,955.4
Accumulated other comprehensive loss, net of tax			(11.9	)		(24.8	)
Treasury stock, at cost, 0.0 and 0.0 shares, respectively			(0.1	)		(0.1	)
Total stockholders' equity			4,413.4			4,056.3

LONG-TERM DEBT
SERIES	DUE DATE
Senior Notes - OGE Energy
0.703%	Senior Notes, Series Due May 26, 2023		500.0			500.0
1.875% - 5.375%	Term Loan Due May 24, 2025		50.0			—
Senior Notes - OG&E
0.553%	Senior Notes, Series Due May 26, 2023		500.0			500.0
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			300.0
3.25%	Senior Notes, Series Due April 1, 2030		300.0			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		9.3			9.3

Other Bonds - OG&E
0.11% - 3.98%	Garfield Industrial Authority, January 1, 2025		47.0			47.0
0.11% - 3.95%	Muskogee Industrial Authority, January 1, 2025		32.4			32.4
0.11% - 3.98%	Muskogee Industrial Authority, June 1, 2027		56.0			56.0
Unamortized debt expense			(22.2	)		(23.8	)
Unamortized discount			(8.9	)		(9.5	)
Total long-term debt			4,548.6			4,496.4
Less: long-term debt due within one year			(999.9	)		—
Total long-term debt (excluding long-term debt due within one year)			3,548.7			4,496.4
Total capitalization (including long-term debt due within one year)		$	8,962.0		$	8,552.7

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

OGE ENERGY CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY


	Common Stock				Treasury Stock						Premium on Common			Retained			Accumulated Other Comprehensive (Loss)
(In millions)	Shares		Value		Shares			Value			Stock			Earnings			Income			Total
Balance at December 31, 2019		200.1	$	2.0		—		$	—		$	1,129.3		$	3,036.1		$	(27.9	)	$	4,139.5
Net loss		—		—		—			—			—			(173.7	)		—			(173.7	)
Other comprehensive loss, net of tax		—		—		—			—			—			—			(4.2	)		(4.2	)
Dividends declared on common stock ($1.5800 per share)		—		—		—			—			—			(317.8	)		—			(317.8	)
Purchase of treasury stock		—		—		0.4			(14.7	)		—			—			—			(14.7	)
Stock-based compensation		—		—		(0.3	)		9.4			(6.7	)		—			—			2.7
Balance at December 31, 2020		200.1	$	2.0		0.1		$	(5.3	)	$	1,122.6		$	2,544.6		$	(32.1	)	$	3,631.8
Net income		—		—		—			—			—			737.3			—			737.3
Other comprehensive income, net of tax		—		—		—			—			—			—			7.3			7.3
Dividends declared on common stock ($1.6250 per share)		—		—		—			—			—			(326.5	)		—			(326.5	)
Stock-based compensation		—		—		(0.1	)		5.2			1.2			—			—			6.4
Balance at December 31, 2021		200.1	$	2.0		—		$	(0.1	)	$	1,123.8		$	2,955.4		$	(24.8	)	$	4,056.3
Net income		—		—		—			—			—			665.7			—			665.7
Other comprehensive income, net of tax		—		—		—			—			—			—			12.9			12.9
Dividends declared on common stock ($1.6482 per share)		—		—		—			—			—			(330.2	)		—			(330.2	)
Stock-based compensation		0.1		—		—			—			8.7			—			—			8.7
Balance at December 31, 2022		200.2	$	2.0		—		$	(0.1	)	$	1,132.5		$	3,290.9		$	(11.9	)	$	4,413.4

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

OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF INCOME AND COMPREHENSIVE INCOME


Year Ended December 31 (In millions)	2022			2021			2020
OPERATING REVENUES
Revenues from contracts with customers	$	3,304.2		$	3,588.7		$	2,069.8
Other revenues		71.5			65.0			52.5
Operating revenues		3,375.7			3,653.7			2,122.3
FUEL, PURCHASED POWER AND DIRECT TRANSMISSION EXPENSE		1,662.4			2,127.6			644.6
OPERATING EXPENSES
Other operation and maintenance		491.9			464.7			464.4
Depreciation and amortization		460.9			416.0			391.3
Taxes other than income		98.0			99.3			97.2
Operating expenses		1,050.8			980.0			952.9
OPERATING INCOME		662.5			546.1			524.8
OTHER INCOME (EXPENSE)
Allowance for equity funds used during construction		6.9			6.7			4.8
Other net periodic benefit income (expense)		1.2			(4.3	)		(3.1	)
Other income		6.5			7.1			5.0
Other expense		(3.4	)		(1.8	)		(2.6	)
Net other income		11.2			7.7			4.1
INTEREST EXPENSE
Interest on long-term debt		157.4			152.7			152.8
Allowance for borrowed funds used during construction		(4.0	)		(3.5	)		(1.9	)
Interest on short-term debt and other interest charges		4.4			2.8			3.9
Interest expense		157.8			152.0			154.8
INCOME BEFORE TAXES		515.9			401.8			374.1
INCOME TAX EXPENSE		76.4			41.8			34.7
NET INCOME		439.5			360.0			339.4
Other comprehensive income, net of tax		—			—			—
COMPREHENSIVE INCOME	$	439.5		$	360.0		$	339.4

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

OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS


Year Ended December 31 (In millions)	2022			2021			2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	439.5		$	360.0		$	339.4
Adjustments to reconcile net income to net cash provided from (used in) operating activities:
Depreciation and amortization		460.9			416.0			391.3
Deferred income taxes and other tax credits, net		220.5			44.6			40.9
Allowance for equity funds used during construction		(6.9	)		(6.7	)		(4.8	)
Stock-based compensation expense		2.9			2.2			3.0
Regulatory assets		702.2			(874.9	)		(112.0	)
Regulatory liabilities		(118.4	)		(71.2	)		(64.0	)
Other assets		—			(2.2	)		(3.4	)
Other liabilities		(5.6	)		(11.2	)		(24.3	)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net		(96.6	)		(3.0	)		4.5
Fuel, materials and supplies inventories		(130.1	)		(3.4	)		(8.9	)
Fuel recoveries		(363.0	)		(180.5	)		63.3
Other current assets		(30.1	)		(21.4	)		(17.3	)
Accounts payable		135.8			(11.0	)		64.8
Income taxes payable - parent		8.0			0.7			(5.3	)
Other current liabilities		19.3			3.3			(26.8	)
Net cash provided from (used in) operating activities		1,238.4			(358.7	)		640.4
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)		(1,050.9	)		(778.5	)		(650.5	)
Net cash used in investing activities		(1,050.9	)		(778.5	)		(650.5	)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital contribution from OGE Energy		—			530.0			—
Proceeds from long-term debt		—			499.8			297.1
Payment of long-term debt		(0.1	)		(0.1	)		(0.1	)
Dividends paid on common stock		—			(265.0	)		(325.0	)
Changes in advances with parent		(187.4	)		372.5			38.1
Net cash (used in) provided from financing activities		(187.5	)		1,137.2			10.1
NET CHANGE IN CASH AND CASH EQUIVALENTS		—			—			—
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		—			—			—
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	—		$	—		$	—

SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of interest capitalized of $4.0, $3.5 and $1.9, respectively)	$	154.6		$	148.9		$	150.2
Income taxes (net of income tax refunds)	$	(152.6	)	$	(3.2	)	$	(0.2	)
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement	$	0.8		$	2.4		$	6.8

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

OKLAHOMA GAS AND ELECTRIC COMPANY

BALANCE SHEETS


December 31 (In millions)	2022		2021
ASSETS
CURRENT ASSETS
Accounts receivable, less reserve of $1.9 and $2.4, respectively	$	249.4	$	162.0
Accrued unbilled revenues		74.2		65.0
Advances to parent		91.0		—
Fuel inventories		108.8		40.6
Materials and supplies, at average cost		180.5		117.9
Fuel clause under recoveries		514.9		151.9
Other		97.8		67.7
Total current assets		1,316.6		605.1
OTHER PROPERTY AND INVESTMENTS		4.4		3.9
PROPERTY, PLANT AND EQUIPMENT
In service		14,689.1		13,893.7
Construction work in progress		436.1		252.0
Total property, plant and equipment		15,125.2		14,145.7
Less: accumulated depreciation		4,584.5		4,318.9
Net property, plant and equipment		10,540.7		9,826.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets		524.3		1,230.8
Other		24.5		21.4
Total deferred charges and other assets		548.8		1,252.2
TOTAL ASSETS	$	12,410.5	$	11,688.0

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

OKLAHOMA GAS AND ELECTRIC COMPANY

BALANCE SHEETS (Continued)


December 31 (In millions)	2022		2021
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES
Accounts payable	$	395.8	$	240.6
Advances from parent		—		101.3
Customer deposits		88.8		81.1
Accrued taxes		46.5		50.8
Accrued interest		40.8		40.4
Accrued compensation		27.8		27.8
Long-term debt due within one year		500.0		—
Other		49.3		33.8
Total current liabilities		1,149.0		575.8
LONG-TERM DEBT		3,498.9		3,996.5
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		98.3		75.1
Deferred income taxes		1,271.1		1,000.4
Deferred investment tax credits		12.0		12.8
Regulatory liabilities		1,147.1		1,231.1
Other		188.9		193.5
Total deferred credits and other liabilities		2,717.4		2,512.9
Total liabilities		7,365.3		7,085.2
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDER'S EQUITY
Common stockholder's equity		1,574.6		1,571.7
Retained earnings		3,470.6		3,031.1
Total stockholder's equity		5,045.2		4,602.8
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	12,410.5	$	11,688.0

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

OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF CAPITALIZATION


December 31 (In millions except per share data)		2022			2021
STOCKHOLDER'S EQUITY
Common stock, par value $2.50 per share; authorized 100.0 shares; and outstanding 40.4 shares and 40.4 shares, respectively		$	100.9		$	100.9
Premium on common stock			1,473.7			1,470.8
Retained earnings			3,470.6			3,031.1
Total stockholder's equity			5,045.2			4,602.8

LONG-TERM DEBT
SERIES	DUE DATE
Senior Notes
0.553%	Senior Notes, Series Due May 26, 2023		500.0			500.0
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			300.0
3.25%	Senior Notes, Series Due April 1, 2030		300.0			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		9.3			9.3

Other Bonds
0.11% - 3.98%	Garfield Industrial Authority, January 1, 2025		47.0			47.0
0.11% - 3.95%	Muskogee Industrial Authority, January 1, 2025		32.4			32.4
0.11% - 3.98%	Muskogee Industrial Authority, June 1, 2027		56.0			56.0
Unamortized debt expense			(21.9	)		(23.7	)
Unamortized discount			(8.9	)		(9.5	)
Total long-term debt			3,998.9			3,996.5
Less: long-term debt due within one year			(500.0	)		—
Total long-term debt (excluding long-term debt due within one year)			3,498.9			3,996.5
Total capitalization (including long-term debt due within one year)		$	9,044.1		$	8,599.3

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

OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY


(In millions)	Shares Outstanding		Common Stock		Premium on Common Stock		Retained Earnings			Total
Balance at December 31, 2019		40.4	$	100.9	$	935.7	$	2,921.7		$	3,958.3
Net income		—		—		—		339.4			339.4
Dividends declared on common stock		—		—		—		(325.0	)		(325.0	)
Stock-based compensation		—		—		2.9		—			2.9
Balance at December 31, 2020		40.4	$	100.9	$	938.6	$	2,936.1		$	3,975.6
Net income		—		—		—		360.0			360.0
Dividends declared on common stock		—		—		—		(265.0	)		(265.0	)
Capital contribution from OGE Energy		—		—		530.0		—			530.0
Stock-based compensation		—		—		2.2		—			2.2
Balance at December 31, 2021		40.4	$	100.9	$	1,470.8	$	3,031.1		$	4,602.8
Net income		—		—		—		439.5			439.5
Stock-based compensation		—		—		2.9		—			2.9
Balance at December 31, 2022		40.4	$	100.9	$	1,473.7	$	3,470.6		$	5,045.2

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

COMBINED NOTES TO FINANCIAL STATEMENTS

Index of Combined Notes to Financial Statements

The Combined Notes to the Financial Statements are a combined presentation for OGE Energy and OG&E. The following table indicates the Registrant(s) to which each Note applies.


	OGE Energy	OG&E
Note 1. Summary of Significant Accounting Policies	X	X
Note 2. Accounting Pronouncements	X	X
Note 3. Revenue Recognition	X	X
Note 4. Leases	X	X
Note 5. Fair Value Measurements	X	X
Note 6. Stock-Based Compensation	X	X
Note 7. Income Taxes	X	X
Note 8. Common Equity	X	X
Note 9. Long-Term Debt	X	X
Note 10. Short-Term Debt and Credit Facilities	X	X
Note 11. Retirement Plans and Postretirement Benefit Plans	X	X
Note 12. Report of Business Segments	X
Note 13. Commitments and Contingencies	X	X
Note 14. Rate Matters and Regulation	X	X

Summary of Significant Accounting Policies

Organization

OGE Energy is a holding company with investments in energy and energy services providers offering physical delivery and related services for electricity in Oklahoma and western Arkansas. Prior to September 30, 2022, OGE Energy also held investments in Enable and Energy Transfer, which offered natural gas, crude oil and NGL services. OGE Energy reports these activities through two business segments: (i) electric company and (ii) natural gas midstream operations. The accounts of OGE Energy and its wholly-owned subsidiaries, including OG&E, are included in OGE Energy's consolidated financial statements. All intercompany transactions and balances are eliminated in such consolidation. For periods prior to the December 2, 2021 closing of the Enable and Energy Transfer merger, OGE Energy accounted for its investment in Enable as an equity method investment and reported it within OGE Energy's natural gas midstream operations segment. For the period of December 2, 2021 through September 30, 2022, OGE Energy accounted for its investment in the Energy Transfer units it acquired in the merger as an investment in equity securities, as further discussed below. As of the end of September 2022, OGE Energy had sold all of its Energy Transfer limited partner units, becoming primarily an electric company.

Natural Gas Midstream Operations. For the period of December 2, 2021 to September 30, 2022, OGE Energy's natural gas midstream operations segment included OGE Energy's investment in Energy Transfer's equity securities acquired in the Enable/Energy Transfer merger. For the year ended December 31, 2022, this segment also includes legacy Enable seconded employee pension and postretirement costs. Prior to OGE Energy's sale of all Energy Transfer limited partner units, the investment in Energy Transfer's equity securities was held through wholly-owned subsidiaries and ultimately OGE Holdings. OGE Energy accounted for its investment in Energy Transfer as an investment in equity securities, as further discussed under "Investment in Equity Securities of Energy Transfer" below.

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.

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


December 31 (In millions)	2022		2021
REGULATORY ASSETS
Current:
Oklahoma fuel clause under recoveries	$	474.3	$	140.4
Arkansas fuel clause under recoveries		40.6		11.5
Oklahoma Energy Efficiency Rider under recoveries (A)		7.7		11.7
Other (A)		4.7		19.0
Total current regulatory assets	$	527.3	$	182.6
Non-current:
Oklahoma deferred storm expenses	$	206.3	$	172.8
Benefit obligations regulatory asset		119.7		109.2
Arkansas Winter Storm Uri costs		78.2		88.9
Pension tracker		57.2		42.9
Sooner Dry Scrubbers		18.1		18.9
Arkansas deferred pension expenses		12.3		12.1
Unamortized loss on reacquired debt		8.0		8.9
COVID-19 impacts		7.7		8.2
Frontier Plant deferred expenses		5.2		6.7
Oklahoma Winter Storm Uri costs		—		747.9
Other		11.6		14.3
Total non-current regulatory assets	$	524.3	$	1,230.8
REGULATORY LIABILITIES
Current:
SPP cost tracker over recovery (B)	$	3.0	$	—
Other (B)		2.5		2.5
Total current regulatory liabilities	$	5.5	$	2.5
Non-current:
Income taxes refundable to customers, net	$	894.7	$	930.7
Accrued removal obligations, net		250.5		296.8
Other		1.9		3.6
Total non-current regulatory liabilities	$	1,147.1	$	1,231.1

(A)

Included in Other Current Assets in the balance sheets.

(B)

Included in Other Current Liabilities in the 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.

OG&E recovers program costs related to the Energy Efficiency Program in Oklahoma through the Energy Efficiency Rider, which operates on a three-year program cycle. The current program cycle, which runs through 2024, 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.

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 typically recovers the amounts deferred each year over a five to ten year period in accordance with historical practice.

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 presents a summary of the components of the benefit obligations regulatory asset.


December 31 (In millions)	2022		2021
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	110.0	$	89.6
Postretirement Benefit Plans:
Net loss		9.7		23.2
Prior service cost		—		(3.6	)
Total	$	119.7	$	109.2

In February 2021, Winter Storm Uri resulted in record winter peak demand for electricity and extremely high natural gas and purchased power prices in OG&E's service territory. The OCC allowed OG&E to create a regulatory asset for the Oklahoma portion of all deferred costs, and the Oklahoma Winter Storm Uri regulatory asset was fully recovered in July 2022 through OG&E's receipt of securitization funds from the ODFA, as further discussed in Note 14. In 2021, the APSC allowed OG&E to create a regulatory asset for the Arkansas portion of all deferred costs and, as ordered in January 2023, to amortize the regulatory asset balance over 10 years using a weighted average cost of capital as a carrying charge, as further discussed in Note 14.

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 discussed in Note 14, the OCC recently approved recovery of the over/under-recovery balance of the Pension tracker over 15 years, which is a change from the previous five-year recovery period.

As approved by the OCC, 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, and these costs are being recovered over 25 years.

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 has been 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 11.

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.

In response to the COVID-19 pandemic, the OCC and APSC issued orders allowing OG&E to defer certain expenses related to its COVID-19 response, such as incremental expenses that were related to the suspension of or delay in disconnection of service and additional expenses associated with ensuring the continuity of electric utility service. As discussed in Note 14, the OCC approved recovery of these costs over five years in OG&E's most recent Oklahoma general rate review.

OG&E deferred to a regulatory asset the Oklahoma jurisdictional portion of costs, including non-fuel operation and maintenance expenses, depreciation, taxes other than income taxes and a return on capital, for its investment in the Frontier plant. The OCC approved recovery of these costs within base rates through the Oklahoma general rate review order received in September 2022.

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, primarily represents the reduction in accumulated deferred income taxes that resulted from the reduction in the federal income tax rate as part of the Tax Cuts and Jobs Act of 2017 as well as other state tax rate changes, partially offset by income taxes recoverable from customers primarily related to the equity component of the allowance for funds used during construction. These net 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 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 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 Registrants' financial statements. However, the Registrants believe they have taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Registrants that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas where the most significant judgment is exercised include the determination of pension and postretirement plan assumptions, income taxes, contingency reserves, asset retirement obligations, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable.

Cash and Cash Equivalents

For purposes of the financial statements, the Registrants consider 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

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, oil and alternative fuel. 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 $108.8 million and $40.6 million at December 31, 2022 and 2021, 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 statements of income as Other Expense. Repair and replacement of minor items of property are included in the statements of income as Other Operation and Maintenance Expense.

The following tables 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 statements of income.


December 31, 2022 (In millions)	Percentage Ownership			Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
McClain Plant (A)		77	%	$	261.9	$	119.4	$	142.5
Redbud Plant (A)(B)		51	%	$	542.1	$	225.2	$	316.9

(A)

Construction work in progress was $0.7 million and $1.5 million for the McClain and Redbud Plants, respectively.

(B)

This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $78.2 million.


December 31, 2021 (In millions)	Percentage Ownership			Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
McClain Plant (A)		77	%	$	258.5	$	109.0	$	149.5
Redbud Plant (A)(B)		51	%	$	538.2	$	203.4	$	334.8

(A)

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

(B)

This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $72.8 million.

The following tables present the Registrants' major classes of property, plant and equipment and related accumulated depreciation.


December 31, 2022 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
OG&E:
Distribution assets	$	5,781.3	$	1,527.1	$	4,254.2
Electric generation assets (A)		5,188.1		1,982.7		3,205.4
Transmission assets (B)		3,180.5		667.9		2,512.6
Intangible plant		384.0		193.6		190.4
Other property and equipment		591.3		213.2		378.1
OG&E property, plant and equipment		15,125.2		4,584.5		10,540.7
Non-OG&E property, plant and equipment		6.1		—		6.1
Total OGE Energy property, plant and equipment	$	15,131.3	$	4,584.5	$	10,546.8

(A)

This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $78.3 million.

(B)

This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $1.0 million.


December 31, 2021 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
OG&E:
Distribution assets	$	5,225.8	$	1,477.5	$	3,748.3
Electric generation assets (A)		5,037.9		1,839.0		3,198.9
Transmission assets (B)		3,038.2		627.0		2,411.2
Intangible plant		301.1		171.7		129.4
Other property and equipment		542.7		203.7		339.0
OG&E property, plant and equipment		14,145.7		4,318.9		9,826.8
Non-OG&E property, plant and equipment		6.1		—		6.1
Total OGE Energy property, plant and equipment	$	14,151.8	$	4,318.9	$	9,832.9

(A)

This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $72.8 million.

(B)

This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.9 million.

OG&E's unamortized computer software costs, included in intangible plant above, were $143.2 million and $103.7 million at December 31, 2022 and 2021, respectively. OG&E's amortization expense for computer software costs was $23.5 million, $18.1 million and $14.9 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Depreciation and Amortization

The provision for depreciation, which was 2.7 percent and 2.6 percent of the average depreciable utility plant for 2022 and 2021, respectively, 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 2023, 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, 2022, 43.1 percent will be amortized over 6.7 years, 56.3 percent will be amortized over 13.8 years and the remaining 0.6 percent will be amortized over 22.4 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 is being amortized over a 37 to 59-year period.

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. OG&E has recorded asset retirement obligations that are being accreted over their respective lives ranging from five to 68 years. Asset retirement obligations are included in Other Deferred Credits in the Registrants' balance sheets.

The following table presents changes to OG&E's asset retirement obligations during the years ended December 31, 2022 and 2021.


(In millions)	2022			2021
Balance at January 1	$	80.2		$	79.6
Accretion expense		0.6			0.6
Liabilities settled		(2.5	)		—
Balance at December 31	$	78.3		$	80.2

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. OG&E had $24.2 million and $25.8 million in accrued environmental liabilities at December 31, 2022 and 2021, respectively, which are included in OG&E'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 statements of income and as an increase to Construction Work in Progress in the 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 4.8 percent, 7.4 percent and 7.3 percent for the years ended December 31, 2022, 2021 and 2020, 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 measures its customers' metered usage 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 balance sheets and in Revenues from Contracts with Customers in the 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 Fuel, Purchased Power and Direct Transmission Expense in the statements of income. OG&E's 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

Other Revenues in the 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 generally recoverable from 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 Registrants evaluate 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 Registrants recognize a right-of-use asset and a lease liability in their balance sheets. The Registrants recognize and measure a lease liability when they conclude the contract contains an identified asset that the Registrants control 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 Registrants utilize 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 Registrants start with a current pricing report for their senior unsecured notes, which indicates rates for periods reflective of the lease term, and adjust for the effects of collateral to arrive at the secured incremental borrowing rate. As permitted by ASC 842, the Registrants made an accounting policy election to not apply the balance sheet recognition requirements to short-term leases and to not separate lease components from non-lease components when recognizing and measuring lease liabilities. For income statement purposes, the Registrants record operating lease expense on a straight-line basis.

Income Taxes

OGE Energy files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. OG&E is a part of the consolidated tax return of OGE Energy. Income taxes are generally allocated to each company in the affiliated group, including OG&E, based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric company property have been deferred and will be amortized to income over the life of the related property. The Registrants use 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 Registrants recognize interest related to unrecognized tax benefits in Interest Expense and recognize penalties in Other Expense in the statements of income. Deferred tax assets are evaluated for future realization and reduced by a valuation allowance to the extent the Registrants believe they will not be realized.

Accrued Vacation

The Registrants accrue 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.

Related Party Transactions

OGE Energy charges operating costs to OG&E based on several factors, and operating costs directly related to OG&E 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. OGE Energy adopted this method as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.

OGE Energy charged operating costs to OG&E of $135.5 million, $139.3 million and $140.6 million during the years ended December 31, 2022, 2021 and 2020, respectively. In 2022, no dividends were declared from OG&E to OGE Energy. In 2021 and 2020, OG&E declared dividends to OGE Energy of $265.0 million and $325.0 million, respectively.

Accumulated Other Comprehensive Income (Loss)

The following table presents changes in the components of accumulated other comprehensive income (loss) attributable to OGE Energy during 2022 and 2021. All amounts below are presented net of tax.


	Pension Plan and Restoration of Retirement Income Plan						Postretirement Benefit Plans
(In millions)	Net Gain (Loss)			Prior Service Cost (Credit)			Net Gain (Loss)			Prior Service Cost (Credit)			Other Comprehensive Gain (Loss) from Unconsolidated Affiliates			Total
Balance at December 31, 2020	$	(33.9	)	$	(0.2	)	$	1.7		$	1.6		$	(1.3	)	$	(32.1	)
Other comprehensive income (loss) before reclassifications		1.4			(1.1	)		(0.7	)		—			1.3			0.9
Amounts reclassified from accumulated other comprehensive income (loss)		1.6			0.1			0.1			(1.4	)		—			0.4
Settlement cost		6.0			—			—			—			—			6.0
Net current period other comprehensive income (loss)		9.0			(1.0	)		(0.6	)		(1.4	)		1.3			7.3
Balance at December 31, 2021		(24.9	)		(1.2	)		1.1			0.2			—			(24.8	)
Other comprehensive income (loss) before reclassifications		(7.6	)		—			5.5			—			—			(2.1	)
Amounts reclassified from accumulated other comprehensive income (loss)		1.4			0.2			—			(0.2	)		—			1.4
Settlement cost		13.6			—			—			—			—			13.6
Net current period other comprehensive income (loss)		7.4			0.2			5.5			(0.2	)		—			12.9
Balance at December 31, 2022	$	(17.5	)	$	(1.0	)	$	6.6		$	—		$	—		$	(11.9	)

The following table presents significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the years ended December 31, 2022 and 2021.


Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)						Affected Line Item in OGE Energy's Statements of Income
	Year Ended December 31,
(In millions)	2022			2021
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses	$	(1.6	)	$	(2.5	)	(A)
Prior service cost		(0.3	)		(0.1	)	(A)
Settlement cost		(17.9	)		(8.7	)	(A)
		(19.8	)		(11.3	)	Income Before Taxes
		(4.6	)		(3.6	)	Income Tax Expense
	$	(15.2	)	$	(7.7	)	Net Income

Amortization of postretirement benefit plans items:
Prior service credit	$	0.3		$	1.8		(A)
Actuarial losses		—			(0.1	)	(A)
		0.3			1.7		Income Before Taxes
		0.1			0.4		Income Tax Expense
	$	0.2		$	1.3		Net Income

Total reclassifications for the period, net of tax	$	(15.0	)	$	(6.4	)	Net Income

(A)

These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).

Investment in Unconsolidated Affiliates and Related Party Transactions (Enable)

On December 2, 2021, Energy Transfer completed its acquisition of Enable, and all of the 110,982,805 common units of Enable owned by OGE Energy were exchanged for 95,389,721 common units of Energy Transfer. As part of the transaction, Energy Transfer also acquired the general partner interests of Enable from OGE Energy and CenterPoint for cash consideration. OGE Energy accounted for its investment in Enable as an equity method investment until the merger with Energy Transfer closed on December 2, 2021. As a result of the transaction, OGE Energy recorded a pre-tax gain of $344.4 million, which contemplates the December 2, 2021 fair value of the Energy Transfer securities, the December 2, 2021 balance of OGE Energy's equity method investment in Enable, the $35.0 million cash payment received as part of the transaction ($5.0 million from Energy Transfer and $30.0 million from CenterPoint), the accumulated other comprehensive loss impact of OGE Energy's share of Enable's interest rate derivative losses and OGE Energy's transaction costs of $8.6 million. Further discussion of the transaction can be found in OGE Energy's 2021 Form 10-K.

Under the equity method, the investment was adjusted each period for contributions made, distributions received and OGE Energy's share of the investee's comprehensive income as adjusted for basis differences.

OGE Energy considered distributions received from Enable which did not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and were classified as operating activities in the statements of cash flows. OGE Energy considered distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and were classified as investing activities in the statements of cash flows.

In this Form 10-K, Enable activity is included for the relevant portion of OGE Energy's 2021 information presented through December 2, 2021. The below information is provided for prior year context.

The following tables present summarized unaudited financial information for 100 percent of Enable as of December 2, 2021 and for the period of January 1, 2021 through December 2, 2021 and the year ended December 31, 2020.


Balance Sheet	December 2, 2021
(In millions)
Current assets	$	594
Non-current assets	$	11,227
Current liabilities	$	1,254
Non-current liabilities	$	3,281


	Period of
Income Statement	January 1, 2021 through December 2, 2021		Year Ended December 31, 2020
(In millions)
Total revenues	$	3,466	$	2,463
Cost of natural gas and NGLs (excluding depreciation and amortization)	$	1,959	$	965
Operating income	$	634	$	465
Net income	$	461	$	52

The following table presents a reconciliation of OGE Energy's equity in earnings (losses) of unconsolidated affiliates for the period of January 1, 2021 through December 2, 2021 and the year ended December 31, 2020.


	Period of
(In millions)	January 1, 2021 through December 2, 2021			Year Ended December 31, 2020
Enable net income	$	461.0		$	52.0
Differences due to timing of OGE Energy and Enable accounting close		9.0			—
Enable net income used to calculate OGE Energy's equity in earnings	$	470.0		$	52.0
OGE Energy's percent ownership at period end		25.5	%		25.5	%
OGE Energy's portion of Enable net income	$	119.8		$	13.2
Amortization of basis difference and dilution recognition (A)		50.0			98.8
Impairment of OGE Energy's equity method investment in Enable (B)		—			(780.0	)
Equity in earnings (losses) of unconsolidated affiliates (C)	$	169.8		$	(668.0	)

(A)

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

(B)

During the year ended December 31, 2020, OGE Energy recorded a $780.0 million impairment on its investment in Enable as, effective March 31, 2020, OGE estimated the fair value of its investment in Enable was below the book value and concluded the decline in value was not temporary.

(C)

For the year ended December 31, 2020, Enable recorded a $225.0 million impairment on an equity method investment, which ran through OGE Energy's portion of Enable net income and was offset by basis differences that flow through the amortization of basis difference and dilution recognition line item above.

Distributions received from Enable were $73.4 million and $91.7 million during the years ended December 31, 2021 and 2020, respectively.

Related Party Transactions - OGE Energy and Enable

Prior to December 2, 2021, OGE Energy charged operating costs to Enable based on several factors, and operating costs directly related to Enable were assigned as such.

Further, OGE Energy and Enable were parties to several agreements whereby OGE Energy provided specified support services to Enable, such as certain information technology, payroll and benefits administration. Under these agreements, OGE Energy charged operating costs to Enable of $0.3 million and $0.4 million for the period of January 1, 2021 through December 2, 2021 and the year ended December 31, 2020, respectively.

OGE Energy also provided retirement benefits and retiree health care benefits to employees previously seconded to Enable. OGE Energy billed Enable for reimbursement of $12.2 million and $17.3 million in 2021 and 2020, respectively, under the former seconding agreement for employment costs. As of a result of the merger between Enable and Energy Transfer, the seconding agreement was terminated, and those employees are no longer employed by OGE Energy. If lump sum payments were made to those employees previously seconded to Enable, OGE Energy would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at OGE Energy by $5.1 million. Settlement and curtailment charges associated with the employees previously seconded to Enable are not reimbursable to OGE Energy.

OGE Energy had accounts receivable from Enable for amounts billed for support services, including the cost of seconded employees, of $0.3 million as of December 31, 2021, which is included in Accounts Receivable in OGE Energy's balance sheets.

Related Party Transactions - OG&E and Enable

Enable provided gas transportation services to OG&E pursuant to agreements that granted Enable the responsibility of delivering natural gas to OG&E's generating facilities and performing an imbalance service. Upon the closing of the merger between Enable and Energy Transfer, these contracts were assumed by Energy Transfer. The following table presents summarized related party transactions between OG&E and Enable during the period of January 1, 2021 through December 2, 2021 and the year ended December 31, 2020.


	Period of
(In millions)	January 1, 2021 through December 2, 2021			Year Ended December 31, 2020
Operating revenues:
Electricity to power electric compression assets	$	13.3		$	15.1
Fuel, purchased power and direct transmission expense:
Natural gas transportation services	$	32.7		$	32.8
Natural gas purchases (sales)	$	(33.5	)	$	2.7

Investment in Equity Securities of Energy Transfer

For the period of December 2, 2021 through September 30, 2022, OGE Energy accounted for its investment in Energy Transfer's equity securities as an equity investment with a readily determinable fair value under ASC 321, "Investments – Equity Securities." As of the end of September 2022, OGE Energy had sold all of its 95.4 million Energy Transfer limited partner units, resulting in pre-tax net proceeds of $1,067.2 million. Prior to exiting its Energy Transfer investment, OGE Energy presented the Energy Transfer equity securities at fair value in its balance sheet. OGE Energy presents realized gains and losses of the equity securities, as well as dividend income from the investment, within the Other Income (Expense) section in its statement of income, as appropriate. During the year ended December 31, 2022, OGE Energy recognized a gain of $282.1 million related to its investment in Energy Transfer's equity securities. Due to OGE Energy's sale of all Energy Transfer limited partner units, at December 31, 2022, there is no unrecognized gain or loss related to the investment. For the period between December 2, 2021 and December 31, 2021, OGE Energy had an unrealized loss of $8.6 million related to its investment in Energy Transfer's equity securities. During the year ended December 31, 2022, OGE Energy received distributions of $34.0 million from Energy Transfer, which are presented within Other Income in OGE Energy's 2022 consolidated income statement.

