SEC Filing | OGE Energy Corporation

View:

oge-20211231

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, 2021

☐ 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. þ Yes o No Oklahoma Gas and Electric Company þ Yes o No

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

OGE Energy Corp. o Yes þ No Oklahoma Gas and Electric Company o Yes þ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

OGE Energy Corp. þ Yes o No Oklahoma Gas and Electric Company þ Yes o No

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

OGE Energy Corp. þ Yes o No Oklahoma Gas and Electric Company þ Yes o No

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

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 ☑

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 þ No Oklahoma Gas and Electric Company ☐ Yes þ No

At June 30, 2021, 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 $6,735,867,248 based on the number of shares held by non-affiliates (200,174,361) and the reported closing market price of the common stock on the New York Stock Exchange on such date of $33.65.

At June 30, 2021, there was no voting or non-voting common equity of Oklahoma Gas and Electric Company held by non-affiliates.

At January 31, 2022, there were 200,201,818 shares of OGE Energy Corp.'s common stock, par value $0.01 per share, outstanding.

At January 31, 2022, 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 2022 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, 2021

TABLE OF CONTENTS


			Page
GLOSSARY OF TERMS			ii
FORWARD-LOOKING STATEMENTS			1


Part I
Item 1. Business			3








Item 1A. Risk Factors			14
Item 1B. Unresolved Staff Comments			25
Item 2. Properties			25
Item 3. Legal Proceedings			26
Item 4. Mine Safety Disclosures			26

Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			27
Item 6. [Reserved]			27
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations			27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			47
Item 8. Financial Statements and Supplementary Data			48
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			116
Item 9A. Controls and Procedures			116
Item 9B. Other Information			120
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections			120

Part III
Item 10. Directors, Executive Officers and Corporate Governance			120
Item 11. Executive Compensation			120
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			120
Item 13. Certain Relationships and Related Transactions, and Director Independence			121
Item 14. Principal Accountant Fees and Services			121

Part IV
Item 15. Exhibit and Financial Statement Schedules			123
Item 16. Form 10-K Summary			128
Signatures			129

GLOSSARY OF TERMS

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


Abbreviation			Definition

2020 Form 10-K			Annual Report on Form 10-K for the year ended December 31, 2020
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
Enogex Holdings			Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex LLC			Enogex LLC, collectively with its subsidiaries (effective July 31, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)

EPA			U.S. Environmental Protection Agency


Federal Clean Water Act			Federal Water Pollution Control Act of 1972, as amended
FERC			Federal Energy Regulatory Commission
GAAP			Accounting principles generally accepted in the U.S.
IRP			Integrated Resource Plan
ISO			Independent system operator
kV			Kilovolt
LIBOR			London Interbank Offered Rate

MMBtu			Million British thermal unit



MW			Megawatt
MWh			Megawatt-hour

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 (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



QF contract			Contract with qualified cogeneration facilities and small power production producers
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
SESH			Southeast Supply Header, LLC, in which Enable owned a 50 percent interest, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast

SO2			Sulfur dioxide
SOFR			Secured Overnight Funding Rate
SPP			Southwest Power Pool
Stock Incentive Plan			2013 Stock Incentive Plan
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

iii

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," "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 its subsidiaries to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;

•the ability to obtain timely and sufficient rate relief to allow for recovery, including through securitization, of items such as capital expenditures, fuel 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;

•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 current pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in the Registrants' markets

and operational challenges if large percentages of key employee groups become sick and are unable to work for an extended period of time;

•potential employee engagement issues and/or increased rates of employee turnover if federal or state authorities impose COVID-19-related vaccine or testing mandates;

•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;

•business conditions in the energy and natural gas midstream industries, including specifically for Energy Transfer that may affect the fair value of OGE Energy's investment in Energy Transfer's equity securities and the level of distributions OGE Energy receives from Energy Transfer;

•difficulty in making accurate assumptions and projections regarding future distributions associated with OGE Energy's investment in Energy Transfer's equity securities, as OGE Energy does not control Energy Transfer; 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, incorporated in August 1995 in the State of Oklahoma, is a holding company with investments in energy and energy services providers offering physical delivery and related services for electricity in Oklahoma and western Arkansas and natural gas, crude oil and NGLs across the U.S. OGE Energy conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations.

Electric Utility Operations. OGE Energy's electric utility 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 utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Natural Gas Midstream Operations. On December 2, 2021, Energy Transfer completed its previously announced acquisition of Enable. Pursuant to and subject to the conditions of the merger agreement, all outstanding common units of Enable were acquired by Energy Transfer in an all-equity transaction. Under the terms of the merger agreement, Enable's common unitholders, including OGE Energy, received 0.8595 of one common unit representing limited partner interests in Energy Transfer for each common unit of Enable. Therefore, on December 2, 2021, 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. Prior to December 2, 2021, OGE Energy's natural gas midstream operations segment represented OGE Energy's investment in Enable, which OGE Energy accounted for as an equity method investment. Formed in 2013, Enable was primarily engaged in the business of gathering, processing, transporting and storing natural gas, with natural gas gathering and processing assets located in four states which served natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owned crude oil gathering assets in the Anadarko and Williston Basins and had natural gas transportation and storage assets located in Oklahoma, the Texas Panhandle, Louisiana, Illinois and Alabama. For further discussion regarding Enable's business, see OGE Energy's 2020 Form 10-K. Upon the closing of the Energy Transfer and Enable merger, OGE Energy's natural gas midstream operations segment represents OGE Energy's investment in Energy Transfer's equity securities and legacy Enable seconded employee pension and postretirement costs. The investment in Energy Transfer's equity securities is held through wholly-owned subsidiaries and ultimately OGE Holdings. At December 31, 2021, OGE energy owned 95.4 million, or approximately three percent, of Energy Transfer's limited partner units. OGE Energy does not have board representation at and does not own general partner units of Energy Transfer. As such, OGE Energy accounts for its investment in Energy Transfer as an investment in equity securities. See "Natural Gas Midstream Operations - Energy Transfer" below for further discussion of Energy Transfer's business. OGE Energy intends to exit the midstream segment in a prudent manner.

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 at www.oge.com/sec-filings, 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 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 utility, 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. OGE Energy plans to fully exit its natural gas midstream operations segment by prudently selling its Energy Transfer units. OGE Energy will continue to utilize cash distributions from its natural gas midstream operations segment and reinvest the proceeds from the sale of Energy Transfer units to help fund its business. In the next five years, OGE Energy expects to continue to grow the dividend, targeting a dividend payout ratio of 65 to 70 percent based on utility earnings. 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 879,000 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 2021 from sales in Oklahoma and the remainder from sales in Arkansas. OG&E does not currently serve wholesale customers in either state.

In 2021, OG&E's system control area peak demand was 6,722 MWs on August 25, 2021, and OG&E's load responsibility peak demand was 5,896 MWs on August 25, 2021. The following table presents system sales and variations in system sales for 2021, 2020 and 2019.


Year Ended December 31	2021	2021 vs. 2020	2020	2020 vs. 2019	2019
System sales (Millions of MWh)	27.7	2.6%	27.0	(4.9)%	28.4

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	2021		2020		2019
ELECTRIC ENERGY (Millions of MWh)
Generation (exclusive of station use)	16.3		17.5		17.0
Purchased	14.6		12.9		14.0
Total generated and purchased	30.9		30.4		31.0
OG&E use, free service and losses	(1.6)		(1.4)		(1.4)
Electric energy sold	29.3		29.0		29.6
ELECTRIC ENERGY SOLD (Millions of MWh)
Residential	9.6		9.5		9.7
Commercial	6.8		6.3		6.5
Industrial	4.2		4.2		4.5
Oilfield	4.2		4.2		4.6
Public authorities and street light	2.9		2.8		3.1

System sales	27.7		27.0		28.4
Integrated market	1.6		2.0		1.2
Total sales	29.3		29.0		29.6
ELECTRIC OPERATING REVENUES (In millions)
Residential	$	1,342.1	$	869.0	$	891.1
Commercial	766.9		479.4		503.1
Industrial	328.2		197.3		223.0
Oilfield	316.8		172.3		204.0
Public authorities and street light	289.5		176.9		195.8

System sales revenues	3,043.5		1,894.9		2,017.0
Provision for rate refund	—		3.8		(0.9)
Integrated market	468.9		49.6		38.4
Transmission	140.2		143.3		148.0
Other	1.1		30.7		29.1
Total operating revenues	$	3,653.7	$	2,122.3	$	2,231.6
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential	749,091		740,174		731,797
Commercial	103,337		100,200		98,565
Industrial	2,585		2,710		2,965
Oilfield	6,804		6,822		7,071
Public authorities and street light	17,630		17,483		17,356

Total customers	879,447		867,389		857,754
AVERAGE RESIDENTIAL CUSTOMER SALES (A)
Average annual revenue	$	1,374.76	$	1,180.82	$	1,222.95
Average annual use (kilowatt-hour)	12,827		12,848		13,344
Average price per kilowatt-hour (cents)	10.72		9.19		9.16

(A)Excludes impact from Winter Storm Uri in 2021 where opportunities exist for the recovery of increased costs to be spread over an extended period of time through securitization as discussed in Note 16 within "Item 8. Financial Statements and Supplementary Data."

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 2021, 89 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and three 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 16 within "Item 8. Financial Statements and Supplementary Data."

Regulatory Assets and Liabilities

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

OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets or liabilities, which could have significant financial effects. See Note 1 within "Item 8. Financial Statements and Supplementary Data" for further discussion of OG&E's regulatory assets and liabilities.

Rate Structures

Oklahoma

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

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

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

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

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

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

OG&E has Public Schools-Demand and Public Schools Non-Demand rate classes that provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E also provides service level, seasonal and time period fuel charge differentiation that allows customers to pay fuel costs that better reflect the underlying costs of providing electric service. Lastly, OG&E has a military base rider that demonstrates Oklahoma's continued commitment to 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 is not to exceed five years from the date of the APSC final order in the last general rate review, May 18, 2017, unless additional approval is obtained from the APSC. On October 1, 2021, OG&E filed a request to extend the Formula Rate Plan Rider for an additional five years and expects a decision from the APSC in April 2022.

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.

Fuel Supply and Generation

The following table presents the OG&E-generated energy produced and purchased and the weighted-average cost of fuel used, by type, for the last three years.


	Generation Mix (A)			Fuel Cost (B) (In cents/Kilowatt-Hour)
	2021	2020	2019	2021	2020	2019
Natural gas	48%	62%	59%	11.907	2.077	2.188
Coal	40%	25%	27%	1.935	1.821	2.029
Renewable	12%	13%	14%	—	—	—
Total	100%	100%	100%	6.833	1.863	1.970

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

(B)Total fuel and purchased power weighted-average cost was 6.892, 2.117 and 2.534 cents per kilowatt-hour in 2021, 2020 and 2019, respectively.

The increase in the weighted average cost of fuel in 2021 compared to 2020 was primarily due to higher fuel prices as a result of Winter Storm Uri. The increase in coal as a percentage of generation mix was primarily in response to an increase in natural gas prices during 2021. The decrease in the weighted average cost of fuel in 2020 compared to 2019 was primarily due to lower fuel prices. These 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 which have been deferred to separate regulatory assets for recovery in each jurisdiction. See Notes 1 and 16 within "Item 8. Financial Statements and Supplementary Data" for further discussion.

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.

Of OG&E's 7,207 total MWs of generation capability reflected in the table within "Item 2. Properties," 4,876 MWs, or 67.7 percent, are from natural gas generation, 1,534 MWs, or 21.3 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 27 MWs, or 0.4 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.

Coal

OG&E's coal-fired units are designed to burn primarily low sulfur western sub-bituminous coal. The combination of all 2021 coal purchased had a weighted average sulfur content of 0.2 percent. Based on the average sulfur content and EPA-certified data, OG&E's coal units have an approximate emission rate of 0.1 lbs. of SO2 per MMBtu.

For the first two quarters of 2022, OG&E has coal supply agreements for 100 percent of its coal requirements for the Sooner, Muskogee and River Valley facilities. OG&E plans to fill the remainder of its 2022 coal needs through additional term agreements, spot purchases and the use of existing inventory. OG&E has no coal agreements beyond June 2022 and will need to satisfy its coal needs through term agreements and spot purchases. In 2021, OG&E purchased 4.393 million tons of coal from its sub-bituminous suppliers and 0.0373 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

* Performance testing is currently being completed.

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 beginning in 2023. OG&E will continue to evaluate the need to add additional solar sites to its generation portfolio based on customer demand, cost and reliability.

Safety and Health Regulation

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

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

In September 2021, President Biden announced an executive order requiring federal contractors to require that their employees be fully vaccinated against COVID-19 (the "vaccine mandate"). At this time, the Registrants will not be required to incorporate the language of the vaccine mandate into OG&E's area-wide service contracts, and therefore, the Registrants are not deemed federal contractors for these purposes. Consequently, the Registrants do not currently have to comply with the vaccine mandate. In September 2021, President Biden also announced a proposed new rule requiring all employers with at least 100 employees to require that their employees be fully vaccinated against COVID-19 or tested weekly (the "testing mandate"). On January 25, 2022, OSHA announced it is currently focusing on implementing a permanent COVID-19 healthcare standard, similar to the testing mandate. The Registrants are monitoring this development and potential impact to their operations.

Natural Gas Midstream Operations - Energy Transfer

Energy Transfer owns and operates one of the largest and most diversified portfolios of energy assets in North America, with a strategic footprint in all of the major U.S. production basins. Energy Transfer is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, NGL and refined product transportation and terminalling assets; and NGL fractionation. In addition, Energy Transfer owns investments in other businesses, including Sunoco LP and USA Compression Partners, LP, both of which are publicly traded master limited partnerships.

•Energy Transfer's natural gas intrastate transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities, power generators and other third-party pipelines. Energy Transfer operates one of the largest intrastate pipeline systems in the U.S. providing energy logistics to major trading hubs and industrial consumption areas throughout the U.S. Energy Transfer's intrastate transportation and storage business focuses on the transportation of natural gas to major markets from prolific natural gas producing areas such as Permian, Barnett, Haynesville and Eagle Ford Shale.

•Energy Transfer's interstate natural gas transportation pipelines receive natural gas from supply sources including other transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users and other pipelines. Energy Transfer's interstate natural gas network spans the U.S. from Florida to

California and Texas to Michigan, offering a comprehensive array of pipeline and storage services. Energy Transfer's pipelines have the capability to transport natural gas from nearly all Lower 48 onshore and offshore supply basins to customers in the Southeast, Gulf Coast, Southwest, Midwest, Northeast and Canada.

•Energy Transfer owns and operates natural gas gathering and NGL pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities. Energy Transfer's midstream operations are currently concentrated in major producing basins and shales in South Texas, West Texas, New Mexico, North Texas, East Texas, West Virginia, Pennsylvania, Ohio, Oklahoma, Arkansas, Kansas and Louisiana. Many of Energy Transfer's midstream assets are integrated with their intrastate transportation and storage assets.

•Energy Transfer's NGL operations transport, store and execute acquisition and marketing activities utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Energy Transfer's refined products operations provide transportation and terminalling services through the use of refined products pipelines and refined products marketing terminals, which are located primarily in the northeast, midwest and southwest U.S.

•Energy Transfer's crude oil operations provide transportation (via pipeline and trucking), terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest, northwestern and northeastern U.S. Energy Transfer's crude oil acquisition and marketing activities utilize their pipeline and terminal assets, their proprietary fleet crude oil tractor trailers and truck unloading facilities, as well as third-party assets, to service crude oil markets principally in the midcontinent U.S.

Environmental Matters

General

The activities of the Registrants 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 2022 or 2023. For further discussion of environmental matters and capital expenditures related to environmental factors that may affect the Registrants, see "2021 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. At December 31, 2021, OGE Energy had 2,185 employees, of which 1,812 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 in their action plans in order to respond to the feedback and further enhance employee engagement.

Safety

Employee safety is paramount in the work we perform. One of our company core beliefs is to "Live Safely," which to us means that 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 of our employees on our incident and injury free workplace vision. We report and analyze all near misses and incidents to understand the causal factors and associated corrective actions necessary to reduce the likelihood of reoccurrence. We share what we have learned company-wide to provide real-time learning opportunities for all employees. We track our safety performance and benchmark ourselves to our peer utility group, the Southeast Electric Exchange. For 2021, our Southeast Electric Exchange OSHA incident rate of 0.28 was the best in the group and the best in company history. The incident rate is calculated by counting the number of injuries and illnesses per 100 employees' standard base labor hours divided by the number of actual hours employees worked. We consistently rank among the top of our 17-member peer group, ranking first in the Southeast Electric Exchange in two of the last four years. We continue to analyze trends and engage in discussions with our employees, creating a dialogue to enhance safety performance and work towards our incident and injury-free workplace. Our focus on safety has contributed to each of the last six years being the safest in our 120-year history. Further discussion of the steps we are taking to help ensure employee safety during the COVID-19 pandemic can be found in "Item 7. Management's Discussion and Analysis – Recent Developments – COVID-19."

Diversity and Inclusion

Within our overall recruitment efforts, we are focused on diversity with the over-arching goal of the company's workforce looking like the members of 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.

We strive to reinforce the belief that our employees 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. We are also focused on the inclusion of diverse individuals in leadership positions. Representation of females and other diverse members among our officers, management-level directors and senior managers has been trending upward for the past 5 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.

The company currently has employee-led Member Resource Groups ("MRGs") supporting African Americans, Asian American & Pacific Islanders, Latin/Hispanic heritage, Public Service, Veterans and Women. 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. All groups are voluntary and inclusive.

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 23, 2022:


Name	Age	Current Title and Business Experience
Sean Trauschke	54	2017 - Present:	Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp.

W. Bryan Buckler	49	2021 - Present:	Chief Financial Officer of OGE Energy Corp.
		2019 - 2020:	Vice President of Investor Relations - Duke Energy Corporation
		2017 - 2019:	Director of Financial Planning and Analysis - Duke Energy Corporation
Sarah R. Stafford	40	2018 - Present:	Controller and Chief Accounting Officer of OGE Energy Corp.
		2017 - 2018:	Accounting Research Officer of OGE Energy Corp.