Accounting Pronouncements

In November 2021, the Financial Accounting Standards Board issued ASU 2021-10, "Government Assistance (Topic 832) Disclosures by Business Entities about Government Assistance." This standard requires additional annual disclosures when a business receives government assistance and uses a grant or contribution accounting model by analogy to other accounting guidance such as the grant model under International Accounting Standards 20, "Accounting for Government Grants and Disclosures of Government Assistance" and GAAP ASC 958-605, "Not-for-Profit Entities - Revenue Recognition." The standard was effective January 1, 2022, and the Registrants adopted this standard prospectively. As further discussed in Note 14, the ODFA issued securitization bonds in July 2022, and, in connection with this securitization transaction, OG&E received approximately $750 million from the ODFA to fund the extreme fuel and purchased power costs incurred by OG&E during Winter Storm Uri. The Registrants accounted for this transaction by analogy to the grant model under International Accounting Standards 20, as the Registrants believe there is no specific GAAP guidance directly applicable to the Registrants' facts and circumstances. The Registrants recorded the receipt of proceeds from the ODFA and removal of the Oklahoma Winter Storm Uri regulatory asset by debiting Cash and Cash Equivalents and crediting Regulatory Assets in their 2022 condensed balance sheets. Further, this transaction is reflected within Operating Activities in the Registrants' 2022 condensed statements of cash flows.

In September 2022, the Financial Accounting Standards Board issued ASU 2022-04, "Liabilities - Supplier Finance Programs (Subtopic 405-50)." The amendments in this update require that a buyer in a supplier finance program disclose in each annual reporting period: (i) the key terms of the program, including a description of the payment terms and assets pledged as security or other forms of guarantees provided for the committed payment to the finance provider and (2) the amount outstanding that remains unpaid by the buyer as of year-end, a description of where those obligations are presented in the balance sheet and a rollforward of those obligations during the annual period. The standard is effective January 1, 2023, except for the amendment on rollforward information, which is effective January 1, 2024. Early adoption is permitted. The Registrants are currently evaluating the impact of adopting this standard on their financial statements.

The Registrants believe that other recently adopted and recently issued accounting standards that are not yet effective do not appear to have a material impact on the Registrants' financial position, results of operations or cash flows upon adoption.

Revenue Recognition

The following table presents OG&E's revenues from contracts with customers disaggregated by customer classification. OG&E's operating revenues disaggregated by customer classification can be found in "OG&E (Electric Company) Results of Operations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."


	Year Ended December 31,
(In millions)	2022			2021		2020
Residential	$	1,272.6		$	1,309.1	$	842.7
Commercial		803.5			749.2		465.6
Industrial		317.2			323.0		192.6
Oilfield		304.2			312.8		169.2
Public authorities and street light		291.6			284.4		172.3
System sales revenues		2,989.1			2,978.5		1,842.4
Provision for rate refund		(1.2	)		—		3.8
Integrated market		163.8			468.9		49.6
Transmission		131.7			140.2		143.3
Other		20.8			1.1		30.7
Revenues from contracts with customers	$	3,304.2		$	3,588.7	$	2,069.8

Leases

Based on their evaluation of all contracts under ASC 842, as described in Note 1, the Registrants concluded they have operating lease obligations as described below.

OG&E Railcar Lease Agreement

OG&E holds 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 recoverable 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.

Effective October 1, 2022, OG&E entered into an additional railcar lease agreement for 135 rotary gondola railcars to transport coal with a term of October 1, 2022 to December 31, 2025.

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.

Financial Statement Information and Maturity Analysis of Lease Liabilities

The following tables present amounts recognized for operating leases in the Registrants' income statements, cash flow statements and balance sheets and supplemental information related to those amounts recognized.


	OGE Energy						OG&E
	Year Ended December 31,						Year Ended December 31,
(In millions)	2022		2021		2020		2022		2021		2020
Operating lease cost	$	5.9	$	6.3	$	6.4	$	5.9	$	5.7	$	5.5
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	5.3	$	6.3	$	6.4	$	5.3	$	5.7	$	5.5
Right-of-use assets obtained in exchange for new operating lease liabilities	$	1.5	$	—	$	1.4	$	1.5	$	—	$	1.4


	OGE Energy						OG&E
(Dollars in millions)	December 31, 2022			December 31, 2021			December 31, 2022			December 31, 2021
Right-of-use assets at period end (A)	$	30.2		$	33.0		$	30.2		$	33.0
Operating lease liabilities at period end (B)	$	34.8		$	37.6		$	34.8		$	37.6
Operating lease weighted-average remaining lease term (in years)		11.6			12.2			11.6			12.2
Operating lease weighted-average discount rate		4.0	%		3.9	%		4.0	%		3.9	%

(A)

Included in Property, Plant and Equipment in the Registrants' balance sheets.

(B)

Included in Other Deferred Credits and Other Liabilities in the Registrants' balance sheets.

The following table presents a maturity analysis of the Registrants' operating lease liabilities.


Future minimum operating lease payments as of December 31:	OGE Energy		OG&E
(In millions)
2023	$	5.7	$	5.7
2024		3.7		3.7
2025		3.5		3.5
2026		3.0		3.0
2027		3.0		3.0
Thereafter		25.7		25.7
Total future minimum lease payments		44.6		44.6
Less: Imputed interest		9.8		9.8
Present value of net minimum lease payments	$	34.8	$	34.8

Fair Value Measurements

The classification of the Registrants' 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).

OG&E had no financial instruments measured at fair value on a recurring basis at December 31, 2022 and 2021. The following table presents OGE Energy's previous financial instrument measured at fair value on a recurring basis and the carrying amount and fair value of the Registrants' financial instruments at December 31, 2022 and 2021, as well as the classification level within the fair value hierarchy. As of the end of September 2022, OGE Energy had sold all of the Energy Transfer limited partner units it received as a result of the merger transaction between Enable and Energy Transfer in December 2021.


	2022				2021
December 31 (In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Classification
Financial instrument measured at fair value on a recurring basis:
OGE Energy investment in Energy Transfer's equity securities	$	—	$	—	$	785.1	$	785.1	Level 1
Financial instruments for which fair value is only disclosed:
Long-term Debt (including Long-term Debt due within one year):
OGE Energy Senior Notes	$	499.9	$	491.2	$	499.9	$	497.8	Level 2
OGE Energy Term Loan	$	49.8	$	50.0	$	—	$	—	Level 2
OG&E Senior Notes	$	3,854.2	$	3,477.1	$	3,851.8	$	4,460.2	Level 2
OG&E Industrial Authority Bonds	$	135.4	$	135.4	$	135.4	$	135.4	Level 2
Tinker Debt	$	9.3	$	7.3	$	9.3	$	10.0	Level 3

Stock-Based Compensation

In 2022, OGE Energy adopted, and its shareholders approved, the 2022 Stock Incentive Plan. The 2022 Stock Incentive Plan replaced the 2013 Stock Incentive Plan, and no further awards will be granted under the 2013 Stock Incentive Plan. Under the 2022 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 OGE Energy and its subsidiaries, including OG&E. OGE Energy has authorized the issuance of up to 8,417,755 shares under the 2022 Stock Incentive Plan.

The following table presents the Registrants' pre-tax compensation expense and related income tax benefit for the years ended December 31, 2022, 2021 and 2020 related to performance units and restricted stock units for the Registrants' employees.


	OGE Energy						OG&E
Year Ended December 31 (In millions)	2022		2021		2020		2022		2021		2020
Performance units:
Total shareholder return	$	7.2	$	7.5	$	7.9	$	2.2	$	1.8	$	2.3
Earnings per share (A)		—		—		1.0		—		—		0.3
Total performance units		7.2		7.5		8.9		2.2		1.8		2.6
Restricted stock units		2.5		2.3		0.9		0.7		0.4		0.4
Total compensation expense	$	9.7	$	9.8	$	9.8	$	2.9	$	2.2	$	3.0
Income tax benefit	$	2.3	$	2.5	$	2.5	$	0.7	$	0.6	$	0.8

(A)

In 2019, the Compensation Committee of OGE Energy's Board of Directors voted to grant restricted stock units in lieu of performance units based on earnings per share. The final grants of performance units based on earnings per share vested as of December 31, 2020 and were paid out in March 2021.

During the year ended December 31, 2020, OGE Energy purchased 405,000 shares of its common stock, and 247,252 of these shares were used during 2020 to satisfy payouts of earned performance units and restricted stock unit grants to the Registrants' employees pursuant to OGE Energy's 2013 Stock Incentive Plan. During the year ended December 31, 2020, there was also an immaterial number of shares of new common stock issued pursuant to OGE Energy's 2013 Stock Incentive Plan to satisfy restricted stock unit grants to employees.

During the year ended December 31, 2021, 154,523 shares of treasury stock were used to satisfy payouts of earned performance units and restricted stock unit grants to the Registrants' employees pursuant to OGE Energy's 2013 Stock Incentive Plan.

During the year ended December 31, 2022, OGE Energy issued 27,278 shares of new common stock pursuant to OGE Energy's 2013 Stock Incentive Plan and issued an immaterial amount of treasury stock to satisfy payouts of restricted stock unit grants to the Registrants' employees.

Performance Units

Under the 2013 Stock Incentive Plan, OGE Energy has issued performance units which represent the value of one share of OGE Energy's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the 2013 Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with OGE Energy 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 Registrants estimate 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 OGE Energy'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 OGE Energy's total shareholder return ranking relative to a peer group of companies. These performance units are classified as equity in the 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 OGE Energy'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.

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 OGE Energy's common stock for the past three years and is 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 OGE Energy's performance units based on total shareholder return. The following table presents 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.


	OGE Energy									OG&E
	2022			2021			2020			2022			2021			2020
Number of units granted		216,437			249,909			201,552			60,923			68,720			67,975
Fair value of units granted	$	41.10		$	38.14		$	38.03		$	41.10		$	38.14		$	38.03
Expected dividend yield		4.8	%		4.7	%		3.5	%		4.8	%		4.7	%		3.5	%
Expected price volatility		29.0	%		29.0	%		15.0	%		29.0	%		29.0	%		15.0	%
Risk-free interest rate		1.71	%		0.22	%		1.17	%		1.71	%		0.22	%		1.17	%
Expected life of units (in years)		2.85			2.84			2.85			2.85			2.85			2.85

Restricted Stock Units

Under the 2013 Stock Incentive Plan, OGE Energy 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. 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 OGE Energy 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 OGE Energy'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, OGE Energy 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 OGE Energy's restricted stock units. The following table presents the number of restricted stock units granted and the grant date fair value.


	OGE Energy						OG&E
	2022		2021		2020		2022		2021		2020
Restricted stock units granted		116,539		89,197		67,193		32,804		22,911		22,665
Fair value of restricted stock units granted	$	35.72	$	31.11	$	43.69	$	35.72	$	30.91	$	43.69

Performance Units and Restricted Stock Units Activity

The following tables present a summary of the activity for the Registrants' performance units and restricted stock units for the year ended December 31, 2022. The table designated as "OGE Energy" below includes the OG&E standalone activity, as OGE Energy represents consolidated results.


OGE Energy	Performance Units						Restricted Stock Units
(Dollars in millions)	Number of Units				Aggregate Intrinsic Value		Number of Shares			Aggregate Intrinsic Value
Units/shares outstanding at 12/31/21		581,252						133,671
Granted		216,437		(A)				116,539
Converted		(172,748	)	(B)	$	—	N/A
Vested	N/A							(47,995	)	$	1.9
Forfeited		(16,566	)					(12,732	)
Units/shares outstanding at 12/31/22		608,375			$	34.1		189,483		$	7.5
Units/shares fully vested at 12/31/22		161,690		(C)	$	3.7	N/A			N/A


OG&E	Performance Units						Restricted Stock Units
(Dollars in millions)	Number of Units				Aggregate Intrinsic Value		Number of Shares				Aggregate Intrinsic Value
Units/shares outstanding at 12/31/21		161,310						35,613
Granted		60,923		(A)				32,804
Converted		(48,195	)	(B)	$	—	N/A
Vested	N/A							(11,807	)		$	0.5
Forfeited		(4,217	)					(4,342	)
Employee migration		802		(D)				491		(D)
Units/shares outstanding at 12/31/22		170,623			$	9.6		52,759			$	2.1
Units/shares fully vested at 12/31/22		44,550		(C)	$	1.0	N/A				N/A

(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 were canceled at December 31, 2021 due to the performance metric threshold not being met.

(C)

These amounts represent performance units that vested at December 31, 2022. Actual expected amounts to be paid out in 2023 will differ based on the percentage at which the performance metric was met and are dependent upon Compensation Committee approval.

(D)

Due to certain employees transferring between OG&E and OGE Energy.

The following tables present a summary of the activity for the Registrants' non-vested performance units and restricted stock units for the year ended December 31, 2022. The table designated as "OGE Energy" below includes the OG&E standalone activity, as OGE Energy represents consolidated results.


OGE Energy	Performance Units						Restricted Stock Units
	Number of Units				Weighted-Average Grant Date Fair Value		Number of Shares			Weighted-Average Grant Date Fair Value
Units/shares non-vested at 12/31/21		408,504			$	38.05		133,671		$	35.64
Granted		216,437		(A)	$	41.10		116,539		$	35.72
Vested		(161,690	)		$	38.04		(47,995	)	$	39.63
Forfeited		(16,566	)		$	39.45		(12,732	)	$	35.95
Units/shares non-vested at 12/31/22		446,685			$	39.53		189,483		$	33.75


OG&E	Performance Units						Restricted Stock Units
	Number of Units				Weighted-Average Grant Date Fair Value		Number of Shares				Weighted-Average Grant Date Fair Value
Units/shares non-vested at 12/31/21		113,115			$	38.10		35,613			$	35.52
Granted		60,923		(A)	$	41.10		32,804			$	35.72
Vested		(44,550	)		$	38.03		(11,807	)		$	39.71
Forfeited		(4,217	)		$	39.96		(4,342	)		$	35.93
Employee migration		802		(B)	$	42.18		491		(B)	$	34.83
Units/shares non-vested at 12/31/22		126,073			$	39.53		52,759			$	33.78

(A)

(B)

Due to certain employees transferring between OG&E and OGE Energy.

Fair Value of Vested Performance Units and Restricted Stock Units

The following table presents a summary of the Registrants' fair value for vested performance units and restricted stock units.


	OGE Energy						OG&E
Year Ended December 31 (In millions)	2022		2021		2020		2022		2021		2020
Performance units:
Total shareholder return	$	6.2	$	8.1	$	8.7	$	1.7	$	2.3	$	2.8
Earnings per share	$	—	$	—	$	2.5	$	—	$	—	$	0.8
Restricted stock units	$	2.1	$	2.2	$	0.1	$	0.5	$	0.5	$	0.1

Unrecognized Compensation Cost

The following table presents a summary of the Registrants' unrecognized compensation cost for non-vested performance units and restricted stock units and the weighted-average periods over which the compensation cost is expected to be recognized.


	OGE Energy				OG&E
December 31, 2022	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)		Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance units	$	7.7		1.66	$	2.2		1.65
Restricted stock units		3.5		1.76		0.7		1.77
Total unrecognized compensation cost	$	11.2			$	2.9

Income Taxes

Income Tax Expense (Benefit)

The following table presents the components of income tax expense (benefit).


	OGE Energy									OG&E
Year Ended December 31 (In millions)	2022			2021			2020			2022			2021			2020
Provision (benefit) for current income taxes:
Federal	$	250.8		$	16.4		$	8.4		$	(141.2	)	$	(9.0	)	$	(3.8	)
State		28.8			1.7			0.5			(0.9	)		9.0			(0.6	)
Total provision (benefit) for current income taxes		279.6			18.1			8.9			(142.1	)		—			(4.4	)
Provision (benefit) for deferred income taxes, net:
Federal		(110.8	)		133.1			(105.2	)		219.9			58.3			45.7
State		(45.2	)		(10.0	)		(31.1	)		(1.4	)		(16.5	)		(6.6	)
Total provision (benefit) for deferred income taxes, net		(156.0	)		123.1			(136.3	)		218.5			41.8			39.1
Total income tax expense (benefit)	$	123.6		$	141.2		$	(127.4	)	$	76.4		$	41.8		$	34.7

OGE Energy files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. OG&E is a part of the consolidated income tax return of OGE Energy. With few exceptions, the Registrants are no longer subject to U.S. federal tax or state and local examinations by tax authorities for years prior to 2018. Income taxes are generally allocated to each company in the affiliated group, including OG&E, based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric company property have been deferred and will be amortized to income over the life of the related property. Additionally, OG&E earned federal tax credits associated with production from its wind facilities through January 2022. 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 table presents a reconciliation of the statutory tax rates to the effective income tax rate.


	OGE Energy									OG&E
Year Ended December 31	2022			2021			2020			2022			2021			2020
Statutory federal tax rate		21.0	%		21.0	%		21.0	%		21.0	%		21.0	%		21.0	%
State income taxes, net of federal income tax benefit		(1.0	)		0.9			(1.4	)		(0.4	)		(1.4	)		(1.6	)
Stock-based compensation		—			0.1			(0.3	)		—			—			—
Executive compensation limitation		0.1			0.1			0.2			—			—			—
Amortization of net unfunded deferred taxes		(3.2	)		(2.1	)		(4.4	)		(5.0	)		(4.6	)		(4.8	)
Federal renewable energy credit (A)		—			(2.0	)		(5.0	)		—			(4.4	)		(5.4	)
Remeasurement of state deferred taxes due to Energy Transfer merger (B)		—			(1.1	)		—			—			—			—
Remeasurement of state deferred tax liabilities		(0.6	)		(0.6	)		0.9			—			—			—
401(k) dividends		(0.2	)		(0.2	)		(0.4	)		—			—			—
Impairment of OGE Energy's investment in Enable (C)		—			—			31.6			—			—			—
Other		(0.4	)		—			0.1			(0.8	)		(0.2	)		0.1
Effective income tax rate		15.7	%		16.1	%		42.3	%		14.8	%		10.4	%		9.3	%

(A)

Represents credits primarily associated with the production from OG&E's wind farms.

(B)

In connection with the Enable and Energy Transfer merger, the state income tax rates were expected to decrease, as Energy Transfer operates in significantly more states with generally lower tax rates than the historic Enable operating area.

(C)

As discussed in Note 1, OGE Energy recorded a $780.0 million impairment on its investment in Enable in March 2020, which resulted in a tax benefit being recorded that caused a significant variance to the effective tax rate. This variance has been presented in the table as a single line item in order to facilitate comparability of other components of the effective tax rate.

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 following table presents the components of Deferred Income Taxes at December 31, 2022 and 2021.


	OGE Energy						OG&E
December 31 (In millions)	2022			2021			2022			2021
Deferred income tax liabilities, net:
Accelerated depreciation and other property related differences	$	1,714.5		$	1,677.3		$	1,714.5		$	1,677.3
Investment in Energy Transfer's equity securities		—			363.5			—			—
Regulatory assets		54.8			52.1			54.7			52.1
Pension Plan		18.0			10.7			35.4			32.0
Other		(5.1	)		7.4			(5.8	)		(4.7	)
Derivative instruments		2.4			2.2			—			—
Bond redemption-unamortized costs		1.6			1.8			1.6			1.8
Income taxes recoverable from customers, net		(216.7	)		(225.8	)		(216.7	)		(225.8	)
State tax credits		(221.2	)		(221.2	)		(208.5	)		(205.9	)
Federal tax credits		—			(208.4	)		—			(209.8	)
Regulatory liabilities		(60.8	)		(72.0	)		(60.8	)		(72.0	)
Asset retirement obligations		(18.8	)		(19.4	)		(18.8	)		(19.4	)
Postretirement medical and life insurance benefits		(19.2	)		(19.2	)		(12.7	)		(13.0	)
Accrued liabilities		(11.2	)		(9.5	)		(7.3	)		(7.3	)
Deferred federal investment tax credits		(2.9	)		(3.1	)		(2.9	)		(3.1	)
Net operating losses		—			(1.0	)		—			—
Accrued vacation		(1.4	)		(1.5	)		(1.1	)		(1.2	)
Uncollectible accounts		(0.5	)		(0.6	)		(0.5	)		(0.6	)
Total deferred income tax liabilities, net	$	1,233.5		$	1,333.3		$	1,271.1		$	1,000.4

As of December 31, 2022, the Registrants have 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.

The following table presents a reconciliation of the Registrants' total gross unrecognized tax benefits as of the years ended December 31, 2022, 2021 and 2020.


(In millions)	2022			2021			2020
Balance at January 1	$	22.4		$	21.9		$	20.7
Tax positions related to current year:
Additions		—			1.7			1.2
Reductions		(1.7	)		(1.2	)		—
Balance at December 31	$	20.7		$	22.4		$	21.9

As of December 31, 2022, 2021 and 2020, there were $16.4 million, $18.1 million and $17.6 million, respectively, of unrecognized tax benefits that, if recognized, would affect the annual effective tax rate.

Where applicable, the Registrants classify income tax-related interest and penalties as interest expense and other expense, respectively. During the years ended December 31, 2022, 2021 and 2020, there were no income tax-related interest or penalties recorded with regard to uncertain tax positions.

The Registrants recognize tax benefits from an uncertain tax position only if it is more likely than not the tax position will be sustained on examination by taxing authorities based on the technical merits of the position. The tax benefits in the financial statements from such positions are then measured based on the largest benefit that has a greater than 50 percent likelihood of being realized on settlement. In 2022, the reserve for certain federal research and development credits of $1.7 million, which was recorded in 2021, was reversed.

The Registrants sustained federal and state tax operating losses through 2012 caused primarily by bonus depreciation and other book versus tax temporary differences. Federal and state net operating losses generated during those years have been fully utilized, and the related various tax credits are being carried as deferred tax assets and will be utilized in future periods. Under current law, the Registrants anticipate future taxable income will be sufficient to utilize all credits before they begin to expire after 2022. The following table presents a summary of these carry forwards.


	OGE Energy				OG&E
(In millions)	Carry Forward Amount		Deferred Tax Asset		Carry Forward Amount		Deferred Tax Asset		Earliest Expiration Date
State tax credits:
Oklahoma investment tax credits	$	242.8	$	191.8	$	226.7	$	179.1	N/A
Oklahoma capital investment board credits	$	12.8	$	12.8	$	12.8	$	12.8	N/A
Oklahoma zero emission tax credits	$	22.6	$	16.6	$	22.6	$	16.6	2023

N/A - not applicable

In connection with its investment in Energy Transfer during 2022, OGE Energy anticipates operating losses in various state jurisdictions. As discussed in Note 1, OGE Energy has fully disposed of its investment in Energy Transfer, and it does not expect future taxable income in these states. Therefore, as of December 31, 2022, OGE Energy has recorded a valuation allowance of $2.7 million, which eliminated the related deferred tax asset balance. OGE Energy did not record any valuation allowances as of December 31, 2021.

Common Equity

OGE Energy

Automatic Dividend Reinvestment and Stock Purchase Plan

OGE Energy issued no new shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan in 2022. Under the terms of the Automatic Dividend Reinvestment and Stock Purchase Plan, OGE Energy may, from time to time, issue new shares to satisfy purchases under the plan or have shares purchased on the open market. At December 31, 2022, there were 3,932,647 shares of unissued common stock reserved for issuance under OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan.

Earnings (Loss) Per Share

Basic earnings (loss) per share is calculated by dividing net income (loss) attributable to OGE Energy by the weighted average number of OGE Energy's common shares outstanding during the period. In the calculation of diluted earnings (loss) 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 OGE Energy consist of performance units and restricted stock units. The following table presents the calculation of basic and diluted earnings (loss) per share for OGE Energy.


(In millions except per share data)	2022		2021		2020
Net income (loss)	$	665.7	$	737.3	$	(173.7	)
Average common shares outstanding:
Basic average common shares outstanding		200.2		200.1		200.1
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)		0.6		0.2		—
Diluted average common shares outstanding		200.8		200.3		200.1
Basic earnings (loss) per average common share	$	3.33	$	3.68	$	(0.87	)
Diluted earnings (loss) per average common share	$	3.32	$	3.68	$	(0.87	)
Anti-dilutive shares excluded from earnings per share calculation		—		—		0.3

Dividend Restrictions

OGE Energy's Certificate of Incorporation places restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Before OGE Energy 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 OGE Energy's ability to pay dividends to its shareholders. OGE Energy utilizes dividends from OG&E to pay dividends to its shareholders.

On December 19, 2022, OGE Energy entered into an amendment to its revolving credit facility that increased the permitted leverage ratio (percentage of debt to total capitalization) for OGE Energy from an amount not to exceed 65 percent to an amount not to exceed 70 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 $816.9 million of OGE Energy's retained earnings from being paid out in dividends. Accordingly, approximately $2.5 billion of OGE Energy's retained earnings as of December 31, 2022 are unrestricted for the payment of dividends.

OG&E

There were no new shares of OG&E common stock issued in 2022, 2021 or 2020.

Dividend Restrictions

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 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 $579.3 million of OG&E's retained earnings from being paid out in dividends. Accordingly, approximately $2.9 billion of OG&E's retained earnings as of December 31, 2022 are unrestricted for the payment of dividends.

Long-Term Debt

A summary of the Registrants' long-term debt is included in the statements of capitalization. At December 31, 2022, the Registrants were in compliance with all of their debt agreements.

Maturities of OGE Energy's consolidated long-term debt during the next five years consist of $1.0 billion in 2023, $129.4 million in 2025 and $181.0 million in 2027. Maturities of OG&E's long-term debt during the next five years consist of $500.0 million in 2023, $79.4 million in 2025 and $181.0 million in 2027. All other long-term debt of the Registrants matures after 2027.

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

million term loan, in order to preserve general financial flexibility within the company. Advances under this agreement were used to refinance existing indebtedness and for working capital and general corporate purposes of OGE Energy. The credit agreement, under certain circumstances, may be increased to a maximum commitment limit of $135.0 million and includes a maximum leverage ratio of 0.65 to 1.0. The other covenants under this credit agreement are substantially the same as OGE Energy's existing $550.0 million revolving credit agreement. The credit agreement is scheduled to terminate on May 24, 2025. At December 31, 2022, the weighted-average interest rate for the amount drawn on the term loan under this credit agreement was 3.48 percent during the year.

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 following table presents information about these bonds, which can be tendered at the option of the holder during the next 12 months.


Series			Date Due	Amount
				(In millions)
0.11%	—	3.98%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.11%	—	3.95%	Muskogee Industrial Authority, January 1, 2025		32.4
0.11%	—	3.98%	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 balance sheets. OG&E believes that it has sufficient liquidity to meet these obligations.

10.

Short-Term Debt and Credit Facilities

The Registrants borrow on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under their revolving credit agreements. OGE Energy also borrows under term credit agreements maturing in one year or less, as necessary. As of December 31, 2022, OGE Energy had no short-term debt as compared to $486.9 million of short-term debt at December 31, 2021.

The following table presents information regarding the Registrants' revolving credit agreements at December 31, 2022.


Entity	Aggregate Commitment		Amount Outstanding (A)		Weighted-Average Interest Rate				Expiration
	(In millions)
OGE Energy (B)	$	550.0	$	—		—		(F)	December 17, 2027 (G)
OGE Energy (C)		50.0		—		—		(F)	May 24, 2025
OG&E (D)(E)		550.0		0.4		1.15	%	(F)	December 17, 2027 (G)
Total	$	1,150.0	$	0.4		1.15	%

(A)

Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2022.

(B)

This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.

(C)

See Note 9 for further information about this revolving credit facility.

(D)

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.

(E)

OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $450.0 million of OGE Energy's revolving credit amount. This agreement has a termination date of December 17, 2027. At December 31, 2022, there were $84.1 million in intercompany borrowings under this agreement.

(F)

Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

(G)

In December 2021, the Registrants entered into unsecured five-year revolving credit agreements totaling $1.1 billion. Each of the revolving credit facilities contained an option, which could be exercised up to two times, to extend the term of the respective facility for an additional year. In December 2022, the Registrants each entered into an amendment to their credit facility that extends the term of each credit facility for one year, until December 2027. Further, each credit facility amendment gives each of the Registrants the option of extending such commitments for up to two additional one-year periods.

In December 2022, the Registrants each entered into an amendment to their revolving credit facilities that replaced the LIBOR rate with the SOFR rate. The amendment to OGE Energy's credit facility also increased OGE Energy's maximum debt to capitalization ratio from 65 percent to 70 percent. OG&E's credit facility has a financial covenant requiring that OG&E maintains a maximum debt to capitalization ratio of 65 percent, as defined in such facility. The Registrants' 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 Registrants' 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 Registrants' 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 Registrants' 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 Registrants' short-term borrowings, but a reduction in the Registrants' 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 Registrants to post collateral or letters of credit.

11.

Retirement Plans and Postretirement Benefit Plans

OGE Energy sponsors defined benefit pension plans, 401(k) savings plans and other postretirement plans covering certain employees of the Registrants.

Pension Plan and Restoration of Retirement Income Plan

OGE Energy periodically makes contributions to the Pension Plan considering information such as net periodic pension expense and funded status from OGE Energy'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. OGE Energy did not make a contribution to its Pension Plan in 2022 and made a $40.0 million contribution to its Pension Plan in 2021, of which $30.0 million was attributed to OG&E in 2021. OGE Energy does not expect it will need to make any contributions to the Pension Plan in 2023. Any contribution to the Pension Plan during 2023 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. OGE Energy 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 2022, 2021 and 2020, the Registrants 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 Registrants recording pension plan settlement charges as presented in the Pension Plan net periodic benefit cost table below. The pension settlement charges did not require a cash outlay by the Registrants and did not increase total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.

OGE Energy provides a Restoration of Retirement Income Plan to those participants in OGE Energy'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 OGE Energy'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.

OG&E's employees participate in OGE Energy's Pension Plan and Restoration of Retirement Income Plan.

Obligations and Funded Status

The details of the funded status of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the balance sheets for 2022 and 2021 are included in the following tables. 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 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 statements of income in future periods. The benefit obligation for OGE Energy'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 OGE Energy'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.

OGE Energy's seconded employee contract with Enable was terminated on December 2, 2021. OGE Energy retains the obligations to the balances and accrued benefits of these former employees as of the termination of the contract.


	OGE Energy												OG&E
	Pension Plan						Restoration of Retirement Income Plan						Pension Plan						Restoration of Retirement Income Plan
December 31 (In millions)	2022			2021			2022			2021			2022			2021			2022			2021
Change in benefit obligation
Beginning obligations	$	502.9		$	654.6		$	5.9		$	7.8		$	363.2		$	484.1		$	0.5		$	3.0
Service cost		7.6			11.2			1.1			0.8			6.2			7.7			—			—
Interest cost		15.7			13.3			0.2			0.1			12.1			9.7			—			—
Plan settlements		(95.8	)		(158.6	)		(1.5	)		(4.6	)		(38.8	)		(120.4	)		—			(2.9	)
Plan amendments		—			—			—			1.4			—			—			—			—
Plan curtailments		—			—			—			(0.1	)		—			—			—			—
Actuarial (gains) losses		(56.9	)		(3.5	)		0.1			0.5			(41.3	)		(6.0	)		—			0.4
Benefits paid		(15.0	)		(14.1	)		—			—			(12.9	)		(11.9	)		—			—
Ending obligations	$	358.5		$	502.9		$	5.8		$	5.9		$	288.5		$	363.2		$	0.5		$	0.5

Change in plans' assets
Beginning fair value	$	486.0		$	570.3		$	—		$	—		$	353.0		$	420.3		$	—		$	—
Actual return on plans' assets		(82.2	)		48.4			—			—			(62.4	)		35.0			—			—
Employer contributions		—			40.0			0.2			4.6			—			30.0			—			2.9
Plan settlements		(95.8	)		(158.6	)		(0.2	)		(4.6	)		(38.8	)		(120.4	)		—			(2.9	)
Benefits paid		(15.0	)		(14.1	)		—			—			(12.9	)		(11.9	)		—			—
Ending fair value	$	293.0		$	486.0		$	—		$	—		$	238.9		$	353.0		$	—		$	—
Funded status at end of year	$	(65.5	)	$	(16.9	)	$	(5.8	)	$	(5.9	)	$	(49.6	)	$	(10.2	)	$	(0.5	)	$	(0.5	)
Accumulated postretirement benefit obligation	$	342.7		$	475.2		$	4.8		$	5.4		$	275.2		$	341.0		$	0.4		$	0.4

For the year ended December 31, 2022, Pension Plan actuarial gains were primarily due to significantly higher discount rates, partially offset by demographic experience and a larger than expected amount of early 2023 lump sum payouts. For the year ended December 31, 2021, Pension Plan actuarial gains were primarily due to favorable demographic experience and a higher discount rate. These gains were partially offset by a difference in lump sum interest rates and the long-term assumption for Enable seconded employee terminations and more retirements and terminations than expected with lump sum payouts.


	OGE Energy						OG&E
	Postretirement Benefit Plans						Postretirement Benefit Plans
December 31 (In millions)	2022			2021			2022			2021
Change in benefit obligation
Beginning obligations	$	137.3		$	144.5		$	102.4		$	109.5
Service cost		0.2			0.2			0.1			0.1
Interest cost		3.5			3.4			2.7			2.6
Plan curtailments		—			1.9			—			—
Participants' contributions		3.5			3.5			2.4			2.6
Actuarial (gains) losses		(29.1	)		(3.7	)		(21.0	)		(2.5	)
Benefits paid		(13.5	)		(12.5	)		(10.2	)		(9.9	)
Ending obligations	$	101.9		$	137.3		$	76.4		$	102.4

Change in plans' assets
Beginning fair value	$	44.3		$	47.6		$	39.9		$	42.7
Actual return on plans' assets		(8.2	)		(0.5	)		(7.4	)		(0.5	)
Employer contributions		6.7			6.2			5.1			5.0
Participants' contributions		3.5			3.5			2.4			2.6
Benefits paid		(13.5	)		(12.5	)		(10.2	)		(9.9	)
Ending fair value	$	32.8		$	44.3		$	29.8		$	39.9
Funded status at end of year	$	(69.1	)	$	(93.0	)	$	(46.6	)	$	(62.5	)

Curtailment loss for the year ended December 31, 2021 is related to Enable seconded employees who terminated employment as a result of the merger with Energy Transfer. This reduction in future service of the active participants triggered curtailment accounting as of December 31, 2021.

Net Periodic Benefit Cost

The following tables present the net periodic benefit cost components, before consideration of capitalized amounts, of OGE Energy's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the financial statements. Service cost is presented within Other Operation and Maintenance Expense, and the remaining net period benefit cost components as listed in the following tables are presented within Other Net Periodic Benefit Income (Expense) in the statements of income. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table in Note 1 and within Other Net Periodic Benefit Income (Expense) in the statements of income.


OGE Energy	Pension Plan									Restoration of Retirement Income Plan
Year Ended December 31 (In millions)	2022			2021			2020			2022		2021		2020
Service cost	$	7.6		$	11.2		$	13.2		$	1.1	$	0.8	$	0.8
Interest cost		15.7			13.3			17.0			0.2		0.1		0.2
Expected return on plan assets		(25.4	)		(34.1	)		(37.6	)		—		—		—
Amortization of net loss		8.9			9.4			17.1			0.2		0.2		0.5
Plan curtailments		—			—			—			—		—		0.2
Special termination benefits		—			—			7.6			—		—		—
Amortization of unrecognized prior service cost (A)		—			—			—			0.2		0.1		—
Settlement cost		30.6			41.3			14.1			0.3		2.1		2.7
Total net periodic benefit cost		37.4			41.1			31.4			2.0		3.3		4.4
Less: Amount paid by unconsolidated affiliates		—			(0.2	)		2.0			—		0.1		0.1
Net periodic benefit cost	$	37.4		$	41.3		$	29.4		$	2.0	$	3.2	$	4.3

(a)

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


OG&E	Pension Plan									Restoration of Retirement Income Plan
Year Ended December 31 (In millions)	2022			2021			2020			2022		2021		2020
Service cost	$	6.2		$	7.7		$	9.2		$	—	$	—	$	0.1
Interest cost		12.1			9.7			12.6			—		—		0.1
Expected return on plan assets		(19.6	)		(24.7	)		(27.9	)		—		—		—
Amortization of net loss		7.4			7.0			12.1			—		0.1		0.4
Special termination benefits		—			—			5.1			—		—		—
Settlement cost		12.9			33.1			11.4			—		1.6		2.4
Total net periodic benefit cost		19.0			32.8			22.5			—		1.7		3.0
Plus: Amount allocated from OGE Energy		5.2			6.5			5.9			1.5		1.5		1.3
Net periodic benefit cost	$	24.2		$	39.3		$	28.4		$	1.5	$	3.2	$	4.3

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 2022, 2021 and 2020, the Registrants recognized the following:


Year Ended December 31 (In millions)	2022		2021		2020
Increase of regulatory asset related to pension expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	15.2	$	23.0	$	13.8
Deferral of pension expense related to pension settlement, curtailment and special termination benefits charges included in the above line item:
Oklahoma jurisdiction (A)	$	15.4	$	37.9	$	21.6
Arkansas jurisdiction (A)	$	1.4	$	3.5	$	2.0

(A)

Included in the pension regulatory asset in each jurisdiction, as indicated in the regulatory assets and liabilities table in Note 1.


	OGE Energy									OG&E
	Postretirement Benefit Plans									Postretirement Benefit Plans
Year Ended December 31 (In millions)	2022			2021			2020			2022			2021			2020
Service cost	$	0.2		$	0.2		$	0.2		$	0.1		$	0.1		$	0.2
Interest cost		3.5			3.4			4.2			2.7			2.6			3.2
Expected return on plan assets		(1.8	)		(1.8	)		(1.8	)		(1.6	)		(1.7	)		(1.7	)
Amortization of net loss		1.5			2.8			2.0			1.5			2.7			2.1
Plan curtailments		—			—			1.5			—			—			1.3
Amortization of unrecognized prior service cost (A)		(3.8	)		(6.9	)		(8.4	)		(3.6	)		(5.0	)		(6.1	)
Total net periodic benefit income		(0.4	)		(2.3	)		(2.3	)		(0.9	)		(1.3	)		(1.0	)
Less: Amount paid by unconsolidated affiliates (B)		—			(0.5	)		(0.7	)
Plus: Amount allocated from OGE Energy (B)											—			(0.5	)		(0.5	)
Net periodic benefit income	$	(0.4	)	$	(1.8	)	$	(1.6	)	$	(0.9	)	$	(1.8	)	$	(1.5	)

(A)

(B)

"Amount paid by unconsolidated affiliates" is only applicable to OGE Energy. "Amount allocated from OGE Energy" is only applicable to OG&E.

In addition to the net periodic benefit income amounts recognized, as presented in the table above, for the postretirement benefit plans in 2022, 2021 and 2020, the Registrants recognized the following:


Year Ended December 31 (In millions)	2022			2021		2020
Increase (decrease) of regulatory liability related to postretirement expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	(0.6	)	$	0.4	$	1.6
Deferral of postretirement expense related to postretirement plan curtailment charges included in the above line item:
Oklahoma jurisdiction (A)	$	—		$	—	$	(1.4	)
Arkansas jurisdiction (A)	$	—		$	—	$	(0.1	)

(A)

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

The following table presents the amount of net periodic benefit cost capitalized and attributable to each of the Registrants for OGE Energy's Pension Plan and postretirement benefit plans in 2022, 2021 and 2020.


	OGE Energy						OG&E
(In millions)	2022		2021		2020		2022		2021		2020
Capitalized portion of net periodic pension benefit cost	$	3.0	$	3.4	$	3.8	$	2.5	$	2.9	$	3.1
Capitalized portion of net periodic postretirement benefit cost	$	0.2	$	0.2	$	0.2	$	0.1	$	0.1	$	0.1

Rate Assumptions


	Pension Plan and Restoration of Retirement Income Plan									Postretirement Benefit Plans
Year Ended December 31	2022			2021			2020			2022			2021			2020
Assumptions to determine benefit obligations:
Discount rate		5.45	%		2.75	%		2.30	%		5.40	%		2.80	%		2.45	%
Rate of compensation increase		4.20	%		4.20	%		4.20	%	N/A			N/A			N/A
Interest crediting rate		3.50	%		3.50	%		3.50	%	N/A			N/A			N/A
Assumptions to determine net periodic benefit cost:
Discount rate		4.01	%		2.63	%		2.88	%		2.80	%		2.45	%		3.25	%
Expected return on plan assets		7.00	%		7.00	%		7.50	%		4.00	%		4.00	%		4.00	%
Rate of compensation increase		4.20	%		4.20	%		4.20	%	N/A			N/A			N/A
Interest crediting rate		3.50	%		3.50	%		4.00	%	N/A			N/A			N/A

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 2022 and 2021, 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 is used in determining net periodic benefit cost. 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 6.25 percent in 2023 with the rates trending downward to 4.50 percent by 2030.

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 following table presents 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 following table.


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%

OGE Energy has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of the Registrants' members and OGE Energy'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.

The following table presents a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against and the focus of the asset class.


Asset Class	Comparative Benchmark(s)	Focus of Asset Class
Active Duration Fixed Income (A)(B)	Bloomberg Barclays Aggregate	- Maximize risk-adjusted performance while providing long bond exposure managed according to the manager's forecast on interest rates. - All invested assets must reach at or above Baa3 or BBB- investment grade. - Limited five percent exposure to any single issuer, except the U.S. Government or affiliates.
Long Duration Fixed Income (A)(B)	Duration blended Barclays Long Government/Credit & Barclays Universal	- Maximize risk-adjusted performance. - At least 75 percent of invested assets much reach at or above Baaa3 or BBB- investment grade. - Limited five percent exposure to any single issuer, except the U.S. Government or affiliates. - May invest up to 10 percent of the market value in convertible bonds as long as quality guidelines are met. - May invest up to 15 percent of the market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio.
Equity Index (B)(C)	Standard & Poor's 500 Index	- Focus on replicating the performance of the S&P 500 Index.
Mid-Cap Equity (B)(C) Small-Cap Equity (B)(C)	Russell Midcap Index Russell Midcap Value Index Russell 2000 Index Russell 2000 Value Index	- Focus on undervalued stocks expected to earn average return and pay out higher than average dividends. - Invest in companies with market capitalizations lower than average company on public exchanges: - Price/earnings ratio at or near referenced - Small dividend yield and return on equity at or near referenced index; and - Earnings per share growth rate at or near referenced index.
International Equity (D)	Morgan Stanley Capital International ACWI ex-U.S.	- Invest in non-dollar denominated equity securities. - Diversify the overall trust investments.

(A)

Investment grades are by Moody's Investors Service, S&P Global Ratings or Fitch Ratings.

(B)

The purchase of any of OGE Energy's equity, debt or other securities is prohibited.

(C)

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 from OGE Energy's Investment Committee is received. The purchase of securities on margin, securities lending, private placement purchases and venture capital purchases are prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.

(D)

The manager of this asset class is required to operate under certain restrictions including regional constraints, diversification requirements and percentage of U.S. securities. 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).

Pension Plan Investments

The following tables present the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2022 and 2021. There were no Level 3 investments held by the Pension Plan at December 31, 2022 and 2021.


(In millions)	December 31, 2022			Level 1		Level 2		Net Asset Value (A)
Common stocks	$	71.9		$	71.9	$	—	$	—
U.S. Treasury notes and bonds (B)		44.6			44.6		—		—
Mortgage- and asset-backed securities		26.2			—		26.2		—
Corporate fixed income and other securities		65.5			—		65.5		—
Commingled fund (C)		18.2			—		—		18.2
Foreign government bonds		0.5			—		0.5		—
U.S. municipal bonds		0.9			—		0.9		—
Money market fund		5.9			—		—		5.9
Mutual fund		60.4			60.4		—		—
Preferred stocks		1.5			1.5		—		—
U.S. Treasury futures:
Cash collateral		0.3			0.3		—		—
Forward contracts:
Receivable (foreign currency)		0.1			—		0.1		—
Total Pension Plan investments		296.0		$	178.7	$	93.2	$	24.1
Interest and dividends receivable		1.6
Receivable from broker for securities sold		20.6
Payable to broker for securities purchased		(25.2	)
Total OGE Energy Pension Plan assets	$	293.0
Pension Plan investments attributable to affiliates		(54.1	)
Total OG&E Pension Plan assets	$	238.9


(In millions)	December 31, 2021			Level 1		Level 2		Net Asset Value (A)
Common stocks	$	86.1		$	86.1	$	—	$	—
U.S. Treasury notes and bonds (B)		135.2			135.2		—		—
Mortgage- and asset-backed securities		24.6			—		24.6		—
Corporate fixed income and other securities		107.0			—		107.0		—
Commingled fund (C)		23.6			—		—		23.6
Foreign government bonds		0.9			—		0.9		—
U.S. municipal bonds		1.4			—		1.4		—
Money market fund		5.5			—		—		5.5
Mutual fund		99.8			99.8		—		—
Preferred stocks		1.1			1.1		—		—
U.S. Treasury futures:
Cash collateral		0.6			0.6		—		—
Forward contracts:
Receivable (foreign currency)		0.1			—		0.1		—
Total Pension Plan investments		485.9		$	322.8	$	134.0	$	29.1
Interest and dividends receivable		2.1
Payable to broker for securities purchased		(2.0	)
Total OGE Energy Pension Plan assets	$	486.0
Pension Plan investments attributable to affiliates		(133.0	)
Total OG&E Pension Plan assets	$	353.0

(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 presents the benefit payments the Registrants expect to pay related to the Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure OGE Energy's benefit obligation at the end of the year and include benefits attributable to estimated future employee service.


(In millions)	OGE Energy		OG&E
2023	$	92.0	$	80.1
2024	$	29.4	$	23.1
2025	$	27.7	$	21.8
2026	$	28.9	$	23.0
2027	$	35.1	$	21.3
2028-2032	$	128.6	$	99.7

Postretirement Benefit Plans

In addition to providing pension benefits, OGE Energy 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 OGE Energy 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.

OGE Energy's contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level, and OGE Energy 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. OGE Energy provides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to an OGE Energy-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 present the postretirement benefit plans' investments that are measured at fair value on a recurring basis at December 31, 2022 and 2021. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2022 and 2021.


(In millions)	December 31, 2022			Level 1		Level 3
Group retiree medical insurance contract	$	21.6		$	—	$	21.6
Mutual funds		11.2			11.2		—
Total OGE Energy plan investments	$	32.8		$	11.2	$	21.6
Plan investments attributable to affiliates		(3.0	)
Total OG&E plan investments	$	29.8


(In millions)	December 31, 2021			Level 1		Level 3
Group retiree medical insurance contract	$	28.1		$	—	$	28.1
Mutual funds		16.2			16.2		—
Total OGE Energy plan investments	$	44.3		$	16.2	$	28.1
Plan investments attributable to affiliates		(4.4	)
Total OG&E plan investments	$	39.9

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 presents a reconciliation of 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)	2022
Group retiree medical insurance contract:
Beginning balance	$	28.1
Claims paid		(4.8	)
Net unrealized losses related to instruments held at the reporting date		(1.8	)
Investment fees		(0.1	)
Realized losses		(0.6	)
Interest income		0.7
Dividend income		0.1
Ending balance	$	21.6

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 presents the gross benefit payments the Registrants expect to pay related to the postretirement benefit plans, including prescription drug benefits.


(In millions)	OGE Energy		OG&E
2023	$	12.0	$	9.1
2024	$	11.7	$	8.9
2025	$	10.0	$	7.5
2026	$	9.5	$	7.1
2027	$	8.9	$	6.7
After 2027	$	37.0	$	27.8

Post-Employment Benefit Plan

Disabled employees receiving benefits from OGE Energy's Group Long-Term Disability Plan are entitled to continue participating in OGE Energy'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 Group Long-Term Disability Plan and their dependents, as defined in OGE Energy'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 OGE Energy's Group Long-Term Disability Plan due to death, recovery from disability or eligibility for retiree medical benefits. OGE Energy's post-employment benefit obligation was $1.8 million and $2.0 million at December 31, 2022 and 2021, respectively, of which $1.3 million and $1.5 million, respectively, was OG&E's portion of the obligation.

401(k) Plan

OGE Energy provides a 401(k) Plan, and each regular full-time employee of OGE Energy or a participating affiliate is eligible to participate in the 401(k) Plan immediately upon hire. All other employees of OGE Energy 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 75 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, OGE Energy 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 OGE Energy 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, OGE Energy's contribution may be directed to any available investment option in the 401(k) Plan. OGE Energy match

contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their OGE Energy 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 OGE Energy or its affiliates. OGE Energy contributed $17.1 million, $15.4 million and $18.2 million in 2022, 2021 and 2020, respectively, to the 401(k) Plan, of which $13.9 million, $12.0 million and $14.3 million, respectively, related to OG&E.

Deferred Compensation Plan

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. OGE Energy 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 OGE Energy or termination of the plan. Deferrals, plus any OGE Energy 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 2022, 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. OGE Energy accounts for the contributions related to its executive officers in this plan as Accrued Benefit Obligations and accounts for the contributions related to OGE Energy's directors in this plan as Other Deferred Credits and Other Liabilities in the balance sheets. The investment associated with these contributions is accounted for as Other Property and Investments in the 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 statements of income.

Supplemental Executive Retirement Plan

OGE Energy provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of OGE Energy's Board of Directors who may not otherwise qualify for a sufficient level of benefits under OGE Energy'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.

12.

Report of Business Segments

OGE Energy reports its operations in two business segments: (i) the electric company segment, which is engaged in the generation, transmission, distribution and sale of electric energy and (ii) natural gas midstream operations segment. Prior to the Enable and Energy Transfer merger closing on December 2, 2021, OGE Energy's natural gas midstream operations segment included its equity method investment in Enable. For the period of December 2, 2021 to September 30, 2022, OGE Energy's natural gas midstream operations segment included OGE Energy's investment in Energy Transfer's equity securities acquired in the merger. For the year ended December 31, 2022, this segment also includes legacy Enable seconded employee pension and postretirement costs. 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 present the results of OGE Energy's business segments for the years ended December 31, 2022, 2021 and 2020.


2022	Electric Company		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	3,375.7	$	—		$	—		$	—		$	3,375.7
Fuel, purchased power and direct transmission expense		1,662.4		—			—			—			1,662.4
Other operation and maintenance		491.9		12.6			(3.1	)		—			501.4
Depreciation and amortization		460.9		—			—			—			460.9
Taxes other than income		98.0		0.1			3.4			—			101.5
Operating income (loss)		662.5		(12.7	)		(0.3	)		—			649.5
Gain on equity securities		—		282.1			—			—			282.1
Other income (expense)		11.2		10.0			4.9			(2.1	)		24.0
Interest expense		157.8		—			10.6			(2.1	)		166.3
Income tax expense (benefit)		76.4		48.1			(0.9	)		—			123.6
Net income (loss)	$	439.5	$	231.3		$	(5.1	)	$	—		$	665.7
Total assets	$	12,410.5	$	1.2		$	683.7		$	(550.7	)	$	12,544.7
Capital expenditures	$	1,050.9	$	—		$	—		$	—		$	1,050.9


2021	Electric Company		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	3,653.7	$	—		$	—		$	—		$	3,653.7
Fuel, purchased power and direct transmission expense		2,127.6		—			—			—			2,127.6
Other operation and maintenance		464.7		1.6			(3.2	)		—			463.1
Depreciation and amortization		416.0		—			—			—			416.0
Taxes other than income		99.3		0.2			3.3			—			102.8
Operating income (loss)		546.1		(1.8	)		(0.1	)		—			544.2
Equity in earnings of unconsolidated affiliates		—		169.8			—			—			169.8
Gain on Enable/Energy Transfer transaction, net		—		344.4			—			—			344.4
Other income (expense)		7.7		(26.4	)		(2.0	)		(0.9	)		(21.6	)
Interest expense		152.0		—			7.2			(0.9	)		158.3
Income tax expense (benefit)		41.8		101.0			(1.6	)		—			141.2
Net income (loss)	$	360.0	$	385.0		$	(7.7	)	$	—		$	737.3
Total assets	$	11,688.0	$	786.6		$	350.3		$	(218.5	)	$	12,606.4
Capital expenditures	$	778.5	$	—		$	—		$	—		$	778.5


2020	Electric Company		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	2,122.3	$	—		$	—		$	—		$	2,122.3
Fuel, purchased power and direct transmission expense		644.6		—			—			—			644.6
Other operation and maintenance		464.4		1.7			(3.3	)		—			462.8
Depreciation and amortization		391.3		—			—			—			391.3
Taxes other than income		97.2		0.4			3.8			—			101.4
Operating income (loss)		524.8		(2.1	)		(0.5	)		—			522.2
Equity in losses of unconsolidated affiliates (A)		—		(668.0	)		—			—			(668.0	)
Other income (expense)		4.1		(2.9	)		3.6			(1.6	)		3.2
Interest expense		154.8		—			5.3			(1.6	)		158.5
Income tax expense (benefit)		34.7		(158.0	)		(4.1	)		—			(127.4	)
Net income (loss)	$	339.4	$	(515.0	)	$	1.9		$	—		$	(173.7	)
Investment in unconsolidated affiliates	$	—	$	374.3		$	—		$	—		$	374.3
Total assets	$	10,489.0	$	378.1		$	116.4		$	(264.7	)	$	10,718.8
Capital expenditures	$	650.5	$	—		$	—		$	—		$	650.5

(A)

In March 2020, OGE Energy recorded a $780.0 million impairment on its investment in Enable.

13.

Commitments and Contingencies

Purchase Obligations and Commitments

The following table presents the Registrants' future purchase obligations and commitments estimated for the next five years.


(In millions)	2023		2024		2025		2026		2027		Total
Purchase obligations and commitments:
Minimum purchase commitments	$	110.0	$	92.2	$	66.4	$	24.6	$	24.6	$	317.8
Expected wind purchase commitments		56.0		56.6		56.9		57.3		57.7		284.5
Long-term service agreement commitments		2.7		14.5		2.8		17.1		23.8		60.9
Total purchase obligations and commitments	$	168.7	$	163.3	$	126.1	$	99.0	$	106.1	$	663.2

OG&E Minimum Purchase Commitments

OG&E has coal contracts for purchases through December 31, 2025. OG&E may also purchase 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 Energy Transfer, ONEOK, Inc. and Southern Star. The contracts with Energy Transfer end in December 2024 and December 2038; the contracts with ONEOK, Inc. end in March 2024 and August 2037; and the contract with Southern Star ends in June 2024. These transportation contracts grant Energy Transfer, ONEOK, Inc. and Southern Star the responsibility of delivering natural gas to OG&E's generating facilities.

OG&E Wind Power Purchase Commitments

The following table presents OG&E's wind purchased power 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 presents a summary of OG&E's wind power purchases for the years ended December 31, 2022, 2021 and 2020.


Year Ended December 31 (In millions)	2022		2021		2020
CPV Keenan	$	25.8	$	27.3	$	27.5
Edison Mission Energy		24.9		21.7		22.8
NextEra Energy		7.3		6.8		7.0
Total wind power purchased	$	58.0	$	55.8	$	57.3

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 2035. 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 2032. 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

CO2 Emission Limits for Existing Generating Units

On January 19, 2021, the U.S. Court of Appeals vacated the EPA's latest effort to adopt CO2 emissions standards for existing coal-fired electric generating units, and the court remanded the matter to the EPA for further consideration. The EPA has indicated that administrative proceedings to respond to the U.S. Court of Appeals' remand in a new rulemaking action are ongoing but has not announced rulemaking details. The decision was based on the court's conclusion that the Clean Air Act does not require the EPA to limit the standards to measures that can be applied at and to an existing unit. On October 29, 2021, the U.S. Supreme Court granted petitions to review the decision and heard oral arguments on February 28, 2022. On June 22, 2022, the U.S. Supreme Court ruled that the approach the EPA took in the rule exceeded the powers granted by Congress and remanded greenhouse gas regulation for existing units to the EPA. With the ruling and remand by the U.S. Supreme Court, there continues to be no applicable greenhouse gas regulation for existing power plants, 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 Registrants' future 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 Registrants are 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 Registrants have 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 financial statements. At the present time, based on currently available information, the Registrants believe 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 their financial statements and would not have a material adverse effect on their financial position, results of operations or cash flows.

14.

Rate Matters and Regulation

Regulation and Rates

Completed Regulatory Matters

APSC Proceedings

Arkansas 2021 Formula Rate Plan Filing

In October 2021, OG&E filed its fourth evaluation report under its Formula Rate Plan, and on February 1, 2022, OG&E, the APSC General Staff and the Office of the Arkansas Attorney General filed a non-unanimous joint settlement agreement, which included an annual electric revenue increase of $4.2 million. The only non-signatory to the settlement agreement agreed not to oppose the settlement. On March 4, 2022, the APSC issued a final order approving the non-unanimous settlement agreement, and new rates became effective April 1, 2022.

Winter Storm Uri

In February 2021, Winter Storm Uri resulted in record winter peak demand for electricity and extremely high natural gas and purchased power prices in OG&E's service territory. On April 1, 2021, OG&E filed with the APSC a motion seeking approval to defer, amortize and recover the extraordinary fuel costs over a 10-year period with a carrying charge of OG&E's pre-tax rate of return of 6.60 percent, through a special factor within OG&E's Energy Cost Recovery Rider beginning with the first billing cycle of May 2021. On April 13, 2021, the APSC issued an order allowing OG&E interim recovery at an interest rate equal to the customer deposit interest rate over a period of 10 years beginning with the first billing cycle of May 2021, subject to true-up.

On July 5, 2022, OG&E filed a motion to request recovery of the regulatory asset balance over 10 years using a weighted average cost of capital. A hearing on the merits was scheduled to be held on December 2, 2022 but was cancelled after all interested parties agreed to waive the hearing and have the APSC decide the matter based on the established record. In January 2023, the APSC issued an order approving OG&E's requested relief and authorizing OG&E to amortize the regulatory asset balance over 10 years using a pre-tax weighted average cost of capital of 6.49 percent as a carrying charge beginning March 2021. The impact of this order will be recorded beginning in the first quarter of 2023, as the order was received from the APSC in January 2023.

Arkansas 2021 Formula Rate Plan Filing - Extension

On May 18, 2022, the APSC issued an order granting OG&E's request for a five-year extension of the Formula Rate Plan Rider with certain terms and conditions, including continuation of OG&E's current return on equity of 9.5 percent and a change to OG&E's current debt-to-equity ratio of 50/50 percent to 55/45 percent. On June 17, 2022, OG&E filed a request for rehearing seeking reconsideration by the APSC of their decision to alter the Formula Rate Plan Rider's capital structure. On September 19, 2022, the APSC issued an order reversing its May 18, 2022 order and denying the extension of OG&E's Formula Rate Plan Rider. On September 20, 2022, the APSC Staff filed a motion for clarification for the extension denial, and OG&E, the Arkansas Attorney General and Arkansas River Valley Energy Consumers filed responses to the clarification. On September 30, 2022, the APSC issued an order clarifying that OG&E is authorized to file its 2022 and 2023 evaluation reports under the Formula Rate Plan Rider to true-up prior projected year rate adjustments. On October 28, 2022, Arkansas River Valley Energy Consumers and Walmart Inc. filed a request for rehearing of the APSC's September 30, 2022 order and asked the APSC to reverse its position and prohibit OG&E from making any further filings under its current Formula Rate Plan. On November 1, 2022, OG&E submitted its opposition to the request for rehearing. On November 28, 2022, the APSC granted the application for rehearing solely for the purpose of further consideration. On January 20, 2023, the APSC issued an order denying the request for rehearing of the September 30, 2022 order and ruling that OG&E is able to undertake two more true-up updates to its Formula Rate Plan Rider with adjustments to rates occurring in April 2023 and April 2024. Despite the denial of OG&E's extension request, the Formula Rate Plan Rider will continue until new rates are set in a future general rate review.

OCC Proceedings

Winter Storm Uri

In December 2021, the OCC approved a settlement agreement in a final financing order authorizing the issuance of securitization bonds in an amount up to $760.0 million, which included estimated finance costs and was subject to change for carrying costs, any updates from the SPP settlement process and actual securitization issuance costs. On July 20, 2022, the ODFA issued the securitization bonds consistent with the OCC's order.

In connection with the securitization transaction, the ODFA and OG&E entered into an agreement on July 20, 2022 whereby the ODFA purchased, and OG&E sold, the securitization property that was created pursuant to legislation enacted by the State of Oklahoma in April 2021 and the financing order received from the OCC in December 2021. Such securitization property includes the right to assess, impose, adjust, collect and receive funds, in the form of the winter event securitization charge, from OG&E's existing and future Oklahoma customers in amounts intended to be sufficient to pay the principal and interest and financing charges on the

securitization bonds. On July 20, 2022, OG&E received proceeds of approximately $750 million for the sale of the securitization property, which represented the amount of the securitization bonds sold less the issuance costs. OG&E used these proceeds to fund the Oklahoma Winter Storm Uri regulatory asset by recovering the authorized extreme, extraordinary fuel and purchased power costs incurred during Winter Storm Uri, as well as carrying costs. Beginning August 1, 2022, OG&E acts as a servicer for collecting the funds from Oklahoma customers that are then submitted to the ODFA to repay the securitization bonds over 28 years.

2021 Oklahoma General Rate Review

In December 2021, OG&E filed a general rate review in Oklahoma seeking a rate increase of $163.5 million and a 10.2 percent return on equity based on a common equity percentage of 53.37 percent. The rate review was based on a September 30, 2021 test year and included a request for recovery of $1.2 billion of capital investment since the last general rate review. OG&E had the right to implement interim rates subject to refund beginning July 1, 2022 (180 days after the filing of its application on December 30, 2021). On July 1, 2022, OG&E implemented an annual interim rate increase of $30.0 million, subject to refund for amounts in excess of the rates approved by the OCC.

On September 8, 2022, the OCC approved a Joint Stipulation and Settlement Agreement that had been entered into by OG&E, the OCC Public Utility Division Staff, the Oklahoma Attorney General, the OG&E Shareholders Association, Oklahoma Industrial Energy Consumers and other intervenors. Non-signatory parties had agreed not to contest this agreement. Key terms of the agreement, as approved by the OCC, include, among others:

•

A base rate revenue increase of $30.0 million;

•

OG&E would issue a refund, over a 12-month period, for the tax expense savings arising from the reduction in the Oklahoma state corporate income tax rate from 6 percent to 4 percent for the period from January 1, 2022 through June 30, 2022, as well as amortize over five years the excess accumulated deferred income tax balance resulting from this corporate tax rate change;

•

There would be no change in OG&E's current return on equity of 9.5 percent, and OG&E's requested capital structure based on a common equity percentage of 53.37 percent would be approved;

•

OG&E would utilize depreciation rates based on the recommendations of the Oklahoma Attorney General with the exception of transmission and general plant accounts, which would be based on the depreciation rates recommended by the Oklahoma Industrial Energy Consumers;

•

OG&E's Grid Enhancement Plan projects recorded as of March 31, 2022 would be considered prudent and be included in base rates;

•

OG&E's Grid Enhancement Plan interim recovery would continue and updated terms include: (i) cost recovery through a rider mechanism will be limited to projects placed in service in 2022, 2023 and 2024, capped at a revenue requirement of $6.0 million for each annual investment plan and include communication, automation and technology systems projects, as well as certain weather hardening projects; and (ii) the rider mechanism will terminate by the issuance of a final order in OG&E's first general rate review following completion of projects included in the 2024 annual investment plan or no later than July 1, 2025;

•

OG&E would amend several of its rider tariffs to incorporate the agreements of the stipulating parties; and

•

Regulatory accounting treatments approved include, among other things, the establishment of a regulatory asset to defer operation and maintenance costs associated with OG&E's SAP S/4 HANA enterprise resource planning system project for consideration in future rate proceedings with the carrying cost accruing at OG&E's short-term cost of debt, the amortization of COVID-19 regulatory asset balance over five years and the amortization of over/under-recovery balance of the pension tracker over 15 years, which is a change from the previous five-year recovery period.

Due to the September 8, 2022 OCC approval of the rate increase of $30.0 million, no refund of interim rates was necessary.

Pending Regulatory Matters

Various proceedings pending before state or federal regulatory agencies are described below. Unless stated otherwise, the Registrants cannot predict when the regulatory agency will act or what action the regulatory agency will take. The Registrants' financial results are dependent in part on timely and constructive decisions by the regulatory agencies that set OG&E's rates.

FERC Proceedings

Order for Sponsored Transmission Upgrades within SPP

Under Attachment Z2 of 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 Tariff required the SPP to charge for these upgrades beginning in 2008, but the SPP did not begin charging its customers for these upgrades until 2016 due to information system limitations. At that time, the SPP sought a waiver of a time limitation in its tariff that otherwise would have prevented it from waiting until 2016 to bill for the 2008 through 2015 period. The FERC granted the waiver, and the SPP then billed OG&E as a user for these Z2 charges while simultaneously crediting OG&E as a sponsor of Z2 transmission upgrades, resulting in OG&E being a net recipient 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 2016 order approving the waiver and then appealed it. While that appeal was pending, the FERC obtained a remand and then reversed itself and ruled that the SPP tariff provision that prohibited the 2008 through 2015 charges could not be waived. It ordered the SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, in April 2019, OG&E filed a request for rehearing at the FERC. The next month, it also filed a Complaint at the FERC against the SPP contending that the SPP and not OG&E should bear the cost of any refunds resulting from the SPP's tariff violation and that SPP’s actions also violated its contracts with OG&E. In February 2020, the FERC denied OG&E's request for rehearing but did not consider SPP's refund plan. No date for payment of refunds was established. In August 2021, the U.S. Court of Appeals for the District of Columbia Circuit denied OG&E's petition for review of the FERC's order denying the waiver and requiring refunds. After denying rehearing of its ruling, the court of appeals returned the matter in November 2021 to the FERC for further proceedings in accordance with its opinion. The FERC has not acted on that remand.

If the FERC proceeds to order refunds in full, 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. The SPP has stated in filings with the FERC both before and after the court of appeals decision that there are considerable complexities in implementing the refunds that will have to be resolved before they can be paid. Payment of refunds would shift recovery of these upgrade credits to future periods. The SPP filed a report on January 4, 2022 confirming that administering refunds would be complex and could take years unless the SPP is allowed to make certain simplifying assumptions. The SPP also urged that all pending complaint proceedings, including OG&E's complaint and three similar complaints against the SPP, be resolved before any refund process is ordered to begin. OG&E and other parties filed responses to the SPP report, and the matter remains pending at the FERC. Of the $13.0 million, the Registrants would be impacted by $5.0 million in expense that initially benefited the Registrants 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. As of December 31, 2022, the Registrants have reserved $13.0 million plus estimated interest for a potential refund.