Scott A. Briggs	50	2020 - Present:	Vice President - Human Resources of OG&E
		2019 - 2020:	Managing Director Human Resources of OG&E
		2017 - 2018:	Chief Operating Officer of The Oklahoma Publishing Co., d/b/a The Oklahoma Media Company
Robert J. Burch	59	2020 - Present:	Vice President - Utility Technical Services of OG&E
		2018 - 2020:	Managing Director Utility Technical Services of OG&E
		2017 - 2018:	Director Power Supply Services of OG&E
Andrea M. Dennis	45	2019 - Present:	Vice President - Transmission and Distribution Operations of OG&E
		2019:	Managing Director Transmission and Distribution Operations of OG&E
		2017 - 2019:	Director System Operations of OG&E



Patricia D. Horn	63	2017 - Present:	Vice President - Governance and Corporate Secretary of OGE Energy Corp.
Donnie O. Jones	55	2019 - Present:	Vice President - Utility Operations of OG&E
		2017 - 2019:	Vice President - Power Supply Operations of OG&E


Cristina F. McQuistion	57	2020 - Present:	Vice President - Corporate Responsibility and Stewardship of OGE Energy Corp.
		2017 - 2020:	Vice President - Chief Information Officer of OG&E

Kenneth A. Miller	55	2019 - Present:	Vice President - Regulatory and Legislative Affairs of OG&E
		2017 - 2018:	State Treasurer of Oklahoma
David A. Parker	45	2020 - Present:	Vice President - Technology, Data and Security of OG&E
		2019 - 2020:	Director Enterprise Security & Risk of OGE Energy Corp.
		2017 - 2019:	Director of Internal Audit of OGE Energy Corp.
Matthew J. Schuermann	42	2020 - Present:	Vice President - Power Supply Operations of OG&E
		2019 - 2020:	Managing Director Power Plant Operations of OG&E
		2017 - 2019:	Special Projects Director of OG&E
William H. Sultemeier	54	2017 - Present:	General Counsel and Chief Compliance Officer of OGE Energy Corp.


Charles B. Walworth	47	2017 - Present:	Treasurer of OGE Energy Corp.
Christine O. Woodworth	51	2021 - Present:	Vice President - Corporate Communications, Brand and Marketing of OG&E
		2017 - 2021:	Vice President of Public Relations - Sonic Drive-In

No family relationship exists between any of the Executive Officers of the Registrants. Messrs. Trauschke, Buckler, Sultemeier, Walworth and Mses. Horn, 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 19, 2022.

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. OGE Energy also is subject to risks associated with its investment in Energy Transfer's equity securities.

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 experienced in February 2021 due to Winter Storm Uri that resulted in winter record winter peak demand for electricity in OG&E's service territory and extreme natural gas and purchased power prices. The utility commissions in the states where OG&E operates regulate many aspects of its utility operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the utility operations is dependent on OG&E's ability to fully recover costs related to providing energy and utility services to its customers in a timely manner. Any failure to obtain utility commission approval to increase rates to fully recover costs, or a delay in the receipt of such approval, could have an adverse impact on OG&E's results of operations. In addition, OG&E's jurisdictions have fuel adjustment clauses that permit OG&E to recover fuel costs through rates without a general rate review, subject to a later determination that such fuel costs were prudently incurred. If the state regulatory commissions determine that the fuel costs were not prudently incurred, recovery could be disallowed. See Note 16 within "Item 8. Financial Statements and Supplementary Data" for further discussion of the significant fuel and purchased power costs incurred during Winter Storm Uri and the related regulatory filings with the OCC and the APC, including the securitization filing approved by the OCC in December 2021.

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 or the imposition of additional regulations 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 utility. Most of its revenue results from the sale of electricity to retail customers subject to bundled rates that are approved by the applicable state utility commission.

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

Costs of compliance with environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, 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. 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 could lead to increased compliance costs for OGE Energy and its affiliates. For example, the EPA has indicated that it is currently "evaluating additional opportunities" to reduce greenhouse gas emissions from existing power plants.

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. 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. We record the SPP Integrated Marketplace transactions as sales or purchases with results reported as Revenues from Contracts with Customers or Fuel, Purchased Power and Direct Transmission Expense in its financial statements. 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 could have a significant financial impact on us and consequently impact our revenue.

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

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

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

The NERC is responsible for the development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. OG&E's plan is to comply with all applicable standards and to expediently correct a violation should it occur. 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. We are dependent on coal and natural gas for much of our electric generating capacity. We rely on suppliers to deliver coal and natural gas in accordance with short- and long-term contracts. We have certain supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal and natural gas to us. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply coal and natural gas to us under certain circumstances, such as in the event of a natural disaster. Deliveries may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather, availability of equipment and labor shortages. Failure or delay by our suppliers of coal and natural gas deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.

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

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

•operator error or safety related stoppages;

•disruptions in the delivery of electricity; and

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

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

timing of the maintenance is not reasonable and prudent. If OG&E is unable to recover any of these increased costs in rates, it could have a material adverse effect on our financial performance.

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

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

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

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 a significant amount of our employees hired before December 1, 2009. We also have defined benefit postretirement plans that cover a significant amount of our employees hired prior to February 1, 2000. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our results of operations and funding requirements. We expect to make future contributions to maintain required funding levels as necessary. 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.

Finally, OGE Energy provided retirement benefits and retiree health care benefits to 63 employees previously seconded to Enable. As 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 $19.4 million. Settlement and curtailment charges associated with the employees previously seconded to Enable are not reimbursable to OGE Energy.

OGE Energy is a holding company with its primary assets being investments in its subsidiary, OG&E, and in its ownership of a portion of the equity securities of Energy Transfer.

OGE Energy is a holding company and thus its primary assets are its investments in its subsidiary, OG&E, and in the equity securities of Energy Transfer. Substantially all of OGE Energy's operations are conducted by its subsidiary and through its investment in Energy Transfer's equity securities. 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 Energy Transfer and the payment of funds by them to OGE Energy in the form of dividends or distributions. At December 31, 2021, OGE Energy and OG&E had outstanding indebtedness and other liabilities of $8.6 billion. OG&E and Energy Transfer are separate legal entities that have 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, their ability to pay dividends or distributions to OGE Energy depends on any statutory and contractual restrictions that may be applicable to such entity, which may include requirements to maintain minimum levels of working capital and other assets. Claims of creditors, including general creditors, of OG&E and Energy Transfer on their respective 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.

RISKS ASSOCIATED WITH OGE ENERGY'S INVESTMENT IN ENERGY TRANSFER'S EQUITY SECURITIES

OGE Energy does not control Energy Transfer and therefore is not able to cause or prevent actions by Energy Transfer.

As discussed in "Item 1. Business," OGE Energy's investment in Energy Transfer is accounted for as an investment in equity securities, primarily based on OGE Energy's approximately three percent ownership in Energy Transfer. Further, OGE Energy does not have influence over Energy Transfer, as OGE Energy does not own general partner units or have board representation. Accordingly, OGE Energy is unable to cause or prevent actions by Energy Transfer. Further, OGE Energy cannot control the actions of the other investors. OGE Energy's interests may not align with those of Energy Transfer or other investors, and this lack of control could adversely impact OGE Energy's investment in Energy Transfer's equity securities.

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

Changes in Energy Transfer's fair value could adversely affect OGE Energy's net income.

Energy Transfer is a publicly traded company. OGE Energy accounts for its investment in Energy Transfer as an investment in equity securities and records the investment at fair value through net income each quarter. If Energy Transfer's unit price were to lose value, regardless of cause, OGE Energy's net income would be adversely impacted.

OGE Energy's operating cash flow is derived partially from cash distributions it receives from Energy Transfer.

OGE Energy's operating cash flow is derived partially from cash distributions it receives from Energy Transfer. The amount of cash Energy Transfer can distribute on its units principally depends upon the amount of cash generated from its operations, which will fluctuate from quarter to quarter based on, among other things, Energy Transfer's earnings and the general health and stability of the natural gas midstream sector.

Energy Transfer's fair value and the amount of cash it has available for distribution can fluctuate from quarter to quarter.

Energy Transfer's fair value and the amount of cash it has available for distribution can fluctuate from quarter to quarter and will depend upon, among other things:

•the amount of natural gas, NGLs, crude oil and refined products transported through Energy Transfer's pipelines;

•the level of throughput in its processing and treating operations;

•the fees charged and the margins realized by Energy Transfer for its services;

•the price of natural gas, NGLs, crude oil and refined products;

•the relationship between natural gas, NGL and crude oil prices;

•the weather in its operating areas;

•the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;

•the level of its operating costs and maintenance and integrity capital expenditures;

•the tax treatment being dependent on Energy Transfer's continuing status as a partnership for federal income tax purposes, as well as Energy Transfer not being subject to a material amount of entity-level taxation;

•prevailing economic conditions;

•the level and results of its derivative activities;

•any product liability claims and litigation; and

•performance of pipeline integrity programs and related repairs that could result in significant costs and liabilities.

In addition, the actual amount of cash that Energy Transfer will have available for distribution will also depend on other factors, such as:

•the level of capital expenditures it makes;

•the level of costs related to litigation and regulatory compliance matters;

•the cost of acquisitions, if any;

•the levels of any margin calls that result from changes in commodity prices;

•debt service requirements;

•fluctuations in working capital needs;

•its ability to borrow under its revolving credit facilities;

•its ability to access capital markets;

•restrictions on distributions contained in its debt agreements; and

•the amount, if any, of cash reserves established by its board of directors and its general partners in their discretion for the proper conduct of its businesses.

Income from Energy Transfer's midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products that are beyond Energy Transfer's control.

The prices for natural gas, NGLs, crude oil and refined products reflect market demand that fluctuates with changes in global and U.S. economic conditions and other factors, including:

•the level of domestic natural gas, NGL, refined products and oil production;

•the level of natural gas, NGL, refined products and oil imports and exports, including liquefied natural gas;

•actions taken by natural gas and oil producing nations;

•instability or other events affecting natural gas and oil producing nations;

•the impact of weather, public health crises such as pandemics (including COVID-19), and other events of nature on the demand for natural gas, NGLs, refined products and oil;

•the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;

•the price, availability and marketing of competitive fuels;

•the demand for electricity;

•activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas and related products;

•the cost of capital needed to maintain or increase production levels and to construct and expand facilities;

•the impact of energy conservation and fuel efficiency efforts; and

•the extent of governmental regulations, taxation, fees and duties.

In the past, the prices of natural gas, NGLs, refined products and oil have been extremely volatile, and we expect this volatility to continue.

Any loss of business from Energy Transfer's existing customers or inability to attract new customers due to a decline in demand for natural gas, NGLs, refined products or oil could have a material adverse effect on its revenues and results of operations. In addition, significant price fluctuations for natural gas, NGL, refined products and oil commodities could materially affect Energy Transfer's profitability.

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 could negatively impact our business and our results of operations.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital. Economic conditions may also impact the valuation of certain long-lived assets 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.

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

We face risks related to health epidemics and other outbreaks.

The outbreak of COVID-19 continues to be a developing situation around the globe that has adversely impacted economic activity and conditions worldwide. In particular, efforts to control the spread of COVID-19 have led to shutdowns of various facilities as well as disrupted supply chains around the world. Efforts to control the spread of COVID-19 have also resulted in remote work arrangements, increased unemployment, customer slow payment or non-payment and decreased commercial and industrial load in the U.S. generally and in our service territory to a lesser extent. We expect these particular COVID-19 impacts will likely continue in the near future. We are continuing to monitor developments involving our workforce, customers and supply chains and cannot predict whether COVID-19 will have a material impact on our results of operations, financial condition and prospects. However, 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. Additionally, we could experience employee engagement and/or turnover issues if federal or state authorities impose COVID-19-related vaccine or testing mandates. We could also face operational challenges if the pandemic worsens and large percentages of key personnel groups become sick and are unable to work for an extended period of time. Further, the negative impacts on the economy could also adversely impact the market value of the assets that fund our pension plans, which could necessitate accelerated funding of the plans to meet minimum federal government requirements.

In addition, we have experienced and expect to experience raw material inflation, logistical challenges and certain component shortages. We cannot predict the ongoing impact that COVID-19 will have on our customers, suppliers, vendors and other business partners and each of their financial conditions; however, any material effect on these parties could adversely impact us. The continued progression of, and global response to, the COVID-19 outbreak has increased and may continue to increase the risk of delays in construction activities and equipment deliveries related to our capital investment plan, potentially resulting in an inability to deliver service in accordance with our plans and limiting the growth of the company. The impact of COVID-19 may also exacerbate the other risks discussed within this Form 10-K, any of which could have a material effect on us. As this situation continues and can change rapidly, additional impacts may arise that we are not aware of currently.

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, 19 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.

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

Certain provisions of our certificate of incorporation and bylaws, as well as the Oklahoma corporation statute, may have the effect of delaying, deferring or preventing a change in control of OGE Energy. Such provisions, including those regulating the nomination of directors, limiting who may call special stockholders' meetings and eliminating stockholder action by written consent, together with the possible issuance of preferred stock of OGE Energy without stockholder approval, may make it more difficult for other persons, without the approval of our Board of Directors, to make a tender offer or otherwise

acquire substantial amounts of our common stock or to launch other takeover attempts that a stockholder might consider to be in such stockholder's best interest.

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

The terms of the indentures governing our debt securities do not fully prohibit 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.

Loans to the Registrants under their credit facilities may be eurodollar loans or alternate base rate loans. LIBOR is the subject of national, international and other regulatory guidance and proposals for reform. For example, the U.K.'s Financial Conduct Authority, which regulates LIBOR, has announced that it intends to phase out LIBOR as a benchmark. The Federal Reserve Bank of New York publishes a SOFR, which the Alternative Reference Rates Committee recommended as an alternative reference rate to U.S. Dollar LIBOR. It is not possible to predict what effect the phase out of LIBOR, or a change to SOFR or other alternative rates, may have on financial markets for LIBOR-linked financial instruments.

The Registrants' current credit facilities provide a mechanism for determining an alternative rate of interest upon the occurrence of certain events related to the phase out of LIBOR. The phase out of LIBOR, or a change to SOFR or 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 phase out of LIBOR, or a 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. Our credit facilities each have a financial covenant requiring us 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.

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 16 generating stations with an aggregate capability of 7,207 MWs at December 31, 2021. 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.


					Fuel Capability	2021 Capacity Factor (A)		Unit Capability (MW)	Station Capability (MW)
			Year Installed
Station & Unit				Unit Design Type
Seminole	1		1971	Steam-Turbine	Gas	8.0	%	485
	2		1973	Steam-Turbine	Gas	10.2	%	500
	3		1975	Steam-Turbine	Gas	12.7	%	498	1,483
Muskogee	4		1977	Steam-Turbine	Gas	7.4	%	484
	5		1978	Steam-Turbine	Gas	6.2	%	488
	6		1984	Steam-Turbine	Coal	60.4	%	503	1,475
Sooner	1		1979	Steam-Turbine	Coal	29.0	%	516
	2		1980	Steam-Turbine	Coal	39.8	%	515	1,031
Horseshoe Lake	5A	(B)	1971	Combustion-Turbine	Gas/Jet Fuel	1.2	%	33
	5B	(B)	1971	Combustion-Turbine	Gas/Jet Fuel	1.2	%	31
	6		1958	Steam-Turbine	Gas	10.2	%	168
	7		1963	Steam-Turbine	Gas	5.9	%	211
	8		1969	Steam-Turbine	Gas	8.7	%	377
	9		2000	Combustion-Turbine	Gas	27.6	%	45
	10		2000	Combustion-Turbine	Gas	19.3	%	43	908
Redbud (C)	1		2003	Combined Cycle	Gas	38.5	%	154
	2		2003	Combined Cycle	Gas	36.2	%	154
	3		2003	Combined Cycle	Gas	36.7	%	153
	4		2003	Combined Cycle	Gas	41.9	%	153	614
Mustang	6		2018	Combustion-Turbine	Gas	31.8	%	57
	7		2018	Combustion-Turbine	Gas	28.4	%	57
	8		2017	Combustion-Turbine	Gas	32.6	%	58
	9		2018	Combustion-Turbine	Gas	33.1	%	58
	10		2018	Combustion-Turbine	Gas	33.6	%	57
	11		2018	Combustion-Turbine	Gas	32.8	%	57
	12		2018	Combustion-Turbine	Gas	32.6	%	57	401
McClain (D)	1		2001	Combined Cycle	Gas	48.0	%	378	378
Frontier	1		1989	Combined Cycle	Gas	36.4	%	120	120
River Valley	1		1991	Steam-Turbine	Coal/Gas	25.4	%	161
	2		1991	Steam-Turbine	Coal/Gas	47.6	%	160	321
Total Generating Capability (all stations, excluding renewable)									6,731

(A)2021 Capacity Factor = 2021 Net Actual Generation / (2021 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 planned 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					2021 Capacity Factor (A)		Unit Capability (MW)	Station Capability (MW)
	Year Installed		Number of Units	Fuel Capability
Station		Location
Crossroads	2011	Canton, OK	98	Wind	40.4	%	2.3	228
Centennial	2007	Laverne, OK	80	Wind	12.1	%	1.5	120
OU Spirit	2009	Woodward, OK	44	Wind	17.1	%	2.3	101
Mustang	2015	Oklahoma City, OK	90	Solar	18.2	%	< 0.1	2
Covington	2018	Covington, OK	4	Solar	24.0	%	2.5	10
Choctaw Nation	2020	Durant, OK	2	Solar	22.3	%	2.5	5
Chickasaw Nation	2020	Davis, OK	2	Solar	25.8	%	2.5	5
Branch	2021	Branch, AR	2	Solar	11.8	%	2.5	5
Total Generating Capability (renewable)								476

In the first quarter of 2022, OG&E finished constructing the Durant 2 solar site, which is located near Durant, Oklahoma, and performance testing is currently being completed. The Durant 2 solar site has a maximum capacity of 5 MWs and consists of 15,471 photovoltaic panels.