In November 2022, the FERC issued an order denying OG&E's complaint against SPP. It also issued orders granting the other three complaints against the SPP in part but awarded no relief. All four complainants timely sought rehearing of these orders. Those rehearing petitions remain pending, though OG&E and the other complainants can appeal them now if they choose to do so on the basis that they have been deemed denied by operation of law. The FERC, however, can continue to consider the rehearings on the merits, and the complainants will be able appeal any denial on the merits as well.

In June 2020, the FERC approved, effective July 1, 2020, an SPP proposal to eliminate Attachment Z2 revenue crediting and replace it with a different rate mechanism that would provide project sponsors, such as OG&E, the same level of recovery. This elimination of the Attachment Z2 revenue crediting would only prospectively impact OG&E and its recovery of any future upgrade costs that it may incur as a project sponsor subsequent to July 2020. All of the existing projects that are eligible to receive revenue credits under Attachment Z2 will remain eligible, which includes the $13.0 million that is at issue in the remand from OG&E's appeal and in OG&E's complaint proceeding.

Incentive Adders for Transmission Rates

The FERC issued a NOPR in March 2020, and issued a supplemental NOPR in April 2021, proposing to update its transmission incentives policy. Among other things, the NOPR proposes (i) the current 50-basis point return on equity adder for RTO/ISO participation would be applicable only to transmitting utilities that join an RTO/ISO, and this incentive would only apply for the first three years in which the utility is an RTO/ISO member and (ii) transmitting utilities that have been members of an RTO/ISO for three years or more, such as OG&E, would be required to make a compliance filing to remove the existing return on equity adder from their rates. Currently, there is no specific deadline for the FERC to take further action, and it is unknown whether the FERC will address the RTO participation adder individually or as part of a larger order on transmission incentives.

APSC Proceedings

Arkansas 2022 Formula Rate Plan Filing

On October 3, 2022, OG&E filed its fifth evaluation report under its Formula Rate Plan, including a request to increase its Arkansas retail revenues by $8.5 million, which reflects a cap of 4.0 percent of annualized filing year revenues as of June 2022. After utilizing an adjustment to annualized filing year revenues as of October 2022, the capped revenue requirement increase rose to approximately $9.6 million. On December 29, 2022, intervening parties filed errors and objections to OG&E's fifth evaluation report. The Arkansas Attorney General made no recommended adjustments to the revenue requirement, and the Arkansas Valley Electric Consumers reiterated legal arguments about the legal permissibility of the fifth evaluation report. The APSC Staff made certain minor adjustments but agreed that the overall revenue requirement adjustment should reflect the capped amount of $9.6 million. On February 1, 2023, OG&E and the APSC Staff filed a non-unanimous joint settlement agreement, which includes an annual electric revenue increase of $9.6 million. The Arkansas Attorney General and the Arkansas Valley Electric Consumers have agreed not to oppose the settlement, and the settlement agreement is subject to approval by the APSC. OG&E and the APSC Staff have requested a final order from the APSC by early March 2023, with new rates to be effective April 1, 2023.

Prudence Review - Winter Storm Uri Extraordinary Costs

On February 2, 2023, the APSC issued an order to initiate proceedings to address the prudence and appropriate allocation of the extraordinary costs incurred by Arkansas jurisdictional electric and natural gas utilities during Winter Storm Uri. As discussed above, in January 2023, the APSC issued an order approving OG&E's recovery of the Winter Storm Uri regulatory asset balance, which included setting the carrying charges and term of recovery. The APSC did not rule on prudence or cost allocation at that time. OG&E's direct testimony is due in April 2024, and a hearing on the merits is expected to begin in August 2024.

OCC Proceedings

Oklahoma Retail Electric Supplier Certified Territory Act Causes

Several 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. There have been five complaint cases initiated at the OCC, and the OCC has issued decisions on each of them. The OCC ruled in favor of the electric cooperatives in three of those cases and ruled in favor of OG&E in two of those cases. All five of those cases have been appealed to the Oklahoma Supreme Court, where they have been made companion cases but will be individually briefed and have individual final decisions.

If the Oklahoma Supreme Court ultimately were to find that some or all of the customers being served are not exempted from the Oklahoma Retail Electric Supplier Certified Territory Act, OG&E would have to evaluate the recoverability of some plant investments made to serve these customers. The total amount of OG&E's plant investments made to serve the customers in all five cases is approximately $28.0 million, of which $11.7 million applies to the three cases where the OCC ruled in favor of the electric cooperatives. In addition to the evaluation of the recoverability of the investments, OG&E may also be required to reimburse certified territory suppliers for an amount of lost revenue. The amount of such lost revenue would depend on how the OCC calculates the revenue requirement but could range from approximately $16.2 million to $63.9 million for all five cases, of which $4.4 million to $7.9 million would apply to the three cases where the OCC ruled in favor of the electric cooperatives.

2021 Oklahoma Fuel Prudency

On July 1, 2022, the OCC Public Utility Division Staff filed their application initiating the review of the 2021 fuel adjustment clause and prudence review. On February 21, 2023, a Joint Stipulation and Settlement Agreement was filed, and OG&E filed its testimony in support of such agreement. The stipulating parties, which include the OCC Public Utility Division Staff and the Oklahoma Attorney General, agree that: (i) OG&E's practices, policies and judgment for fuel procurement during 2021 were prudent; (ii) OG&E's power purchase costs and expenses, monthly fuel filings and processes and fuel-related investments and decisions for 2021 were fair, just and reasonable and (iii) OG&E exercised prudent judgement pertaining to all such matters and that the electric generation, purchased power and fuel procurement expenses were prudently incurred. Further, the stipulating parties agree to certain revisions of the fuel clause adjustment tariff, including a revised semi-annual fuel clause adjustment factor redetermination process which will be subject to the OCC Public Utility Division approval or denial. A hearing on the merits for the Joint Stipulation and Settlement Agreement is scheduled for February 23, 2023.

Fuel Cost Adjustment Show Cause

On September 29, 2022, the OCC Public Utility Division Staff initiated a cause to determine the appropriate methodology to recover OG&E's fuel clause under recovery balance of $424.0 million and how OG&E's fuel factors should be set going forward. The Staff requested that OG&E explain how it arrived at the noted under recovery balance, explain its fuel forecasting process, justify its

amortization period of 24 months and explain the adequacy of its resource mix and fuel supply plans. Updated fuel factors were implemented by OG&E on October 1, 2022 to recover the balance from customers over 24 months. The OCC Public Utility Division Staff did not oppose OG&E's implementation of updated fuel factors on an interim basis and subject to refund. A hearing on the merits was held on November 3 and 4, 2022. Despite several public deliberations, the OCC has not issued a final order in this proceeding. On January 1, 2023, OG&E implemented its annual redetermination of its fuel factors, without further action or opposition from the OCC.

SPP Proceedings

Planning Reserve Margin and Performance Based Accreditation

On July 26, 2022, the SPP Board of Directors approved a planning reserve margin increase from 12 percent to 15 percent that each load serving entity, such as OG&E, must maintain. This change will be effective for the summer of 2023. At the same time, the SPP Board of Directors also approved a new unit accreditation methodology for conventional generation, effective 2024. As a result, OG&E is currently evaluating its plan to fill the incremental capacity needs brought about by these policy changes.

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, 2022 and 2021, the related consolidated statements of income, comprehensive income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2022, 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, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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 as of December 31, 2020. In the consolidated financial statements, the Company's investment in Enable is stated at $374.3 million as of December 31, 2020, and the Company's equity in the net income of Enable is stated at $13.2 million in 2020. 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 for 2020, 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, 2022, 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 22, 2023, 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 accounts or disclosures to which it relates.

Regulatory Assets and Liabilities


Description of the Matter	As discussed in Note 1 to the consolidated financial statements, the Company conducts its electric utility operations through Oklahoma Gas & Electric Company (OG&E). 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. In addition, we tested that amortization of regulatory assets and liabilities corresponded to relevant regulatory rulings. For example, we tested whether the regulatory assets and liabilities were appropriately amortized through the Company's rates charged to customers based on rulings from regulatory bodies.

/s/ Ernst & Young LLP

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

Oklahoma City, Oklahoma

February 22, 2023

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder and the Board of Directors of Oklahoma Gas and Electric Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas and Electric Company (the Company) as of December 31, 2022 and 2021, the related statements of income and comprehensive income, changes in stockholder's equity and cash flows for each of the three years in the period ended December 31, 2022, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles.

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, 2022, 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 22, 2023, expressed an unqualified opinion thereon.

Basis for 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 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.

Regulatory Assets and Liabilities


Description of the Matter	As discussed in Note 1 to the 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. In addition, we tested that amortization of regulatory assets and liabilities corresponded to relevant regulatory rulings. For example, we tested whether the regulatory assets and liabilities were appropriately amortized through the Company's rates charged to customers based on rulings from regulatory bodies.

/s/ Ernst & Young LLP

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

Oklahoma City, Oklahoma

February 22, 2023

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

None.

Item 9A. Controls and Procedures.

The Registrants maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Registrants in reports that they file or submit 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 Registrants' management, including the chief executive officer and chief financial officer, of the effectiveness of the Registrants' 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 Registrants' disclosure controls and procedures are effective.

No change in the Registrants' internal control over financial reporting has occurred during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrants' 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).

Management's Report on Internal Control Over Financial Reporting

The management of the Registrants is responsible for establishing and maintaining adequate internal control over financial reporting. The Registrants' internal control systems were designed to provide reasonable assurance to management and OGE Energy's 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 Registrants' management assessed the effectiveness of their internal control over financial reporting as of December 31, 2022. 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, 2022, the Registrants' internal control over financial reporting is effective based on those criteria.

The Registrants' independent auditors have issued an attestation report on the Registrants' 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/ W. Bryan Buckler
W. Bryan Buckler
Chief Financial Officer

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, 2022, 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, 2022, 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 consolidated balance sheets and consolidated statements of capitalization of OGE Energy Corp. as of December 31, 2022 and 2021, 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, 2022, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 22, 2023 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 22, 2023

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder and the Board of Directors of Oklahoma Gas and Electric Company

Opinion on Internal Control over Financial Reporting

We have audited Oklahoma Gas and Electric Company's internal control over financial reporting as of December 31, 2022, 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, Oklahoma Gas and Electric Company (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, 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 balance sheets and statements of capitalization of Oklahoma Gas & Electric Company as of December 31, 2022 and 2021, the related statements of income and comprehensive income, changes in stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2022, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 22, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

Definition and Limitations of Internal Control Over Financial Reporting

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

February 22, 2023

Item 9B. Other Information.

On February 22, 2023, the Board of Directors approved and adopted the OGE Energy Corp. 2023 Annual Executive Incentive Compensation Plan (the "Annual Plan"). The Annual Plan replaces the OGE Energy Corp. 2022 Annual Executive Incentive Compensation Plan (the "current annual plan"). The Annual Plan is very similar to the current annual plan, with the only difference being changing the annual incentive payout amounts from 0% - 150% to 0% - 200% of target based on peer review.

Officers, executives or other key employees of OGE Energy and its subsidiaries who are selected by the Compensation Committee are eligible to be granted awards under the Annual Plan, which provides for the payment of annual cash bonuses based on OGE Energy performance and individual performance relative to performance goals approved by the Compensation Committee. The level of achievement of the specified OGE Energy and individual performance goals at the end of the plan year will determine the amount of each participant's target company award and/or target individual award that such participant will receive, which may exceed 100 percent of the participant's target awards.

This summary of the Annual Plan is qualified in its entirety by reference to the Annual Plan filed as Exhibit 10.14 to this 2022 Form 10-K.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Code of Ethics Policy

OGE Energy 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 OGE Energy's website at www.oge.com/governance. The code of ethics will be provided, free of charge, upon request. OGE Energy 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. OGE Energy will also include in its proxy statement information regarding the Audit Committee financial experts.

OGE Energy. Information regarding OGE Energy's executive officers is set forth in "Part I, Item 1. Business - Information About the Registrants' Executive Officers." As permitted by General Instruction G of Form 10-K, the information required by Item 10, other than information regarding the executive officers and the Code of Ethics, will be set forth in OGE Energy's definitive proxy statement for the 2023 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 3, 2023. Such proxy statement is incorporated herein by reference.

OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 10 for OG&E has been omitted.

Item 11. Executive Compensation

OGE Energy. As permitted by General Instruction G of Form 10-K, the information required by Item 11 will be set forth in OGE Energy's definitive proxy statement for the 2023 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 3, 2023. Such proxy statement is incorporated herein by reference.

OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 11 for OG&E has been omitted.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

OGE Energy. As permitted by General Instruction G of Form 10-K, the information required by Item 12 will be set forth in OGE Energy's definitive proxy statement for the 2023 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 3, 2023. Such proxy statement is incorporated herein by reference.

OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 12 for OG&E has been omitted.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

OGE Energy. As permitted by General Instruction G of Form 10-K, the information required by Item 13 will be set forth in OGE Energy's definitive proxy statement for the 2023 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 3, 2023. Such proxy statement is incorporated herein by reference.

OG&E. Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 13 for OG&E has been omitted.

Item 14. Principal Accountant Fees and Services.

The following discussion relates to the audit fees paid by OGE Energy to its principal independent accountants for the services provided to OGE Energy and its subsidiaries, including OG&E.

Fees for Principal Independent Accountants


Year Ended December 31	2022		2021
Integrated audit of OGE Energy and its subsidiaries financial statements and internal control over financial reporting	$	1,232,000	$	1,209,000
Services in support of debt and stock offerings		59,000		65,000
Other (A)		447,500		361,000
Total audit fees (B)		1,738,500		1,635,000
Employee benefit plan audits		138,000		133,000
Total audit-related fees		138,000		133,000
Assistance with examinations and other return issues		219,892		237,481
Review of federal and state tax returns		34,000		32,000
Total tax preparation and compliance fees		253,892		269,481
Total tax fees		253,892		269,481
Total fees	$	2,130,392	$	2,037,481

(A)

Includes reviews of the financial statements included in the Registrants' Quarterly Reports on Form 10-Q, audits of OGE Energy's subsidiaries, preparation for Audit Committee meetings, agreed-upon procedures and fees for consulting with the Registrants' executives regarding accounting issues.

(B)

The aggregate audit fees include fees billed for the audit of the Registrants' annual financial statements and for the reviews of the financial statements included in the Registrants' Quarterly Reports on Form 10-Q. For 2022, this amount includes estimated billings for the completion of the 2022 audit, which services were rendered after year-end.

All Other Fees

There were no other fees billed by the principal independent accountants to OGE Energy in 2022 and 2021 for other services.

Audit Committee Pre-Approval Procedures

Rules adopted by the Securities and Exchange Commission in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. OGE Energy's Audit Committee follows procedures pursuant to which audit, audit-related and tax services, and all permissible non-audit services are pre-approved by category of service. The fees are budgeted, and actual fees versus the budget are monitored throughout the year. During the year, circumstances may arise when it may become necessary to engage the principal independent accountants for additional services not contemplated in the original pre-approval. In those instances, OGE Energy will obtain the specific pre-approval of the Audit Committee before engaging the principal independent accountants. The procedures require the Audit Committee to be informed of each service, and the procedures do not include any delegation of the Audit Committee's responsibilities to management. The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated will report any pre-approval decisions to the Audit Committee at its next scheduled meeting.

For 2022, 100 percent of the audit fees, audit-related fees and tax fees were pre-approved by the Audit Committee or the Chairman of the Audit Committee pursuant to delegated authority.

PART IV

Item 15. Exhibit and Financial Statement Schedules.

(a) 1. Financial Statements

(i)

The following financial statements are included in Part II, Item 8 of this Annual Report:

OGE Energy

•

Consolidated Statements of Income for the years ended December 31, 2022, 2021 and 2020

•

Consolidated Statements of Comprehensive Income for the years ended December 31, 2022, 2021 and 2020

•

Consolidated Statements of Cash Flows for the years ended December 31, 2022, 2021 and 2020

•

Consolidated Balance Sheets at December 31, 2022 and 2021

•

Consolidated Statements of Capitalization at December 31, 2022 and 2021

•

Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2022, 2021 and 2020

•

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)

OG&E

•

Statements of Income for the years ended December 31, 2022, 2021 and 2020

•

Statements of Comprehensive Income for the years ended December 31, 2022, 2021 and 2020

•

Statements of Cash Flows for the years ended December 31, 2022, 2021 and 2020

•

Balance Sheets at December 31, 2022 and 2021

•

Statements of Capitalization at December 31, 2022 and 2021

•

Statements of Changes in Stockholder's Equity for the years ended December 31, 2022, 2021 and 2020

•

Notes to 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)

The reports of the Registrants' independent registered public accounting firm (PCAOB ID:42) with respect to the above-referenced financial statements and their reports on internal control over financial reporting are included in Item 8 and Item 9A of this Form 10-K. Their consents for each Registrant appear as Exhibit 23.01 and Exhibit 23.02 of this Form 10-K.

(ii)

The audited financial statements and Notes to Consolidated Financial Statements of Enable Midstream Partners, LP, for the year ending December 31, 2020 required pursuant to Rule 3-09 of Regulation S-X are filed as Exhibit 99.03.

The report of the independent registered public accounting firm Deloitte & Touche LLP (PCAOB ID No. 34), located in Oklahoma City, Oklahoma, with respect to the above-referenced financial statements is included in Exhibit 99.03. Their related consent appears as Exhibit 23.03 of this Form 10-K.

(iii)

The unaudited financial statements and Notes to Consolidated Financial Statements of Enable Midstream Partners, LP, for the nine month period ending September 30, 2021 required pursuant to Rule 3-09 of Regulation S-X are filed as Exhibit 99.04.

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 financial statements or notes thereto.

3. Exhibits


Exhibit No.	Description	OGE Energy	OG&E
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).	X
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).	X
3.03	Copy of Restated Oklahoma Gas and Electric Company Certificate of Incorporation. (Filed as Exhibit 3.01 to OG&E's Form 8-K filed May 19, 2011 (File No. 1-1097) and incorporated by reference herein).		X
3.04	Copy of Amended Oklahoma Gas and Electric Company By-laws dated November 30, 2015. (Filed as Exhibit 3.02 to OGE Energy's Form 8-K filed November 30, 2015 (File No. 1-12579) and incorporated by reference herein).		X
4.01	Trust Indenture dated October 1, 1995, from OG&E to Boatmen's First National Bank of Oklahoma, Trustee. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed October 24, 1995 and incorporated by reference herein).	X	X
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).	X	X
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).	X	X
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).	X	X
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).	X	X
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).	X	X
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).	X	X
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).	X	X
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).	X	X
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).	X	X
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).	X	X
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).	X	X
4.13	Supplemental Indenture No. 14 dated as of March 15, 2014 , being a 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).	X	X
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).	X	X
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).	X	X


4.16	Supplemental Indenture No. 17 dated as of August 1, 2017 , being a 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).	X	X
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 OG&E 's Registration Statement on Form S-3ASR filed May 18, 2018 (File No. 333-225030 -01 ) and incorporated by reference herein).	X	X
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 O G&E 's Form 8-K filed August 17, 2018 (File No. 1-1 097 ) and incorporated by reference herein).	X	X
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 OG &E 's Form 8-K filed June 7, 2019 (File No. 1-1 097 ) and incorporated by reference herein).	X	X
4.20	Supplemental Indenture No. 21 dated as of April 1, 2020 , being a supplemental instrument to Exhibit 4 .01 hereto. (Filed as Exhibit 4.01 to OG &E 's Form 8-K filed April 1, 2020 (File No. 1-1 097 ) and incorporated by reference herein).	X	X
4.21	Supplemental Indenture No. 22 dated as of May 27, 2021 , be ing a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed May 27 , 2021 (File No. 1-1097) and incorporated by reference herein).	X	X
4.22	Supplemental Indenture No. 23 dated as of January 5, 2023, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed January 5, 2023 (File No. 1-1097) and incorporated by reference herein).	X	X
4.23	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).	X
4.24	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).	X
4.25	Supplemental Indenture No. 3 dated as of April 26, 2018 , being a supplemental instrument to Exhibit 4.2 2 hereto. (Filed as Exhibit 4.04 to OGE Energy's Registration Statement on Form S-3ASR filed May 18, 2018 (File No. 333-225030) and incorporated by reference herein).	X
4.26	Supplemental Indenture No. 4 dated as of May 27, 2021 , be ing a supplemental instrument to Exhibit 4.22 hereto . (Filed as Exhibit 4.01 to OGE Energy's Form 8-K filed May 27, 2021 (File No. 1-12579) and incorporated by reference herein).	X
4.27+	Description of Capital Stock.	X
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).	X	X
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).	X	X
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).	X	X
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).	X	X
10.05*	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).	X	X
10.06*	Amendment No. 1 to the OGE Energy Corp. Supplemental Executive Retirement Plan. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended June 30, 2021 (File No. 1-12579) and incorporated by reference herein).	X	X
10.07*	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).	X	X


10.08*	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).	X	X
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).	X	X
10.10*+	OGE Energy's Director Compensation.	X	X
10.11*+	OGE Energy's Executive Officer Compensation.	X	X
10.12*	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).	X	X
10.13*	OGE Energy's 2022 Stock Incentive Plan. (Filed as Appendix B to OGE Energy's Proxy Statement for the 2022 Annual Meeting of Shareholder (File No. 1-12579) and incorporated by reference herein).	X	X
10.14*+	OGE Energy's 2023 Annual Executive Incentive Compensation Plan.	X	X
10.15*	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).	X	X
10.16*	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).	X	X
10.17*+	Form of Performance Unit Agreement under OGE Energy's 2022 Stock Incentive Plan.	X	X
10.18*+	Form of Restricted Stock Unit Agreement under OGE Energy's 2022 Stock Incentive Plan.	X	X
10.19*	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).	X	X
10.20	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).	X	X
10.21	Amended and Restated Credit Agreement dated as of December 17, 2021 by and among OGE Energy Corp. and Wells Fargo Bank, National Association, as Agent, JPMorgan Chase Bank, N.A. and Mizuho Bank, Ltd., as Co-Syndication Agents, 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 December 21, 2021 (File No. 1-12579) and incorporated by reference herein).	X
10.22	First Amendment dated as of December 19, 2022, to Amended and Restated Credit Agreement dated as of December 17, 2021, by and among OGE Energy, the Lenders thereto, Wells Fargo Bank, National Association, as Agent, JPMorgan Chase Bank, N.A. and Mizuho Bank, Ltd., as Co-Syndication Agents, and MUFG Bank, Ltd., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents. (Filed as Exhibit 10.01 to OGE Energy's Form 8-K filed December 19, 2022 (File No. 1-12579) and incorporated by reference herein).	X
10.23	Amended and Restated Credit Agreement dated as of December 17, 2021 by and among Oklahoma Gas and Electric Company and Wells Fargo Bank, National Association, as Agent, JPMorgan Chase Bank, N.A. and Mizuho Bank, Ltd., as Co-Syndication Agents, 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 OG&E's Form 8-K filed December 21, 2021 (File No. 1-1097) and incorporated by reference herein).	X	X
10.24	First Amendment dated as of December 19, 2022, to Amended and Restated Credit Agreement dated as of December 17, 2021, by and among OG&E, the Lenders thereto, Wells Fargo Bank, National Association, as Agent, JPMorgan Chase Bank, N.A. and Mizuho Bank, Ltd., as Co-Syndication Agents, and MUFG Bank, Ltd., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents. (Filed as Exhibit 10.02 to OG&E's Form 8-K filed December 19, 2022 (File No. 1-1097) and incorporated by reference herein).	X	X
10.25	Securitization Property Purchase and Sale Agreement dated as of July 20, 2022 by and between Oklahoma Development Finance Authority, as Issuer, and Oklahoma Gas and Electric Company, as Seller. (Filed as Exhibit 10.01 to OGE Energy's Form 8-K filed July 20, 2022 (File No. 1-12579) and incorporated by reference herein).		X
21.01+	Subsidiaries of OGE Energy.	X


23.01+	Consent of Ernst & Young LLP.	X
23.02+	Consent of Ernst & Young LLP.		X
23.03+	Consent of Deloitte & Touche LLP for the Financial Statements of Enable Midstream Partners, LP as of and for the three years ended December 31, 2020 as listed at Exhibit 99.03.	X
24.01+	Power of Attorney.	X
24.02+	Power of Attorney.		X
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.	X
31.02+	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.		X
32.01+	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	X
32.02+	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.		X
99.01	Credit Agreement dated as of May 24, 2022 by and among OGE Energy Corp., the Lenders and BOKF NA, dba Bank of Oklahoma as Sole Administrative Agent, Sole Syndication Agent, Lead Arranger and Sole Bookrunner (Filed as Exhibit 99.01 to OGE Energy's Form 10-Q for the quarter ended June 30, 2022 (File No. 1-12579) and incorporated by reference herein).	X	X
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).	X	X
99.03+	Audited Financial Statements of Enable Midstream Partners, LP as of and for the three years ended December 31, 2020.	X
99.04+	Financial Statements of Enable Midstream Partners, LP as of and for the nine months ended September 30, 2021 (unaudited).	X
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.	X	X
101.SCH	Inline XBRL Taxonomy Schema Document.	X	X
101.PRE	Inline XBRL Taxonomy Presentation Linkbase Document.	X	X
101.LAB	Inline XBRL Taxonomy Label Linkbase Document.	X	X
101.CAL	Inline XBRL Taxonomy Calculation Linkbase Document.	X	X
101.DEF	Inline XBRL Definition Linkbase Document.	X	X
104	Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101).	X	X

* Represents executive compensation plans and arrangements.
+ Represents exhibits filed herewith. All exhibits not so designated are incorporated by reference to a prior filing, as indicated.

OGE ENERGY CORP.

OKLAHOMA GAS AND ELECTRIC COMPANY

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, 2020
Reserve for Uncollectible Accounts	$	1.5	$	3.0	$	1.9	$	2.6
Balance at December 31, 2021
Reserve for Uncollectible Accounts	$	2.6	$	3.2	$	3.4	$	2.4
Balance at December 31, 2022
Reserve for Uncollectible Accounts	$	2.4	$	2.8	$	3.3	$	1.9

(A)

Uncollectible accounts receivable written off, net of recoveries.

Item 16. Form 10-K Summary.

None.

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 22nd, 2023.


	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 22, 2023

/s/ W. Bryan Buckler
W. Bryan Buckler	Principal Financial Officer;	February 22, 2023

/s/ Sarah R. Stafford
Sarah R. Stafford	Principal Accounting Officer;	February 22, 2023

Frank A. Bozich	Director;
Peter D. Clarke	Director;
Cathy R. Gates	Director;
David L. Hauser	Director;
Luther C. Kissam, IV	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 22, 2023

SIGNATURES


	OKLAHOMA GAS AND ELECTRIC COMPANY
	(Registrant)

	By /s/	Sean Trauschke
		Sean Trauschke
		Chairman of the Board, President
		and Chief Executive Officer


Signature	Title	Date

/s/ Sean Trauschke
Sean Trauschke	Principal Executive
	Officer and Director;	February 22, 2023

/s/ W. Bryan Buckler
W. Bryan Buckler	Principal Financial Officer;	February 22, 2023

/s/ Sarah R. Stafford
Sarah R. Stafford	Principal Accounting Officer;	February 22, 2023

Frank A. Bozich	Director;
Peter D. Clarke	Director;
Cathy R. Gates	Director;
David L. Hauser	Director;
Luther C. Kissam, IV	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 22, 2023

EX-4

Exhibit 4.27

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 200,229,215 shares were outstanding on January 31, 2023. 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, our cash flow and ability to pay dividends will be dependent on the earnings and cash flow of our subsidiary and the distribution or other payment of those earnings to us in the form of dividends. 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 Oklahoma Gas and Electric Company ("OG&E") on its common stock. 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.

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 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

Exhibit 10.10

OGE Energy Corp.

Director Compensation

Compensation of non-management directors of OGE Energy Corp. ("OGE Energy") in 2022 included an annual retainer fee of $250,000, of which $110,000 was payable in cash in quarterly installments and $140,000 was deposited in the director's account under OGE Energy's Deferred Compensation Plan and converted to 3,489.5 common stock units based on the closing price of OGE Energy's Common Stock on December 13, 2022. In 2022, the independent directors did not receive additional compensation for attending Board or committee meetings but were instead paid a quarterly cash retainer. The lead director that served in 2022 received an additional $30,000 cash retainer in 2022. The chair of each of the Compensation, Nominating, Corporate Governance and Stewardship and Audit Committees that served in 2022 received an additional $15,000 annual cash retainer in 2022. 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 OGE Energy and Oklahoma Gas and Electric Company in 2022.

Under OGE Energy'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 2022 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 OGE Energy's Deferred Compensation Plan. In 2022, 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. When an individual ceases to be a director of OGE Energy, all amounts credited under OGE Energy'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 OGE Energy's Deferred Compensation Plan.

On December 6, 2022, the Compensation Committee met to consider director compensation. At that meeting, the Compensation Committee recommended, and the Board subsequently approved, increasing the annual cash retainer from $110,000 in 2022 to $115,000 for 2023 and the annual equity retainer, credited on December 13, 2022, was increased from $135,000 to $140,000.

EX-10

Exhibit 10.11

OGE Energy Corp.

Executive Officer Compensation

Executive Compensation

In December 2022, the Compensation Committee of the OGE Energy Corp. ("OGE Energy") board of directors took actions setting executives' salaries and target amount of annual incentive awards for 2023. In February 2023, the Compensation Committee took action setting executives' target amounts of long-term compensation awards for 2023. 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 2023 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 2023 for the OGE Energy officers who are expected to be named in the Summary Compensation Table in OGE Energy's 2023 Proxy Statement are listed in the table below.


Executive Officer	2023 Base Salary
Sean Trauschke, Chairman, President and Chief Executive Officer	$1,158,292
W. Bryan Buckler, Chief Financial Officer	$489,720
William H. Sultemeier, General Counsel, Corporate Secretary and Chief Compliance Officer	$497,490
Donnie O. Jones, Vice President - Utility Operations of OG&E	$437,076
Cristina F. McQuistion, Vice President - Corporate Responsibility and Stewardship	$351,488

Establishment of 2023 Annual Incentive Awards

As stated above, at its December 2022 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 2023 corporate goals to receive from 0 percent to 200 percent of such targeted amount. For 2023, the targeted amount ranged from 45 percent to 110 percent of the approved 2023 base salary for the executive officers in the above table.

Establishment of Long-Term Awards

At its February 2023 meeting, the Compensation Committee approved the level of target long-term incentive awards, expressed as a percentage of salary. For 2023, the targeted amount ranged from 80 percent to 360 percent of the approved 2023 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 OGE Energy's employees hired before December 1, 2009, including executive officers, are eligible to participate in OGE Energy's Pension Plan and certain employees are eligible to participate in OGE Energy's Restoration of Retirement Income Plan that enables participants, including executive officers, to receive the same benefits that they would have received under OGE Energy'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 OGE Energy's Board of Directors who may not otherwise qualify for a sufficient level of benefits under OGE Energy'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 OGE Energy, 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 75 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, OGE Energy contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation. OGE Energy 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 OGE Energy 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, OGE Energy's contribution may be directed to any available investment option in the 401(k) Plan. OGE Energy match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their OGE Energy 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 OGE Energy or its affiliates.

OGE Energy 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 OGE Energy 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.

OGE Energy 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 OGE Energy or termination of the plan.

Deferrals, plus any OGE Energy 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 2022, 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 OGE Energy'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 OGE Energy's Plan Administration Committee.

Perquisites. OGE Energy 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 OGE Energy's executive officers has an employment agreement with OGE Energy. 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 OGE Energy "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, OGE Energy's Board of Directors decided not to include this additional benefit in OGE Energy's agreements. Instead, under OGE Energy'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 OGE Energy'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-10

Exhibit 10.14

OGE ENERGY CORP.

2023 ANNUAL EXECUTIVE INCENTIVE COMPENSATION PLAN

PURPOSE

The purpose of the 2023 Annual Executive Incentive Compensation Plan (the “Executive STI Plan”) is to maximize the efficiency and effectiveness of the operations of OGE Energy Corp. and its subsidiaries by providing incentive compensation opportunities to certain key executives and managers responsible for operational effectiveness. The Executive STI Plan is intended to encourage and reward the achievement of certain results critical to meeting the Company's operational goals. It is also designed to assist in the attraction and retention of quality employees, to link further the financial interest and objectives of employees with those of the Company and to foster accountability and teamwork throughout the Company.

This Executive STI Plan is designed to provide incentive compensation opportunities; awards made under this Executive STI Plan are in addition to base salary adjustments given to maintain market competitive salary levels. The Executive STI Plan shall be effective as of February 22, 2023.

II.

DEFINITIONS

When used in the Executive STI Plan, the following words and phrases shall have the following meanings:

2.1

“Affiliate” means in respect of Energy Corp. or other Company, any corporation, limited liability company, partnership, joint venture, trust, association or other business enterprise which is a member of the same controlled group of corporations, trades or businesses as Energy Corp. or such other Company, as the case may be, within the meaning of Code Section 414(b) or (c); provided, however, that, except for purposes of the term “Affiliate” when used in Section 10.3 below, in applying Code Section 1563(a)(1), (2), and (3) in determining a controlled group of corporations under Code Section 414(b), the language “at least 50 percent” shall be used instead of “at least 80 percent” each place it appears in Code Section 1563(a)(1), (2), and (3), and in applying Treasury Reg.§ 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code Section 414(c), “at least 50 percent” shall be used instead of “at least 80 percent” each place it appears in Treasury Reg. § 1.414(c)-2.

2.2

“Base Salary” means the actual base salary paid to a Participant during the Plan Year as shown in the payroll records of the Company (annualized in the event the Participant was not employed for the whole of such Plan Year or whose salary was changed during the Plan Year).

2.3

“Board” means the Board of Directors of Energy Corp.

2.4

“Change of Control” shall mean the happening of any of the following events:

(i)

An acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 35% or more of either (1) the then outstanding shares of common stock of Energy Corp. (the “Outstanding Company Common Stock”) or (2) the combined voting power of the then outstanding voting securities of Energy Corp. entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); excluding, however, the following: (1) any acquisition directly from Energy Corp., (2) any acquisition by Energy Corp., (3) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Energy Corp. or any corporation or other Person controlled by Energy Corp. or (4) any acquisition by any corporation or other Person pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (iii) below provided, however, that it shall not be deemed a Change of Control if the Person acquires beneficial ownership of 35% or more of the Outstanding Company Common Stock or Outstanding Company Voting Securities solely as a result of an acquisition by Energy Corp. of shares of Energy Corp. common stock, until such time thereafter as such Person shall become the beneficial owner (other than by means of a stock dividend or stock split) of any additional shares of Energy Corp. common stock; or

(ii)

A change in the composition of the Board such that the individuals who, as of February 22, 2023, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual who becomes a member of the Board subsequent to February 22, 2023, whose election, or nomination for election by Energy Corp.'s shareholders, was approved by a vote of at least a majority of those individuals then

comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board; but, provided further, that any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board shall not be so considered as a member of the Incumbent Board; or

(iii)

Consummation of a reorganization, merger, share exchange or consolidation or sale or other disposition of all or substantially all of the assets of Energy Corp. (a “Business Combination”), excluding, however, such a Business Combination pursuant to which (1) all or substantially all of the individuals and entities who are the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the outstanding shares of common stock or equity interests and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors or other controlling persons, as the case may be, of the corporation or other Person resulting from such Business Combination (including, without limitation, a corporation or other Person which as a result of such transaction owns Energy Corp. or all or substantially all of Energy Corp.'s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (other than the corporation or other Person resulting from such Business Combination or any employee benefit plan (or related trust) of Energy Corp. or such corporation or other Person resulting from such Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the outstanding shares of common stock or equity interests of the corporation or other Person resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation or other Person except to the extent that such ownership existed with respect to Energy Corp. prior to the Business Combination and (3) at least a majority of the members of the board of directors or other governing body of the corporation or other Person resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or the action of the Board, providing for such Business Combination; or

(iv)

The approval by the shareholders of Energy Corp. of a complete liquidation or dissolution of Energy Corp.

2.5

“Code” means the Internal Revenue Code of 1986, as amended.

2.6

“Committee” shall mean the Compensation Committee of the Board or any subcommittee appointed by the Compensation Committee and approved by the Board.

2.7

“Company” means Energy Corp., its subsidiary, Oklahoma Gas and Electric Company, and any directly or indirectly owned domestic subsidiary or division of these entities, as designated by the Committee for participation in the Executive STI Plan.

2.8

“Company Performance Goals” shall have the meaning ascribed to it by Section 6.2 hereof.

2.9

“Earned Award” means the Earned Individual Award, if any, and the Earned Company Award, if any, for a Participant for the applicable Plan Year.

2.10

“Earned Company Award” means the actual award earned under a Participant's Target Company Award during a Plan Year as determined by the Committee after the end of the Plan Year (pursuant to Section 6.3 hereof).

2.11

“Earned Individual Award” means the actual award earned under a Participant's Target Individual Award during a Plan Year as determined by the Committee after the end of the Plan Year (pursuant to Section 5.4 hereof).

2.12

“Energy Corp.” shall mean OGE Energy Corp. and its successors and assigns.

2.13

“Executive STI Plan” means this 2023 Annual Incentive Compensation Plan, as it may be amended from time to time.

2.14

“Participant” means any officer, executive or other key employee of the Company who has been selected by the Committee to be eligible to receive an award under the Executive STI Plan as provided in Article IV. Members of the Board who are not employed on a full-time basis by the Company are not eligible to receive awards under the Executive STI Plan.

2.15

“Performance Matrix” means the chart or charts or other schedules approved by the Committee that are used to determine the percentage of each Participant's Target Company Award which the Participant will actually receive as a result of the attainment of Company Performance Goals.

2.16

“Plan Year” means a fiscal year beginning January 1 and ending December 31.

2.17

“Separation from Service” means, in respect of a Participant, the Participant's “separation from service” (as such phrase is defined in Code Section 409A and the regulations promulgated thereunder) with the Participant's employing Company and its Affiliates because of death, retirement or termination of employment for any other reason; provided, however, that no Separation of Service shall be deemed to occur for purposes of the Executive STI Plan while the Participant continues to perform services for such Company or its Affiliates in a capacity as an employee or as an independent contractor at a level that is more than 20% of the average level of bona fide services performed (whether as an employee or otherwise) by the Participant during the immediately preceding 36-month period (or, if employed less than 36 months, such lesser period).

2.18

“Target Company Award” means an award established pursuant to Article VI hereof. Such Target Company Award shall be expressed as a percentage of the Participant's Base Salary.

2.19

“Target Individual Award” means an award established pursuant to Article V hereof. Such Target Individual Award shall be expressed as a percentage of the Participant's Base Salary.

III.

ADMINISTRATION OF THE EXECUTIVE STI PLAN

The Executive STI Plan shall be administered by the Committee. Subject to the provisions of the Executive STI Plan, the Board shall have exclusive authority to amend, modify, suspend or terminate the Executive STI Plan at any time.

IV.

ELIGIBILITY AND PARTICIPATION

4.1

Eligibility. Eligibility for participation in the Executive STI Plan shall be limited to those officers, executives or other key employees of the Company who are nominated for participation by the Chief Executive Officer of Energy Corp. (the “Chief Executive Officer”) and then selected by the Committee to participate in the Executive STI Plan.

4.2

Participation. Participation in the Executive STI Plan shall be determined annually based upon nomination by the Chief Executive Officer and selection by the Committee. Specific criteria for participation shall be determined by the Committee prior to the beginning of each Plan Year. Persons selected for participation shall be notified in writing of their selection, and of their individual performance goals and Company Performance Goals and related Target Individual Awards and Target Company Awards, as soon after approval as is practicable.

4.3

Partial Plan Year Participation. Subject to Article VI herein, the Committee may, upon recommendation of the Chief Executive Officer, allow an individual who becomes eligible after the beginning of a Plan Year to participate in the Executive STI Plan for that period. In such case, the Participant's Earned Award normally shall be prorated based on the number of full months of participation during such Plan Year. However, subject to Section 5.1 and Article VI herein, the Chief Executive Officer, subject to Committee approval, may authorize an unreduced Earned Award.

4.4

Termination of Approval. In its sole discretion, the Committee may withdraw its approval for participation in the Executive STI Plan with respect to a Plan Year for a Participant at any time during such Plan Year; provided, however, that such withdrawal must occur before the end of such Plan Year and provided further that, in the event a Change of Control occurs during a Plan Year, the Committee may not thereafter withdraw its approval for a Participant during such Plan Year. In the event of such withdrawal, the employee concerned shall cease to be a Participant as of the date designated by the Committee, and the employee shall not be entitled to any part of an Earned Award for the Plan Year in which such withdrawal occurs. Such employee shall be notified of such withdrawal in writing as soon as practicable following such action.

INDIVIDUAL AWARDS

5.1

Award Opportunities. In each Plan Year, the Committee shall establish Target Individual Award levels for each Participant who is to be granted an opportunity to achieve an Earned Individual Award. The established levels may vary in relation to the responsibility level of the Participant. In the event a Participant changes job levels during the Plan Year, the Target Individual Award may be adjusted at the discretion of the Chief Executive Officer to reflect the amount of time at each job level, subject to approval of the Committee at the time of determining the Earned Individual Award under Section 5.4. Notwithstanding any provision in this Executive STI Plan to the contrary, for any Plan Year Target Individual Awards shall not be dependent in any manner on, and shall be established independently of and in addition to, the establishment of any Target Company Awards or the payout of any Earned Company Awards pursuant to Article VI herein.

5.2

Individual Performance Goals. In each Plan Year, the Chief Executive Officer shall recommend individual performance goals (which may be based in whole or in part on one or more performance measures relating to Energy Corp. and/or any of its

subsidiaries and/or one or more business or functional units thereof) for each Participant who is granted a Target Individual Award. The Committee shall consider and approve or modify the recommendations as appropriate. The level of achievement of the Participant's individual performance goals at the end of the Plan Year, as determined pursuant to Section 5.4 below, will determine such Participant's Earned Individual Award, which may range from 0% to 200% of such Participant's Target Individual Award.

5.3

Adjustment of Individual Performance Goals. The Chief Executive Officer shall have the right to adjust the individual performance goals (either up or down) during the Plan Year if he determines that external changes or other unanticipated conditions have materially affected the fairness of the goals and unduly influenced the ability to meet them; provided, however, that no such adjustment to the Chief Executive Officer's individual performance goals shall be made unless approved by the Committee; and provided further that no adjustment of such individual performance goals for any Participant shall be made based upon the failure, or the expected failure, to attain or exceed the Company Performance Goals for any Target Company Award granted to such Participant under Article VI herein and provided further that no adjustment shall be made of such individual performance goals for a Plan Year in which a Change of Control occurs.

5.4

Earned Individual Award Determination. After the end of each Plan Year, the Chief Executive Officer shall review the level of achievement of the individual performance goals of each Participant who received a Target Individual Award. Based on the Chief Executive Officer's determination as to the level of achievement of a Participant's individual performance goals, the Chief Executive Officer shall make a recommendation to the Committee as to the Earned Individual Award to be received by such Participant. The payment of all Earned Individual Awards is subject to approval by the Committee. The payment of an Earned Individual Award to a Participant shall not be contingent in any manner upon the attainment of, or failure to attain, the Company Performance Goals for the Target Company Awards granted to such Participant under Article VI.

VI.

COMPANY AWARDS

In addition to any Target Individual Awards granted under Article V, Target Company Awards based solely on performance of Energy Corp., one or more of its subsidiaries or one or more business or functional units thereof may be established under this Article VI for Participants.

6.1

Award Opportunities. In each Plan Year, the Committee shall establish in writing for each Participant for whom a Target Company Award is to be granted under this Article VI, the Target Company Award and specific objective performance goals for the Plan Year, which goals shall meet the requirements of Section 6.2 herein (such goals are hereinafter referred to as “Company Performance Goals”). The extent, if any, to which an Earned Company Award will be payable to a Participant will be based solely upon the degree of achievement of such preestablished Company Performance Goals over the specified Plan Year; provided, however, that, unless and until a Change of Control occurs, the Committee may, in its sole discretion, reduce or eliminate the amount which would otherwise be payable with respect to a Plan Year. Payment of an Earned Company Award to a Participant shall consist of a cash award from the Company to be based upon a percentage (which may range from 0% to 200%) of the Participant's Target Company Award.

6.2

Company Performance Goals. The Company Performance Goals established by the Committee pursuant to Section 6.1 will be based on one or more, or a combination, of the following relating to Energy Corp., one or more of its subsidiaries, or one or more business or functional units thereof: total shareholder return; return on equity; return on capital; earnings per share; market share; stock price; sales; costs; net operating income; net income; return on assets; earnings before income taxes, depreciation and amortization; return on total assets employed; capital expenditures; earnings before income taxes; economic value added; cash flow; cash available for distribution; retained earnings; results of customer satisfaction surveys; aggregate product price and other product price measures; safety record; service reliability; demand-side management (including conservation and load management); operating and/or maintenance cost management (including operation and maintenance expenses per Kwh); and energy production availability performance measures. At the time of establishing a Company Performance Goal, the Committee shall specify the manner in which the Company Performance Goal shall be calculated. In so doing, the Committee may exclude the impact of certain specified events from the calculation of the Company Performance Goal. For example, if the Company Performance Goal were earnings per share, the Committee could, at the time this Company Performance Goal was established, specify that earnings per share are to be calculated without regard to any subsequent change in accounting standards required by the Financial Accounting Standards Board. Company Performance Goals also may be based on the attainment of specified levels of performance of Energy Corp., and/or any of its subsidiaries and/or one or more business or functional units thereof under one or more of the measures described above relative to the performance of other corporations or indices. As part of the establishment of Company Performance Goals for a Plan Year, the Committee shall also establish a minimum level of achievement of the Company Performance Goals that must be met for a Participant to receive any portion of his Target Company Award.

6.3

Payment of an Earned Company Award. At the time the Target Company Award for a Participant is established, the Committee

shall prescribe a formula to determine the percentage (which may range from 0% to 200%) of the Target Company Award which may be payable to the Participant based upon the degree of attainment of the Company Performance Goals during the Plan Year. Such formula may be expressed in terms of a graph or chart in which the amount that may be payable to a Participant is dependent upon the combined degree of attainment of more than one Company Performance Goal. Upon written certification by the Committee that the Company Performance Goals have been satisfied to a particular extent and that any other material terms and conditions of the Target Company Awards have been satisfied, payment of an Earned Company Award shall be made to the Participant for that Plan Year in accordance with the prescribed formula except that, unless and until a Change of Control occurs, the Committee may determine, in its sole discretion, to reduce or eliminate the payment to be made.

VII.

FORM AND TIME OF PAYMENT OF AWARDS

Earned Award payments, if any, to be made for a Plan Year under Articles V and VI shall be paid, in cash, as soon as practicable after the end of the Plan Year during which the award was earned, but in no event later than the 15th day of the third month after the end of such Plan Year.

VIII.

SEPARATION FROM SERVICE

8.1

Separation from Service Due to Death, Disability, or Retirement. In the event a Participant incurs a Separation from Service by reason of death, total and permanent disability (as determined by the Committee), or retirement (as determined by the Committee) during a Plan Year and such separation does not occur within twenty-four (24) months after a Change of Control, the Participant shall retain his or her right to an Earned Award, determined in accordance with Section 5.4 and Section 6.3 herein, for such Plan Year, which Earned Amount shall be reduced to reflect the Participant's participation prior to such Separation from Service. This reduction shall be determined by multiplying said Earned Award by a fraction; the numerator of which is the months of participation through the date of separation rounded up to whole months and the denominator of which is 12. The Earned Award thus determined for a Plan Year shall be paid as provided in Article VII.

8.2

Separation from Service for Other Reasons. In the event a Participant incurs a Separation from Service for any reason other than death, total and permanent disability (as determined by the Committee) or retirement (as determined by the Committee) during a Plan Year and such termination does not occur within twenty-four (24) months after a Change of Control, all of the Participant's rights to an Earned Award for the Plan Year then in progress shall be forfeited; provided that, except in the event of a Separation from Service for cause (as determined in the sole discretion of the Committee and without regard to Section 10.2 hereof), the Committee, in its sole discretion, may pay the Earned Award, determined in accordance with Section 5.4 and Section 6.3 herein, for such Plan Year, reduced to reflect the prorated portion of that Plan Year that the Participant was employed by Energy Corp. or any of its subsidiaries, computed as determined by the Committee. The Earned Award thus determined for a Plan Year shall be paid as provided in Article VII.

IX.

BENEFICIARY DESIGNATION

Each Participant under the Executive STI Plan may, from time to time, name any beneficiary or beneficiaries (who may be named contingently or successively and who may include a trustee under a will or living trust) to whom any benefit under the Executive STI Plan is to be paid in case of his death before he received any or all of such benefit. Each designation will revoke all prior designations by the same Participant, shall be in a form prescribed by the Committee, and will be effective only when filed by the Participant in writing with the Committee during his lifetime. In the absence of any such designation, or if all designated beneficiaries predecease the Participant, benefits remaining unpaid at the Participant's death shall be paid to the Participant's estate.

CHANGE OF CONTROL

10.1

Termination Other than for Cause. Notwithstanding any other provisions of the Executive STI Plan, in the event a Participant incurs a Separation from Service voluntarily or involuntarily for any reason other than for cause (with cause being determined by the Committee in accordance with Section 10.2 hereof), within twenty-four (24) months after a Change of Control, the Target Company Award and Target Individual Award, if any, established for the Participant for the Plan Year in progress at the time of the employment termination, prorated for the number of days in the Plan Year in which the Participant was employed by Energy Corp. or any of its subsidiaries, up to and including the date of separation, shall be paid to the Participant within ten (10) business days after the Separation from Service. Provided, however, any such payment to a Participant pursuant to this Section 10.1 shall be reduced to the extent the Participant otherwise is entitled to receive payment of such Target Company Award or Target Individual Award pursuant to the terms of any employment agreement, plan, contract or other arrangement involving the Participant and Energy Corp. or any of its subsidiaries.

10.2

Termination for Cause. In the event a Participant incurs a Separation from Service for cause (as determined by the Committee in the manner hereinafter set forth) within twenty-four (24) months after a Change of Control, no Earned Award will be paid

for the Plan Year in progress at the time of the Separation from Service; provided that, following a Change of Control, a Participant shall be deemed to have a Separation from Service for cause only if his employment was terminated involuntarily at the written direction of the Committee due solely to: (i) the willful and continued failure of the Participant to substantially perform his duties (other than any such failure resulting from physical or mental illness) for a minimum period of two weeks after receiving a written demand for substantial performance from the Committee which specifically identifies the manner in which the Committee or Chief Executive Officer believes that the Participant has not substantially performed his duties or (ii) the willful engaging by the Participant in illegal conduct or gross misconduct that is materially and demonstrably injurious to the Company.

XI.

MISCELLANEOUS

11.1

Nontransferability. No Participant shall have the right to anticipate, alienate, sell, transfer, assign, pledge or encumber his or her right to receive any award made under the Executive STI Plan until such an award becomes payable to him or her.

11.2

No Right to Company Assets. Any benefits which become payable hereunder shall be paid from the general assets of Energy Corp. or applicable subsidiary. No Participant shall have any lien on any assets of the Company by reason of any award made under the Executive STI Plan.

11.3

No Implied Rights; Employment. The adoption of the Executive STI Plan or any modification or amendment hereof does not imply any commitment to continue or adopt the same plan, or any modification thereof, or any other plan for incentive compensation for any succeeding year, provided, that no such modification or amendment shall adversely affect the rights of any person, without his or her written consent, under any award theretofore granted under the Executive STI Plan unless such modification or amendment is made in order to cause the Executive STI Plan or award to comply with, or qualify for an exemption from, Code Section 409A and the regulations promulgated thereunder. Neither the Executive STI Plan nor any award made under the Executive STI Plan shall create any employment contract between the Company and any Participant.

11.4

Participation. No Participant or other employee shall at any time have a right to be selected for participation in the Executive STI Plan for any Plan Year, despite having been selected for participation in a prior Plan Year. Nothing in this Executive STI Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon any Participant any right to continue in the employ of the Company.

11.5

All Determinations Final. All determinations of the Committee or the Board as to any disputed questions arising under the Executive STI Plan, including questions of construction and interpretation, shall be final, binding and conclusive upon all Participants and all other persons and shall not be reviewable.

11.6

Executive STI Plan Description. Each Participant shall be provided with an Executive STI Plan description and an Executive STI Plan agreement for each Plan Year which shall include Target Individual Awards, individual performance goals, Target Company Awards, Company Performance Goals and a Performance Matrix for each year. In the event of a conflict between the terms of the Executive STI Plan description and the Executive STI Plan, the terms of the Executive STI Plan shall control unless the Committee decides otherwise.

11.7

Successors. This Executive STI Plan shall be binding on the successors and assigns of Energy Corp.

11.8

Section 409A Compliance. It is the intention of the Company that the provisions of this Executive STI Plan comply with Section 409A of the Code, to the extent that the requirements of Section 409A are applicable thereto, and after application of all available exemptions, including but not limited to, the “short-term deferral rule” and “involuntary separation pay plan exception” and the provisions of this Executive STI Plan shall be construed in a manner consistent with that intention. The Company shall not have any liability to Participants with respect to tax obligations that result under any tax law and makes no representation with respect to the tax treatment of the payments and/or benefits provided under this Executive STI Plan. Any provision required for compliance with Section 409A that is omitted from this Executive STI Plan shall be incorporated herein by reference and shall apply retroactively, if necessary, and be deemed a part of this Executive STI Plan to the same extent as though expressly set forth herein.

11.9

Tax Penalty Avoidance. The provisions of this Executive STI Plan are not intended, and should not be construed to be legal, business or tax advice. The Company, Participants and any other party having any interest herein are hereby informed that the U.S. federal tax advice contained in this document (if any) is not intended or written to be used, and cannot be used, for the purpose of (i) avoiding penalties under the Code or (ii) promoting, marketing or recommending to any party any transaction or matter addressed herein.

EX-10

Exhibit 10.17

OGE ENERGY CORP.
PERFORMANCE UNIT AGREEMENT

OGE Energy Corp. (the "Company") hereby awards to __________ (the "Participant") an initial grant (the “Target Number”) of _______ Performance Units pursuant to the OGE Energy Corp. 2022 Stock Incentive Plan (the "Plan"), the definitions and provisions of which are incorporated herein by reference.

The specific terms and conditions of the Award (in addition to the terms and conditions set forth in the Plan) are set forth hereinafter. Capitalized terms used herein that are not defined but that are defined in the Plan are used herein as defined in the Plan.

1. Performance Units and Award Cycle. Each Performance Unit credited to the Participant hereunder represents the right of the Participant to receive, subject to the terms of this Agreement and the Plan, one share of Common Stock and related dividend equivalents as described in Section 4. Subject to the provisions of the Plan, the Performance Units awarded to the Participant may not be sold, assigned, transferred, pledged, hypothecated or otherwise encumbered or disposed of during the award cycle established with respect thereto beginning on __________ and ending on __________ (the "Award Cycle").

2. Performance Goal Condition. The Performance Units are contingently awarded at the Target Number level subject to the condition that the number of Performance Units, if any, earned by the Participant upon the expiration of the Award Cycle will be a percentage of the Target Number and such percentage is dependent (in the manner hereinafter set forth) on the performance of the Company's total shareholder return relative to the total shareholder return of all of the companies (the "EEI Companies") comprising the Edison Electric Institute Index of U.S. Shareholder-Owned Electric Utilities as of __________ and __________ (or their successors from a merger or other combination with another company listed in such Index, but excluding any company subject to a Business Combination, as hereinafter defined on __________). Total shareholder return ("TSR") for any company, including the Company, shall include both price appreciation (depreciation) and cash dividends, shall be calculated in the same manner that EEI calculated total return as of __________ and shall be measured by the company's total return that shareholders receive over the Award Cycle by investment at the first day of the Award Cycle.

The number of Performance Units earned is dependent on the performance ranking of the Company's total shareholder return for the Award Cycle, as set forth below (expressed in terms of the Company's position among the EEI Companies when ranked by total shareholder return for the Award Cycle):


COMPANY TSR PERCENTILE RANKING VS. EEI COMPANIES	PERCENT OF TARGET NUMBER OF PERFORMANCE UNITS EARNED
____ percentile	____%
____ percentile	____%
____ percentile	____%
____ percentile	____%
____ percentile	____%
____ percentile	____%
____ percentile	____%
____ percentile	____%
Below ____ percentile	____%

Performance Units earned for performance between the percentiles shown above will be determined by straight-line interpolation; provided, that, in all cases, the number of Performance Units which the Participant earns shall be a whole number (disregarding any fraction).

Any portion of the Target Number of Performance Units awarded hereunder that the Participant does not earn at the end of the Award Cycle pursuant to the foregoing schedule shall be forfeited.

The provisions of this Section 2 shall not affect in any way any forfeiture under Section 5 below or Section 8(b) of the Plan or any provision regarding the earning of Performance Units at the 100% level under Section 9 of the Plan upon the occurrence of a Change of Control.

For purposes of determining whether any of the EEI Companies is subject to a Business Combination on __________, a company shall be deemed subject to a Business Combination on __________, if such company is: (i) the subject of a tender offer or exchange offer by a third party seeking to acquire more than 20% of the outstanding voting securities of such company

or (ii) a party to a merger, consolidation, share exchange or reorganization agreement or an agreement providing for the sale or disposition of all or substantially all of its assets.

3. Payout. Subject to Section 9 of the Plan, as soon as practicable following the end of the Award Cycle, the Committee shall evaluate the actual performance of the Performance Goal set forth in Section 2, shall certify in writing the extent to which such Performance Goal and other material terms of this award have been satisfied and shall determine the number, if any, of Performance Units that have been earned (the "Earned Performance Units"). The Committee shall then cause to be issued to the Participant (or, in the event of the Participant's death, to the Participant's beneficiary under the Plan) no later than March 15, 2026: (i) a certificate for shares of Common Stock equal in number to the Earned Performance Units (disregarding any fraction) and (ii) a lump sum cash payment equal to the amount of any applicable cash dividends as described in Section 4.

4. Dividend Equivalents. The Participant will receive at the time of payout of the Participant’s Earned Performance Units a cash payment equal to the sum of any cash dividends declared that would have been paid on the number of shares of Common Stock payable in respect of such Earned Performance Units, with respect to cash dividends on the outstanding shares of the Common Stock declared by the Board and with a record date during the Award Cycle.

5. Forfeiture. All Performance Unit awards are subject to the terms and conditions of the Plan relating to Performance Units. If the Participant incurs a Termination of Employment for any reason on or before the end of the Award Cycle, all rights to or in respect of Performance Units awarded hereunder shall be forfeited except as provided in Section 8(b)(iii) or Section 9(a)(iii) of the Plan and except that, [in the case of the Participant's Termination of Employment after being credited with at least 80 Points as defined in Section 2.49 of the OGE Energy Corp. Retirement Plan, as amended and restated effective as of January 1, 2013, such Termination of Employment will be considered a Termination of Employment due to Retirement under Section 8(b)(iii) of the Plan.

6. Acceptance of Award. By acceptance of this Agreement, the Participant accepts the Award, acknowledges receipt of a copy of the Plan, and represents that the Participant is familiar with the terms and provisions thereof and agrees to be bound thereby. The Participant further agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee with respect to any questions arising under the Plan and this Agreement, including any calculation of, or in connection with, the total shareholder return of the Company or any other company for the Award Cycle.

7. Taxes and Other Matter.

(a) By acceptance of this Agreement, the Participant agrees to pay all withholding and other taxes payable by the Participant with respect to Performance Units earned under this Agreement at such times and in such manner as the Company may request, and the Participant further agrees to comply with all Federal and State securities laws.

(b) The Participant may elect, subject to approval of the Committee, to satisfy the Participant’s tax withholding requirements under Federal, State and local laws and regulations thereunder in respect of a Performance Unit, in whole or in part, by having the Company withhold shares of Common Stock having a Fair Market Value equal to all or a portion of the amount so required to be withheld. The Fair Market Value of the shares to be withheld is to be based upon the same price of the shares that is utilized to determine the amount of withholding tax that the Participant owes. All elections under this Section 7(b) shall be (i) irrevocable and (ii) made electronically through the Company Stock Plan Services Administrator (or by such other method as the Committee determines).

8. Clawback Provision. Notwithstanding any provision of this Agreement or the Plan to the contrary, any Performance Units awarded hereunder may be cancelled or forfeited and any Common Stock issued hereunder may be forfeited and required to be repaid to the Company (including, for the avoidance of doubt, any cash received in the settlement of an Award) upon such terms and conditions as may be required by the Committee or under Section 10D of the Exchange Act and any applicable rules or regulations promulgated by the Commission or any national securities exchange or national securities association on which the shares of Common Stock may be traded.

9. Other Condition. The award of Performance Units evidenced by this Agreement shall be subject to the Participant’s timely acceptance of this Agreement.

Date of Agreement: __________

OGE ENERGY CORP.

__________________________________________________
Chairman of the Board, President and Chief Executive Officer

ACCEPTED AND AGREED TO (Effective as of the above Date of Agreement):
_______________
Participant Name

EX-10

Exhibit 10.18

OGE ENERGY CORP.
RESTRICTED STOCK Unit AGREEMENT

OGE Energy Corp. (the "Company") hereby awards to ______________ (the "Participant") ______________ Restricted Stock Units (the “Units”) pursuant to the OGE Energy Corp. 2022 Stock Incentive Plan (the "Plan"), the definitions and provisions of which are incorporated herein by reference.

The specific terms and conditions of the Award are set forth hereinafter. Capitalized terms used herein that are not defined herein but that are defined in the Plan are used herein as defined in the Plan.

1. Nature of Units, Restrictions on Transfer, Vesting and Dividend Equivalents.

(a) Each Unit credited to the Participant hereunder represents the right of the Participant to receive, subject to the terms of this Agreement and the Plan, one share of Common Stock and related dividend equivalents as described in Section 1(d). The Units may not be sold, assigned, transferred, pledged, or otherwise encumbered by the Participant.

(b) Except as provided in Section 1(c) or Section 2, one hundred percent (100%) of the Units shall vest on ______________. The date on which a Unit vests under this Section 1(b) or any other section of this Agreement is hereinafter referred to as the "Vesting Date" and a Unit that has vested is hereinafter referred to as a “Vested Unit.”

(c) Absent a prior forfeiture, each unvested Unit subject to this Agreement shall vest (i) upon a Change of Control or (ii) if determined by the Committee upon an event described in Section 2.

(d) The Participant will receive at the time of payout of the Participant’s Vested Units a cash payment equal to the sum of any cash dividends declared that would have been paid on the number of shares of Common Stock payable in respect of such Vested Units, with respect to cash dividends on the outstanding shares of the Common Stock declared by the Board and with a record date during the period beginning on the date of this Agreement (as set forth at the end of this Agreement and hereinafter referred to as the “Date of Agreement”) and ending on the Vesting Date.

2. Termination of Service.

If the Participant has a Termination of Employment, all Units which are then not vested shall be forfeited and of no further effect; provided, however, that if the Participant incurs such a Termination of Employment due to death, Disability, Retirement or involuntary termination the Committee may provide that all or a portion of such unvested Units shall become Vested Units upon such event.

3. Vesting and Payout of Units.

As soon as practicable following the Vesting Date for one or more of the Units (and in any event no later than March 15 of the year following the year in which the Vesting Date occurs), the Company shall cause to be delivered to the Participant: (i) a number of shares of Common Stock (less the number of shares withheld pursuant to Section 6(b)) equal to the number of Vested Units in such manner as the Committee may deem appropriate, including book-entry or other electronic registration or issuance of one or more stock certificates, provided that any fractional Units shall be settled in cash based on the Fair Market Value of a share of Common Stock on the date on which shares of Common Stock are delivered to the Participant pursuant to this Section 3, and (ii) a lump sum cash payment equal to the amount of any applicable cash dividends as described in Section 1(d).

4. Participant’s Rights.

The Participant acknowledges and agrees that the Units do not evidence, and do not entitle the Participant to, any rights of a shareholder of the Company.

5. Acceptance of Award.

By acceptance of this Agreement, the Participant accepts the Award, acknowledges receipt of a copy of the Plan, and represents that the Participant is familiar with the terms and provisions thereof and agrees to be bound thereby. The Participant further agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee with respect to any questions arising under the Plan and this Agreement.

6. Taxes and Other Matters.

(a) By acceptance of this Agreement, the Participant agrees to pay all withholding and other taxes payable with respect to the Units evidenced by this Agreement, at such times and in such manner as the Company may request and to comply with all Federal and State securities laws.

(b) The Participant may elect, subject to approval of the Committee, to satisfy the Participant’s tax withholding requirements under Federal, State and local laws and regulations thereunder in respect of a Vested Unit, in whole or in part, by having the Company withhold shares of Common Stock having a Fair Market Value equal to all or a portion of the amount so required to be withheld. The Fair Market Value of the shares to be withheld is to be based upon the same price of the shares that is utilized to determine the amount of withholding tax that the Participant owes. All elections under this Section 6(b) shall be (i) irrevocable and (ii) made electronically through the Company Stock Plan Services Administrator (or by such other method as the Committee determines).

7. Clawback Provision.

Notwithstanding any provision of this Agreement or the Plan to the contrary, any Units awarded hereunder may be cancelled or forfeited and any Common Stock issued hereunder may be forfeited and required to be repaid to the Company (including, for the avoidance of doubt, any cash received in the settlement of an Award) upon such terms and conditions as may be required by the Committee or under Section 10D of the Exchange Act and any applicable rules or regulations promulgated by the Commission or any national securities exchange or national securities association on which the shares of Common Stock may be traded.

8. Other Condition.

The award of Units evidenced by this Agreement shall be subject to the Participant’s timely acceptance of this Agreement.

Date of Agreement: ______________

OGE ENERGY CORP.
 
Chairman of the Board, President and Chief Executive Officer

ACCEPTED AND AGREED TO (Effective as of the above Date of Agreement):

Participant Name

EX-21

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 OGE Energy's subsidiaries have been omitted from the list above in accordance with Rule 1-02(w) of Regulation S-X.

EX-23

Exhibit 23.01

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statements:

(1)

Registration Statement (Form S-8 No. 333-92423) pertaining to the deferred compensation plan of OGE Energy Corp.,

(2)

Registration Statement (Form S-8 No. 333-104497) pertaining to the employees' stock ownership and retirement savings plan of OGE Energy Corp.,

(3)

Registration Statement (Form S-8 No. 333-190406) pertaining to the employees' stock ownership and retirement savings plan of OGE Energy Corp.,

(4)

Registration Statement (Form S-8 No. 333-190405) pertaining to the 2013 stock incentive plan of OGE Energy Corp.,

(5)

Registration Statement (Form S-3ASR No. 333-249236) pertaining to the dividend reinvestment and stock purchase plan of OGE Energy Corp.,

(6)

Registration Statement (Form S-3ASR No. 333-255823) pertaining to common stock and debt securities of OGE Energy Corp., and

(7)

Registration Statement (Form S-8 No. 333-266540) pertaining to the OGE Energy Corp. 2022 Stock Incentive Plan of OGE Energy Corp.;

of our reports dated February 22, 2023, 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) of OGE Energy Corp. for the year ended December 31, 2022.