At December 31, 2021, OG&E's transmission system included: (i) 54 substations with a total capacity of 14.4 million kV-amps and 5,122 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.9 million kV-amps and 277 structure miles of lines in Arkansas. At December 31, 2021, OG&E's distribution system included: (i) 350 substations with a total capacity of 10.6 million kV-amps, 29,494 structure miles of overhead lines, 3,365 miles of underground conduit and 11,125 miles of underground conductors in Oklahoma and (ii) 29 substations with a total capacity of 1.0 million kV-amps, 2,795 structure miles of overhead lines, 349 miles of underground conduit and 662 miles of underground conductors in Arkansas.

During the three years ended December 31, 2021, both Registrants' gross property, plant and equipment (excluding construction work in progress) additions were $2.3 billion, and gross retirements were $363.8 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 16.3 percent of gross property, plant and equipment (excluding construction work in progress) for both Registrants at December 31, 2021.

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, 2021, there were 12,635 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.

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.

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 and natural gas, crude oil and NGLs across the U.S. OGE Energy conducts these activities through two business segments: (i) electric utility 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. OGE Energy generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance.

Natural Gas Midstream Operations. In February 2021, Enable entered into a definitive merger agreement with Energy Transfer, pursuant to which all outstanding common units of Enable were to be acquired by Energy Transfer in an all-equity transaction. The transaction closed on December 2, 2021, and under the terms of the merger agreement, OGE Energy received 95,389,721 common units of Energy Transfer for OGE Energy’s 110,982,805 common units of Enable. Upon the transaction closing, OGE Energy owned approximately three percent of Energy Transfer's outstanding limited partner units in lieu of the 25.5 percent interest in Enable that it previously owned. For periods prior to December 2, 2021, OGE Energy's natural gas midstream operations segment represented OGE Energy's investment in Enable, which OGE Energy accounted for as an equity method investment. Formed in 2013, Enable was primarily engaged in the business of gathering, processing, transporting and storing natural gas primarily in the south central U.S. Upon the closing of the Energy Transfer and Enable merger, OGE Energy's natural gas midstream operations segment represents OGE Energy's investment in Energy Transfer's equity securities and legacy Enable seconded employee pension and postretirement costs. The investment in Energy Transfer's equity securities is held through wholly-owned subsidiaries and ultimately OGE Holdings. At December 31, 2021, OGE energy owned 95.4 million, or approximately three percent, of Energy Transfer's limited partner units. OGE Energy does not have significant influence over Energy Transfer, as OGE Energy does not own general partner units in or have board representation at Energy Transfer. As such, OGE Energy accounts for its investment in Energy Transfer as an investment in equity securities under ASC 321, "Investments - Equity Securities" and records its investment at fair value through net income each reporting period. 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 intends to exit the midstream segment in a prudent manner.

Energy Transfer's business is impacted by commodity prices which have experienced significant volatility in recent years. Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by Energy Transfer's systems, and the volumes on Energy Transfer's systems can be negatively impacted if producers decrease drilling and production in those areas served. A decrease in volumes on Energy Transfer's systems due to a decrease in drilling or production by Energy Transfer's producer customers could decrease the cash flows from Energy Transfer's systems. In addition, Energy Transfer's processing arrangements expose them to commodity price fluctuations. A portion of OGE Energy's earnings and operating cash flows depend on the performance of, and distributions from, Energy Transfer. Energy Transfer is subject to a number of risks, including the reliance on the drilling and production decisions of others and the volatility of natural gas, NGLs and crude oil prices. The effects of COVID-19, including negative impacts on demand and commodity prices, could exacerbate these risks, as experienced in 2020. If any of those risks were to occur or reoccur, OGE Energy's business, financial condition, results of operations or cash flows could be materially adversely affected.

On January 25, 2022, Energy Transfer announced a 15 percent increase in its quarterly cash distribution, resulting in a distribution of $0.175 per unit on its outstanding common units that was paid on February 18, 2022.

Overview

Strategy

OGE Energy is focused on:

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

•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;

•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.

Recent Developments

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. Both the OCC and APSC have approved regulatory mechanisms for OG&E's recovery of the significant fuel and purchased power costs associated with Winter Storm Uri, as further discussed in Note 16 within "Item 8. Financial Statements and Supplementary Data." As of December 31, 2021, OG&E has recorded regulatory assets of $747.9 million and $88.9 million for the Oklahoma and Arkansas jurisdictional portions, respectively, of fuel and purchased power costs incurred during Winter Storm Uri.

In March 2021, OGE Energy entered into a $1.0 billion unsecured 364-day term loan agreement and borrowed the full $1.0 billion to help cover the significant fuel and purchased power costs incurred during Winter Storm Uri. In May 2021, OGE Energy and OG&E each issued $500.0 million in senior notes, and using these proceeds, OGE Energy repaid $900.0 million of the $1.0 billion term loan, as further described in Notes 11 and 12 within "Item 8. Financial Statements and Supplementary Data." In December 2021, OGE Energy repaid the remaining $100.0 million outstanding that was borrowed under the term loan agreement. The Oklahoma and Arkansas legislatures have both passed legislation that would help alleviate the immediate burden on customers and OGE Energy by securitizing the cost impacts from Winter Storm Uri. The securitization of these costs could spread out the recovery of the costs over a longer period of time at a lower finance carrying charge. On April 26, 2021, OG&E filed an application seeking OCC approval to securitize its costs related to Winter Storm Uri, and on October 8, 2021, OG&E filed a settlement agreement between OG&E, the Public Utility Division Staff of the OCC, the Oklahoma Industrial Energy Consumers, the OG&E Shareholders Association and Walmart Inc. The settling parties agreed the OCC should issue a financing order authorizing the securitization of $760.0 million, which includes estimated finance costs and is subject to change for carrying costs, any updates from the SPP settlement process and actual securitization issuance costs. The settlement agreement was approved by the OCC on December 16, 2021. Further discussion can be found in Note 16 within "Item 8. Financial Statements and Supplementary Data."

COVID-19 Pandemic

In March 2020, the World Health Organization declared the outbreak of COVID-19 as a pandemic, which continues to spread throughout the U.S. and world. Currently, COVID-19 vaccines are available to all Oklahoma and Arkansas residents, and the Registrants have provided on-site access to COVID-19 vaccines to their employees. One of the Registrants' top priorities is to protect their employees and their families, as well as their customers and communities. The Registrants have established a team to monitor cases and update the Registrants' response and are taking precautionary measures as directed by health authorities and local and federal governments. This team also determines whether any occupancy reductions or closures are necessary to help ensure the health and safety of the Registrants' employees and customers. The OCC and the APSC both issued accounting orders allowing the Registrants to defer for recovery the incremental costs incurred for pandemic-related safety measures and the incremental bad debt resulting from COVID-19. These orders are further discussed in the Registrants' 2020 Form 10-K.

In September 2021, President Biden announced an executive order requiring federal contractors to require that their employees be fully vaccinated against COVID-19 (the "vaccine mandate"). At this time, the Registrants will not be required to incorporate the language of the vaccine mandate into OG&E's area-wide service contracts, and therefore, the Registrants are not deemed federal contractors for these purposes. Consequently, the Registrants do not currently have to comply with the vaccine mandate. In September 2021, President Biden also announced a proposed new rule requiring all employers with at least 100 employees to require that their employees be fully vaccinated against COVID-19 or tested weekly (the "testing mandate"). On January 25, 2022, OSHA announced it is currently focusing on implementing a permanent COVID-19 healthcare standard, similar to the testing mandate. If the Registrants are subject to any such mandates or new standards, it could result in employee attrition, which could adversely affect the Registrants' business and results of operations. The ultimate impact of COVID-19 on operations and financial performance in future periods remains uncertain and will depend on future pandemic-related developments, including the duration of the pandemic and potential government actions to prevent and manage disease spread, which cannot be predicted.

The ongoing global COVID-19 pandemic and related governmental and business responses continue to have an impact on the Registrants' operations, supply chains and end-user customers. The Registrants have experienced raw material inflation, logistical challenges and certain component shortages. The timing and extent of the financial impact from the COVID-19 pandemic is 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 16 within "Item 8. Financial Statements and Supplementary Data."

Summary of OGE Energy 2021 Operating Results Compared to 2020

OGE Energy's net income was $737.3 million, or $3.68 per diluted share, in 2021 as compared to a net loss of $173.7 million, or $0.87 per diluted share, in 2020. The increase in net income of $911.0 million, or $4.55 per diluted share, in 2021 as compared to 2020 is further discussed below. As the merger between Enable and Energy Transfer closed on December 2, 2021, the majority of the operating results for OGE Holdings for the year ended December 31, 2021 was impacted by Enable.

•An increase in net income at OG&E of $20.6 million, or $0.10 per diluted share of OGE Energy's common stock, was primarily due to higher operating revenues driven by strong load growth, increased revenues from the recovery of capital investments and more favorable weather (excluding impacts of recoverable fuel, purchased power and direct transmission expense not impacting earnings), partially offset by losses from the Guaranteed Flat Bill program during Winter Storm Uri, higher depreciation and amortization expense due to additional assets being placed into service and higher income tax expense.

•Net income at OGE Holdings of $385.0 million, or $1.92 per diluted share of OGE Energy's common stock, during the year ended December 31, 2021 compared to net loss of $515.0 million, or $2.58 per diluted share of OGE Energy's common stock, during the year ended December 31, 2020 was primarily due to a $344.4 million gain ($264.8 million after tax) on the Enable merger transaction that closed on December 2, 2021 and an increase in equity earnings of Enable, which was driven by increased net income from Enable's business resulting primarily from higher average natural gas sales prices and higher average market prices for NGL products, as well as the 2020 impact of lower equity in earnings of Enable related to impairments, as adjusted for basis differences, partially offset by an increase in income tax expense and other expense.

•An increase in net loss of other operations (holding company) of $9.6 million, or $0.05 per diluted share of OGE Energy's common stock, was primarily due to higher other expense and lower income tax benefit in 2021.

A more detailed discussion regarding the financial performance for the year ended December 31, 2021 as compared to December 31, 2020 can be found under "Results of Operations" below. A discussion of the financial performance for the year ended December 31, 2020 compared to December 31, 2019 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' 2020 Form 10 -K.

2022 Outlook

Key assumptions for 2022 include:

OG&E

OG&E is projected to earn approximately $375 million to $395 million, or $1.87 to $1.97 per average diluted share, with a midpoint of $385 million, or $1.92 per average diluted share, in 2022 and is based on the following assumptions:

•normal weather patterns are experienced for the year;

•operating revenues growth driven by total retail load growth between 3.5 percent and 5.0 percent (weather normalized) and new rates related to OG&E's general rate review take effect in Oklahoma by July 1, 2022;

•operating expenses of approximately $1.029 billion to $1.035 billion, with operation and maintenance expenses comprising approximately 47 percent of the total;

•net interest expense of approximately $160 million to $162 million which assumes a $3 million allowance for borrowed funds used during construction reduction to interest expense and assumes a debt issuance at OG&E of $300 million in the second half of 2022;

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

•income before taxes of approximately $442 million to $466 million; 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.

Consolidated OGE Energy

OGE Energy is not issuing guidance for its natural gas midstream operations segment and therefore is not issuing 2022 consolidated earnings guidance; other consolidated assumptions include:

•approximately 200.5 million average diluted shares outstanding; and

•a loss of $2 million to $4 million, or one to two cents per average diluted share, at the holding company.

Results of Operations

The following discussion and analysis presents factors that affected the Registrants' results of operations for the years ended December 31, 2021 and 2020 and the Registrants' financial positions at December 31, 2021 and 2020. 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)	2021		2020
Net income (loss)	$	737.3	$	(173.7)
Basic average common shares outstanding	200.1		200.1
Diluted average common shares outstanding	200.3		200.1
Basic earnings (loss) per average common share	$	3.68	$	(0.87)
Diluted earnings (loss) per average common share	$	3.68	$	(0.87)
Dividends declared per common share	$	1.62500	$	1.58000

Results by Business Segment


	Year Ended December 31,
(In millions)	2021		2020
Net income (loss):
OG&E (Electric Utility)	$	360.0	$	339.4
OGE Holdings (Natural Gas Midstream Operations) (A)	385.0		(515.0)
Other operations (B)	(7.7)		1.9
OGE Energy net income (loss)	$	737.3	$	(173.7)

(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 5 within "Item 8. Financial Statements and Supplementary Data." In March 2020, OGE Energy recorded a $780.0 million impairment ($589.6 million after tax) on its investment in Enable, as further discussed in Notes 5 and 7 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 Utility)


Year Ended December 31 (Dollars in millions)	2021		2020
Operating revenues	$	3,653.7	$	2,122.3
Fuel, purchased power and direct transmission expense	2,127.6		644.6
Other operation and maintenance	464.7		464.4
Depreciation and amortization	416.0		391.3
Taxes other than income	99.3		97.2
Operating income	546.1		524.8
Allowance for equity funds used during construction	6.7		4.8
Other net periodic benefit expense	4.3		3.1
Other income	7.1		5.0
Other expense	1.8		2.6
Interest expense	152.0		154.8
Income tax expense	41.8		34.7
Net income	$	360.0	$	339.4
Operating revenues by classification:
Residential	$	1,342.1	$	869.0
Commercial	766.9		479.4
Industrial	328.2		197.3
Oilfield	316.8		172.3
Public authorities and street light	289.5		176.9

System sales revenues	3,043.5		1,894.9
Provision for rate refund	—		3.8
Integrated market	468.9		49.6
Transmission	140.2		143.3
Other	1.1		30.7
Total operating revenues	$	3,653.7	$	2,122.3




MWh sales by classification (In millions)
Residential	9.6		9.5
Commercial	6.8		6.3
Industrial	4.2		4.2
Oilfield	4.2		4.2
Public authorities and street light	2.9		2.8

System sales	27.7		27.0
Integrated market	1.6		2.0
Total sales	29.3		29.0
Number of customers	879,447		867,389
Weighted-average cost of energy per kilowatt-hour (In cents)
Natural gas (A)	11.907		2.077
Coal	1.935		1.821
Total fuel (A)	6.833		1.863
Total fuel and purchased power (A)	6.892		2.117
Degree days (B)
Heating - Actual	3,281		3,303
Heating - Normal	3,452		3,354
Cooling - Actual	1,896		1,804
Cooling - Normal	1,912		2,095

(A)Increased primarily due to both higher market prices related to increased natural gas prices and elevated pricing from Winter Storm Uri 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 2021.

OG&E's net income increased $20.6 million, or 6.1 percent, in 2021 as compared to 2020. The following section discusses the primary drivers for the increase in net income in 2021 as compared to 2020.

Operating revenues increased $1,531.4 million, or 72.2 percent, in 2021 as compared to 2020, primarily driven by the below factors.


(In millions)	$ Change
Fuel, purchased power and direct transmission expense (A)	$	1,483.0
Price variance (B)	43.7
Quantity impacts (primarily weather) (C)	22.1
Non-residential demand and related revenues	8.1
New customer growth	7.2
Industrial and oilfield sales	4.1
Other	3.2
Wholesale transmission revenue (D)	(7.2)
Guaranteed Flat Bill program (E)	(32.8)


Change in operating revenues (F)	$	1,531.4

(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 increase in fuel, purchased power and direct transmission expense during the period are further detailed in the table below.

(B)Increased primarily due to increased recovery through rider mechanisms, such as the Storm Cost Recovery Rider and the Oklahoma Demand Program Rider.

(C)Increased primarily due to a 5.1 percent increase in cooling degree days and a 1.0 percent decrease in heating degree days.

(D)Decreased primarily due to a reserve of $5.0 million plus estimated interest related to SPP transmission Z2 credits that are not passed through to customers through rider or formula rate mechanisms, as further discussed in Note 16 within "Item 8. Financial Statements and Supplementary Data."

(E)Decreased primarily due to the loss from the Guaranteed Flat Bill program 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 resulted in those customers not being allocated incremental fuel and purchased power costs incurred during Winter Storm Uri.

(F)Operating revenues were negatively impacted by COVID-19 in 2020. The above increases include positive impacts as customers have returned to more normal usage patterns during 2021.

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 increased $1,483.0 million, primarily driven by the below factors.


(In millions)	$ Change		% Change


Fuel expense (A)	$	786.4	*
Purchased power costs:
Purchases from SPP (B)	691.6		*

Wind	(1.5)		(2.6)	%
Other	2.2		28.0	%
Transmission expense	4.3		6.0	%

Change in fuel, purchased power and direct transmission expense	$	1,483.0

* Change is greater than 100 percent

(A)Increased primarily due to higher natural gas costs and higher fuel costs related to Winter Storm Uri.

(B)Increased primarily due to both higher market prices related to increased natural gas prices and elevated pricing from Winter Storm Uri.

Other operation and maintenance expense increased $0.3 million, or 0.1 percent, primarily driven by the below factors.


(In millions)	$ Change		% Change
Contract technical and construction services (A)	$	9.2	21.3	%
Vegetation management	5.5		16.4	%
Other	(1.6)		(0.7)	%
Capitalized labor	(5.1)		(4.2)	%
Payroll and benefits	(7.7)		(3.0)	%



Change in other operation and maintenance expense	$	0.3

(A)Increased primarily due to intentional cost reduction and the delay of certain projects due to COVID-19 in 2020.

Depreciation and amortization expense increased $24.7 million, or 6.3 percent, primarily due to additional assets being placed into service and increased amortization of the regulatory asset related to storms.

Income tax expense increased $7.1 million, or 20.5 percent, reflecting additional income taxes primarily related to higher pretax income.

OGE Holdings (Natural Gas Midstream Operations)

On December 2, 2021, Energy Transfer completed its previously announced acquisition of Enable. Prior to the Enable and Energy Transfer merger closing, OGE Energy's natural gas midstream operations segment included its equity method investment in Enable. Subsequent to December 2, 2021, OGE Energy's natural gas midstream operations segment includes its investment in Energy Transfer's equity securities and legacy Enable seconded employee pension and postretirement costs.