/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

February 22, 2023

EX-23

Exhibit 23.02

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-3ASR No. 333-255823-01) of Oklahoma Gas and Electric Company pertaining to debt securities of our reports dated February 22, 2023, with respect to the financial statements and schedule of Oklahoma Gas and Electric Company, and the effectiveness of internal control over financial reporting of Oklahoma Gas and Electric Company, included in this Annual Report (Form 10-K) for the year ended December 31, 2022.


/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

February 22, 2023

EX-23

Exhibit 23.03

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-92423, 333-104497, 333-190406, 333-190405, including Post-Effective Amendment No. 1 thereto, and 333-266540 on Form S-8; and Registration Statement Nos. 333-255823 and 333-249236 on Form S-3ASR of OGE Energy Corp. of our report dated February 24, 2021, relating to the financial statements of Enable Midstream Partners, LP appearing in this Annual Report on Form 10-K of OGE Energy Corp. for the year ended December 31, 2022.

/s/ DELOITTE & TOUCHE LLP

Oklahoma City, Oklahoma

February 22, 2023

EX-24

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, 2022; 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, W. BRYAN BUCKLER 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 22nd day of February, 2023.


Sean Trauschke, Chairman, Principal Executive Officer and Director	/s/	Sean Trauschke
Frank A. Bozich, Director	/s/	Frank A. Bozich
Peter D. Clarke, Director	/s/	Peter D. Clarke
Cathy R. Gates, Director	/s/	Cathy R. Gates
David L. Hauser, Director	/s/	David L. Hauser
Luther C. Kissam, IV	/s/	Luther C. Kissam, IV
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
W. Bryan Buckler, Principal Financial Officer	/s/	W. Bryan Buckler
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 22nd day of February, 2023.

/s/ Kelly G. Hamilton-Coyer

By: Kelly G. Hamilton-Coyer

Notary Public

My commission expires:

July 6, 2025

EX-24

Exhibit 24.02

Power of Attorney

WHEREAS, OKLAHOMA GAS AND ELECTRIC COMPANY, 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, 2022; and

WHEREAS, each of the undersigned holds the office or offices in the Company herein-below set opposite his or her name, respectively;

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 22nd day of February, 2023.


Sean Trauschke, Chairman, Principal Executive Officer and Director	/s/	Sean Trauschke
Frank A. Bozich, Director	/s/	Frank A. Bozich
Peter D. Clarke, Director	/s/	Peter D. Clarke
Cathy R. Gates, Director	/s/	Cathy R. Gates
David L. Hauser, Director	/s/	David L. Hauser
Luther C. Kissam, IV	/s/	Luther C. Kissam, IV
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
W. Bryan Buckler, Principal Financial Officer	/s/	W. Bryan Buckler
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 OKLAHOMA GAS AND ELECTRIC COMPANY, 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 22nd day of February, 2023.

/s/ Kelly G. Hamilton-Coyer

By: Kelly G. Hamilton-Coyer

Notary Public

My commission expires:

July 6, 2025

EX-31

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 22, 2023


/s/ Sean Trauschke
Sean Trauschke
Chairman of the Board, President and Chief Executive Officer

CERTIFICATIONS

I, W. Bryan Buckler, certify that:

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

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

Date: February 22, 2023


/s/ W. Bryan Buckler
W. Bryan Buckler
Chief Financial Officer

EX-31

Exhibit 31.02

CERTIFICATIONS

I, Sean Trauschke, certify that:

1. I have reviewed this annual report on Form 10-K of Oklahoma Gas and Electric Company;

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 22, 2023


/s/ Sean Trauschke
Sean Trauschke
Chairman of the Board, President and Chief Executive Officer

CERTIFICATIONS

I, W. Bryan Buckler, certify that:

1. I have reviewed this annual report on Form 10-K of Oklahoma Gas and Electric Company;

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 22, 2023


/s/ W. Bryan Buckler
W. Bryan Buckler
Chief Financial Officer

EX-32

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. ("OGE Energy") on Form 10-K for the year ended December 31, 2022, 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 OGE Energy.

February 22, 2023


	/s/ Sean Trauschke
	Sean Trauschke
	Chairman of the Board, President and Chief Executive Officer


	/s/ W. Bryan Buckler
	W. Bryan Buckler
	Chief Financial Officer

EX-32

Exhibit 32.02

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 Oklahoma Gas and Electric Company ("OG&E") on Form 10-K for the year ended December 31, 2022, 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 OG&E.

February 22, 2023


	/s/ Sean Trauschke
	Sean Trauschke
	Chairman of the Board, President and Chief Executive Officer


	/s/ W. Bryan Buckler
	W. Bryan Buckler
	Chief Financial Officer

EX-99

Exhibit 99.03

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, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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, 2020, 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 24, 2021 (not presented herein), 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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Evaluation of the estimated undiscounted cash flows in the long-lived assets impairment analysis - Refer to Notes 1 and 8 to the consolidated financial statements

Critical Audit Matter Description

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.

Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing COVID-19 pandemic and the economic effects of the pandemic, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, events or changes in circumstances indicated that the carrying value of certain assets groups in the Gathering & Processing (“G&P”) segment may not be recoverable. The net book value of the G&P asset groups was $7,470 million as of December 31, 2020. The Partnership recognized a $16 million impairment during the year ended December 31, 2020.

Given the significant judgments made by management to estimate the recoverability of G&P asset groups, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future revenues, including the revenue growth rate, of G&P asset groups 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 forecasts of future revenues, including the revenue growth rate, used by management to estimate the recoverability of G&P asset groups included the following, among others:

•

We tested the effectiveness of controls over management’s long-lived assets impairment evaluation, including those over the determination of the recoverability of G&P asset groups, such as controls related to management’s 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:

–

Agreements in place between the Partnership and current customers for G&P asset groups.

–

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 revenue growth rate by:

–

Testing the source information underlying the determination of the revenue growth rate and the mathematical accuracy of the calculation.

–

Developing a range of independent estimates and comparing those to the revenue growth rate selected by management.

Other-Than-Temporary-Impairment (“OTTI”) of the Southeast Supply Header, LLC (“SESH”) equity method investment - Refer to Notes 1 and 11 to the consolidated financial statements

Critical Audit Matter Description

SESH is an approximately 290-mile interstate pipeline that provides transportation services in Louisiana, Mississippi and Alabama. The Partnership own a 50% interest in SESH and provides field operations for the pipeline. Enbridge Inc. owns the remaining 50% interest in SESH and provides gas control and commercial operations for the pipeline.

The Partnership evaluates its investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the fair value of its investment has occurred and the fair value of its investment is less than the carrying amount.

During the third quarter of 2020, due to the expiration of a transportation contract and the current status of renewal negotiations, the Partnership evaluated its equity method investment in SESH for other-than-temporary impairment. The Partnership utilized the market and income approaches to measure the estimated fair value of its investment in SESH. The Partnership determined the decline in value of its investment in SESH was other-than-temporary, and recorded an impairment of its investment in SESH of $225 million.

Given the significant judgments made by management to estimate the fair value of SESH, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future revenues, including the revenue growth

rate, and the selection of the weighted average cost of capital and market multiple of SESH 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, market multiple, and forecasts of future revenues, including the revenue growth rate, used by management to estimate the fair value of SESH included the following, among others:

•

We tested the effectiveness of controls over management’s equity method investment impairment evaluation, including those over the determination of the fair value of SESH, such as controls related to management’s forecasts of future revenues, including the revenue growth rate, and selection of the weighted average cost of capital and market multiple.

•

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:

–

Agreements in place between SESH and current customers.

–

Historical revenues.

–

Internal communications to management and the Board of Directors.

•

With the assistance of our fair value specialists, we evaluated the reasonableness of the (1) valuation methodology and (2) weighted average cost of capital, market multiple, and revenue growth rate by:

–

Testing the source information underlying the determination of the weighted average cost of capital, market multiple, and revenue growth rate and the mathematical accuracy of the calculations.

–

Developing a range of independent estimates and comparing those to the weighted average cost of capital, market multiple, and revenue growth rate selected by management.

/s/ DELOITTE & TOUCHE LLP

Oklahoma City, Oklahoma

February 24, 2021

We have served as the Partnership's auditor since 2013.

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME


	Year Ended December 31,
	2020	2019	2018

	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 16)):
Product sales	$ 1,132	$ 1,533	$ 2,106
Service revenues	1,331	1,427	1,325
Total Revenues	2,463	2,960	3,431
Cost and Expenses (including expenses from affiliates (Note 16)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	965	1,279	1,819
Operation and maintenance	418	423	388
General and administrative	98	103	113
Depreciation and amortization	420	433	398
Impairments of property, plant and equipment and goodwill (Notes 8 and 10)	28	86	—
Taxes other than income tax	69	67	65
Total Cost and Expenses	1,998	2,391	2,783
Operating Income	465	569	648
Other Income (Expense):
Interest expense	(178)	(190)	(152)
Equity in earnings (losses) of equity method affiliate, net	(210)	17	26
Other, net	6	3	—
Total Other Expense	(382)	(170)	(126)
Income Before Income Tax	83	399	522
Income tax benefit	—	(1)	(1)
Net Income	$ 83	$ 400	$ 523
Less: Net income (loss) attributable to noncontrolling interests	(5)	4	2
Net Income Attributable to Limited Partners	$ 88	$ 396	$ 521
Less: Series A Preferred Unit distributions (Note 7)	36	36	36
Net Income Attributable to Common Units (Note 6)	$ 52	$ 360	$ 485

Basic and diluted earnings per common unit (Note 6)
Basic	$ 0.12	$ 0.83	$ 1.12
Diluted	$ 0.12	$ 0.82	$ 1.11

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Net income	$ 83	$ 400	$ 523
Other comprehensive loss:
Change in fair value of interest rate derivative instruments	(7)	(3)	—
Reclassification of interest rate derivative losses to net income	4	—	—
Other comprehensive loss	(3)	(3)	—
Comprehensive income	80	397	523
Less: Comprehensive income (loss) attributable to noncontrolling interests	(5)	4	2
Comprehensive income attributable to Limited Partners	$ 85	$ 393	$ 521

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS


	December 31,
	2020	2019

	(In millions, except units)
Current Assets:
Cash and cash equivalents	$ 3	$ 4
Accounts receivable, net of allowance for doubtful accounts (Note 1)	248	244
Accounts receivable—affiliated companies	15	25
Inventory	42	46
Gas imbalances	42	35
Other current assets	31	35
Total current assets	381	389
Property, Plant and Equipment:
Property, plant and equipment	13,220	13,161
Less accumulated depreciation and amortization	2,555	2,291
Property, plant and equipment, net	10,665	10,870
Other Assets:
Intangible assets, net	539	601
Goodwill	—	12
Investment in equity method affiliate	76	309
Other	68	85
Total other assets	683	1,007
Total Assets	$ 11,729	$ 12,266
Current Liabilities:
Accounts payable	$ 149	$ 161
Accounts payable—affiliated companies	2	1
Short-term debt	250	155
Current portion of long-term debt	—	251
Taxes accrued	34	32
Gas imbalances	19	19
Accrued compensation	43	31
Customer deposits	18	17
Other	67	113
Total current liabilities	582	780
Other Liabilities:
Accumulated deferred income tax, net	5	4
Regulatory liabilities	25	24
Other	71	80
Total other liabilities	101	108
Long-Term Debt	3,951	3,969
Commitments and Contingencies (Note 17)


Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2020 and December 31, 2019, respectively)	362	362
Common Units (435,549,892 issued and outstanding at December 31, 2020 and 435,201,365 issued and outstanding at December 31, 2019)	6,713	7,013
Accumulated other comprehensive loss	(6)	(3)
Noncontrolling interests	26	37
Total Partners’ Equity	7,095	7,409
Total Liabilities and Partners’ Equity	$ 11,729	$ 12,266

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Cash Flows from Operating Activities:
Net income	$ 83	$ 400	$ 523
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	420	433	398
Deferred income tax	1	(1)	(1)
Impairments of property, plant and equipment and goodwill	28	86	—
Net loss on sale/retirement of assets	24	8	1
Gain on extinguishment of debt	(5)	—	—
Equity in (earnings) losses of equity method affiliate, net	210	(17)	(26)
Return on investment in equity method affiliate	15	17	26
Equity-based compensation	13	16	16
Amortization of debt costs and discount (premium)	4	(1)	(1)
Changes in other assets and liabilities:
Accounts receivable, net	(5)	43	(10)
Accounts receivable—affiliated companies	10	(6)	(1)
Inventory	4	4	(10)
Gas imbalance assets	(7)	(6)	8
Other current assets	3	9	(21)
Other assets	5	11	(12)
Accounts payable	(10)	(75)	4
Accounts payable—affiliated companies	1	(3)	1
Gas imbalance liabilities	—	(3)	10
Other current liabilities	(32)	39	4
Other liabilities	(5)	(12)	15
Net cash provided by operating activities	757	942	924
Cash Flows from Investing Activities:
Capital expenditures	(215)	(432)	(728)
Acquisitions, net of cash acquired	—	—	(443)
Proceeds from sale of assets	20	1	8
Proceeds from insurance	1	1	2
Return of investment in equity method affiliate	8	8	7
Other, net	4	(8)	—
Net cash used in investing activities	(182)	(430)	(1,154)
Cash Flows from Financing Activities:
Increase (decrease) increase in short-term debt	95	(494)	244
Proceeds from long-term debt, net of issuance costs	—	1,544	787
Repayment of long-term debt	(267)	(700)	(450)


Proceeds from Revolving Credit Facility	869	—	350
Repayment of Revolving Credit Facility	(869)	(250)	(100)
Proceeds from issuance of common units, net of issuance costs	—	—	2
Distributions to common unitholders	(360)	(564)	(551)
Distributions to preferred unitholders	(36)	(36)	(36)
Distributions to non-controlling interests	(6)	(5)	(4)
Cash paid for employee equity-based compensation	(2)	(25)	(9)
Net cash (used in) provided by financing activities	(576)	(530)	233
Net (Decrease) Increase in Cash and Cash Equivalents	(1)	(18)	3
Cash and Cash Equivalents at Beginning of Period	4	22	19
Cash and Cash Equivalents at End of Period	$ 3	$ 4	$ 22

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY


	Series A Preferred Units		Common Units		Accumulated Other Comprehensive Earnings	Noncontrolling Interest	Total Partners’ Equity
	Units	Value	Units	Value	Value	Value	Value

	(In millions)
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 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
Net income (loss)	—	36	—	52	—	(5)	83
Other comprehensive loss	—	—	—	—	(3)	—	(3)
Distributions	—	(36)	—	(360)	—	(6)	(402)
Equity-based compensation, net of units for employee taxes	—	—	—	11	—	—	11
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—	—	—	(3)	—	—	(3)
Balance as of December 31, 2020	15	$ 362	435	$ 6,713	$ (6)	$ 26	$ 7,095

ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (the 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. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our 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. Our 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. Our crude oil gathering assets are located in Oklahoma and North Dakota and serve crude oil production in the Anadarko and Williston Basins. Our 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, 2020, 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 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, 2020, 2019 and 2018, the Partnership owned a 50% interest in SESH. See Note 11 for further discussion of SESH. For the years ended December 31, 2020, 2019 and 2018, the Partnership owned a 50% ownership interest in Atoka and consolidated Atoka in the accompanying 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 of November 1, 2018 through December 31, 2020, the Partnership owned a 60% interest in ESCP, which is consolidated in the accompanying 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

statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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). 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 the current month’s nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on the current month’s 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, 2020, one non-affiliate customer accounted for approximately 13%, or $310 million of our consolidated revenue. 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 year ended December 31, 2018. See note 16 for more information on revenues from affiliates.

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 and amortization, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. Estimates for purchases are based on estimated volumes and contracted purchase prices. Estimated 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 $3 million and $0 accrued at December 31, 2020 and 2019, respectively.

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 Tax

The Partnership’s earnings are not subject to income tax (other than Texas state margin tax 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 tax 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 $3 million and $4 million of cash and cash equivalents as of December 31, 2020 and 2019, respectively.

Accounts Receivable and Allowance for Doubtful Accounts

The Partnership adopted ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” on January 1, 2020. Upon adoption, the Partnership recognized a $3 million cumulative adjustment to Partners’ Equity and a corresponding adjustment to 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 primarily upon the historical loss-rate method established for various pools of accounts receivables with similar levels of credit risk. The historical loss-rates are then adjusted, as necessary, based on current conditions and forecast information that could result in 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 and other receivable balances within other assets at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecast economic conditions over the assets contractual lives. The following table summarizes the required allowance for doubtful accounts.


	December 31, 2020	January 1, 2020

	(In millions)
Accounts receivable	$ 1	$ 2
Other assets	3	3
Total Allowance for doubtful accounts	$ 4	$ 5

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, 2020, 2019 and 2018. 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, 2020, 2019 and 2018, the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $10 million, $8 million and $4 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,
	2020	2019

	(In millions)
Materials and supplies	$ 32	$ 32
Natural gas and natural gas liquids	10	14
Total Inventory	$ 42	$ 46

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 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.

Impairment of Long-Lived Assets (including Intangible Assets)

Impairment of Investment in Equity Method Affiliate

The Partnership evaluates its Investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. The Partnership utilizes the market or income approaches to estimate the fair value of the investment, 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 investment is then compared to the carrying amount of the investment and an impairment charge equal to the difference, is recorded to Equity in earnings (losses) of equity method affiliate, net. Any basis difference between our recognized Investment in equity method affiliate and the underlying financial statements of the affiliate are assigned to the applicable net assets of the affiliate. For more information, see Note 11.

Impairment of Goodwill

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, 2020 and 2019, these removal costs of $25 million and $24 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, 2020, 2019 and 2018, the Partnership capitalized interest and AFUDC of $2 million, $2 million and $6 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.

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 certain 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

The Partnership has 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, 2020, 2019 and 2018, the Partnership contributed $20 million, $20 million and $19 million, respectively.

During the years ended December 31, 2020, 2019 and 2018, 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, 2020, 2019 and 2018, the Partnership reimbursed OGE Energy $2 million, $3 million and $3 million, respectively, for these benefits. See Note 16 for further information related to our related party transactions.

(2) New Accounting Pronouncements

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This standard provides optional guidance, for a limited time, to ease the potential burden in accounting for or recognizing the effects of reference rate reform on financial reporting. The standard was effective upon issuance and generally can be applied through December 31, 2022. The Partnership adopted ASU 2020-04 during the year ended December 31, 2020. The implementation had no material impact on the Consolidated Financial Statements and related disclosures.

In January 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This standard clarifies that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. ASU 2021-01 also amends the expedients and exceptions in ASC 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition. ASU 2021-01 was effective upon issuance and generally can be applied through December 31, 2022. The Partnership expects to adopt this standard in the first quarter of 2021 and does not expect the adoption of this standard to have a material impact on the Consolidated Financial Statements and related disclosures.

(3) Revenues

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, 2020, 2019 and 2018.


	Year Ended December 31, 2020
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 249	$ 328	$ (285)	$ 292
Natural gas liquids	762	10	(10)	762
Condensate	68	—	—	68
Total revenues from natural gas, natural gas liquids, and condensate	1,079	338	(295)	1,122
Gain on derivative activity	8	2	—	10
Total Product sales	$ 1,087	$ 340	$ (295)	$ 1,132
Service revenues:
Demand revenues	$ 135	$ 491	$ —	$ 626
Volume-dependent revenues	664	50	(9)	705
Total Service revenues	$ 799	$ 541	$ (9)	$ 1,331
Total Revenues	$ 1,886	$ 881	$ (304)	$ 2,463


	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


	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 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.

MRT Rate Case Settlements

In June 2018, MRT filed a general NGA rate case (the 2018 Rate Case), and in October 2019, MRT filed a second rate case (the 2019 Rate Case). MRT began collecting the rates proposed in the 2018 Rate Case, subject to refund, on January 1, 2019. On March 26, 2020, FERC issued an order approving settlements filed in the 2018 Rate Case and the 2019 Rate Case. Upon issuance of the order and approval of the settlement of the MRT rate cases, the Partnership recognized $17 million of revenues from amounts previously held in reserve related to transportation and storage services performed in 2019. In May 2020, $21 million previously held in reserve was refunded to customers, which is inclusive of interest.

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, net of allowance for doubtful accounts.


	December 31, 2020	December 31, 2019

	(In millions)
Accounts Receivable:
Customers	$ 245	$ 239
Contract assets (1)	12	18
Non-customers	6	12
Total Accounts Receivable (2)	$ 263	$ 269

____________________

(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 contract assets related to firm transportation contracts with tiered rates of $9 million as of December 31, 2020 and $6 million as of December 31, 2019, 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.

The table below summarizes the change in the contract liabilities for the year ended December 31, 2020:


	Year Ended December 31,
	2020	2019

	(In millions)
Deferred revenues, beginning of period (1)	$ 48	$ 48
Amounts recognized in revenues related to the beginning balance	(25)	(24)
Net additions	21	24
Deferred revenues, end of period (1)	$ 44	$ 48

The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2020:


	2021	2022	2023	2024	2025 and After

	(In millions)
Deferred revenues (1)	$ 23	$ 7	$ 6	$ 6	$ 2

____________________

(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, 2020.


	2021	2022	2023	2024	2025 and After

	(In millions)
Transportation and Storage	$ 443	$ 371	$ 336	$ 250	$ 938
Gathering and Processing	120	123	121	101	213
Total remaining performance obligations	$ 563	$ 494	$ 457	$ 351	$ 1,151

(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 operating leases. The Partnership did not recognize a material cumulative adjustment to the Consolidated Statements of Partners’ Equity and we did not have any material changes in the timing of expense recognition or our accounting policies.

Description of Lease Contracts

Our lease obligations are primarily comprised of rentals of field equipment and office space, 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. The Partnership is generally not aware of the implicit rate for either field equipment or office space 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, 2020, the weighted average remaining lease term is 7.0 years and the weighted average discount rate is 5.47%. A description of our lease contracts follows:

Field equipment: Field equipment has an expected lease term of 3 to 5 years, with contractual base terms of 1 to 3 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. The Partnership has compression service agreements, some of which are on a month-to-month basis and some of which expire in 2021. The Partnership also has gas treating lease agreements, of which some are on a month-to-month basis, while others will expire in 2021 and in 2022. Field equipment lease costs are reflected in Operation and maintenance expense in the Consolidated Statements of Income.

Office space: Office spaces have an expected lease term of 7 to 10 years, which is currently the same as the contractual base term. Office space rental arrangements contain market-based renewal options of up to 15 years. Variable lease payments for office spaces are generally comprised of costs for utilities, maintenance and building management services. Variable lease payments due under office space rental arrangements began July 1, 2019, with amounts due monthly. The Partnership occupies principal executive offices in Oklahoma City, Oklahoma, as well as office space in Houston, Texas. Our office leases are long-term in nature and represent $17 million of our right-of-use assets and $20 million of our lease liability as of December 31, 2020. Office space lease costs, including a proportionate percentage of facility expenses, are reflected in General and administrative expense in the Consolidated Statements of Income.

The table below summarizes the operating leases included in the Consolidated Balance Sheets.


	Balance Sheet Location	December 31, 2020	December 31, 2019

		(In millions)
Operating lease asset	Other Assets	$ 25	$ 37
Total right-of-use assets		$ 25	$ 37

Operating lease liabilities	Other Current Liabilities	$ 4	$ 9
Operating lease liabilities	Other Liabilities	24	31
Total lease liabilities		$ 28	$ 40

As of December 31, 2020, all lease obligations were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities.

The following table presents the Partnership’s rental costs associated with field equipment and office space.


	Year Ended December 31,
	2020	2019

	(In millions)
Rental Costs:
Field equipment	$ 16	$ 29
Office space	6	7

The following table presents the Partnership’s lease cost.


	Year Ended December 31,
	2020	2019

	(In millions)
Lease Cost:
Operating lease cost	$ 8	$ 11
Short-term lease cost	12	24
Variable lease cost	2	1
Total Lease Cost	$ 22	$ 36

The Partnership recorded short-term lease costs of $1 million and $2 million in the transportation and storage reportable segment during the years ended December 31, 2020 and 2019, respectively. All other lease costs were included in the gathering and processing reportable segment.

Under ASC 842, as of December 31, 2020, the Partnership has operating lease obligations expiring at various dates. Undiscounted cash flows for operating lease liabilities are as follows:


	Non-cancellable operating leases
	(In millions)
Year Ending December 31,
2021	$ 6
2022	5
2023	5
2024	4
2025	3
After 2025	8
Total	31
Less: impact of the applicable discount rate	3
Total lease liabilities	$ 28

ASC 840 Lease Accounting

Under ASC 840 rental expense was $35 million during the year ended December 31, 2018.

(5) Acquisition

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

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 accompanying Consolidated Financial Statements. The Partnership incurred approximately $6 million of acquisition costs associated with this transaction during the year ended December 31, 2018, 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 year ended December 31, 2018, 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 following table illustrates the Partnership’s calculation of earnings per unit for common units:


	Year Ended December 31,
	2020	2019	2018

	(In millions, except per unit data)
Net income	$ 83	$ 400	$ 523
Net income (loss) attributable to noncontrolling interests	(5)	4	2
Series A Preferred Unit distributions	36	36	36
General partner interest in net income	—	—	—
Net income available to common units	$ 52	$ 360	$ 485

Net income allocable to common units	$ 52	$ 360	$ 485
Dilutive effect of Series A Preferred Unit distribution (1)	—	—	—
Diluted net income allocable to common units	$ 52	$ 360	485

Basic weighted average number of outstanding common units (2)	437	436	434
Dilutive effect of Series A Preferred Units (1)	—	—	—
Dilutive effect of performance units (3)	1	1	2
Diluted weighted average number of outstanding common units	438	437	436

Basic and diluted earnings per common unit
Basic	$ 0.12	$ 0.83	$ 1.12
Diluted	$ 0.12	$ 0.82	$ 1.11

____________________

(1)

For the years ended December 31, 2020, 2019, and 2018, the issuance of “if-converted” common units attributable to the Series A Preferred Units were excluded in the calculation of diluted earnings per common unit as the impact was anti-dilutive.

(2)

Basic weighted average number of outstanding common units for the years ended December 31, 2020, 2019, and 2018 includes approximately 2 million, 1 million, and 1 million time-based phantom units, respectively.

(3)

The dilutive effect of the performance unit awards was less than $0.01 per unit for the years ended December 31, 2020, 2019, and 2018.

(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.

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2020, 2019 and 2018 (in millions, except for per unit amounts):


Quarter Ended	Record Date	Payment Date	Per Unit Distribution	Total Cash Distribution
2020
December 31, 2020 (1)	February 22, 2021	March 1, 2021	$ 0.16525	$ 72
September 30, 2020	November 17, 2020	November 24, 2020	0.16525	72
June 30, 2020	August 18, 2020	August 25, 2020	0.16525	72
March 31, 2020	May 19, 2020	May 27, 2020	0.16525	72

2019
December 31, 2019	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

_____________________

(1)

The Board of Directors declared a $0.16525 per common unit cash distribution on February 12, 2021, to be paid on March 1, 2021, to common unitholders of record at the close of business on February 22, 2021.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2020, 2019, and 2018 (in millions, except for per unit amounts):


Quarter Ended	Record Date	Payment Date	Per Unit Distribution	Total Cash Distribution
2020
December 31, 2020 (1)	February 12, 2021	February 12, 2021	$ 0.625	$ 9
September 30, 2020	November 3, 2020	November 13, 2020	0.625	9
June 30, 2020	August 4, 2020	August 14, 2020	0.625	9
March 31, 2020	May 5, 2020	May 15, 2020	0.625	9

2019
December 31, 2019	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

_____________________

(1)

The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 12, 2021, to be paid on February 12, 2021 to Series A Preferred unitholders of record at the close of business on February 12, 2021.

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.

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 on February 18, 2016.

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

•

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. For the year ended December 31, 2020, the Partnership did not sell any common units under the ATM Program. For the year ended December 31, 2019, 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 registration statement filed with the SEC for the ATM Program expired on May 12, 2020, and the Partnership did not file a replacement registration statement.

(8) Property, Plant and Equipment

Property, plant and equipment includes the following:


	Weighted Average Useful Lives (Years)	December 31,
	Weighted Average Useful Lives (Years)		2020		2019

		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	34.5	$ 8,275		$ 8,252
Transportation and Storage	40.6	4,802		4,778
Construction work-in-progress		143		131
Total		$ 13,220		$ 13,161
Accumulated depreciation:
Gathering and Processing		1,429		1,252
Transportation and Storage		1,126		1,039
Total accumulated depreciation		2,555		2,291
Property, plant and equipment, net		$ 10,665		$ 10,870

The Partnership recorded depreciation expense of $358 million, $371 million and $351 million during the years ended December 31, 2020, 2019 and 2018, respectively. Effective January 1, 2019, the Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage reportable segments and the new depreciation rates were applied prospectively as a change in accounting estimate. On March 26, 2020, FERC issued an order approving MRT’s 2018 Rate Case and 2019 Rate Case settlements. As a result of the settlements, the new depreciation rates for MRT have been applied in accordance with the order. The new depreciation rates did not result in a material change in depreciation expense or results of operations.

Impairment of Property, Plant and Equipment

The Partnership periodically evaluates property, plant and equipment for impairment 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. Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing COVID-19 pandemic and the economic effects of the pandemic, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, as of March 31, 2020, management reassessed the carrying value of the Atoka assets, in which the Partnership owns a 50% interest in the consolidated joint venture, which is a component of the gathering and processing segment. Based on forecasted future undiscounted cash flows, management determined that the carrying value of the Atoka assets were not fully recoverable. The Partnership utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs are forecasted cash flows and the discount rate. The fair value measurement is based on inputs that are not observable in the market and thus represent Level 3 inputs. Applying a discounted cash flow model to the property, plant and equipment, the Partnership recognized a $16 million impairment, which is included in Impairments of property, plant and equipment and goodwill on the Consolidated Statements of Income during the year ended December 31, 2020.

Sale and Retirements of Assets

The Partnership recognizes gains or losses on sale or retirement when the net book value differs from the consideration received from sales proceeds, insurance recovery or other exchanges.

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. On January 27, 2020, FERC approved the sale. The Partnership closed the sale on April 1, 2020. We did not recognize a gain or loss on this transaction.

In April 2020, we sustained damage to an approximately 100-mile gas gathering system in the Ark-La-Tex Basin of our gathering and processing segment. We have ceased operation of this system and are in the process of retiring it. We recognized a loss on retirement of approximately $20 million for the year ended December 31, 2020, which is included in Operation and maintenance expense in the Consolidated Statements of Income.

Additionally, for the years ended December 31, 2020, 2019 and 2018, the Partnership recognized other net losses on sale or retirement of approximately $4 million, $8 million and $1 million, respectively, which are included in Operation and maintenance expense in the Consolidated Statements of Income.

(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,
	2020	2019

	(In millions)
Customer relationships:
Total intangible assets	$ 840	$ 840
Accumulated amortization	301	239
Net intangible assets	$ 539	$ 601

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, $62 million and $47 million during the years ended December 31, 2020, 2019 and 2018, respectively. The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years:


	2021	2022	2023	2024	2025

	(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 2020, the commodity price declines due to the existing oversupply of crude oil, NGLs and natural gas were exacerbated by the ongoing COVID-19 pandemic and the economic effects of the pandemic, in addition to the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia in the first quarter. Despite the subsequent agreement in April 2020 by a coalition of nations including Russia and Saudi Arabia to reduce production of crude oil, the price of NGLs and crude oil have remained significantly lower than pre-pandemic levels. Amid such crude oil, NGL and natural gas price declines, producers cut back spending and shifted 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 Ark-La-Tex Basin reporting unit during the first quarter of 2020. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations 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 Ark-La-Tex Basin reporting unit was more likely than not impaired as of March 31, 2020. As a result, the Partnership performed a quantitative test for our goodwill and determined that the carrying value of the Ark-La-Tex Basin reporting unit exceeded its fair value and that goodwill associated with the Ark-La-Tex Basin was completely impaired in the amount of $12 million. The impairment is included in Impairments of property plant, and equipment and goodwill on the Consolidated Statements of Income for the year ended December 31, 2020.

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 cut back spending and shifted 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.

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, 2018	$ 98	$ —	$ 98
Goodwill impairment	(86)	—	(86)
Balance as of December 31, 2019	12	—	12
Goodwill impairment	(12)	—	(12)
Balance as of December 31, 2020	$ —	$ —	$ —

(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, 2020 and 2019. 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.

At September 30, 2020, the Partnership estimated the fair value of its investment in SESH was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and then current status of renewal negotiations. As a result, the Partnership recorded a $225 million impairment on its investment in SESH, which is included in Equity in earnings (losses) of equity method affiliate, net in the Partnership’s Consolidated Statements of Income for the year ended December 31, 2020. The impairment analysis of the Partnership’s investment in SESH compared the estimated fair value of the investment to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches. Due to the significant unobservable estimates and assumptions required, the Partnership concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. The basis difference for our investment in SESH has been assigned to its property, plant and equipment and will be amortized over its approximately 50-year remaining useful life. See Note 1 for further information concerning the method used to evaluate and measure the impairment on the Partnership’s investment in SESH.

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, 2020, 2019 and 2018, the Partnership billed SESH $15 million, $17 million and $18 million, respectively, associated with these service agreements.