			Year Ended December 31,
(In millions)	2021	2020
Operating revenues			$	—	$	—
Fuel, purchased power and direct transmission expense			—		—
Other operation and maintenance			1.6		1.7

Taxes other than income			0.2		0.4
Operating loss			(1.8)		(2.1)
Equity in earnings (losses) of unconsolidated affiliates (A)			169.8		(668.0)
Gain on Enable/Energy Transfer transaction, net			344.4		—
Other expense (B)			(26.4)		(2.9)

Income (loss) before taxes			486.0		(673.0)
Income tax expense (benefit)			101.0		(158.0)

Net income (loss) attributable to OGE Holdings			$	385.0	$	(515.0)

(A)In March 2020, OGE Energy recorded a $780.0 million impairment on its investment in Enable, as further discussed in Notes 5 and 7 within "Item 8. Financial Statements and Supplementary Data."

(B)Includes an $8.6 million unrealized loss ($6.6 million after tax) that OGE Energy recognized on its investment in Energy Transfer's equity securities for the period of December 2, 2021 through December 31, 2021.

OGE Holdings' net income of $385.0 million compared to net loss of $515.0 million for the period of January 1, 2021 through December 2, 2021 and the year ended December 31, 2020, respectively, was primarily due to the gain recognized for the Enable merger transaction in 2021 and the 2020 impact of the impairment of OGE Energy's investment in Enable, as discussed in Note 5 within "Item 8. Financial Statements and Supplementary Data." Additional drivers of the increase in net income in 2021 compared to 2020 are presented below.

OGE Holdings' income tax expense increased $259.0 million primarily due to higher pre-tax income, partially offset by state deferred tax adjustments related to OGE Energy's midstream investments including a reduction in state deferred tax liabilities resulting from the Energy Transfer merger.

Enable

In light of the Energy Transfer and Enable merger closing on December 2, 2021, the below discussion presents income statement information for the period of January 1, 2021 through December 2, 2021 as compared to the year ended December 31, 2020. The latest available information regarding discussion of the primary drivers for Enable's 2021 operating results is for the period of January 1, 2021 through September 30, 2021, which can be found in Enable's Form 10-Q for the quarterly period ended September 30, 2021.

See Note 5 within "Item 8. Financial Statements and Supplementary Data" for the reconciliation of Enable's net income to OGE Energy's equity in earnings (losses) of unconsolidated affiliates. The following table presents summarized income statement information of Enable for the period of January 1, 2021 through December 2, 2021 compared to the year ended December 31, 2020.


	Period of January 1, 2021 through December 2, 2021		Year Ended
(In millions)			December 31, 2020

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 summarized information regarding Enable's income statement changes for the period of January 1, 2021 through December 2, 2021 compared to the year ended December 31, 2020, and the corresponding impact those changes had on OGE Energy's equity in earnings of Enable. See Note 5 within "Item 8. Financial Statements and Supplementary Data" for further discussion of OGE Energy's former equity method investment in Enable. The increase in Enable's net income was primarily driven by the below factors.



(In millions)	Income Statement Change at Enable		Impact to OGE Energy's Equity in Earnings
Total revenues	$	1,003	$	255.8
Cost of natural gas and NGLs (excluding depreciation and amortization shown separately)	$	994	$	(253.5)
Operation and maintenance, General and administrative (A)	$	(88)	$	18.3
Depreciation and amortization	$	(38)	$	9.7
Impairments of property, plant and equipment and goodwill (B)	$	(28)	$	4.4
Interest expense	$	(25)	$	6.4

Equity in earnings (losses) of equity method affiliate, net (C)	$	217	$	9.5

(A)Included in Enable's operation and maintenance and general and administrative expenses for the year ended December 31, 2020 is a $20.0 million loss on retirement of an Ark-La-Tex gathering system. OGE Energy recorded a $1.0 million pre-tax charge for its share of Enable's loss on retirement, as adjusted for basis differences.

(B)Included in the $28.0 million of impairments recorded by Enable for the year ended December 31, 2020 is a $12.0 million goodwill impairment and a $16.0 million impairment for certain long-lived assets. OGE Energy recorded a $4.4 million pre-tax charge for its share of Enable's goodwill and long-lived asset impairments, as adjusted for basis differences.

(C)Included in Enable's equity in earnings (losses) of equity method affiliate, net for the year ended December 31, 2020 is a $225.0 million impairment on Enable's SESH equity method investment. OGE Energy recorded an $11.5 million pre-tax charge for its share of Enable's equity method investment impairment, as adjusted for basis differences.

Liquidity and Capital Resources

Cash Flows

OGE Energy



Year Ended December 31 (In millions)	2021		2020		$ Change		% Change
Net cash (used in) provided from operating activities (A)	$	(313.3)	$	712.8	$	(1,026.1)	*
Net cash used in investing activities (B)	$	(749.1)	$	(654.9)	$	(94.2)	14.4	%
Net cash provided from (used in) financing activities (C)	$	1,061.3	$	(56.8)	$	1,118.1	*

*Change is greater than 100 percent

(A)Changed primarily due to an increase in vendor payments, including payments for fuel and purchased power costs related to Winter Storm Uri.

(B)Changed primarily due to increased spending on grid modernization projects at OG&E.

(C)Increased primarily due to increases in long-term and short-term debt to provide additional liquidity for the increased fuel and purchased power costs incurred by OG&E related to Winter Storm Uri.

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, 2021 compared to December 31, 2020.

Income Taxes Receivable decreased $5.5 million, or 67.9 percent, primarily due to current year tax expense accruals in excess of the receivables accrued as of December 31, 2020.

Fuel Inventories increased $4.1 million, or 11.2 percent, primarily due to higher coal and gas purchases.

Fuel Clause Recoveries moved from an over recovery position of $28.6 million as of December 31, 2020 to an under recovery balance of $151.9 million as of December 31, 2021, primarily due to lower recoveries from OG&E retail customers as compared to the actual cost of fuel and purchased power. In October 2021, OG&E implemented a revised fuel recovery tariff to begin recovery of the 2021 fuel under recovery balance as well as to incorporate an adjustment for higher forecasted 2022 fuel costs. The increase in the tariff was approximately 7.5 percent for an average residential customer.

Other Current Assets increased $32.1 million, or 77.9 percent, primarily due to an increase in SPP deposits, under-recovered riders and prepayments, partially offset by the SPP transmission formula rate true-up.

Short-term Debt increased $391.9 million, primarily due to increased fuel and purchased power costs and working capital 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 $22.5 million, or 8.9 percent, primarily due to the timing of vendor payments.

Accrued Compensation increased $6.6 million, or 21.2 percent, primarily due to higher accruals for incentive compensation based on company performance in 2021.

2021 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 $778.6 million, and contractual obligations, net of recoveries through fuel adjustment clauses, were $1.0 million, resulting in total net capital requirements and contractual obligations of $779.6 million in 2021. This compares to net capital requirements of $650.6 million and net contractual obligations of $0.9 million totaling $651.5 million in 2020.

In 2021, OGE Energy's primary sources of capital were cash generated from operations, proceeds from the issuance of long- and short-term debt and distributions from Enable. Changes in working capital reflect the seasonal nature of 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.

The Dodd-Frank Act

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

Future 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 and over recoveries and other general corporate purposes. 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 2022 through 2026. These capital investments are customer-focused and targeted to maintain and improve the safety 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)	2022		2023		2024		2025		2026		Total
Transmission	$	175	$	180	$	190	$	225	$	225	$	995
Oklahoma distribution & grid advancement	520		540		545		515		515		2,635
Arkansas distribution	25		20		20		20		20		105
Generation	150		130		110		110		110		610


Other	80		80		85		80		80		405
Total	$	950	$	950	$	950	$	950	$	950	$	4,750

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. OG&E is evaluating infrastructure investments incremental to the amounts above related to new generation capacity needs as outlined in its October 2021 IRP, as well as additional grid investments to address customer growth and grid resiliency. The continued progression of, and global response to, the COVID-19 outbreak has increased and may continue to increase the risk of delays in construction activities and equipment deliveries related to OGE Energy's capital projects, including potential delays in obtaining permits from government agencies, resulting in potential deferral of capital expenditures.

Contractual Obligations

The following table presents OGE Energy's total contractual obligations for the next five years, which include long-term debt, operating leases and purchase obligations and commitments, at December 31, 2021. For further detail of OGE Energy's long-term debt, operating leases and purchase obligations and commitments, including information for maturities beyond the next five years, see the statements of capitalization, Note 4 and Note 15, respectively, within "Item 8. Financial Statements and Supplementary Data."


(In millions)	2022		2023		2024		2025		2026		Total












Total contractual obligations	$	161.7	$	1,114.1	$	105.9	$	188.3	$	94.7	$	1,664.7

Amounts recoverable through fuel adjustment clause (A)	(155.6)		(108.6)		(88.0)		(81.5)		(82.0)		(515.7)
Total contractual obligations, net	$	6.1	$	1,005.5	$	17.9	$	106.8	$	12.7	$	1,149.0

(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 15, 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, 2021, 17.7 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 13 within "Item 8. Financial Statements and Supplementary Data." During 2021, actual returns on the Pension Plan were $48.4 million, compared to expected return on plan assets of $34.1 million. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, increased. Funding levels are dependent on returns on plan assets and future discount rates. OGE Energy made a contribution to its Pension Plan of $40.0 million and $20.0 million in 2021 and 2020, respectively. OGE Energy does not expect to make any contributions to the Pension Plan in 2022. 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, 2021 and 2020. 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)	2021		2020		2021		2020		2021		2020
Benefit obligations	$	502.9	$	654.6	$	5.9	$	7.8	$	137.3	$	144.5
Fair value of plan assets	486.0		570.3		—		—		44.3		47.6
Funded status at end of year	$	(16.9)	$	(84.3)	$	(5.9)	$	(7.8)	$	(93.0)	$	(96.9)

As a result of the merger between Enable and Energy Transfer, OGE Energy's seconding agreement with Enable was terminated. OGE Energy retains the obligations to the accrued benefits of these employees as of the termination of the contract. For further discussion, see Note 6 within "Item 8. Financial Statements and Supplementary Data."

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 2021, the Board of Directors reviewed a recommendation from management of an increase in the quarterly dividend to $0.41 per share from $0.4025 per share and subsequently approved the recommendation to become effective with the dividend payment in October 2021.

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. In addition, distributions from Energy Transfer will be utilized to meet anticipated cash needs until OGE Energy exits its investment in Energy Transfer's equity securities. 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 December 2021, the Registrants each entered into a new $550.0 million credit facility for working capital and general corporate purposes. For further discussion, see "Short-Term Debt and Credit Facilities" below and Note 12 within "Item 8. Financial Statements and Supplementary Data."

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.

On December 17, 2021, OGE Energy and OG&E entered into new, 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. The following table presents information about OGE Energy's revolving credit agreements as of December 31, 2021.


(Dollars in millions)	December 31, 2021
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	$	612.7
Balance of cash and cash equivalents	$	—

The following table presents information about OGE Energy's total short-term debt activity for the year ended December 31, 2021.


(Dollars in millions)	Year Ended December 31, 2021
Average balance of short-term debt	$	568.6
Weighted-average interest rate of average balance of short-term debt	0.51		%
Maximum month-end balance of short-term debt	$	1,443.4

In March 2021, OGE Energy entered into a $1.0 billion unsecured 364-day term loan agreement to provide additional liquidity to help cover the increased fuel and purchased power costs incurred by OG&E during Winter Storm Uri. In May 2021, $900.0 million of the $1.0 billion term loan was repaid using the proceeds from the senior notes issued by both OGE Energy and OG&E, as further described below. In December 2021, OGE Energy repaid the remaining $100.0 million outstanding that was borrowed under the term loan agreement. See Note 12 within "Item 8. Financial Statements and Supplementary Data" for further discussion of the Registrants' short-term debt activity.

OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2021 and ending December 31, 2022.

Issuance of Long-Term Debt

In May 2021, OGE Energy issued $500.0 million of 0.703 percent senior notes, and OG&E issued $500.0 million of 0.553 percent senior notes. Each series is due May 26, 2023 but may be redeemed by OGE Energy or OG&E after November 26, 2021 at a price equal to 100 percent of the principal amount of the senior notes being redeemed, plus any accrued and unpaid interest. The proceeds from these issuances were used to repay $900.0 million of the $1.0 billion term loan OGE Energy entered into in March 2021 to help cover the fuel and purchased power costs incurred by OG&E during Winter Storm Uri.

In the second half of 2022, OG&E expects to issue $300.0 million in long-term debt to support its current year capital investment plan.

Securitization of Oklahoma Winter Storm Uri Extreme Purchase Costs

In April 2021, OG&E filed an application with the OCC seeking its approval to securitize OG&E's costs related to Winter Storm Uri. In October 2021, OG&E filed a settlement agreement between OG&E, the Public Utility Division Staff of the OCC, the Oklahoma Industrial Energy Consumers, the OG&E Shareholders Association and Walmart Inc. The settling parties agreed the OCC should issue a financing order authorizing the securitization of $760.0 million, which includes estimated finance costs and is subject to change for carrying costs, any updates from the SPP settlement process and actual securitization issuance costs. On December 16, 2021, the settlement agreement was approved by the OCC. For further discussion, see Note 16 within "Item 8. Financial Statements and Supplementary Data."

Security Ratings

Moody's Investors Service

S&P's Global Ratings

Fitch Ratings

Rating

Outlook

Rating

Outlook

Rating

Outlook

OG&E Senior Notes

Stable

A-

Negative

Stable

OG&E Commercial Paper

Stable

Negative

Stable

OGE Energy Senior Notes

Baa1

Stable

BBB+

Negative

BBB+

Stable

OGE Energy Commercial Paper

Stable

Negative

Stable

On March 3, 2021, S&P's Global Ratings revised their ratings outlook on both OGE Energy and OG&E from stable to negative. S&P's Global Ratings indicated that the revised outlooks reflect their expectation for weaker financial measures directly associated with the significant increase in fuel and purchased power costs as a result of Winter Storm Uri, the uncertainty regarding timely recovery of those costs and the associated refinancing risk related to the 364-day $1.0 billion term loan. For OGE Energy, S&P's Global Ratings indicated the revised outlook also reflected their expectation of execution risk associated with the closing of Energy Transfer's acquisition of Enable.

On February 9, 2022, Moody's Investors Service revised their ratings outlook on both OGE Energy and OG&E to stable from negative. Moody's Investors Service indicated that the revised outlooks reflect their expectation that OG&E will recover about 99 percent of the costs incurred during Winter Storm Uri in Oklahoma through the issuance of securitization bonds by the ODFA, as authorized by the finance order approved on December 16, 2021 by the OCC.

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 2022 from its Automatic Dividend Reinvestment and Stock Purchase Plan. See Note 10 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 years ended December 31, 2021, 2020 and 2019, Enable made distributions of $73.4 million, $91.7 million and $144.0 million, respectively, to OGE Energy. On January 25, 2022, Energy Transfer announced a 15 percent increase in its quarterly cash distribution, resulting in a distribution of $0.175 per unit on its outstanding common units that was paid on February 18, 2022.

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 financial statements. 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 for the Registrants include the determination of Pension 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 Benefit Plans

OGE Energy has a Pension Plan that covers a significant amount of its 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 a significant amount of its 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 13 within "Item 8. Financial Statements and Supplementary Data." The assumed return on plan assets is based on management's expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. Funding levels are dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the Pension Plan.

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


	Change	Impact on Funded Status
Actual plan asset returns	+/- 1 percent	+/- $4.9 million
Discount rate	+/- 0.25 percent	+/- $9.7 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.

In May 2021, Oklahoma enacted a reduction of the corporate income tax rate to four percent from the previous six percent. This rate reduction took effect on January 1, 2022. A revaluation of the Registrants' state deferred tax liabilities was completed in May 2021 to reflect this lower tax rate. Additionally, in connection with the Enable and Energy Transfer merger, OGE Energy's state deferred tax liabilities were revalued. See Note 9 within "Item 8. Financial Statements and Supplementary Data" for further discussion.

Commitments and Contingencies

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, the average inflation rate, market risk premium, the credit-adjusted risk free interest rate and the timing of incurring costs related to the retirement of the asset.

Regulatory Assets and Liabilities

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 Operating Revenues in the statements of income based on estimates of usage and prices during the period. At December 31, 2021, 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 $0.6 million. At December 31, 2021 and 2020, Accrued Unbilled Revenues were $65.0 million and $67.7 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Allowance for Uncollectible Accounts Receivable

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is 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, such as in response to COVID-19 impacts. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. At December 31, 2021, 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. 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 $2.4 million and $2.6 million at December 31, 2021 and 2020, respectively.

Accounting Pronouncements

As discussed in Note 2 within "Item 8. Financial Statements and Supplementary Data," the Registrants believe that 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.

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 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 15 and 16 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

The activities of OG&E are subject to numerous stringent and complex federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways, including the handling or disposal of waste material, 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.

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.

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 was to identify any cost-effective control measures in a Regional Haze State Implementation Plan to be submitted to the EPA for approval by July 31, 2021. 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 continues to monitor these processes and their possible impact on its operations. Future rules could adopt additional reductions in the emissions budget for Oklahoma or the areas where OG&E's facilities are located. In particular, OG&E monitors possible changes in legal standards for emissions of greenhouse gases, including CO2, sulfur hexafluoride and methane, including the 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 fully by 2035. 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 70 percent and emissions of SO2 have been reduced by approximately 85 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 beginning in 2023. 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 June 1, 2021, the USFWS published a proposed 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, 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. The final rule for the listing decision is expected to occur in June 2022.

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 to 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 is expected to occur in November 2022.

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.

Over 95 percent of the ash from OG&E's Muskogee and Sooner facilities was recovered and sold to the concrete and cement industries in the last three years, and in 2021, River Valley became OG&E's third power plant to enter an agreement to have its fly ash reused. Using ash in this way also helps cement manufacturers minimize their impact on the environment by avoiding the need to extract and process other natural resources. 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 14 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 2021, OG&E obtained refunds of $3.3 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 permits from the State of Oklahoma.