The Partnership includes equity in earnings (losses) of equity method affiliate, net under the Other Income (Expense) caption in the Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018.

SESH:


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Equity in Earnings of Equity Method Affiliate	$ 15	$ 17	$ 26
Impairment of equity method affiliate investment	(225)	—	—
Equity in earnings (losses) of equity method affiliate, net	$ (210)	$ 17	$ 26
Distributions from Equity Method Affiliate (1)	$ 23	$ 25	$ 33

____________________

(1)

Distributions from equity method affiliate includes a $15 million, $17 million and $26 million return on investment and a $8 million, $8 million and $7 million return of investment for the years ended December 31, 2020, 2019 and 2018, respectively.

Summarized financial information of SESH:


	December 31,
	2020	2019

	(In millions)
Balance Sheets:
Current assets	$ 49	$ 49
Property, plant and equipment, net	1,043	1,060
Total assets	$ 1,092	$ 1,109
Current liabilities	$ 31	$ 30
Long-term debt	398	398
Members’ equity	663	681
Total liabilities and members’ equity	$ 1,092	$ 1,109
Reconciliation:
Investment in SESH	$ 76	$ 309
Add: Capitalized interest on investment in SESH	(1)	(1)
Add: Basis difference, net of amortization (1)	256	33
The Partnership’s share of members’ equity	$ 331	$ 341

____________________

(1)

Includes the Partnership’s impairment of investment in equity method affiliate of $225 million recorded during the year ended December 31, 2020.


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Income Statements:
Revenues	$ 96	$ 109	$ 112
Operating income	44	50	67
Net income	26	33	50

(12) Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2020 and 2019.


	December 31, 2020			December 31, 2019
	Outstanding Principal	Premium (Discount)(1)	Total Debt	Outstanding Principal	Premium (Discount)(1)	Total Debt

	(In millions)
Commercial Paper	$ 250	$ —	$ 250	$ 155	$ —	$ 155
Revolving Credit Facility	—	—	—	—	—	—
2019 Term Loan Agreement	800	—	800	800	—	800
2024 Notes	600	—	600	600	—	600
2027 Notes	700	(2)	698	700	(2)	698
2028 Notes	800	(5)	795	800	(5)	795
2029 Notes	547	(1)	546	550	(1)	549
2044 Notes	531	—	531	550	—	550
EOIT Senior Notes	—	—	—	250	1	251
Total debt	$ 4,228	$ (8)	$ 4,220	$ 4,405	$ (7)	$ 4,398
Less: Short-term debt (2)			250			155
Less: Current portion of long-term debt (3)			—			251
Less: Unamortized debt expense (4)			19			23
Total long-term debt			$ 3,951			$ 3,969

___________________

(1)

Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.

(2)

Short-term debt includes $250 million and $155 million of commercial paper outstanding as of December 31, 2020 and 2019, respectively.

(3)

As of December 31, 2019, Current portion of long-term debt included the $251 million outstanding balance of the EOIT Senior Notes which were repaid in March 2020.

(4)

As of December 31, 2020 and 2019, there was an additional $3 million and $4 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):


2021	$ 250
2022	800
2023	—
2024	600
2025	—
Thereafter	$ 2,578

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 $250 million and $155 million outstanding under our commercial paper program at December 31, 2020 and December 31, 2019, respectively. The weighted average interest rate for the outstanding commercial paper was 0.86% as of December 31, 2020.

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 two-year term. As of December 31, 2020, there were no principal advances and no 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, 2020, 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, 2020, 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. Additionally, for the period of time during the construction by the Partnership or certain of its subsidiaries of a qualified project with a cost greater than $15 million and before the date such qualified project is substantially complete and commercially operable, the Partnership may make Qualified Project EBITDA Adjustments (as defined in the Revolving Credit Facility and 2019 Term Loan Agreement) by determining an amount as projected consolidated EBITDA attributable to such qualified project, which may be added to the actual consolidated EBITDA for the Partnership and those certain subsidiaries; provided that such amount (i) shall be no greater than 20% of the total actual consolidated EBITDA of the Partnership and those certain subsidiaries (as determined without the projected consolidated EBITDA attributable to such qualified project) and (ii) shall be subject to approval by the administrative agent.

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. As of December 31, 2020, there was $800 million outstanding under the 2019 Term Loan Agreement. 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, 2020, 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, 2020, the weighted average interest rate of the 2019 Term Loan Agreement was 2.10%.

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 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. For further discussion of Qualified Project EBITDA Adjustments, see “Revolving Credit Facility” above.

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

As of December 31, 2020, the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $8 million of unamortized discount and $19 million of unamortized debt expense at December 31, 2020, resulting in effective interest rates of 4.01%, 4.56%, 5.19%, 4.29% and 4.99%, respectively, during the year ended December 31, 2020. In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement. In March 2020, the EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility.

During the year ended December 31, 2020, the Partnership repurchased $22 million aggregate principal amount of the 2029 Notes and 2044 Notes in open market transactions for approximately $17 million plus accrued interest, which resulted in a $5 million gain on extinguishment of debt. The gain is included in Other, net in the Consolidated Statements of Income.

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, 2020, the Partnership was in compliance with all of their debt agreements, including financial covenants.

(13) Derivative Instruments and Hedging Activities

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 options, futures, swaps and swaptions, and WTI crude oil options, futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;

•

natural gas options, futures, swaps and 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.

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, 2020 and 2019, 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, 2020 and 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes.

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.

As of December 31, 2020 and 2019, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:


	December 31, 2020		December 31, 2019
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps	—	18	10	19
Financial basis futures/swaps	—	27	11	30
Financial swaptions (2)	—	7	—	2
Physical purchases/sales	—	—	—	6
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	—	465	—	990
Financial swaptions (2)	—	90	—	225
Natural gas liquids— MBbl (4)
Financial futures/swaps	855	1,210	2,490	2,415
Financial swaptions (2)	—	45	—	—

____________________

(1)

As of December 31, 2020, 95.7% of the natural gas contracts had durations of one year or less and 4.3% had durations of more than one year and less than two years. As of December 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.

(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, 2020, 100.0% of the crude oil (for condensate) contracts had durations of one year or less. 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.

(4)

As of December 31, 2020, 100.0% of the natural gas liquids contracts had durations of one year or less. 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.

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, 2020 and 2019, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:


	December 31, 2020	December 31, 2019
	Gross Notional Value
	(In millions)
Interest rate swaps	$ 300	$ 300

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, 2020 and 2019 that were not designated as hedging instruments for accounting purposes are as follows:


		December 31, 2020		December 31, 2019
		Fair Value
Instrument	Balance Sheet Location	Assets	Liabilities	Assets	Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$ 2	$ 2	$ 7	$ 5
Financial swaptions	Other Current	1	2	—	—
Physical purchases/sales	Other Current	—	—	5	—
Financial futures/swaps	Other	—	—	—	1
Crude oil (for condensate)
Financial futures/swaps	Other Current	1	13	1	19
Financial futures/swaps	Other	—	—	—	8
Natural gas liquids
Financial futures/swaps	Other Current	15	3	25	3
Financial swaptions	Other Current	—	1	—	—
Financial futures/swaps	Other	—	—	11	2
Total gross derivatives (1)		$ 19	$ 21	$ 49	$ 38

_____________________

(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, 2020 and 2019.

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets as of December 31, 2020 and December 31, 2019 that were designated as hedging instruments for accounting purposes are as follows:


		December 31, 2020		December 31, 2019
		Fair Value
Instrument	Balance Sheet Location	Assets	Liabilities	Assets	Liabilities

		(In millions)
Interest rate swaps	Other Current	$ —	$ 6	$ —	$ 1
Interest rate swaps	Other	—	—	—	2
Total gross interest rate derivatives (1)		$ —	$ 6	$ —	$ 3

_____________________

(1)

All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2020.

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, 2020, 2019 and 2018:


	Amounts Recognized in Income
	Year Ended December 31,
	2020	2019	2018

	(In millions)
Natural Gas
Financial futures/swaps gains (losses)	$ 4	$ 13	$ (8)
Financial swaptions gains (losses)	(2)	—	—
Physical purchases/sales gains	—	2	7
Crude oil (for condensate)
Financial futures/swaps gains (losses)	10	(41)	6
Natural gas liquids
Financial futures/swaps gains (losses)	(2)	42	6
Total	$ 10	$ 16	$ 11

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2020, 2019 and 2018 are reported in Product sales. For derivatives designated as hedges, amounts recognized in income and reported in Interest expense for the years ended December 31, 2020 and 2019 were approximately $4 million and zero, respectively.

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, 2020, 2019 and 2018:


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Change in fair value of derivatives	$ (13)	$ (11)	$ 26
Realized gain (loss) on derivatives	23	27	(15)
Gain on derivative activity	$ 10	$ 16	$ 11

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, 2020, 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 less than $1 million of 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 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, 2020, 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, 2020, 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, 2020 and 2019:


	December 31, 2020		December 31, 2019
	Carrying Amount	Fair Value	Carrying Amount	Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$ —	$ —	$ —	$ —
2019 Term Loan Agreement (Level 2)	800	800	800	800
2024 Notes (Level 2)	600	612	600	614
2027 Notes (Level 2)	698	709	698	698
2028 Notes (Level 2)	795	817	795	811
2029 Notes (Level 2)	546	544	549	526
2044 Notes (Level 2)	531	499	550	506
EOIT Senior Notes (Level 2)	—	—	251	252

______________________

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $250 million and $155 million of commercial paper was outstanding as of December 31, 2020 and 2019, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 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, 2020, 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, 2020, all of the asset groups were considered recoverable. Based upon review for other than temporary declines in fair value, the investment in equity method affiliate was considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions including the oversupply of crude oil, NGLs and natural gas as well as the ongoing COVID-19 pandemic and the economic effects of the pandemic, could reduce forecast undiscounted cash flows for the asset groups and result in other than temporary declines in the fair value of the investment in equity method affiliate.

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, 2020 and 2019, the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments. As of December 31, 2020 and 2019, there were no Level 3 commodity contracts. 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, 2020 and 2019:


December 31, 2020	Commodity Contracts		Gas Imbalances (1)
	Assets	Liabilities	Assets (2)	Liabilities (3)

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$ 2	$ 14	$ —	$ —
Significant other observable inputs (Level 2)	17	7	23	16
Total fair value	19	21	23	16
Netting adjustments	(19)	(19)	—	—
Total	$ —	$ 2	$ 23	$ 16


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
Total fair value	49	38	14	11
Netting adjustments	(37)	(37)	—	—
Total	$ 12	$ 1	$ 14	$ 11

______________________

(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, 2020 and 2019.

(2)

Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $19 million and $21 million at December 31, 2020 and 2019, 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 $3 million and $8 million at December 31, 2020 and 2019, 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.

(15) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$ 180	$ 185	$ 148
Income tax, net of refunds	1	1	3
Non-cash transactions:
Accounts payable related to capital expenditures	9	10	54
Lease liabilities related to (derecognition) recognition of right-of-use assets	(5)	45	—
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	(3)	—	—

(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

MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. As part of the MRT rate case settlements, contracts for these services were extended and are in effect through July 31, 2028 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.

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 firm transportation, firm transportation with seasonal demand, firm storage and no-notice transportation with storage contracts were extended and have terms running through March 31, 2030. The maximum rate firm transportation contracts were also extended and have terms running through March 31, 2024.

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. We reimbursed CenterPoint Energy’s LDCs less than $1 million for the year ended December 31, 2020, and $2 million for the year ended December 31, 2019, in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines. For the year ended December 31, 2018, we reimbursed CenterPoint Energy’s LDCs $1 million in connection with a reimbursement associated with an unplanned pipeline outage.

Transportation and Storage Agreements 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 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 through December 1, 2038. EOIT paid OGE Energy $2 million and waived $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%, 6% and 5% of total revenues during the years ended December 31, 2020, 2019 and 2018, 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,
	2020	2019	2018

	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$ 100	$ 108	$ 111
Natural gas product sales — CenterPoint Energy	1	8	11
Gas transportation and storage service revenues — OGE Energy	38	41	37
Natural gas product sales — OGE Energy	10	10	4
Total revenues — affiliated companies	$ 149	$ 167	$ 163

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,
	2020	2019	2018

	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$ 1	$ —	$ 3
Cost of natural gas purchases — OGE Energy	24	33	23
Total cost of natural gas purchases — affiliated companies	$ 25	$ 33	$ 26

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 2020 are less than $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, 2020, 2019 and 2018, 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 2020 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,
	2020	2019	2018

	(In millions)
Corporate Services — CenterPoint Energy	$ —	$ —	$ 1
Operating Lease — CenterPoint Energy	—	1	1
Seconded Employee Costs — OGE Energy	17	18	29
Corporate Services — OGE Energy	—	—	1
Total corporate services, operating lease and seconded employee expense	$ 17	$ 19	$ 32

(17) Commitments and Contingencies

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.

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, 2020, the Partnership estimates the remaining associated minimum volume commitment fee to be $172 million in the aggregate. Minimum volume commitment fees are expected to be $23 million per year from 2021 through 2027 and $11 million in 2028.

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 requested approval to transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. The Partnership filed applications with FERC to obtain authorization to construct and operate the pipeline on February 28, 2020. FERC issued the environmental assessment on October 29, 2020. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project would be as much as $500 million. The project is backed by a 20-year firm transportation service agreement. 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 late 2022.

(18) Income Tax

The Partnership’s earnings are generally not subject to income tax (other than Texas state margin tax and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) 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 tax 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).

The items comprising income tax expense are as follows:


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Provision for current income tax
Federal	$ (2)	$ —	$ —
State	1	—	—
Total provision for current income tax	(1)	—	—
Benefit for deferred income tax, net
Federal	$ 1	$ (1)	$ (1)
State	—	—	—
Total benefit for deferred income tax, net	1	(1)	(1)
Total income tax benefit	$ —	$ (1)	$ (1)

The components of Deferred Income Tax as of December 31, 2020 and 2019 were as follows:


	December 31,
	2020	2019

	(In millions)
Deferred tax liabilities, net:
Non-current:
Intercompany management fee	$ 16	$ 17
Depreciation	5	6
Net operating loss	(1)	(2)
Accrued compensation	(15)	(17)
Total deferred tax liabilities, net	$ 5	$ 4

Uncertain Income Tax Positions

There were no unrecognized tax benefits as of December 31, 2020, 2019 and 2018.

Tax Audits and Settlements

The federal income tax return of the Partnership has been audited through the 2013 tax year.

Net Operating Losses

The Partnership’s corporate subsidiary, Enable Midstream Services, has federal and state net operating losses (NOL) the tax benefits of which are recorded as deferred tax assets. As of December 31, 2020, the Partnership had approximately $4 million of Federal NOLs, which can be carried forward indefinitely and approximately $8 million of various State NOLs, of which approximately $2 million will expire between 2023 and 2039. Additionally, as of December 31, 2020, the Partnership had a deferred tax asset related to Federal and State NOLs of $1 million and zero, respectively.

(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 Sheets. The following table summarizes the Partnership’s equity-based compensation expense for the years ended December 31, 2020, 2019 and 2018 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Performance units	$ 7	$ 9	$ 9
Restricted units	—	—	1
Phantom units	6	7	6
Total equity-based compensation expense	$ 13	$ 16	$ 16

Performance Units

Awards of performance based phantom units (performance units) have been made under the LTIP in 2020, 2019 and 2018 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 2020, 2019 and 2018 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 2020, 2019 and 2018 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.


	2020	2019	2018
Number of units granted	933,738	638,798	551,742
Fair value of units granted	$ 7.00	$ 19.95	$ 17.70
Expected price volatility	27.7 %	34.2 %	44.2 %
Risk-free interest rate	0.85 %	2.54 %	2.36 %
Distribution yield	12.27 %	8.38 %	8.56 %
Expected life of units (in years)	3	3	3

Phantom Units

Awards of phantom units have been made under the LTIP in 2020, 2019 and 2018 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.


	2020	2019	2018
Phantom units granted	1,002,345	695,486	546,708
Fair value of phantom units granted	$2.67 - $10.13	$8.95 - $15.04	$13.74 - $17.00

Other Awards

In 2020, 2019 and 2018, 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.


	2020	2019	2018
Common units granted	63,963	28,221	16,335
Fair value of common units granted	$ 4.23	$ 10.43	$ 14.94

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 2020 and changes during 2020 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 12/31/2019	1,393,329	$ 19.04	1,392,560	$ 14.65
Granted (1)	933,738	7.00	1,002,345	6.44
Vested (2)(3)	(390,079)	19.21	(399,406)	15.76
Forfeited	(171,480)	14.25	(204,654)	10.46
Units outstanding at 12/31/2020	1,765,508	13.10	1,790,845	$ 10.29
Aggregate intrinsic value of units outstanding at December 31, 2020	$ 9		$ 9

_____________________

(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, 2020 include 376,292 from the 2017 annual grant, 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 the performance period of January 1, 2017 through December 31, 2019, no performance units vested.

(3)

Performance units outstanding as of December 31, 2020 include 389,817 units from the 2018 annual grants, which were approved by the Board of Directors in 2018 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2018 through December 31, 2020, will vest at 0%. 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, 2020, 2019 and 2018 are shown in the following tables.


	Year Ended December 31, 2020
	Performance Units	Restricted Stock	Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$ —	$ —	$ 3
Fair value of units vested	7	—	6


	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	—

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, 2020
	Unrecognized Compensation Cost (In millions)	Weighted Average Period for Recognition (In years)
Performance Units	$ 9	1.43
Phantom Units	6	1.30
Total	$ 15

As of December 31, 2020, there were 5,234,214 units available for issuance under the long-term incentive plan.

(20) Reportable Segments

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 reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our 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.

Financial data for reportable segments are as follows:


Year Ended December 31, 2020	Gathering and Processing	Transportation and Storage (1)	Eliminations	Total

	(In millions)
Product sales	$ 1,087	$ 340	$ (295)	$ 1,132
Service revenues	799	541	(9)	1,331
Total Revenues	1,886	881	(304)	2,463
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	936	332	(303)	965
Operation and maintenance, General and administrative	334	183	(1)	516
Depreciation and amortization	299	121	—	420
Impairments of property, plant and equipment and goodwill	28	—	—	28
Taxes other than income tax	42	27	—	69
Operating Income	$ 247	$ 218	$ —	$ 465
Total Assets	$ 10,830	$ 5,729	$ (4,830)	$ 11,729
Capital expenditures	$ 107	$ 108	$ —	$ 215


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 of property, plant and equipment and goodwill	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


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
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

_____________________

(1)

See Note 11 for discussion regarding ownership interests in SESH and related equity earnings (losses) included in the transportation and storage reportable segment for the years ended December 31, 2020, 2019 and 2018.

(21) Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2020 and 2019 are as follows:


	Quarters Ended
	March 31, 2020	June 30, 2020	September 30, 2020	December 31, 2020

	(in millions, except per unit data)
Total Revenues	$ 648	$ 515	$ 596	$ 704
Cost of natural gas and natural gas liquids	226	177	250	312
Operating income	146	80	100	139
Net income (loss) (1)	105	44	(163)	97
Net income (loss) attributable to limited partners	112	44	(164)	96
Net income (loss) attributable to common units	103	35	(173)	87

Basic and diluted earnings per unit
Basic	$ 0.24	$ 0.08	$ (0.40)	$ 0.20
Diluted	$ 0.19	$ 0.08	$ (0.40)	$ 0.19

	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 (2)	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 and diluted earnings per unit
Basic	$ 0.26	$ 0.26	$ 0.28	$ 0.02
Diluted	$ 0.26	$ 0.26	$ 0.28	$ 0.02

_____________________

(1)

The Partnership recorded an impairment of $225 million in Equity in earnings (losses) of equity method affiliate, net during the third quarter related to its investment in SESH. See Note 11 for further information.

(2)

The Partnership recorded impairments to goodwill of $12 million and $86 million during the first quarter 2020 related to the Ark-La-Tex Basin reporting unit and the fourth quarter of 2019 related to the Anadarko Basin reporting unit, respectively, included in the gathering and processing reportable segment. See Note 10 for further information.

(22) Subsequent Event

On February 17, 2021, the Partnership and Energy Transfer announced their entry into a definitive merger agreement pursuant to which Energy Transfer, through wholly owned subsidiaries, will acquire the Partnership. Under the terms of the merger agreement, the Partnership’s common unitholders will receive 0.8595 of one common unit representing limited partner interests in Energy Transfer in exchange for each Partnership common unit. In addition, each issued and outstanding Series A preferred unit of the Partnership will be exchanged for 0.0265 of an Energy Transfer Series G preferred unit, and Energy Transfer will make a $10 million cash payment for the limited liability company interests in the Partnership’s general partner.

The transaction has been approved by the Conflicts Committee and the Board of Directors of Enable GP. CenterPoint Energy and OGE Energy, who collectively own approximately 79.2% of Partnership common units, have entered into support agreements pursuant to which they have agreed to vote their common units in favor of the merger. The transaction is subject to the satisfaction of customary closing conditions.

EX-99

Exhibit 99.04

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 13)):
Product sales	$ 623	$ 280	$ 1,710	$ 764
Service revenues	333	316	1,003	995
Total Revenues	956	596	2,713	1,759
Cost and Expenses (including expenses from affiliates (Note 13)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	565	250	1,510	653
Operation and maintenance	92	96	267	313
General and administrative	27	28	89	73
Depreciation and amortization	104	105	313	314
Impairments of property, plant and equipment and goodwill (Note 7)	—	—	—	28
Taxes other than income tax	16	17	52	52
Total Cost and Expenses	804	496	2,231	1,433
Operating Income	152	100	482	326
Other Income (Expense):
Interest expense	(41)	(43)	(125)	(136)
Equity in earnings (losses) of equity method affiliate, net	4	(222)	5	(211)
Other, net	1	2	7	7
Total Other Expense	(36)	(263)	(113)	(340)
Income (Loss) Before Income Tax	116	(163)	369	(14)
Income tax benefit	—	—	—	—
Net Income (Loss)	$ 116	$ (163)	$ 369	$ (14)
Less: Net income (loss) attributable to noncontrolling interest	—	1	2	(6)
Net Income (Loss) Attributable to Limited Partners	$ 116	$ (164)	$ 367	$ (8)
Less: Series A Preferred Unit distributions (Note 6)	9	9	26	27
Net Income (Loss) Attributable to Common Units (Note 5)	$ 107	$ (173)	$ 341	$ (35)

Basic and diluted earnings (loss) per unit (Note 5)
Basic	$ 0.24	$ (0.40)	$ 0.78	$ (0.08)
Diluted	$ 0.24	$ (0.40)	$ 0.76	$ (0.08)

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Net income (loss)	$ 116	$ (163)	$ 369	$ (14)
Other comprehensive income (loss):
Change in fair value of interest rate derivative instruments	—	—	—	(7)
Reclassification of interest rate derivative losses to net income	1	2	4	3
Other comprehensive income (loss)	1	2	4	(4)
Comprehensive income (loss)	117	(161)	373	(18)
Less: Comprehensive income (loss) attributable to noncontrolling interest	—	1	2	(6)
Comprehensive income (loss) attributable to Limited Partners	$ 117	$ (162)	$ 371	$ (12)

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

See Notes to the Unaudited Condensed Consolidated Financial Statements


	September 30, 2021	December 31, 2020

	(In millions)
Current Assets:
Cash and cash equivalents	$ 36	$ 3
Accounts receivable, net of allowance for doubtful accounts (Note 1)	384	248
Accounts receivable—affiliated companies	9	15
Inventory	43	42
Gas imbalances	26	42
Other current assets, net of allowance for doubtful accounts (Note 1)	38	31
Total current assets	536	381
Property, Plant and Equipment:
Property, plant and equipment	13,396	13,220
Less: Accumulated depreciation and amortization	2,785	2,555
Property, plant and equipment, net	10,611	10,665
Other Assets:
Intangible assets, net	492	539
Investment in equity method affiliate	76	76
Other	65	68
Total other assets	633	683
Total Assets	$ 11,780	$ 11,729
Current Liabilities:
Accounts payable	$ 220	$ 149
Accounts payable—affiliated companies	2	2
Current portion of long-term debt	800	—
Short-term debt	50	250
Taxes accrued	55	34
Gas imbalances	28	19
Other	144	128
Total current liabilities	1,299	582
Other Liabilities:
Accumulated deferred income taxes, net	4	5
Regulatory liabilities	27	25
Other	63	71
Total other liabilities	94	101
Long-Term Debt	3,154	3,951
Commitments and Contingencies (Note 14)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at September 30, 2021 and December 31, 2020)	362	362
Common Units (435,877,546 issued and outstanding at September 30, 2021 and 435,549,892 issued and outstanding at December 31, 2020)	6,848	6,713

See Notes to the Unaudited Condensed Consolidated Financial Statements


Accumulated other comprehensive loss	(2)	(6)
Noncontrolling interest	25	26
Total Partners’ Equity	7,233	7,095
Total Liabilities and Partners’ Equity	$ 11,780	$ 11,729

See Notes to the Unaudited Condensed Consolidated Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See Notes to the Unaudited Condensed Consolidated Financial Statements


	Nine Months Ended September 30,
	2021	2020

	(In millions)
Cash Flows from Operating Activities:
Net income (loss)	$ 369	$ (14)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	313	314
Deferred income taxes	—	1
Impairments of property, plant and equipment and goodwill	—	28
Net loss on sale/retirement of assets	1	17
Equity in (earnings) losses of equity method affiliate, net	(5)	211
Return on investment in equity method affiliate	5	14
Equity-based compensation	12	10
Amortization of debt costs and discount	4	3
Other, net	(7)	(5)
Changes in other assets and liabilities:
Accounts receivable, net	(136)	14
Accounts receivable—affiliated companies	6	13
Inventory	(1)	4
Gas imbalance assets	16	(3)
Other current assets, net	(11)	—
Other assets	3	4
Accounts payable	67	(47)
Accounts payable—affiliated companies	—	1
Gas imbalance liabilities	9	(5)
Other current liabilities	42	(14)
Other liabilities	(9)	(3)
Net cash provided by operating activities	678	543
Cash Flows from Investing Activities:
Capital expenditures (excluding equity AFUDC)	(204)	(152)
Proceeds from sale of assets	3	19
Proceeds from insurance	—	1
Return of investment in equity method affiliate	—	9
Other, net	3	3
Net cash used in investing activities	(198)	(120)
Cash Flows from Financing Activities:
Decrease in short-term debt	(200)	179
Repayment of long-term debt	—	(267)
Proceeds from Revolving Credit Facility	—	869
Repayment of Revolving Credit Facility	—	(869)

See Notes to the Unaudited Condensed Consolidated Financial Statements


Distributions to common unitholders	(216)	(288)
Distributions to preferred unitholders	(26)	(27)
Distributions to non-controlling interests	(3)	(5)
Cash paid for employee equity-based compensation	(2)	(1)
Net cash used in financing activities	(447)	(409)
Net Increase in Cash, Cash Equivalents and Restricted Cash	33	14
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	3	4
Cash, Cash Equivalents and Restricted Cash at End of Period	$ 36	$ 18

See Notes to the Unaudited Condensed Consolidated Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(Unaudited)


	Nine Months Ended September 30, 2021
	Series A Preferred Units		Common Units		Accumulated Other Comprehensive Loss	Noncontrolling Interest	Total Partners’ Equity
	Units	Value	Units	Value	Value	Value	Value

	(In millions)
Balance as of December 31, 2020	15	$ 362	435	$ 6,713	$ (6)	$ 26	$ 7,095
Net income	—	9	—	155	—	1	165
Other comprehensive income	—	—	—	—	1	—	1
Distributions	—	(9)	—	(72)	—	(1)	(82)
Equity-based compensation, net of units for employee taxes	—	—	1	2	—	—	2
Balance as of March 31, 2021	15	$ 362	436	$ 6,798	$ (5)	$ 26	$ 7,181
Net income	—	8	—	79	—	1	88
Other comprehensive income	—	—	—	—	2	—	2
Distributions	—	(8)	—	(72)	—	(2)	(82)
Equity-based compensation, net of units for employee taxes	—	—	—	4	—	—	4
Balance as of June 30, 2021	15	$ 362	436	$ 6,809	$ (3)	$ 25	$ 7,193
Net income	—	9	—	107	—	—	116
Other comprehensive income	—	—	—	—	1	—	1
Distributions	—	(9)	—	(72)	—	—	(81)
Equity-based compensation, net of units for employee taxes	—	—	—	4	—	—	4
Balance as of September 30, 2021	15	$ 362	436	$ 6,848	$ (2)	$ 25	$ 7,233

See Notes to the Unaudited Condensed Consolidated Financial Statements


	Nine Months Ended September 30, 2020
	Series A Preferred Units		Common Units		Accumulated Other Comprehensive Loss	Noncontrolling Interest	Total Partners’ Equity
	Units	Value	Units	Value	Value	Value	Value

	(In millions)
Balance as of December 31, 2019	15	$ 362	435	$ 7,013	$ (3)	$ 37	$ 7,409
Net income (loss)	—	9	—	103	—	(7)	105
Other comprehensive loss	—	—	—	—	(6)	—	(6)
Distributions	—	(9)	—	(144)	—	(3)	(156)
Equity-based compensation, net of units for employee taxes	—	—	—	3	—	—	3
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—	—	—	(3)	—	—	(3)
Balance as of March 31, 2020	15	$ 362	435	$ 6,972	$ (9)	$ 27	$ 7,352
Net income	—	9	—	35	—	—	44
Distributions	—	(9)	—	(72)	—	—	(81)
Equity-based compensation, net of units for employee taxes	—	—	—	2	—	—	2
Balance as of June 30, 2020	15	$ 362	435	$ 6,937	$ (9)	$ 27	$ 7,317
Net income (loss)	—	9	—	(173)	—	1	(163)
Other comprehensive loss	—	—	—	—	2	—	2
Distributions	—	(9)	—	(72)	—	(2)	(83)
Equity-based compensation, net of units for employee taxes	—	—	—	3	—	—	3
Balance as of September 30, 2020	15	$ 362	435	$ 6,695	$ (7)	$ 26	$ 7,076

See Notes to the Unaudited Condensed Consolidated Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (the Partnership) is a Delaware limited partnership whose assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner 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. Our 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.

As of September 30, 2021, 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. 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 on an annual or continuing basis and may not remove Enable GP, its current general partner, 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.

As of September 30, 2021, the Partnership owned a 50% interest in SESH. See Note 8 for further discussion of SESH. For the nine months ended September 30, 2021, the Partnership owned a 50% ownership in Atoka and consolidated Atoka in the accompanying Condensed Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, the Partnership held a 60% interest in ESCP, which is consolidated in the accompanying Condensed Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.

Merger Agreement

On February 16, 2021, the Partnership and Energy Transfer entered into a Merger Agreement, whereby the Partnership will be acquired by Energy Transfer in an all-equity transaction, including the assumption of debt and other liabilities. Under the terms of the Merger Agreement, which has been unanimously approved by the Boards of Directors of both companies, Partnership common unitholders will receive 0.8595 of an Energy Transfer common unit for each Partnership common unit. Each of the Partnership’s Series A Preferred Units will be exchanged for 0.0265 Series G preferred units of Energy Transfer. The transaction will also include a $10 million cash payment for the Partnership’s general partner.

Generally, the Merger, including the receipt of equity consideration by common unitholders is expected to be treated as a tax-free transaction subject to certain exceptions as described in a Registration Statement on Form S-4 filed by Energy Transfer. The transaction, which is expected to close in the fourth quarter of 2021, is subject to customary closing conditions. CenterPoint Energy and OGE Energy, who collectively own approximately 79% of the outstanding Partnership common units, delivered their consents to the transaction. The Merger Agreement includes certain customary restrictions on the Partnership until closing of the

Merger, such as limitations on distributions, equity issuances, and incurring and prepaying indebtedness. If the Merger does not occur, under certain circumstances, the Partnership may be required to pay Energy Transfer a termination fee of $97.5 million. Until the closing, we must continue to operate the Partnership as a stand-alone company.

Basis of Presentation

The accompanying Condensed Consolidated Financial Statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying Condensed Consolidated Financial Statements and related notes should be read in conjunction with the Consolidated Financial Statements and related notes included in our Annual Report.

The Condensed Consolidated Financial Statements and the related notes reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures, (d) acquisitions and dispositions of businesses, assets and other interests, and (e) the impact of the ongoing COVID-19 pandemic and its economic effects, which have continued to cause significant volatility in natural gas, NGLs and crude oil prices.

For a description of the Partnership’s reportable segments, see Note 16.

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.

Sales and Retirements of Assets

In April 2020, we sustained damage to an approximately 100-mile gas gathering system in the Ark-La-Tex Basin of our gathering and processing segment. We have ceased operation of this system and are in the process of retiring it. We recognized a loss on retirement of approximately $20 million during the nine months ended September 30, 2020, which is included in Operation and maintenance expense in the Condensed Consolidated Statements of Income.

Accounts Receivable and Allowance for Doubtful Accounts

our customers’ financial strength and liquidity 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 and other receivable balances within other assets at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecast economic conditions over the assets contractual lives. The following table summarizes the required allowance for doubtful accounts.


	September 30, 2021	December 31, 2020

	(In millions)
Accounts receivable	$ 1	$ 1
Other current assets	1	3
Total Allowance for doubtful accounts	$ 2	$ 4

Inventory

Natural gas inventory is held, through the transportation and storage segment, to provide operational support for pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing 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. The Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of zero and $2 million during the three months ended September 30, 2021 and 2020, respectively, and $1 million and $9 million during the nine months ended September 30, 2021 and 2020, respectively.