Since the purchase of the Redbud facility in 2008, OG&E's average use of treated municipal effluent for all of the needed cooling water at Redbud and McClain is approximately 2.5 billion gallons per year. This use of treated municipal effluent offsets the need for fresh water as cooling water, making fresh water available for other beneficial uses like drinking water, irrigation and recreation.

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generates wastes that are

considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E.

For further discussion regarding contingencies relating to environmental laws and regulations, see Note 15 within "Item 8. Financial Statements and Supplementary Data."

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

Market risks are, in most cases, risks that are actively traded in a marketplace and have been well studied in regards to quantification. Market risks include, but are not limited to, changes in interest rates and commodity prices. The Registrants' exposure to changes in interest rates relates primarily to short-term variable-rate debt and commercial paper. The Registrants are exposed to commodity prices in their operations to the extent any fuel price changes are not recovered in customer rates and, for OGE Energy, through its investment in Energy Transfer's equity securities.

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 2021, 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)	2022			2023			2024			2025			2026			Thereafter			Total			12/31/21 Fair Value
OGE Energy (holding company) fixed-rate debt (A):
Principal amount	$	—		$	500.0		$	—		$	—		$	—		$	—		$	500.0		$	497.8
Weighted-average interest rate	—		%	0.703		%	—		%	—		%	—		%	—		%	0.703		%
OG&E fixed-rate debt (A):
Principal amount	$	—		$	500.0		$	—		$	—		$	—		$	3,394.3		$	3,894.3		$	4,470.2
Weighted-average interest rate	—		%	0.553		%	—		%	—		%	—		%	4.48		%	3.98		%
OG&E variable-rate debt (B):
Principal amount	$	—		$	—		$	—		$	79.4		$	—		$	56.0		$	135.4		$	135.4
Weighted-average interest rate	—		%	—		%	—		%	0.17		%	—		%	0.17		%	0.17		%

(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)	2021		2020		2019
OPERATING REVENUES
Revenues from contracts with customers	$	3,588.7	$	2,069.8	$	2,175.5
Other revenues	65.0		52.5		56.1
Operating revenues	3,653.7		2,122.3		2,231.6



FUEL, PURCHASED POWER AND DIRECT TRANSMISSION EXPENSE	2,127.6		644.6		786.9



OPERATING EXPENSES
Other operation and maintenance	463.1		462.8		491.8
Depreciation and amortization	416.0		391.3		355.0


Taxes other than income	102.8		101.4		93.6
Operating expenses	981.9		955.5		940.4
OPERATING INCOME	544.2		522.2		504.3
OTHER INCOME (EXPENSE)
Equity in earnings (losses) of unconsolidated affiliates	169.8		(668.0)		113.9
Allowance for equity funds used during construction	6.7		4.8		4.5
Other net periodic benefit expense	(6.1)		(3.9)		(9.8)
Gain (loss) on equity securities (Note 1)	(8.6)		—		—
Other income	26.3		37.5		21.9
Gain on Enable/Energy Transfer transaction, net (Note 5)	344.4		—		—
Other expense	(39.9)		(35.2)		(23.5)
Net other income (expense)	492.6		(664.8)		107.0
INTEREST EXPENSE
Interest on long-term debt	154.8		152.8		138.3
Allowance for borrowed funds used during construction	(3.5)		(1.9)		(2.8)
Interest on short-term debt and other interest charges	7.0		7.6		12.4
Interest expense	158.3		158.5		147.9
INCOME (LOSS) BEFORE TAXES	878.5		(301.1)		463.4
INCOME TAX EXPENSE (BENEFIT)	141.2		(127.4)		29.8
NET INCOME (LOSS)	$	737.3	$	(173.7)	$	433.6


BASIC AVERAGE COMMON SHARES OUTSTANDING	200.1		200.1		200.1
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.3		200.1		200.7
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE	$	3.68	$	(0.87)	$	2.17
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE	$	3.68	$	(0.87)	$	2.16

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)	2021		2020		2019
Net income (loss)	$	737.3	$	(173.7)	$	433.6
Other comprehensive income (loss), net of tax:
Pension Plan and Restoration of Retirement Income Plan:
Amortization of prior service cost, net of tax of $0.0, $0.0 and $0.0, respectively	0.1		—		—
Amortization of deferred net loss, net of tax of $0.9, $1.2 and $1.1, respectively	1.6		3.9		3.4

Net gain (loss) arising during the period, net of tax of $0.0, ($1.7) and ($2.5), respectively	1.4		(5.1)		(8.1)
Prior service cost arising during the period, net of tax of ($0.3), $0.0 and ($0.1), respectively	(1.1)		—		(0.2)
Settlement cost, net of tax of $2.7, $0.7 and $2.7, respectively	6.0		2.2		8.6
Postretirement benefit plans:
Amortization of prior service credit, net of tax of ($0.4), ($0.6) and ($0.6), respectively	(1.4)		(1.7)		(1.7)
Amortization of deferred net (gain) loss, net of tax of $0.0, $0.0 and $0.0, respectively	0.1		(0.1)		(0.2)

Net loss arising during the period, net of tax of ($0.2), ($0.8) and $(0.1), respectively	(0.7)		(2.4)		(0.2)

Curtailment cost, net of tax of $0.0, $(0.1) and $0.0, respectively	—		(0.3)		—
Other comprehensive gain (loss) from unconsolidated affiliates, net of tax $0.3, ($0.2) and ($0.2), respectively	1.3		(0.7)		(0.6)


Other comprehensive income (loss), net of tax	7.3		(4.2)		1.0
Comprehensive income (loss)	$	744.6	$	(177.9)	$	434.6

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)	2021		2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	737.3	$	(173.7)	$	433.6
Adjustments to reconcile net income (loss) to net cash (used in) provided from operating activities:
Gain on Enable/Energy Transfer transaction (Note 5)	(353.0)		—		—
Depreciation and amortization	416.0		391.3		355.0

Deferred income taxes and other tax credits, net	125.9		(134.5)		27.6
Equity in (earnings) losses of unconsolidated affiliates	(169.8)		668.0		(113.9)
Distributions from unconsolidated affiliates	73.4		91.7		125.5
Unrealized loss on investment in equity securities	8.6		—		—
Allowance for equity funds used during construction	(6.7)		(4.8)		(4.5)


Stock-based compensation expense	9.8		9.8		13.9

Regulatory assets	(874.9)		(112.0)		(47.1)
Regulatory liabilities	(71.2)		(64.0)		(45.6)
Other assets	(9.8)		(9.2)		(3.8)
Other liabilities	(8.1)		(26.3)		19.2
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	(1.9)		3.1		18.8


Income taxes receivable	5.5		2.8		(1.0)
Fuel, materials and supplies inventories	(3.4)		(8.9)		4.2

Fuel recoveries	(180.5)		63.3		(33.0)
Other current assets	(22.7)		(16.8)		5.1
Accounts payable	7.5		59.8		(34.5)



Other current liabilities	4.7		(26.8)		(38.0)
Net cash (used in) provided from operating activities	(313.3)		712.8		681.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(778.5)		(650.5)		(635.5)
Return of capital - unconsolidated affiliates	—		—		18.5
Cash received in Enable/Energy Transfer transaction (Note 5)	35.0		—		—
Other	(5.6)		(4.4)		(7.7)




Net cash used in investing activities	(749.1)		(654.9)		(624.7)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	997.8		297.1		296.5
Increase (decrease) in short-term debt	391.9		(17.0)		112.0
Payment of long-term debt	(0.1)		(0.1)		(250.1)
Dividends paid on common stock	(324.9)		(314.9)		(299.2)
Cash paid for employee equity-based compensation and expense of common stock	(3.4)		(7.1)		(10.3)
Purchase of treasury stock	—		(14.7)		—
Other	—		(0.1)		—






Net cash provided from (used in) financing activities	1,061.3		(56.8)		(151.1)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(1.1)		1.1		(94.3)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	1.1		—		94.3
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	—	$	1.1	$	—
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of interest capitalized of $3.5, $1.9 and $2.8, respectively)	$	156.4	$	153.4	$	152.2
Income taxes (net of income tax refunds)	$	8.7	$	3.9	$	5.5
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement	$	2.4	$	6.8	$	28.9
Investment in Energy Transfer's equity securities (Note 5)	$	793.7	$	—	$	—

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

OGE ENERGY CORP.

CONSOLIDATED BALANCE SHEETS


December 31 (In millions)	2021		2020
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	1.1
Accounts receivable, less reserve of $2.4 and $2.6, respectively	162.3		157.8

Accrued unbilled revenues	65.0		67.6
Income taxes receivable	2.6		8.1
Fuel inventories	40.6		36.5
Materials and supplies, at average cost	117.9		116.2
Fuel clause under recoveries	151.9		—

Other	73.3		41.2
Total current assets	613.6		428.5
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	—		374.3
Equity securities investment in Energy Transfer	785.1		—
Other	120.0		109.8
Total other property and investments	905.1		484.1
PROPERTY, PLANT AND EQUIPMENT
In service	13,899.8		13,296.7
Construction work in progress	252.0		145.5
Total property, plant and equipment	14,151.8		13,442.2
Less: accumulated depreciation	4,318.9		4,067.6
Net property, plant and equipment	9,832.9		9,374.6
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	1,230.8		415.6


Other	24.0		16.0
Total deferred charges and other assets	1,254.8		431.6
TOTAL ASSETS	$	12,606.4	$	10,718.8

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

OGE ENERGY CORP.

CONSOLIDATED BALANCE SHEETS (Continued)


December 31 (In millions)	2021		2020
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	486.9	$	95.0
Accounts payable	274.0		251.5
Dividends payable	82.1		80.5
Customer deposits	81.1		81.1
Accrued taxes	52.9		55.7
Accrued interest	40.8		40.2
Accrued compensation	37.7		31.1

Fuel clause over recoveries	—		28.6
Other	34.1		33.7
Total current liabilities	1,089.6		697.4
LONG-TERM DEBT	4,496.4		3,494.4
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	159.8		231.4
Deferred income taxes	1,333.3		1,268.6
Deferred investment tax credits	12.8		10.9
Regulatory liabilities	1,231.1		1,188.9

Other	227.1		195.4
Total deferred credits and other liabilities	2,964.1		2,895.2
Total liabilities	8,550.1		7,087.0
COMMITMENTS AND CONTINGENCIES (NOTE 15)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,125.8		1,124.6
Retained earnings	2,955.4		2,544.6
Accumulated other comprehensive loss, net of tax	(24.8)		(32.1)
Treasury stock, at cost	(0.1)		(5.3)


Total stockholders' equity	4,056.3		3,631.8
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	12,606.4	$	10,718.8

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)		2021		2020
STOCKHOLDERS' EQUITY
Common stock, par value $0.01 per share; authorized 450.0 shares; and outstanding 200.1 shares and 200.1 shares, respectively		$	2.0	$	2.0
Premium on common stock		1,123.8		1,122.6
Retained earnings		2,955.4		2,544.6
Accumulated other comprehensive loss, net of tax		(24.8)		(32.1)
Treasury stock, at cost, 0.0 and 0.1 shares, respectively		(0.1)		(5.3)


Total stockholders' equity		4,056.3		3,631.8

LONG-TERM DEBT
SERIES	DUE DATE
Senior Notes - OGE Energy
0.703%	Senior Notes, Series Due May 26, 2023	500.0		—
Senior Notes - OG&E

0.553%	Senior Notes, Series Due May 26, 2023	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		9.4

Other Bonds - OG&E
0.11% - 0.27%	Garfield Industrial Authority, January 1, 2025	47.0		47.0
0.11% - 0.33%	Muskogee Industrial Authority, January 1, 2025	32.4		32.4
0.11% - 0.27%	Muskogee Industrial Authority, June 1, 2027	56.0		56.0
Unamortized debt expense		(23.8)		(25.3)
Unamortized discount		(9.5)		(10.1)
Total long-term debt		4,496.4		3,494.4
Less: long-term debt due within one year		—		—
Total long-term debt (excluding long-term debt due within one year)		4,496.4		3,494.4
Total capitalization (including long-term debt due within one year)		$	8,552.7	$	7,126.2

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
(In millions)	Shares	Value		Shares	Value		Premium on Common Stock		Retained Earnings		Accumulated Other Comprehensive (Loss) Income		Total
Balance at December 31, 2018	199.7	$	2.0	—	$	—	$	1,125.7	$	2,906.3	$	(28.9)	$	4,005.1
Net income	—	—		—	—		—		433.6		—		433.6

Other comprehensive income, net of tax	—	—		—	—		—		—		1.0		1.0
Dividends declared on common stock ($1.5050 per share)	—	—		—	—		—		(303.8)		—		(303.8)

Stock-based compensation	0.4	—		—	—		3.6		—		—		3.6





Balance at December 31, 2019	200.1	$	2.0	—	$	—	$	1,129.3	$	3,036.1	$	(27.9)	$	4,139.5
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

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)	2021		2020		2019
OPERATING REVENUES
Revenues from contracts with customers	$	3,588.7	$	2,069.8	$	2,175.5
Other revenues	65.0		52.5		56.1
Operating revenues	3,653.7		2,122.3		2,231.6
FUEL, PURCHASED POWER AND DIRECT TRANSMISSION EXPENSE	2,127.6		644.6		786.9
OPERATING EXPENSES
Other operation and maintenance	464.7		464.4		492.5
Depreciation and amortization	416.0		391.3		355.0
Taxes other than income	99.3		97.2		89.5
Operating expenses	980.0		952.9		937.0
OPERATING INCOME	546.1		524.8		507.7
OTHER INCOME (EXPENSE)
Allowance for equity funds used during construction	6.7		4.8		4.5
Other net periodic benefit expense	(4.3)		(3.1)		(1.2)
Other income	7.1		5.0		6.7
Other expense	(1.8)		(2.6)		(6.9)
Net other income	7.7		4.1		3.1
INTEREST EXPENSE
Interest on long-term debt	152.7		152.8		138.3
Allowance for borrowed funds used during construction	(3.5)		(1.9)		(2.8)
Interest on short-term debt and other interest charges	2.8		3.9		5.0
Interest expense	152.0		154.8		140.5
INCOME BEFORE TAXES	401.8		374.1		370.3
INCOME TAX EXPENSE	41.8		34.7		20.1
NET INCOME	360.0		339.4		350.2
Other comprehensive income, net of tax	—		—		—
COMPREHENSIVE INCOME	$	360.0	$	339.4	$	350.2

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)	2021		2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	360.0	$	339.4	$	350.2
Adjustments to reconcile net income to net cash (used in) provided from operating activities:
Depreciation and amortization	416.0		391.3		355.0
Deferred income taxes and other tax credits, net	44.6		40.9		20.4
Allowance for equity funds used during construction	(6.7)		(4.8)		(4.5)
Stock-based compensation expense	2.2		3.0		4.9

Regulatory assets	(874.9)		(112.0)		(47.1)
Regulatory liabilities	(71.2)		(64.0)		(45.6)
Other assets	(2.2)		(3.4)		3.8
Other liabilities	(11.2)		(24.3)		8.4
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	(3.0)		4.5		17.0

Fuel, materials and supplies inventories	(3.4)		(8.9)		4.2
Fuel recoveries	(180.5)		63.3		(33.0)
Other current assets	(21.4)		(17.3)		5.9
Accounts payable	(11.0)		64.8		(30.0)

Income taxes payable - parent	0.7		(5.3)		(0.7)


Other current liabilities	3.3		(26.8)		(35.1)
Net cash (used in) provided from operating activities	(358.7)		640.4		573.8
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(778.5)		(650.5)		(635.5)


Net cash used in investing activities	(778.5)		(650.5)		(635.5)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital contribution from OGE Energy	530.0		—		—
Proceeds from long-term debt	499.8		297.1		296.5
Payment of long-term debt	(0.1)		(0.1)		(250.1)
Dividends paid on common stock	(265.0)		(325.0)		—
Changes in advances with parent	372.5		38.1		15.3

Net cash provided from financing activities	1,137.2		10.1		61.7
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 $3.5, $1.9 and $2.8, respectively)	$	148.9	$	150.2	$	144.6
Income taxes (net of income tax refunds)	$	(3.2)	$	(0.2)	$	1.3
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement	$	2.4	$	6.8	$	28.9

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

OKLAHOMA GAS AND ELECTRIC COMPANY

BALANCE SHEETS


December 31 (In millions)	2021		2020
ASSETS
CURRENT ASSETS
Accounts receivable, less reserve of $2.4 and $2.6, respectively	$	162.0	$	156.3
Accrued unbilled revenues	65.0		67.7
Advances to parent	—		272.0
Fuel inventories	40.6		36.5
Materials and supplies, at average cost	117.9		116.2
Fuel clause under recoveries	151.9		—
Other	67.7		36.9
Total current assets	605.1		685.6
OTHER PROPERTY AND INVESTMENTS	3.9		4.1
PROPERTY, PLANT AND EQUIPMENT
In service	13,893.7		13,290.6
Construction work in progress	252.0		145.5
Total property, plant and equipment	14,145.7		13,436.1
Less: accumulated depreciation	4,318.9		4,067.6
Net property, plant and equipment	9,826.8		9,368.5
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	1,230.8		415.6
Other	21.4		15.2
Total deferred charges and other assets	1,252.2		430.8
TOTAL ASSETS	$	11,688.0	$	10,489.0

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

OKLAHOMA GAS AND ELECTRIC COMPANY

BALANCE SHEETS (Continued)


December 31 (In millions)	2021		2020
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES

Accounts payable	$	240.6	$	236.7
Advances from parent	101.3		—
Customer deposits	81.1		81.1
Accrued taxes	50.8		53.3
Accrued interest	40.4		40.2
Accrued compensation	27.8		22.5

Fuel clause over recoveries	—		28.6
Other	33.8		33.5
Total current liabilities	575.8		495.9
LONG-TERM DEBT	3,996.5		3,494.4
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	75.1		135.4
Deferred income taxes	1,000.4		1,020.8
Deferred investment tax credits	12.8		10.9
Regulatory liabilities	1,231.1		1,188.9
Other	193.5		167.1
Total deferred credits and other liabilities	2,512.9		2,523.1
Total liabilities	7,085.2		6,513.4
COMMITMENTS AND CONTINGENCIES (NOTE 15)
STOCKHOLDER'S EQUITY
Common stockholder's equity	1,571.7		1,039.5
Retained earnings	3,031.1		2,936.1

Total stockholder's equity	4,602.8		3,975.6
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	11,688.0	$	10,489.0

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)		2021		2020
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		1,470.8		938.6
Retained earnings		3,031.1		2,936.1

Total stockholder's equity		4,602.8		3,975.6

LONG-TERM DEBT
SERIES	DUE DATE
Senior Notes
0.553%	Senior Notes, Series Due May 26, 2023	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		9.4

Other Bonds
0.11% - 0.27%	Garfield Industrial Authority, January 1, 2025	47.0		47.0
0.11% - 0.33%	Muskogee Industrial Authority, January 1, 2025	32.4		32.4
0.11% - 0.27%	Muskogee Industrial Authority, June 1, 2027	56.0		56.0

Unamortized debt expense		(23.7)		(25.3)
Unamortized discount		(9.5)		(10.1)
Total long-term debt		3,996.5		3,494.4
Less: long-term debt due within one year		—		—
Total long-term debt (excluding long-term debt due within one year)		3,996.5		3,494.4
Total capitalization (including long-term debt due within one year)		$	8,599.3	$	7,470.0

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, 2018	40.4	$	100.9	$	930.9	$	2,571.5	$	3,603.3
Net income	—	—		—		350.2		350.2


Stock-based compensation	—	—		4.8		—		4.8
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

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. Investment in Unconsolidated Affiliates	X
Note 6. Related Party Transactions	X	X
Note 7. Fair Value Measurements	X	X
Note 8. Stock-Based Compensation	X	X
Note 9. Income Taxes	X	X
Note 10. Common Equity	X	X
Note 11. Long-Term Debt	X	X
Note 12. Short-Term Debt and Credit Facilities	X	X
Note 13. Retirement Plans and Postretirement Benefit Plans	X	X
Note 14. Report of Business Segments	X
Note 15. Commitments and Contingencies	X	X
Note 16. Rate Matters and Regulation	X	X

1.Summary of Significant Accounting Policies

Organization

Enable's business, see OGE Energy's 2020 Form 10-K. Upon the closing of the Energy Transfer and Enable merger, OGE Energy's natural gas midstream operations segment represents OGE Energy's investment in Energy Transfer's equity securities and legacy Enable seconded employee pension and postretirement costs. The investment in Energy Transfer's equity securities is held through wholly-owned subsidiaries and ultimately OGE Holdings. At December 31, 2021, OGE energy owned 95.4 million, or approximately three percent, of Energy Transfer's limited partner units. OGE Energy does not have significant influence over Energy Transfer, as OGE Energy does not own general partner units in or have board representation at Energy Transfer. As such, OGE Energy accounts for its investment in Energy Transfer as an investment in equity securities, as further discussed under "Investment in Equity Securities of Energy Transfer" below. OGE Energy intends to exit the midstream segment in a prudent manner.

OGE Energy charges operating costs to OG&E, and prior to December 2, 2021, OGE Energy charged operating costs to Enable, based on several factors. Operating costs directly related to OG&E and Enable are assigned as such. Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method. The "Distrigas" method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. 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.

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)	2021		2020
REGULATORY ASSETS
Current:
Fuel clause under recoveries	$	151.9	$	—
Oklahoma Energy Efficiency Rider under recoveries (A)	11.7		—
SPP cost tracker under recovery (A)	9.3		7.0
Generation Capacity Replacement Rider under recovery (A)	1.0		4.4
Other (A)	8.7		8.4
Total current regulatory assets	$	182.6	$	19.8
Non-current:
Oklahoma Winter Storm Uri costs	$	747.9	$	—
Oklahoma deferred storm expenses	172.8		158.8
Benefit obligations regulatory asset	109.2		164.9
Arkansas Winter Storm Uri costs	88.9		—
Pension tracker	42.9		18.1
Sooner Dry Scrubbers	18.9		19.7
Arkansas deferred pension expenses	12.1		9.3
Unamortized loss on reacquired debt	8.9		9.7
COVID-19 impacts	8.2		6.4
Frontier Plant deferred expenses	6.7		6.4
Smart Grid	3.9		11.2

Other	10.4		11.1
Total non-current regulatory assets	$	1,230.8	$	415.6
REGULATORY LIABILITIES
Current:

Fuel clause over recoveries	$	—	$	28.6



Other (B)	2.5		6.5
Total current regulatory liabilities	$	2.5	$	35.1
Non-current:
Income taxes refundable to customers, net	$	930.7	$	867.4
Accrued removal obligations, net	296.8		316.8

Other	3.6		4.7
Total non-current regulatory liabilities	$	1,231.1	$	1,188.9

(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 previous program cycle, which ran through 2021, included 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. A new program cycle related to 2022 through 2024 programs was approved on February 1, 2022, as further discussed in Note 16.

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.

OG&E recovers 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 River Valley plant and, beginning May 1, 2021, the Frontier plant, through the Generation Capacity Replacement Rider. The OCC also authorized OG&E to defer the same costs through April 30, 2021 related to its investment in the Frontier plant to a regulatory asset, and recovery of these costs will be considered in future rate proceedings.

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. OG&E's natural gas costs for the month of February 2021 exceeded the total cost for all of 2020. The OCC allowed OG&E to create a regulatory asset for the Oklahoma portion of all deferred costs with an initial carrying charge based on the effective cost of the related debt financing for an amortization period to be determined at a later date. See Note 16 for further discussion of the Oklahoma securitization process related to this regulatory asset. The APSC allowed OG&E to create a regulatory asset for the Arkansas portion of all deferred costs with an initial carrying charge equal to the current customer deposit interest rate to be recovered over a period of 10 years beginning in May 2021.

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-year period in accordance with historical practice. To mitigate customer impact, OG&E has agreed to recover the portion related to 2020 excess storm costs through the Storm Cost Recovery Rider over a ten-year period.

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)	2021		2020
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	89.6	$	147.3

Postretirement Benefit Plans:
Net loss	23.2		26.2
Prior service cost	(3.6)		(8.6)
Total	$	109.2	$	164.9

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 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 13.

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 are related to the suspension of or delay in disconnection of service and additional expenses associated with ensuring the continuity of utility service.

OG&E deferred to a regulatory asset the incremental and stranded costs that were accumulated during Smart Grid deployment, including (i) costs for web portal access, (ii) costs for education and home energy reports and (iii) stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters. As approved by the OCC and APSC, these costs are being recovered over a six-year period ending in 2022 in Oklahoma and 2023 in Arkansas.

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

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

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

Use of Estimates

In preparing the 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 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

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, such as in response to COVID-19 impacts. 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 $2.4 million and $2.6 million at December 31, 2021 and 2020, respectively.

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

Fuel Inventories

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was $40.6 million and $36.5 million at December 31, 2021 and 2020, 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, 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.


December 31, 2020 (In millions)	Percentage Ownership		Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
McClain Plant (A)	77	%	$	257.1	$	96.0	$	161.1
Redbud Plant (A)(B)	51	%	$	531.8	$	181.9	$	349.9

(A)Construction work in progress was $0.1 million and $1.8 million for the McClain and Redbud Plants, respectively.

(B)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $67.3 million.

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


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.


December 31, 2020 (In millions)	Total Property, Plant and Equipment		Accumulated Depreciation		Net Property, Plant and Equipment
OG&E:
Distribution assets	$	4,809.9	$	1,422.1	$	3,387.8
Electric generation assets (A)	4,932.2		1,713.6		3,218.6
Transmission assets (B)	2,944.6		591.7		2,352.9
Intangible plant	254.1		153.9		100.2
Other property and equipment	495.3		186.3		309.0
OG&E property, plant and equipment	13,436.1		4,067.6		9,368.5
Non-OG&E property, plant and equipment	6.1		—		6.1
Total OGE Energy property, plant and equipment	$	13,442.2	$	4,067.6	$	9,374.6

(A)This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $67.3 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 $103.7 million and $89.7 million at December 31, 2021 and 2020, respectively. OG&E's amortization expense for computer software costs was $18.1 million, $14.9 million and $11.0 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Depreciation and Amortization

The provision for depreciation, which was 2.6 percent of the average depreciable utility plant for both 2021 and 2020, 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 2022, the provision for depreciation is projected to be 2.6 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, 2021, 99.1 percent will be amortized over 10.4 years with the remaining 0.9 percent of the intangible plant balance at December 31, 2021 being amortized over 23.7 years.

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

Investment in Unconsolidated Affiliates

Prior to December 2, 2021, OGE Energy's investment in Enable was considered to be a variable interest entity because the owners of the equity at risk in the entity had disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, OGE Energy was not considered the primary beneficiary of Enable since it did not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable; therefore, OGE Energy accounted for its investment in Enable using the equity method of accounting. 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 are 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 are classified as investing activities in the statements of cash flows.

Investment in Equity Securities of Energy Transfer

OGE Energy accounts 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." OGE Energy presents the Energy Transfer equity securities at estimated fair value in its balance sheet. OGE Energy presents realized and unrealized 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 period between December 2, 2021 and December 31, 2021, OGE Energy recognized an unrealized loss of $8.6 million related to its investment in Energy Transfer's equity securities.

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, 2021 and 2020.


(In millions)	2021		2020
Balance at January 1	$	79.6	$	73.5
Accretion expense	0.6		0.5
Revisions in estimated cash flows (A)	—		5.8

Liabilities settled (B)	—		(0.2)
Balance at December 31	$	80.2	$	79.6

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

(B)Asset retirement obligations were settled for asbestos removal at one of OG&E's generating facilities.

Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost. OG&E had $25.8

million and $25.0 million in accrued environmental liabilities at December 31, 2021 and 2020, 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 7.4 percent, 7.3 percent and 7.6 percent for the years ended December 31, 2021, 2020 and 2019, 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 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 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.

Actual fuel costs from Winter Storm Uri are recoverable from OG&E's customers through securitization of regulatory assets. Both the OCC and the APSC allowed OG&E to create a regulatory asset for each jurisdictional portion of all deferred costs, as further discussed above within "Accounting Records." For additional information on Oklahoma securitization, see Note 16.

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 utility 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.

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.

Accumulated Other Comprehensive Income (Loss)

The following table presents changes in the components of accumulated other comprehensive income (loss) attributable to OGE Energy during 2020 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, 2019	$	(34.9)	$	(0.2)	$	4.2	$	3.6	$	(0.6)	$	(27.9)
Other comprehensive income (loss) before reclassifications	(5.1)		—		(2.4)		—		(0.7)		(8.2)
Amounts reclassified from accumulated other comprehensive income (loss)	3.9		—		(0.1)		(1.7)		—		2.1
Curtailment	—		—		(0.3)		—		—		(0.3)
Settlement cost	2.2		—		—		—		—		2.2
Net current period other comprehensive income (loss)	1.0		—		(2.8)		(1.7)		(0.7)		(4.2)
Balance at December 31, 2020	(33.9)		(0.2)		1.4		1.9		(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)	$	0.8	$	0.5	$	—	$	(24.8)

The following table presents significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income (loss) during the years ended December 31, 2021 and 2020.


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)	2021		2020









Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses	$	(2.5)	$	(5.1)	(A)
Prior service cost	(0.1)		—		(A)
Settlement cost	(8.7)		(2.9)		(A)
	(11.3)		(8.0)		Income (Loss) Before Taxes
	(3.6)		(1.9)		Income Tax Expense (Benefit)


	$	(7.7)	$	(6.1)	Net Income (Loss)

Amortization of postretirement benefit plans items:

Prior service credit	$	1.8	$	2.3	(A)
Curtailment cost	—		0.4		(A)
Actuarial gains (losses)	(0.1)		0.1		(A)
	1.7		2.8		Income (Loss) Before Taxes
	0.4		0.7		Income Tax Expense (Benefit)
	$	1.3	$	2.1	Net Income (Loss)



Total reclassifications for the period, net of tax	$	(6.4)	$	(4.0)	Net Income (Loss)

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

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation. OGE Energy changed the classification of certain investments in its 2020 consolidated balance sheet to conform with current year presentation. The prior year reclassification of $23.1 million from Investment in Unconsolidated Affiliates to Other Property and Investments did not impact previously reported current or total assets.

2.Accounting Pronouncements

The Registrants believe that 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.

3.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 Utility) Results of Operations" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."




	Year Ended December 31,
(In millions)	2021		2020		2019
Residential	$	1,309.1	$	842.7	$	865.8
Commercial	749.2		465.6		486.6
Industrial	323.0		192.6		217.8
Oilfield	312.8		169.2		200.4
Public authorities and street light	284.4		172.3		190.3
System sales revenues	2,978.5		1,842.4		1,960.9
Provision for rate refund	—		3.8		(0.9)
Integrated market	468.9		49.6		38.4
Transmission	140.2		143.3		148.0
Other	1.1		30.7		29.1
Revenues from contracts with customers (A)	$	3,588.7	$	2,069.8	$	2,175.5

(A)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. Operating revenues significantly increased due to increased fuel, purchased power and direct transmission expenses, which are generally recoverable from customers, as a result of Winter Storm Uri. For further discussion, see Note 16 and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

4.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.

Operating Leases

OG&E Railcar Lease Agreement

Effective February 1, 2019, OG&E renewed a railcar lease agreement for 780 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to fuel expense and are 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.

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)	2021		2020		2019		2021		2020		2019












Operating lease cost	$	6.3	$	6.4	$	6.0	$	5.7	$	5.5	$	5.1
Cash paid for amounts included in the measurement of lease liabilities:

Operating cash flows for operating leases	$	6.3	$	6.4	$	5.6	$	5.7	$	5.5	$	4.8

Right-of-use assets obtained in exchange for new operating lease liabilities	$	—	$	1.4	$	10.7	$	—	$	1.4	$	10.7


	OGE Energy						OG&E
(Dollars in millions)	December 31, 2021			December 31, 2020			December 31, 2021			December 31, 2020
Right-of-use assets at period end (A)	$	33.0		$	37.6		$	33.0		$	37.0
Operating lease liabilities at period end (B)	$	37.6		$	42.3		$	37.6		$	41.7
Operating lease weighted-average remaining lease term (in years)	12.2			12.5			12.2			12.7
Operating lease weighted-average discount rate	3.9		%	3.9		%	3.9		%	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)

2022	$	5.7	$	5.7
2023	5.1		5.1
2024	3.1		3.1
2025	3.0		3.0
2026	3.0		3.0
Thereafter	28.7		28.7
Total future minimum lease payments	48.6		48.6
Less: Imputed interest	11.0		11.0
Present value of net minimum lease payments	$	37.6	$	37.6

5.Investment in Unconsolidated Affiliates

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. Further discussion of the transaction can be found in Note 1. The below discussion relates to OGE Energy's equity method investment in Enable prior to December 2, 2021.

In 2013, OGE Energy, CenterPoint and another party formed Enable as a private limited partnership, and OGE Energy and the other party indirectly contributed 100 percent of the equity interests in Enogex LLC to Enable. OGE Energy determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and recorded the contribution at historical cost. The formation of Enable was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes. Under this method, the fair value of the consideration paid by

CenterPoint for Enogex Holdings was allocated to the assets acquired and liabilities assumed based on their fair value. Enogex Holdings' assets, liabilities and equity were accordingly adjusted to estimated fair value, resulting in an increase to Enable's equity of $2.2 billion. Since the contribution of Enogex LLC to Enable was recorded at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations were eliminated in OGE Energy's recording of its equity in earnings of Enable through the closing date of December 2, 2021. As prior real estate sales accounting guidance was superseded by ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets," prior to December 2, 2021, OGE Energy recognized gains or losses on sales or dilution events in its investment in Enable within OGE Energy's earnings, net of proportional basis difference recognition.

OGE Energy recorded equity in earnings of unconsolidated affiliates of $169.8 million for the period of January 1, 2021 through December 2, 2021 compared to equity in losses of unconsolidated affiliates of $668.0 million for the year ended December 31, 2020 and equity in earnings of unconsolidated affiliates of $113.9 million for the year ended December 31, 2019. Equity in earnings (losses) of unconsolidated affiliates includes OGE Energy's share of Enable's earnings adjusted for the amortization of the basis difference of OGE Energy's original investment in Enogex LLC and its previous underlying equity in the net assets of Enable, as well as any impairment OGE Energy recorded on its investment in Enable. Equity in earnings (losses) of unconsolidated affiliates was also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above. These amortizations may also include gain or loss on dilution, net of proportional basis difference recognition.

The following tables present summarized unaudited financial information for 100 percent of Enable as of December 2, 2021 and December 31, 2020 and for the period of January 1, 2021 through December 2, 2021 and the years ended December 31, 2020 and 2019.



Balance Sheet	December 2, 2021		December 31, 2020
(In millions)
Current assets	$	594	$	381
Non-current assets	$	11,227	$	11,348
Current liabilities	$	1,254	$	582
Non-current liabilities	$	3,281	$	4,052


	Period of January 1, 2021 through December 2, 2021		Year Ended
Income Statement	Period of January 1, 2021 through December 2, 2021		December 31, 2020		December 31, 2019
(In millions)
Total revenues	$	3,466	$	2,463	$	2,960
Cost of natural gas and NGLs (excluding depreciation and amortization)	$	1,959	$	965	$	1,279
Operating income	$	634	$	465	$	569
Net income	$	461	$	52	$	360

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 years ended December 31, 2020 and 2019. For further discussion of Enable's net income, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - OGE Holdings (Natural Gas Midstream Operations)."


	Period of January 1, 2021 through December 2, 2021			Year Ended
(In millions)				December 31, 2020			December 31, 2019
Enable net income	$	461.0		$	52.0		$	360.0

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		$	360.0
OGE Energy's percent ownership at period end	25.5		%	25.5		%	25.5		%
OGE Energy's portion of Enable net income	$	119.8		$	13.2		$	91.8
Amortization of basis difference and dilution recognition (A)	50.0			98.8			22.1
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)		$	113.9

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

(B)Effective March 31, 2020, OGE Energy estimated the fair value of its investment in Enable was below the book value and concluded the decline in value was not temporary due to the severity of the decline and recent rapid deterioration, as well as the near term future outlook, of the midstream oil and gas industry. Accordingly, OGE Energy recorded a $780.0 million impairment on its investment in Enable in 2020. Further information concerning the fair value method used to measure the impairment on OGE Energy's investment in Enable can be found in Note 7.