Impairment of Long-Lived Assets (including Intangible Assets)

Impairment of Goodwill

Impairment of Investment in Equity Method Affiliate

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 investment is then compared to the carrying amount of the investment and an impairment charge equal to the difference, is recorded to Equity in earnings (losses) of equity method affiliate, net. Any basis difference between our recognized Investment in equity method affiliate and the underlying financial statements of the affiliate are assigned to the applicable net assets of the affiliate. For more information, see Note 8.

Capitalization of Interest and Allowance for Funds Used During Construction

Capitalized interest represents the approximate net composite interest cost of borrowed funds used for construction of assets other than those assets regulated by FERC. Allowance for funds used during construction (AFUDC) is separated into two components, borrowed funds (debt AFUDC) and equity funds (equity AFUDC). AFUDC is calculated under guidelines prescribed by FERC, and represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction of FERC regulated assets. Although equity 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. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. Capitalized interest and the borrowed funds component of AFUDC are recognized as an offset to Interest expense and the equity funds component of AFUDC is recognized in Other, net on the Condensed Consolidated Statements of Income. The Partnership capitalized interest and combined debt and equity AFUDC of $3 million and $1 million during the three months ended September 30, 2021 and 2020, respectively, and $10 million and $2 million during the nine months ended September 30, 2021 and 2020, respectively.

(2) New Accounting Pronouncements

Reference Rate Reform

In January 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This standard clarifies that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. ASU 2021-01 also amends the expedients and exceptions in ASC 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition. ASU 2021-01 was effective upon issuance and generally can be applied through December 31, 2022. The Partnership adopted ASU 2021-01 during the first quarter of 2021. The implementation had no material impact on the Condensed Consolidated Financial Statements and related disclosures.

(3) Revenues

The following tables disaggregate total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the three and nine months ended September 30, 2021 and 2020.


	Three Months Ended September 30, 2021
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 128	$ 158	$ (154)	$ 132
Natural gas liquids	485	5	(5)	485
Condensate	34	—	—	34
Total revenues from natural gas, natural gas liquids, and condensate	647	163	(159)	651
Loss on derivative activity	(22)	(6)	—	(28)
Total Product sales	$ 625	$ 157	$ (159)	$ 623
Service revenues:
Demand revenues	$ 30	$ 110	$ —	$ 140
Volume-dependent revenues	184	12	(3)	193
Total Service revenues	$ 214	$ 122	$ (3)	$ 333
Total Revenues	$ 839	$ 279	$ (162)	$ 956


	Three Months Ended September 30, 2020
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 58	$ 77	$ (68)	$ 67
Natural gas liquids	208	2	(2)	208
Condensate	15	—	—	15
Total revenues from natural gas, natural gas liquids, and condensate	281	79	(70)	290
Loss on derivative activity	(10)	—	—	(10)
Total Product sales	$ 271	$ 79	$ (70)	$ 280
Service revenues:
Demand revenues	$ 32	$ 116	$ —	$ 148
Volume-dependent revenues	160	10	(2)	168
Total Service revenues	$ 192	$ 126	$ (2)	$ 316
Total Revenues	$ 463	$ 205	$ (72)	$ 596


	Nine Months Ended September 30, 2021
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 331	$ 621	$ (415)	$ 537
Natural gas liquids	1,143	13	(13)	1,143
Condensate	101	—	—	101
Total revenues from natural gas, natural gas liquids, and condensate	1,575	634	(428)	1,781
Loss on derivative activity	(61)	(10)	—	(71)
Total Product sales	$ 1,514	$ 624	$ (428)	$ 1,710
Service revenues:
Demand revenues	$ 87	$ 344	$ —	$ 431
Volume-dependent revenues	535	46	(9)	572
Total Service revenues	$ 622	$ 390	$ (9)	$ 1,003
Total Revenues	$ 2,136	$ 1,014	$ (437)	$ 2,713


	Nine Months Ended September 30, 2020
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 161	$ 207	$ (181)	$ 187
Natural gas liquids	523	7	(7)	523
Condensate	49	—	—	49
Total revenues from natural gas, natural gas liquids, and condensate	733	214	(188)	759
Gain (loss) on derivative activity	6	(1)	—	5
Total Product sales	$ 739	$ 213	$ (188)	$ 764
Service revenues:
Demand revenues	$ 105	$ 371	$ —	$ 476
Volume-dependent revenues	487	38	(6)	519
Total Service revenues	$ 592	$ 409	$ (6)	$ 995
Total Revenues	$ 1,331	$ 622	$ (194)	$ 1,759

MRT Rate Case Settlements

amounts previously held in reserve related to transportation and storage services performed in 2019. In May 2020, $21 million previously held in reserve was refunded to customers, which was inclusive of interest.

Accounts Receivable

The following table summarizes the components of accounts receivable, net of allowance for doubtful accounts.


	September 30, 2021	December 31, 2020

	(In millions)
Accounts Receivable:
Customers	$ 385	$ 245
Contract assets (1)	3	12
Non-customers	5	6
Total Accounts Receivable (2)	$ 393	$ 263

____________________

(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 contract assets related to firm service transportation contracts with tiered rates of $11 million as of September 30, 2021 and $9 million as of December 31, 2020, which are reflected in Other Assets.

(2)

Total Accounts Receivable includes Accounts receivable, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.

Contract Liabilities

Our contract liabilities primarily consist of prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment.

The table below summarizes the change in the contract liabilities.


	September 30, 2021	December 31, 2020

	(In millions)
Deferred revenues, beginning of period (1)	$ 44	$ 48
Amounts recognized in revenues related to the beginning balance	(21)	(25)
Net additions	20	21
Deferred revenues, end of period (1)	$ 43	$ 44

____________________

(1)

Deferred revenues includes deferred revenue—affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities.

The table below summarizes the timing of recognition of these contract liabilities as of September 30, 2021.


	2021	2022	2023	2024	2025 and After
	(In millions)
Deferred revenues (1)	$ 17	$ 8	$ 8	$ 7	$ 3

____________________

(1)

Deferred revenues includes deferred revenue—affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities.

Remaining Performance Obligations

Our remaining performance obligations consist primarily of firm arrangements and minimum volume commitment arrangements. Upon completion of the performance obligations associated with these arrangements, customers are invoiced and revenue is recognized as Service revenues in the Condensed Consolidated Statements of Income.

The table below summarizes the timing of recognition of the remaining performance obligations as of September 30, 2021.


	2021	2022	2023	2024	2025 and After
	(In millions)
Transportation and Storage	$ 114	$ 422	$ 364	$ 270	$ 1,143
Gathering and Processing	30	122	121	101	213
Total remaining performance obligations	$ 144	$ 544	$ 485	$ 371	$ 1,356

(4) Leases

The table below summarizes the operating leases included in the Condensed Consolidated Balance Sheets.


	Balance Sheet Location	September 30, 2021	December 31, 2020

		(In millions)
Operating lease asset	Other Assets	$ 23	$ 25
Total right-of-use assets		$ 23	$ 25

Operating lease liabilities	Other Current Liabilities	$ 4	$ 4
Operating lease liabilities	Other Liabilities	22	24
Total lease liabilities		$ 26	$ 28

As of September 30, 2021, all lease obligations outstanding were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities.

The following table presents the Partnership’s rental costs associated with field equipment and buildings.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Rental Costs:
Field equipment	$ 2	$ 3	$ 7	$ 12
Office space	2	1	5	3

As of September 30, 2021, the weighted average remaining lease term is 6.1 years and the weighted average discount rate is 5.54%.

The following table presents the Partnership’s lease cost.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Lease Cost:
Operating lease cost	$ 1	$ 2	$ 4	$ 5
Short-term lease cost	2	2	6	9
Variable lease cost	1	—	2	1
Total Lease Cost	$ 4	$ 4	$ 12	$ 15

All lease costs were included in the gathering and processing reportable segment during the three and nine months ended September 30, 2021 and 2020.

Under ASC 842, as of September 30, 2021, the Partnership has operating lease obligations expiring at various dates. Undiscounted cash flows for operating lease liabilities are as follows:


	Non-cancellable operating leases

	(In millions)
Year Ending December 31,
2021 - remainder	$ 1
2022	6
2023	6
2024	4
2025	3
2026	2
After 2026	6
Total	28
Less: impact of the applicable discount rate	2
Total lease liabilities	$ 26

(5) Earnings Per Limited Partner Unit

The following table illustrates the Partnership’s calculation of earnings per unit for common units.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions, except per unit data)
Net income (loss)	$ 116	$ (163)	$ 369	$ (14)
Net income (loss) attributable to noncontrolling interest	—	1	2	(6)
Series A Preferred Unit distributions	9	9	26	27
Net income (loss) available to common units	$ 107	$ (173)	$ 341	$ (35)

Net income (loss) allocable to common units	$ 107	$ (173)	$ 341	$ (35)
Dilutive effect of Series A Preferred Unit distributions	8	—	26	—
Diluted net income (loss) allocable to common units	$ 115	$ (173)	$ 367	$ (35)

Basic weighted average number of common units outstanding (1)	438	437	438	437
Dilutive effect of Series A Preferred Units (2)	46	—	46	—
Dilutive effect of performance units (3)	1	—	1	—
Diluted weighted average number of common units outstanding	485	437	485	437

Basic and diluted earnings (losses) per unit
Basic	$ 0.24	$ (0.40)	$ 0.78	$ (0.08)
Diluted	$ 0.24	$ (0.40)	$ 0.76	$ (0.08)

____________________

(1)

Basic weighted average number of outstanding common units includes approximately two million time-based phantom units for each of the three months ended September 30, 2021 and 2020, respectively, and two million time-based phantom units for each of the nine months ended September 30, 2021 and 2020, respectively.

(2)

For the three and nine months ended September 30, 2020, the issuance of “if converted” common units attributable to the Series A Preferred Units were excluded in the calculation of diluted earnings (loss) per unit as the impact was anti-dilutive.

(3)

The contingent effect of the performance unit awards was anti-dilutive for the three and nine months ended September 30, 2020.

(6) Partners’ Equity

The Partnership paid or has authorized payment of the following cash distributions to common unitholders, as applicable, during 2021 and 2020 (in millions, except for per unit amounts):


Three Months Ended	Record Date	Payment Date	Per Unit Distribution	Total Cash Distribution
September 30, 2021 (1)	November 8, 2021	November 17, 2021	$ 0.16525	$ 72
June 30, 2021	August 12, 2021	August 24, 2021	$ 0.16525	$ 72
March 31, 2021	May 13, 2021	May 25, 2021	$ 0.16525	$ 72
December 31, 2020	February 22, 2021	March 1, 2021	$ 0.16525	$ 72
September 30, 2020	November 17, 2020	November 24, 2020	$ 0.16525	$ 72
June 30, 2020	August 18, 2020	August 25, 2020	$ 0.16525	$ 72
March 31, 2020	May 19, 2020	May 27, 2020	$ 0.16525	$ 72

_____________________

(1)

The Board of Directors declared a $0.16525 per common unit cash distribution on October 26, 2021, to be paid on November 17, 2021 to common unitholders of record at the close of business on November 8, 2021.

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, February 18, 2016, to, but not including, the five-year anniversary of the original issue date, February 18, 2021. Thereafter, the holders receive a quarterly cash distribution based on a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5%, which is included for each relevant period in the table below.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2021 and 2020 (in millions, except for per unit amounts):


Three Months Ended	Record Date	Payment Date	Distribution Rate	Per Unit Distribution	Total Cash Distribution
September 30, 2021 (1)	October 26, 2021	November 12, 2021	8.6449 %	$ 0.5403	$ 8
June 30, 2021	July 30, 2021	August 13, 2021	8.7016 %	$ 0.5439	$ 8
March 31, 2021 (2)	April 26, 2021	May 14, 2021	8.7375 %	$ 0.5873	$ 9
December 31, 2020	February 12, 2021	February 12, 2021	10.0 %	$ 0.625	$ 9
September 30, 2020	November 3, 2020	November 13, 2020	10.0 %	$ 0.625	$ 9
June 30, 2020	August 4, 2020	August 14, 2020	10.0 %	$ 0.625	$ 9
March 31, 2020	May 5, 2020	May 15, 2020	10.0 %	$ 0.625	$ 9

_____________________

(1)

The Board of Directors declared a $0.5403 per Series A Preferred Unit cash distribution on October 26, 2021, to be paid on November 12, 2021, to Series A Preferred unitholders of record at the close of business on October 26, 2021.

(2)

The distribution rate for the three months ended March 31, 2021 reflects 10% through February 18, 2021, and the sum of the three-month LIBOR plus 8.5% for the remaining days in the period.

(7) Impairments of Property, Plant and Equipment and Goodwill

Impairment of Property, Plant and Equipment

The Partnership periodically evaluates property, plant and equipment for impairment 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. Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing COVID-19 pandemic and its economic effects, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, as of March 31, 2020, management reassessed the carrying value of the Atoka assets, in which the Partnership owns a 50% interest in the consolidated joint venture, which is a component of the gathering and processing segment. Based on forecasted future undiscounted cash flows, management determined that the carrying value of the Atoka assets were not fully recoverable. The Partnership utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs were forecasted cash flows and the discount rate. The fair value measurement is based on inputs that are not observable in the market and thus represent Level 3 inputs. Applying a discounted cash flow model to the property, plant and equipment, the Partnership recognized a $16 million impairment, which is included in Impairments of property, plant and equipment and goodwill on the Condensed Consolidated Statements of Income during the nine months ended September 30, 2020.

Impairment of Goodwill

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 2020, the commodity price declines due to the existing oversupply of crude oil, NGLs and natural gas were exacerbated by the ongoing COVID-19 pandemic and its economic effects, in addition to the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia in the first quarter. Despite the subsequent agreement in April 2020 by a coalition of nations including Russia and Saudi Arabia to reduce production of crude oil, the price of NGLs and crude oil had remained significantly lower than pre-pandemic levels. Amid such crude oil, NGL and natural gas price declines, producers had 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 Ark-La-Tex Basin reporting unit during the first quarter of 2020. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations had 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 Ark-La-Tex Basin reporting unit would more likely than not be impaired. As a result, the Partnership performed a quantitative test for our goodwill and determined that the carrying value of the Ark-La-Tex Basin reporting unit exceeded its fair value and that goodwill associated with the Ark-La-Tex Basin was completely impaired in the amount of $12 million. The impairment is included in Impairments of property, plant and equipment and goodwill on the Condensed Consolidated Statements of Income for the nine months ended September 30, 2020. The Partnership had no goodwill recorded as of September 30, 2021 and December 31, 2020.

(8) 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. 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 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.

At September 30, 2020, the Partnership estimated the fair value of its investment in SESH was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and the current status of renewal negotiations. As a result, the Partnership recorded a $225 million impairment on its investment in SESH for the three and nine months ended September 30, 2020, which is included in Equity in earnings (losses) of equity method affiliate, net in the Partnership’s Condensed Consolidated Statements of Income. The impairment analysis of the Partnership’s investment in SESH compared the estimated fair value of the investment to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches. Due to the significant unobservable estimates and assumptions required, the Partnership concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. The basis difference for our investment in SESH has been assigned to its property, plant and equipment and will be amortized over its approximately 50-year remaining useful life. See Note 1 for further information concerning the method used to evaluate and measure the impairment on the Partnership’s investment in SESH.

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. The Partnership billed SESH $2 million and $3 million during the three months ended September 30, 2021 and 2020, respectively, and $7 million and $11 million during the nine months ended September 30, 2021 and 2020, respectively, associated with these service agreements.

The Partnership includes equity in earnings (losses) of equity method affiliate, net under the Other Income (Expense) caption in the Condensed Consolidated Statements of Income. The following table presents the amount of Equity in earnings of equity method affiliate recognized, Impairment of equity method affiliate investment and Distributions from equity method affiliate received.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Equity in earnings of equity method affiliate	$ 4	$ 3	$ 5	$ 14
Impairment of equity method affiliate investment	—	(225)	—	(225)
Equity in earnings (losses) of equity method affiliate, net	$ 4	$ (222)	$ 5	$ (211)
Distributions from equity method affiliate (1)	1	4	5	23

___________________

(1)

Distributions from equity method affiliate includes a $5 million and $14 million return on investment and a zero and $9 million return of investment for the nine months ended September 30, 2021 and 2020, respectively.

The following table includes the summarized financial information of SESH.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Income Statements:
Revenues	$ 20	$ 24	$ 51	$ 79
Operating income	8	11	14	40
Net income	3	6	1	27

(9) Debt

The following table presents the Partnership’s outstanding debt.


	September 30, 2021			December 31, 2020
	Outstanding Principal	Discount (1)	Total Debt	Outstanding Principal	Discount (1)	Total Debt

	(In millions)
Commercial Paper	$ 50	$ —	$ 50	$ 250	$ —	$ 250
Revolving Credit Facility	—	—	—	—	—	—
2019 Term Loan Agreement	800	—	800	800	—	800
2024 Notes	600	—	600	600	—	600
2027 Notes	700	(1)	699	700	(2)	698
2028 Notes	800	(4)	796	800	(5)	795
2029 Notes	547	(1)	546	547	(1)	546
2044 Notes	531	—	531	531	—	531
Total debt	$ 4,028	$ (6)	$ 4,022	$ 4,228	$ (8)	$ 4,220
Less: Short-term debt (2)			50			250
Less: Current portion of long-term debt (3)			800			—
Less: Unamortized debt expense (4)			18			19
Total long-term debt			$ 3,154			$ 3,951

____________________

(1)

Unamortized discount on long-term debt is amortized over the life of the respective debt.

(2)

Short-term debt includes $50 million and $250 million of outstanding commercial paper as of September 30, 2021 and December 31, 2020, respectively.

(3)

As of September 30, 2021, Current portion of long-term debt included $800 million outstanding balance of the 2019 Term Loan Agreement.

(4)

As of September 30, 2021 and December 31, 2020, there was an additional $2 million and $3 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.

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 $50 million and $250 million outstanding under our commercial paper program at September 30, 2021 and December 31, 2020, respectively. As of September 30, 2021, the weighted average interest rate for the outstanding commercial paper was 0.40%.

Revolving Credit Facility

The Partnership’s 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 September 30, 2021, there were no principal advances, $3 million letters of credit outstanding and our available borrowing capacity was approximately $1.5 billion under our Revolving Credit Facility.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the 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 September 30, 2021, 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 credit ratings. As of September 30, 2021, the commitment fee under the restated 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 Condensed Consolidated Statements of Income.

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. As of September 30, 2021, there was $800 million outstanding under the 2019 Term Loan Agreement. 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. 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 September 30, 2021, 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 September 30, 2021, the weighted average interest rate of the 2019 Term Loan Agreement was 2.06%, including the impact of the associated interest rate derivatives designated as hedging instruments for accounting purposes.

Senior Notes

As of September 30, 2021, the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $6 million of unamortized discount and $18 million of unamortized debt expense at September 30, 2021, resulting in effective interest rates of 4.00%, 4.56%, 5.18%, 4.30% and 5.08%, respectively, during the nine months ended September 30, 2021. In March 2020, the Partnership’s EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility.

During the nine months ended September 30, 2020, the Partnership repurchased $22 million aggregate principal amount of the 2029 Notes and 2044 Notes in open market transactions for approximately $17 million plus accrued interest, which resulted in a $5 million gain on extinguishment of debt. The gain is included in Other, net in the Condensed Consolidated Statements of Income.

As of September 30, 2021, the Partnership was in compliance with all of its debt agreements, including financial covenants.

(10) Derivative Instruments and Hedging Activities

The primary risks managed using derivative instruments are commodity price and interest rate risks.

Derivatives Not Designated as Hedging Instruments

Quantitative Disclosures Related to Derivative Instruments Not Designated as Hedging Instruments

The following table presents the Partnership’s derivative instruments that were not designated as hedging instruments for accounting purposes.


	September 30, 2021		December 31, 2020
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps	—	4	—	18
Financial basis futures/swaps	1	11	—	27
Financial swaptions (2)	—	2	—	7
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	—	180	—	465
Financial swaptions (2)	—	60	—	90
Natural gas liquids— MBbl (4)
Financial futures/swaps	30	300	855	1,210
Financial options	—	—	—	45

____________________

(1)

As of September 30, 2021, 97.6% of the natural gas contracts had durations of one year or less and 2.4% had durations of more than one year and less than two years. As of December 31, 2020, 95.7% of the natural gas contracts had durations of one year or less and 4.3% had durations of more than one year and less than two years.

(2)

The notional volume 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 volume hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.

(3)

As of September 30, 2021, 93.7% of the crude oil (for condensate) contracts had durations of one year or less and 6.3% had durations of more than one year and less than two years. As of December 31, 2020, 100.0% of the crude oil (for condensate) contracts had durations of one year or less.

(4)

As of September 30, 2021, 95.5% of the natural gas liquids contracts had durations of one year or less and 4.5% had durations of more than one year and less than two years. As of December 31, 2020, 100.0% of the natural gas liquids contracts had durations of one year or less.

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 following table presents the Partnership’s derivative instruments that were designated as hedging instruments for accounting purposes.


	September 30, 2021	December 31, 2020
	Gross Notional Value
	(In millions)
Interest rate swaps	$ 300	$ 300

Balance Sheet Presentation Related to Derivative Instruments

The following table presents the fair value of the derivative instruments that are included in the Partnership’s Condensed Consolidated Balance Sheets that were not designated as hedging instruments for accounting purposes.


		September 30, 2021		December 31, 2020
		Fair Value
Instrument	Balance Sheet Location	Assets	Liabilities	Assets	Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$ —	$ 13	$ 2	$ 2
Financial swaptions	Other Current	—	12	1	2
Crude oil (for condensate)
Financial futures/swaps	Other Current	—	5	1	13
Financial swaptions	Other Current	—	2	—	—
Financial swaptions	Other	—	—	—	—
Natural gas liquids
Financial futures/swaps	Other Current	3	9	15	3
Financial swaptions	Other Current	—	—	—	1
Total gross commodity derivatives (1)		$ 3	$ 41	$ 19	$ 21

_____________________

(1)

See Note 11 for a reconciliation of the Partnership’s commodity derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020.

The following table presents the fair value of the derivative instruments that are included in the Partnership’s Condensed Consolidated Balance Sheets that were designated as hedging instruments for accounting purposes.


		September 30, 2021		December 31, 2020
		Fair Value
Instrument	Balance Sheet Location	Assets	Liabilities	Assets	Liabilities

		(In millions)
Interest rate swaps (1)	Other Current	$ —	$ 2	$ —	$ 6

_____________________

(1)

All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of September 30, 2021 and December 31, 2020.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income.


	Amounts Recognized in Income
	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Natural gas
Financial futures/swaps losses	$ (16)	$ (5)	$ (29)	$ (2)
Financial swaptions losses	(6)	(4)	(11)	(6)
Physical purchases/sales losses	—	(1)	—	—
Crude oil (for condensate)
Financial futures/swaps gains (losses)	(1)	—	(13)	12
Financial swaptions gains (losses)	—	—	(2)	2
Natural gas liquids
Financial futures/swaps losses	(5)	—	(16)	(1)
Total	$ (28)	$ (10)	$ (71)	$ 5

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended September 30, 2021 and 2020, if any, are reported in Product sales.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Change in fair value of commodity derivatives	$ (7)	$ (15)	$ (36)	$ (17)
Realized gains (losses) on commodity derivatives	(21)	5	(35)	22
Gains (losses) on commodity derivative activity	$ (28)	$ (10)	$ (71)	$ 5

The following table presents the effect of derivative instruments that were designated as hedging instruments on the Partnership’s Condensed Consolidated Statements of Income.


	Amounts Recognized in Income
	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Interest rate swaps losses	$ (1)	$ (2)	$ (4)	$ (3)

Interest rate derivatives designated as hedges are recognized in income once settled. Settlement amounts recognized in income for the periods ended September 30, 2021 and 2020 are reported in Interest expense.

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 of 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 September 30, 2021, under these obligations, the Partnership had posted $10 million of cash collateral related to natural gas swaps and swaptions, crude oil swaps and swaptions and NGL swaps and $6 million of 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.

(11) Fair Value Measurements

Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. 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 three and nine months ended September 30, 2021, there were no transfers between levels. As of September 30, 2021, there were no contracts classified as Level 3.

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 Condensed 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.


	September 30, 2021		December 31, 2020
	Carrying Amount	Fair Value	Carrying Amount	Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$ —	$ —	$ —	$ —
2019 Term Loan Agreement (Level 2)	800	800	800	800
2024 Notes (Level 2)	600	637	600	612
2027 Notes (Level 2)	699	776	698	709
2028 Notes (Level 2)	796	900	795	817
2029 Notes (Level 2)	546	593	546	544
2044 Notes (Level 2)	531	581	531	499

____________________

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $50 million and $250 million of commercial paper was outstanding as of September 30, 2021 and December 31, 2020, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes, and 2044 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 September 30, 2021, 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 September 30, 2021, all of the asset groups were considered recoverable. Based upon review for other than temporary declines in fair value, the investment in equity method affiliate was considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions, including the supply of and demand for crude oil, NGLs and natural gas as well as the ongoing COVID-19 pandemic and its economic effects, could reduce forecasted undiscounted cash flows for the asset groups and result in other than temporary declines in the fair value of the investment in equity method affiliate.

Contracts with Master Netting Arrangements

As of September 30, 2021, 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.


September 30, 2021	Commodity Contracts		Gas Imbalances (1)
	Assets	Liabilities	Assets (2)	Liabilities (3)

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$ —	$ 11	$ —	$ —
Significant other observable inputs (Level 2)	3	30	23	26
Total fair value	3	41	23	26
Netting adjustments	(3)	(3)	—	—
Total	$ —	$ 38	$ 23	$ 26


December 31, 2020	Commodity Contracts		Gas Imbalances (1)
	Assets	Liabilities	Assets (2)	Liabilities (3)

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$ 2	$ 14	$ —	$ —
Significant other observable inputs (Level 2)	17	7	23	16
Total fair value	19	21	23	16
Netting adjustments	(19)	(19)	—	—
Total	$ —	$ 2	$ 23	$ 16

______________________

(1)

(2)

Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $3 million and $19 million at September 30, 2021 and December 31, 2020, 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 $2 million and $3 million at September 30, 2021 and December 31, 2020, 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.

(12) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:


	Nine Months Ended September 30,
	2021	2020

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest and debt AFUDC	$ 112	$ 129
Income taxes, net of refunds	(1)	1
Non-cash transactions:
Accounts payable related to capital expenditures	13	9
Lease liabilities related to derecognition of right-of-use assets	(1)	(5)
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—	(3)

(13) Related Party Transactions

The Partnership’s revenues from affiliated companies accounted for 5% and 6% of total revenues during the nine months ended September 30, 2021 and 2020, respectively. The following table presents the amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$ 15	$ 17	$ 58	$ 76
Natural gas product sales — CenterPoint Energy	—	—	5	1
Gas transportation and storage service revenues — OGE Energy	10	9	29	28
Natural gas product sales — OGE Energy	1	4	34	9
Total revenues — affiliated companies	$ 26	$ 30	$ 126	$ 114

The following table presents the amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$ —	$ —	$ —	$ 1
Cost of natural gas purchases — OGE Energy	13	6	56	20
Total cost of natural gas purchases — affiliated companies	$ 13	$ 6	$ 56	$ 21

Corporate services and seconded employees

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 the 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 2021 are both less than $1 million.

As of September 30, 2021, 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 an annual cap of $5 million until secondment is terminated.

The following table presents the amounts charged to the Partnership by affiliates for seconded employees, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Seconded Employee Costs — OGE Energy	$ 4	$ 5	$ 11	$ 13

(14) Commitments and Contingencies

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 for deliveries to the Godley Plant in Johnson County, Texas. As of September 30, 2021, the Partnership estimates the remaining associated minimum volume commitment fee to be $153 million. Minimum volume commitment fees are expected to be $4 million for the remainder of 2021, $23 million per year from 2022 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, the cornerstone shipper for the liquefied natural gas 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 requested approval to transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. The Partnership filed applications with FERC to obtain authorization to construct and operate the pipeline on February 28, 2020. FERC issued the environmental assessment on October 29, 2020. On June 1, 2021, FERC issued the Order Issuing Certificates and Approving Abandonment, which authorizes construction and operation of the Gulf Run Pipeline and transfer of certain existing EGT infrastructure to the Gulf Run Pipeline. On October 19, 2021, FERC issued the Notice to Proceed with Construction. The Partnership estimates the total cost of the Gulf Run Pipeline project would be as much as $540 million, excluding AFUDC. The project is backed by a 20-year firm transportation service agreement. 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 late 2022.

(15) Equity-Based Compensation

The following table summarizes the Partnership’s equity-based compensation expense related to performance units and phantom units for the Partnership’s employees and independent directors.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Performance units	$ 3	$ 1	$ 7	$ 5
Phantom units	1	2	5	5
Total compensation expense	$ 4	$ 3	$ 12	$ 10

The following table presents the assumptions related to the performance units granted in 2021.


	2021
Number of units granted	1,453,897
Fair value of units granted	$ 10.26
Expected distribution yield	12.90 %
Expected price volatility	100.00 %
Risk-free interest rate	0.27 %
Expected life of units (in years)	3

The following table presents the number of phantom units granted and the grant date fair value related to the phantom units granted in 2021.


	2021
Phantom Units granted	1,371,001
Fair value of phantom units granted	$5.41 - $6.87

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units applicable to the Partnership’s employees at September 30, 2021 and changes during 2021 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 December 31, 2020	1,765,508	$ 13.10	1,790,845	$ 10.29
Granted (1)	1,453,897	10.26	1,371,001	6.86
Vested (2)	(398,614)	17.70	(485,662)	13.08
Forfeited	(45,945)	9.94	(139,975)	8.52
Units outstanding at September 30, 2021	2,774,846	$ 11.00	2,536,209	$ 7.99
Aggregate intrinsic value of units outstanding at September 30, 2021	$ 23		$ 21

_____________________

(1)

Performance units 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 September 30, 2021 include 398,614 units from the 2018 annual grant, which were approved by the Board of Directors in 2018 and, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2018 through December 31, 2020, no performance units vested.

Unrecognized Compensation Cost

The following table summarizes the Partnership’s unrecognized compensation cost for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized.


	September 30, 2021
	Unrecognized Compensation Cost (In millions)	Weighted Average Period for Recognition (In years)
Performance Units	$ 16	1.76
Phantom Units	10	1.61
Total	$ 26

As of September 30, 2021, there were 3,151,858 units available for issuance under the long-term incentive plan.

(16) 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 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 excerpt in the Partnership’s audited 2020 Notes to Consolidated Financial Statements included in the Annual Report. 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 reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner 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.

Financial data for reportable segments are as follows:


Three Months Ended September 30, 2021	Gathering and Processing	Transportation (1) and Storage	Eliminations	Total

	(In millions)
Product sales	$ 625	$ 157	$ (159)	$ 623
Service revenues	214	122	(3)	333
Total Revenues	839	279	(162)	956
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	571	154	(160)	565
Operation and maintenance, General and administrative	77	43	(1)	119
Depreciation and amortization	74	30	—	104
Taxes other than income tax	10	6	—	16
Operating income	$ 107	$ 46	$ (1)	$ 152
Total Assets	$ 10,953	$ 6,130	$ (5,303)	$ 11,780
Capital expenditures (excluding equity AFUDC)	$ 27	$ 26	$ —	$ 53


Three Months Ended September 30, 2020	Gathering and Processing	Transportation (1) and Storage	Eliminations	Total

	(In millions)
Product sales	$ 271	$ 79	$ (70)	$ 280
Service revenues	192	126	(2)	316
Total Revenues	463	205	(72)	596
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	244	78	(72)	250
Operation and maintenance, General and administrative	77	47	—	124
Depreciation and amortization	75	30	—	105
Taxes other than income tax	10	7	—	17
Operating income	$ 57	$ 43	$ —	$ 100
Total assets as of December 31, 2020	$ 10,830	$ 5,729	$ (4,830)	$ 11,729
Capital expenditures (excluding equity AFUDC)	$ 21	$ 29	$ —	$ 50


Nine Months Ended September 30, 2021	Gathering and Processing	Transportation (1) and Storage	Eliminations	Total

	(In millions)
Product sales	$ 1,514	$ 624	$ (428)	$ 1,710
Service revenues	622	390	(9)	1,003
Total Revenues	2,136	1,014	(437)	2,713
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	1,406	539	(435)	1,510
Operation and maintenance, General and administrative	229	129	(2)	356
Depreciation and amortization	222	91	—	313
Taxes other than income tax	32	20	—	52
Operating income	$ 247	$ 235	$ —	$ 482
Total Assets	$ 10,953	$ 6,130	$ (5,303)	$ 11,780
Capital expenditures (excluding equity AFUDC)	$ 68	$ 136	$ —	$ 204


Nine Months Ended September 30, 2020	Gathering and Processing	Transportation (1) and Storage	Eliminations	Total

	(In millions)
Product sales	$ 739	$ 213	$ (188)	$ 764
Service revenues	592	409	(6)	995
Total Revenues	1,331	622	(194)	1,759
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	631	215	(193)	653
Operation and maintenance, General and administrative	250	137	(1)	386
Depreciation and amortization	223	91	—	314
Impairments of property, plant and equipment and goodwill	28	—	—	28
Taxes other than income tax	32	20	—	52
Operating income	$ 167	$ 159	$ —	$ 326
Total assets as of December 31, 2020	$ 10,830	$ 5,729	$ (4,830)	$ 11,729
Capital expenditures (excluding equity AFUDC)	$ 79	$ 73	$ —	$ 152

_____________________

(1)

See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and nine months ended September 30, 2021 and 2020.