(C)For the year ended December 31, 2020, Enable recorded a $225.0 million impairment on its SESH equity method investment. Enable estimated the fair value of this equity method investment was below the carrying value at September 30, 2020 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. The impairment 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, $91.7 million and $144.0 million during the years ended December 31, 2021, 2020 and 2019, respectively.

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.

6.Related Party Transactions

OGE Energy charges operating costs to OG&E, and prior to December 2, 2021, charged operating costs to Enable, based on several factors. Operating costs directly related to OG&E and/or Enable are assigned as such. Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method, which is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment.

OGE Energy and OG&E

OGE Energy charged operating costs to OG&E of $139.3 million, $140.6 million and $149.8 million during the years ended December 31, 2021, 2020 and 2019, respectively. In 2021 and 2020, OG&E declared dividends to OGE Energy of $265.0 million and $325.0 million, respectively. In 2019, no dividends were declared from OG&E to OGE Energy.

OGE Energy and Enable

Prior to December 2, 2021, 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, $0.4 million and $0.5 million for the period of January 1, 2021 through December 2, 2021, year ended December 31, 2020 and year ended December 31, 2019, respectively.

OGE Energy provided retirement benefits and retiree health care benefits to 63 employees previously seconded to Enable. OGE Energy billed Enable for reimbursement of $12.2 million, $17.3 million and $23.2 million in 2021, 2020 and 2019, 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 $19.4 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 and $2.0 million as of December 31, 2021 and 2020, respectively, which are included in Accounts Receivable in OGE Energy's balance sheets.

OG&E and Enable

Enable provided gas transportation services to OG&E pursuant to agreements, which expire in May 2024 and December 2038, that granted Enable the responsibility of delivering natural gas to OG&E's generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchased gas from Enable when Enable's deliveries exceeded OG&E's pipeline receipts. Enable purchased gas from OG&E when OG&E's pipeline receipts exceeded Enable's deliveries. Further, an additional gas transportation services contract with Enable became effective in December 2018 related to the project to convert Muskogee Units 4 and 5 from coal to natural gas. 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 years ended December 31, 2020 and 2019.


	Period of January 1, 2021 through December 2, 2021		Year Ended
(In millions)			December 31, 2020		December 31, 2019
Operating revenues:
Electricity to power electric compression assets	$	13.3	$	15.1	$	15.9
Fuel, purchased power and direct transmission expense:
Natural gas transportation services	$	32.7	$	32.8	$	41.2

Natural gas purchases (sales)	$	(33.5)	$	2.7	$	(6.0)

7.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, 2021 and 2020. The following table presents OGE Energy's 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, 2021 and 2020, as well as the classification level within the fair value hierarchy.


	2021				2020
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	(A)		(A)		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	$	497.8	$	—	$	—	Level 2
OG&E Senior Notes	$	3,851.8	$	4,460.2	$	3,349.6	$	4,182.1	Level 2
OG&E Industrial Authority Bonds	$	135.4	$	135.4	$	135.4	$	135.4	Level 2
Tinker Debt	$	9.3	$	10.0	$	9.4	$	10.7	Level 3

(A)OGE Energy's ownership of Energy Transfer securities was effective as of December 2, 2021; therefore, the investment in Energy Transfer's equity securities was not held at December 31, 2020.

Nonrecurring Fair Value Measurements

As further discussed in Note 5, OGE Energy recorded an impairment on its investment in Enable in March 2020. The nonrecurring fair value measurement consisted of calculating a 20-trading day volume weighted average price for Enable's common units through March 31, 2020. This method of valuation was determined to be representative of the fair value of Enable's common units as it incorporated market prices during the period and reduced the impact of volatility that a single day could represent. OGE Energy concluded that this valuation method resulted in a Level 3 nonrecurring fair value measurement.

8.Stock-Based Compensation

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

The following table presents the Registrants' pre-tax compensation expense and related income tax benefit for the years ended December 31, 2021, 2020 and 2019 related to performance units and restricted stock units for the Registrants' employees.


	OGE Energy						OG&E
Year Ended December 31 (In millions)	2021		2020		2019		2021		2020		2019
Performance units:
Total shareholder return	$	7.5	$	7.9	$	8.7	$	1.8	$	2.3	$	3.0
Earnings per share	—		1.0		4.3		—		0.3		1.5
Total performance units	7.5		8.9		13.0		1.8		2.6		4.5
Restricted stock units	2.3		0.9		0.9		0.4		0.4		0.4


Total compensation expense	$	9.8	$	9.8	$	13.9	$	2.2	$	3.0	$	4.9
Income tax benefit	$	2.5	$	2.5	$	3.6	$	0.6	$	0.8	$	1.3

During the year ended December 31, 2020, OGE Energy purchased 405,000 shares of its common stock, and 154,523 and 247,252 of these shares were used during December 31, 2021 and 2020, respectively, to satisfy payouts of earned performance units and restricted stock unit grants to the Registrants' employees pursuant to OGE Energy's Stock Incentive Plan. The shares were purchased at an average cost of $38.04 and $33.14 per share on the open market during March 2020 and August 2020, respectively. OGE Energy records treasury stock purchases at cost. Treasury stock is presented as a reduction of stockholders' equity in OGE Energy's balance sheets.

During the year ended December 31, 2020, there was an immaterial number of shares of new common stock issued pursuant to OGE Energy's Stock Incentive Plan to satisfy restricted stock unit grants to employees. During the year ended December 31, 2019, OGE Energy issued 443,900 shares of new common stock to satisfy payouts of earned performance units and restricted stock unit grants to the Registrants' employees.

Performance Units

Under the 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 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. The performance units granted based on earnings per share were contingently awarded and will be payable in shares of OGE Energy's common stock based on OGE Energy's earnings per share growth over a primarily three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of OGE Energy's Board of Directors. All of 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.

Performance Units – Total Shareholder Return

The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the primarily three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends are accrued on a quarterly basis pending achievement of payout criteria and are included in the fair value calculations. Expected price volatility is based on the historical volatility of 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
	2021			2020			2019			2021			2020			2019
Number of units granted	249,909			201,552			208,647			68,720			67,975			68,396
Fair value of units granted	$	38.14		$	38.03		$	47.00		$	38.14		$	38.03		$	47.00
Expected dividend yield	4.7		%	3.5		%	4.0		%	4.7		%	3.5		%	4.0		%
Expected price volatility	29.0		%	15.0		%	17.0		%	29.0		%	15.0		%	17.0		%
Risk-free interest rate	0.22		%	1.17		%	2.47		%	0.22		%	1.17		%	2.47		%
Expected life of units (in years)	2.84			2.85			2.86			2.85			2.85			2.86

Performance Units – Earnings Per Share

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 last outstanding grant of performance units based on earnings per share paid out during 2021. Prior to payout, OGE Energy reassessed at each reporting date whether achievement of the performance condition was probable and accrued compensation expense if and when achievement of the performance condition was probable. As a result, the compensation expense recognized for these performance units varied from period to period. There are no post-vesting restrictions related to OGE Energy's performance units based on earnings per share.

Restricted Stock Units

Under the 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, and as of the 2019 grant cycle, restricted stock units are granted in lieu of performance units based on earnings per share. The restricted stock units vest primarily in a three-year award cycle (i.e., three-year cliff vesting period). Prior to vesting, each restricted stock unit is subject to forfeiture if the recipient ceases to render substantial services to 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
	2021		2020		2019		2021		2020		2019
Restricted stock units granted	89,197		67,193		75,929		22,911		22,665		26,141
Fair value of restricted stock units granted	$	31.11	$	43.69	$	41.71	$	30.91	$	43.69	$	41.63

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, 2021. 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
	Total Shareholder Return				Earnings Per Share
(Dollars in millions)	Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value		Number of Shares	Aggregate Intrinsic Value
Units/shares outstanding at 12/31/20	612,262				79,002				124,919
Granted	249,909	(A)			—				89,197

Converted	(236,990)	(B)	$	5.4	(79,002)	(B)	$	2.7	—
Vested	N/A				N/A				(53,274)	$	2.2
Forfeited	(43,929)				—				(27,171)
Units/shares outstanding at 12/31/21	581,252		$	17.5	—		$	—	133,671	$	5.1
Units/shares fully vested at 12/31/21	172,748		$	—	—		$	—	47,907	$	2.0


OG&E	Performance Units								Restricted Stock Units
	Total Shareholder Return				Earnings Per Share
(Dollars in millions)	Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value		Number of Shares		Aggregate Intrinsic Value
Units/shares outstanding at 12/31/20	182,363				25,235				34,130
Granted	68,720	(A)			—				22,911
Converted	(75,693)	(B)	$	1.7	(25,235)	(B)	$	0.8	—
Vested	N/A				N/A				(12,461)		$	0.6
Forfeited	(14,132)				—				(8,986)
Employee migration	52	(C)			—	(C)			19	(C)
Units/shares outstanding at 12/31/21	161,310		$	4.8	—		$	—	35,613		$	1.4
Units/shares fully vested at 12/31/21	48,195		$	—	—		$	—	11,241		$	0.5

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

(B)These amounts represent performance units that vested at December 31, 2020 which were settled in February 2021.

(C)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, 2021. 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
	Total Shareholder Return
	Number of Units		Weighted-Average Grant Date Fair Value			Number of Shares	Weighted-Average Grant Date Fair Value
Units/shares non-vested at 12/31/20	375,272		$	42.51		124,919	$	42.69
Granted	249,909	(A)	$	38.14		89,197	$	31.11

Vested	(172,748)		$	47.00		(53,274)	$	41.59
Forfeited	(43,929)		$	41.02		(27,171)	$	42.37
Units/shares non-vested at 12/31/21	408,504		$	38.05		133,671	$	35.64


OG&E	Performance Units -				Restricted Stock Units
	Total Shareholder Return
	Number of Units		Weighted-Average Grant Date Fair Value			Number of Shares		Weighted-Average Grant Date Fair Value
Units/shares non-vested at 12/31/20	106,670		$	42.49		34,130		$	42.67
Granted	68,720	(A)	$	38.14		22,911		$	30.91

Vested	(48,195)		$	47.00		(12,461)		$	45.67
Forfeited	(14,132)		$	41.12		(8,986)		$	42.51
Employee migration	52	(B)	$	41.01		19	(B)	$	37.71
Units/shares non-vested at 12/31/21	113,115		$	38.10		35,613		$	35.52

(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)	2021		2020		2019		2021		2020		2019
Performance units:
Total shareholder return	$	8.1	$	8.7	$	9.3	$	2.3	$	2.8	$	3.2
Earnings per share	$	—	$	2.5	$	5.2	$	—	$	0.8	$	0.9
Restricted stock units	$	2.2	$	0.1	$	0.1	$	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, 2021	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 - total shareholder return	$	7.5	1.71	$	2.0	1.72


Restricted stock units	3.5		1.48	0.8		1.39
Total unrecognized compensation cost	$	11.0		$	2.8

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)	2021		2020		2019		2021		2020		2019
Provision (benefit) for current income taxes:
Federal	$	16.4	$	8.4	$	(6.4)	$	(9.0)	$	(3.8)	$	(7.9)
State	1.7		0.5		5.1		9.0		(0.6)		4.1
Total provision (benefit) for current income taxes	18.1		8.9		(1.3)		—		(4.4)		(3.8)
Provision (benefit) for deferred income taxes, net:
Federal	133.1		(105.2)		48.5		58.3		45.7		37.7
State	(10.0)		(31.1)		(17.4)		(16.5)		(6.6)		(13.8)
Total provision (benefit) for deferred income taxes, net	123.1		(136.3)		31.1		41.8		39.1		23.9

Total income tax expense (benefit)	$	141.2	$	(127.4)	$	29.8	$	41.8	$	34.7	$	20.1

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 utility property have been deferred and will be amortized to income over the life of the related property. Additionally, OG&E earns federal tax credits associated with production from its wind facilities. Oklahoma production and investment state tax credits are also earned on investments in electric and solar generating facilities which further reduce OG&E's effective tax rate.

The following table presents a reconciliation of the statutory tax rates to the effective income tax rate.


	OGE Energy						OG&E
Year Ended December 31	2021		2020		2019		2021		2020		2019
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	0.9		(1.4)		(1.2)		(1.4)		(1.6)		(1.8)
Stock-based compensation	0.1		(0.3)		(1.2)		—		—		—
Executive compensation limitation	0.1		0.2		0.2		—		—		—
Amortization of net unfunded deferred taxes	(2.1)		(4.4)		(4.5)		(4.6)		(4.8)		(5.6)
Federal renewable energy credit (A)	(2.0)		(5.0)		(6.0)		(4.4)		(5.4)		(7.6)
Remeasurement of state deferred taxes due to Energy Transfer merger (B)	(1.1)		—		—		—		—		—
Remeasurement of state deferred tax liabilities	(0.6)		0.9		(0.8)		—		—		—
401(k) dividends	(0.2)		(0.4)		(0.4)		—		—		—
Impairment of OGE Energy's investment in Enable (C)	—		31.6		—		—		—		—
Other	—		0.1		(0.7)		(0.2)		0.1		(0.6)


Effective income tax rate	16.1	%	42.3	%	6.4	%	10.4	%	9.3	%	5.4	%

(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 are expected to decrease, as Energy Transfer operates in significantly more states with generally lower tax rates than the historic Enable operating area.

(C)As further discussed in Note 5, 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, 2021 and 2020.
















	OGE Energy				OG&E
December 31 (In millions)	2021		2020		2021		2020
Deferred income tax liabilities, net:
Accelerated depreciation and other property related differences	$	1,677.3	$	1,721.2	$	1,677.3	$	1,721.2

Investment in Enable	—		302.6		—		—
Investment in Energy Transfer's equity securities	363.5		—		—		—
Regulatory assets	52.1		52.3		52.1		52.3
Pension Plan	10.7		3.9		32.0		27.4
Other	7.4		(1.4)		(4.7)		(6.5)
Derivative instruments	2.2		1.7		—		—
Bond redemption-unamortized costs	1.8		2.0		1.8		2.0


Income taxes recoverable from customers, net	(225.8)		(221.8)		(225.8)		(221.8)
State tax credits	(221.2)		(204.4)		(205.9)		(189.0)
Federal tax credits	(208.4)		(236.6)		(209.8)		(236.6)
Regulatory liabilities	(72.0)		(81.0)		(72.0)		(81.0)
Asset retirement obligations	(19.4)		(20.3)		(19.4)		(20.3)
Postretirement medical and life insurance benefits	(19.2)		(22.4)		(13.0)		(15.3)
Accrued liabilities	(9.5)		(9.6)		(7.3)		(5.2)
Deferred federal investment tax credits	(3.1)		(2.7)		(3.1)		(2.7)
Net operating losses	(1.0)		(12.0)		—		(1.4)
Accrued vacation	(1.5)		(2.2)		(1.2)		(1.6)
Uncollectible accounts	(0.6)		(0.7)		(0.6)		(0.7)

Total deferred income tax liabilities, net	$	1,333.3	$	1,268.6	$	1,000.4	$	1,020.8

As of December 31, 2021, the Registrants have classified $18.1 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, 2021, 2020 and 2019.


(In millions)	2021		2020		2019
Balance at January 1	$	21.9	$	20.7	$	20.7
Tax positions related to current year:
Additions	1.7		1.2		—

Reductions	(1.2)		—		—
Balance at December 31	$	22.4	$	21.9	$	20.7

As of December 31, 2021, 2020 and 2019, there were $18.1 million, $17.6 million and $16.4 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 year ended December 31, 2021, 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 September 2021, the Registrants recorded an additional reserve for certain federal

research and development credits in the amount of $1.7 million. The $1.2 million reserve recorded in 2020 was reversed upon completion of the audit.

The Registrants sustained federal and state tax operating losses through 2012 caused primarily by bonus depreciation and other book versus tax temporary differences. Federal net operating losses generated during those years have been fully utilized. State operating losses are being carried forward for utilization in future years. In addition to the tax operating losses, the Registrants were unable to utilize the various tax credits that were generated during those years. These tax losses and 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 remaining losses and credits before they begin to expire after 2021. 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 operating loss	$	33.4	$	1.0	$	—	$	—	2032
Federal tax credits	$	208.4	$	208.4	$	209.8	$	209.8	2032
State tax credits:
Oklahoma investment tax credits	$	227.1	$	179.4	$	207.8	$	164.2	N/A
Oklahoma capital investment board credits	$	12.8	$	12.8	$	12.8	$	12.8	N/A
Oklahoma zero emission tax credits	$	37.5	$	28.9	$	37.5	$	28.9	2021
Louisiana inventory credits	$	0.1	$	0.1	$	—	$	—	2032

N/A - not applicable

Oklahoma Corporate Tax Rate Change

In May 2021, Oklahoma enacted a reduction of the corporate income tax rate to four percent from the previous six percent. This rate reduction took effect on January 1, 2022. ASC 740, "Income Taxes," requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Therefore, during the second quarter of 2021, the Registrants revalued state deferred tax liabilities to reflect this change in tax rate. For entities subject to ASC 980, "Accounting for Regulated Entities," such as OG&E, those entities are required to recognize a regulatory liability for the decrease in taxes payable for the change in tax rates that are expected to be returned to customers through future rates and to recognize a regulatory asset for the increase in taxes receivable for the change in tax rates that are expected to be recovered from customers through future rates. The revaluation resulted in a regulatory liability of $97.7 million recorded for OG&E and an income tax benefit of $6.6 million for OGE Energy related to Enable and other operations (holding company) for the year ended December 31, 2021.

10.Common Equity

OGE Energy

Automatic Dividend Reinvestment and Stock Purchase Plan

OGE Energy issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan in 2021. OGE Energy may, from time to time, issue shares under its Automatic Dividend Reinvestment and Stock Purchase Plan or purchase shares traded on the open market. At December 31, 2021, there were 4,774,442 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)	2021		2020		2019
Net income (loss)	$	737.3	$	(173.7)	$	433.6
Average common shares outstanding:
Basic average common shares outstanding	200.1		200.1		200.1
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.2		—		0.6
Diluted average common shares outstanding	200.3		200.1		200.7
Basic earnings (loss) per average common share	$	3.68	$	(0.87)	$	2.17
Diluted earnings (loss) per average common share	$	3.68	$	(0.87)	$	2.16
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. Prior to December 2021, OGE Energy utilized receipts from its equity method investment in Enable to pay dividends to its shareholders. In light of the completed Energy Transfer merger, OGE Energy expects to utilize, in part, cash distributions from Energy Transfer to pay dividends to its shareholders.

Pursuant to the leverage restriction in OGE Energy's revolving credit agreement, OGE Energy 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 $1.6 billion of OGE Energy's retained earnings from being paid out in dividends. Accordingly, approximately $1.4 billion of OGE Energy's retained earnings as of December 31, 2021 are unrestricted for the payment of dividends.

OG&E

There were no new shares of OG&E common stock issued in 2021, 2020 or 2019.

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 also maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $580.9 million of OG&E's retained earnings from being paid out in dividends. Accordingly, approximately $2.5 billion of OG&E's retained earnings as of December 31, 2021 are unrestricted for the payment of dividends.

11.Long-Term Debt

A summary of the Registrants' long-term debt is included in the statements of capitalization. At December 31, 2021, the Registrants were in compliance with all of their debt agreements.

Maturities of OGE Energy's long-term debt during the next five years consist of $1.0 billion in 2023 and $79.4 million in 2025. Maturities of OG&E's long-term debt during the next five years consist of $500.0 million in 2023 and $79.4 million in 2025. All other long-term debt of the Registrants matures after 2026.

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.

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%	-	0.27%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.11%	-	0.33%	Muskogee Industrial Authority, January 1, 2025	32.4
0.11%	-	0.27%	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.

Issuance of Long-Term Debt

In May 2021, OGE Energy issued $500.0 million of 0.703 percent senior notes, and OG&E issued $500.0 million of 0.553 percent senior notes. Each series of notes is due May 26, 2023 but may be redeemed by OGE Energy or OG&E after November 26, 2021 at a price equal to 100 percent of the principal amount of the senior notes being redeemed, plus any accrued and unpaid interest. The proceeds from these issuances were used to repay $900.0 million of the $1.0 billion term loan OGE Energy entered into in March 2021 to help cover the fuel and purchased power costs incurred by OG&E during Winter Storm Uri.

12.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, 2021, OGE Energy had $486.9 million short-term debt as compared to $95.0 million short-term debt at December 31, 2020. At December 31, 2021, OG&E had $101.3 million in advances from OGE Energy compared to $272.0 million in advances to OGE Energy at December 31, 2020.

In March 2021, OGE Energy entered into a $1.0 billion unsecured 364-day term loan agreement and borrowed the full $1.0 billion to help cover the increased fuel and purchased power costs incurred by OG&E during Winter Storm Uri. The term loan contained substantially the same covenants as OGE Energy's revolving credit agreement in place at that time, including various financial ratio covenants. Contemporaneously with the closing of the term loan agreement, in March 2021, OGE Energy made a capital contribution of $530.0 million to OG&E using the term loan proceeds, and OGE Energy also loaned $470.0 million to OG&E pursuant to an intercompany note issued by OG&E to OGE Energy. In May 2021, OG&E repaid the $470.0 million to OGE Energy, and OGE Energy used this repayment and other funds from its issuance of senior notes in May

2021 to repay $900.0 million of the $1.0 billion term loan, as further discussed in Note 11. In December 2021, OGE Energy repaid the remaining $100.0 million outstanding that was borrowed under the term loan agreement.

On December 17, 2021, OGE Energy and OG&E each entered into new $550.0 million unsecured five-year revolving credit facilities to replace existing facilities. Each of these new facilities is scheduled to terminate on December 17, 2026. However, each of OGE Energy and OG&E have the right to request an extension of the revolving credit facility termination date under their respective facility for an additional one-year period, which extension option can be exercised up to two times. All such extension requests are subject to majority lender group approval (and only the commitments of those lenders that consent to such extension (or that agree to replace any non-consenting lender) will be extended for such additional period).

Borrowings under OGE Energy's new facility bear interest at rates equal to either the eurodollar base rate (reserve adjusted, if applicable), plus a margin of 0.80 percent to 1.475 percent, or an alternate base rate, plus a margin of 0.0 percent to 0.475 percent. OGE Energy's new facility has a facility fee that ranges from 0.075 percent to 0.275 percent. Interest rate margins and facility fees are based on OGE Energy's then-current senior unsecured credit ratings. Borrowings under OG&E's new facility shall bear interest at rates equal to either the eurodollar base rate (reserve adjusted, if applicable), plus a margin of 0.69 percent to 1.275 percent, or an alternate base rate, plus a margin of 0.0 percent to 0.275 percent. OG&E's new facility has a facility fee that ranges from 0.06 percent to 0.225 percent. Both OGE Energy's and OG&E's new facilities include customary LIBOR replacement language. Interest rate margins and facility fees for both OGE Energy and OG&E are based on each of their then-current senior unsecured credit ratings.

Each of the facilities contains a mechanism which, subject to approval by the respective borrower, the sustainability structuring agent, and the required lenders, permits a reduction in the applicable margin and/or facility fees if the respective borrower meets certain environmental, social and governance targets.

Each of the facilities provides for issuance of letters of credit, provided that (i) the aggregate outstanding credit exposure shall not exceed the amount of the revolving credit facilities and (ii) the aggregate outstanding stated amount of letters of credit issued under such facility shall not exceed a specified maximum sublimit ($100.0 million for each of OGE Energy and OG&E). Advances under the facilities may be used to refinance existing indebtedness and for working capital and general corporate purposes of the respective borrower and its subsidiaries, including commercial paper liquidity support, letters of credit, acquisitions and distributions.

Each of the facilities is unsecured and, under certain circumstances, may be increased (by up to $150.0 million in each case for OGE Energy and OG&E), to a maximum revolving commitment limit of $700.0 million for each of OGE Energy and OG&E. Advances of revolving loans and letters of credit under the facilities are subject to certain conditions precedent, including the accuracy of certain representations and warranties and the absence of any default or unmatured default.

The following table presents information regarding the Registrants' revolving credit agreements at December 31, 2021.


	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
	(In millions)
OGE Energy (B)	$	550.0	$	486.9	0.36	%	(E)	December 17, 2026
OG&E (C)(D)	550.0		0.4		1.15	%	(E)	December 17, 2026
Total	$	1,100.0	$	487.3	0.36	%

(A)Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2021.

(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)This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.

(D)OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $350.0 million of OGE Energy's revolving credit amount. This agreement has a termination date of December 17, 2026. At December 31, 2021, there were $60.0 million in intercompany borrowings under this agreement.

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

The Registrants' credit facilities each have a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent, as defined in each such facility. The 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.

13.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

It is OGE Energy's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by 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 made a $40.0 million and $20.0 million contribution to its Pension Plan in 2021 and 2020, of which $30.0 million and $10.0 million was attributed to OG&E in 2021 and 2020, respectively. OGE Energy does not expect it will need to make any contributions to the Pension Plan in 2022. Any contribution to the Pension Plan during 2022 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 2021, 2020 and 2019, 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. 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 2021 and 2020 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)	2021		2020		2021		2020		2021		2020		2021		2020
Change in benefit obligation
Beginning obligations	$	654.6	$	616.1	$	7.8	$	10.3	$	484.1	$	462.0	$	3.0	$	6.1
Service cost	11.2		13.2		0.8		0.8		7.7		9.2		—		0.1
Interest cost	13.3		17.0		0.1		0.2		9.7		12.6		—		0.1
Plan settlements	(158.6)		(42.8)		(4.6)		(5.3)		(120.4)		(33.5)		(2.9)		(4.5)
Plan amendments	—		—		1.4		—		—		—		—		—
Plan curtailments	—		—		(0.1)		0.2		—		—		—		—
Special termination benefits	—		7.6		—		—		—		5.1		—		—

Actuarial (gains) losses	(3.5)		57.7		0.5		1.6		(6.0)		41.0		0.4		1.2
Benefits paid	(14.1)		(14.2)		—		—		(11.9)		(12.3)		—		—
Ending obligations	$	502.9	$	654.6	$	5.9	$	7.8	$	363.2	$	484.1	$	0.5	$	3.0

Change in plans' assets
Beginning fair value	$	570.3	$	530.3	$	—	$	—	$	420.3	$	399.1	$	—	$	—
Actual return on plans' assets	48.4		77.0		—		—		35.0		57.0		—		—
Employer contributions	40.0		20.0		4.6		5.3		30.0		10.0		2.9		4.5
Plan settlements	(158.6)		(42.8)		(4.6)		(5.3)		(120.4)		(33.5)		(2.9)		(4.5)

Benefits paid	(14.1)		(14.2)		—		—		(11.9)		(12.3)		—		—
Ending fair value	$	486.0	$	570.3	$	—	$	—	$	353.0	$	420.3	$	—	$	—
Funded status at end of year	$	(16.9)	$	(84.3)	$	(5.9)	$	(7.8)	$	(10.2)	$	(63.8)	$	(0.5)	$	(3.0)
Accumulated postretirement benefit obligation	$	475.2	$	610.8	$	5.4	$	6.9	$	341.0	$	454.7	$	0.4	$	2.9

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. For the year ended December 31, 2020, Pension Plan actuarial losses were primarily due to movement in the discount rate, special termination benefits due to a voluntary retirement program offered by OGE Energy and more retirements and terminations than expected which were expected to accelerate lump sum payments in 2021. These losses were partially offset by gains from lowering the interest crediting rate and plan mortality assumptions.


	OGE Energy				OG&E
	Postretirement Benefit Plans				Postretirement Benefit Plans
December 31 (In millions)	2021		2020		2021		2020
Change in benefit obligation
Beginning obligations	$	144.5	$	136.5	$	109.5	$	104.7
Service cost	0.2		0.2		0.1		0.2
Interest cost	3.4		4.2		2.6		3.2

Plan curtailments	1.9		4.0		—		3.1
Participants' contributions	3.5		3.3		2.6		2.4
Actuarial (gains) losses	(3.7)		7.3		(2.5)		4.5
Benefits paid	(12.5)		(11.0)		(9.9)		(8.6)
Ending obligations	$	137.3	$	144.5	$	102.4	$	109.5

Change in plans' assets
Beginning fair value	$	47.6	$	47.0	$	42.7	$	41.9
Actual return on plans' assets	(0.5)		1.2		(0.5)		1.1
Employer contributions	6.2		7.1		5.0		5.9

Participants' contributions	3.5		3.3		2.6		2.4
Benefits paid	(12.5)		(11.0)		(9.9)		(8.6)
Ending fair value	$	44.3	$	47.6	$	39.9	$	42.7
Funded status at end of year	$	(93.0)	$	(96.9)	$	(62.5)	$	(66.8)

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. Special termination benefits and curtailment loss for the year ended December 31, 2020 are related to a voluntary retirement program offered by OGE Energy in the fourth quarter of 2020. A curtailment gain or loss is required when the expected future services or benefits in a benefit plan are significantly reduced or eliminated.

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 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 Expense in the statements of income.


	OGE Energy												OG&E
	Pension Plan						Restoration of Retirement Income Plan						Pension Plan						Restoration of Retirement Income Plan
Year Ended December 31 (In millions)	2021		2020		2019		2021		2020		2019		2021		2020		2019		2021		2020		2019
Service cost	$	11.2	$	13.2	$	12.9	$	0.8	$	0.8	$	0.5	$	7.7	$	9.2	$	9.0	$	—	$	0.1	$	0.2
Interest cost	13.3		17.0		20.7		0.1		0.2		0.4		9.7		12.6		15.6		—		0.1		0.2
Expected return on plan assets	(34.1)		(37.6)		(36.1)		—		—		—		(24.7)		(27.9)		(27.6)		—		—		—

Amortization of net loss	9.4		17.1		17.3		0.2		0.5		0.5		7.0		12.1		12.9		0.1		0.4		0.3
Plan curtailments	—		—		—		—		0.2		—		—		—		—		—		—		—
Special termination benefits	—		7.6		—		—		—		—		—		5.1		—		—		—		—
Amortization of unrecognized prior service cost (A)	—		—		—		0.1		—		—		—		—		—		—		—		—
Settlement cost	41.3		14.1		27.6		2.1		2.7		0.5		33.1		11.4		16.4		1.6		2.4		0.5
Total net periodic benefit cost	41.1		31.4		42.4		3.3		4.4		1.9		32.8		22.5		26.3		1.7		3.0		1.2
Less: Amount paid by unconsolidated affiliates (B)	(0.2)		2.0		2.9		0.1		0.1		0.1
Plus: Amount allocated from OGE Energy (B)													6.5		5.9		4.5		1.5		1.3		0.5
Net periodic benefit cost	$	41.3	$	29.4	$	39.5	$	3.2	$	4.3	$	1.8	$	39.3	$	28.4	$	30.8	$	3.2	$	4.3	$	1.7

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

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

In conjunction with the net periodic benefit cost amounts recognized, as presented in the table above, for the Pension and Restoration of Retirement Income Plans in 2021, 2020 and 2019, the Registrants recognized the following:



Year Ended December 31 (In millions)	2021		2020		2019
Increase of regulatory asset related to pension expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	23.0	$	13.8	$	16.1
Deferral of pension expense related to pension settlement, curtailment and special termination benefits charges included in the above line item:
Oklahoma jurisdiction (A)	$	37.9	$	21.6	$	17.9
Arkansas jurisdiction (A)	$	3.5	$	2.0	$	1.7

(A)Included in the pension regulatory asset or liability 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)	2021		2020		2019		2021		2020		2019
Service cost	$	0.2	$	0.2	$	0.2	$	0.1	$	0.2	$	0.2
Interest cost	3.4		4.2		5.6		2.6		3.2		4.3
Expected return on plan assets	(1.8)		(1.8)		(1.9)		(1.7)		(1.7)		(1.7)
Amortization of net loss	2.8		2.0		2.0		2.7		2.1		2.1
Plan curtailments	—		1.5		—		—		1.3		—
Amortization of unrecognized prior service cost (A)	(6.9)		(8.4)		(8.4)		(5.0)		(6.1)		(6.1)
Total net periodic benefit income	(2.3)		(2.3)		(2.5)		(1.3)		(1.0)		(1.2)
Less: Amount paid by unconsolidated affiliates (B)	(0.5)		(0.7)		(0.6)
Plus: Amount allocated from OGE Energy (B)							(0.5)		(0.5)		(0.6)
Net periodic benefit income	$	(1.8)	$	(1.6)	$	(1.9)	$	(1.8)	$	(1.5)	$	(1.8)

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

In conjunction with the net periodic benefit income amounts recognized, as presented in the table above, for the postretirement benefit plans in 2021, 2020 and 2019, the Registrants recognized the following:


Year Ended December 31 (In millions)	2021		2020		2019
Increase of regulatory liability related to postretirement expense to maintain allowed recoverable amount in Oklahoma jurisdiction (A)	$	0.4	$	0.2	$	1.0
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 2021, 2020 and 2019.


	OGE Energy						OG&E
(In millions)	2021		2020		2019		2021		2020		2019
Capitalized portion of net periodic pension benefit cost	$	3.4	$	3.8	$	3.6	$	2.9	$	3.1	$	3.0
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	2021		2020		2019		2021		2020		2019
Assumptions to determine benefit obligations:
Discount rate	2.75	%	2.30	%	3.15	%	2.80	%	2.45	%	3.25	%
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




Assumptions to determine net periodic benefit cost:
Discount rate	2.63	%	2.88	%	3.63	%	2.45	%	3.25	%	4.30	%
Expected return on plan assets	7.00	%	7.50	%	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	%	4.00	%	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 2021 and 2020, 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 due to recent returns on OGE Energy's long-term investment portfolio. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans' current and expected asset allocation.

The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 6.50 percent in 2022 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	l Maximize risk-adjusted performance while providing long bond exposure managed according to the manager's forecast on interest rates. l All invested assets must reach at or above Baa3 or BBB- investment grade. l 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	l Maximize risk-adjusted performance. l At least 75 percent of invested assets much reach at or above Baaa3 or BBB- investment grade. l Limited five percent exposure to any single issuer, except the U.S. Government or affiliates. l May invest up to 10 percent of the market value in convertible bonds as long as quality guidelines are met. l 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	l Focus on replicating the performance of the S&P 500 Index.


Mid-Cap Equity (B)(C)	Russell Midcap Index Russell Midcap Value Index	l Focus on undervalued stocks expected to earn average return and pay out higher than average dividends. l Invest in companies with market capitalizations lower than average company on public exchanges: l Price/earnings ratio at or near referenced index; l Small dividend yield and return on equity at or near referenced index; and l Earnings per share growth rate at or near referenced index.

Small-Cap Equity (B)(C)	Russell 2000 Index Russell 2000 Value Index

International Equity (D)	Morgan Stanley Capital International ACWI ex-U.S.	l Invest in non-dollar denominated equity securities. l 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, 2021 and 2020. There were no Level 3 investments held by the Pension Plan at December 31, 2021 and 2020.


(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.


(In millions)	December 31, 2020		Level 1		Level 2		Net Asset Value (A)

Common stocks	$	252.3	$	252.3	$	—	$	—


U.S. Treasury notes and bonds (B)	134.3		134.3		—		—
Mortgage- and asset-backed securities	29.3		—		29.3		—


Corporate fixed income and other securities	116.6		—		116.6		—

Commingled fund (C)	25.4		—		—		25.4
Foreign government bonds	4.6		—		4.6		—
U.S. municipal bonds	1.8		—		1.8		—

Money market fund	8.8		—		—		8.8

Mutual fund	9.2		9.2		—		—
Preferred stocks	0.6		0.6		—		—
U.S. Treasury Futures:


Cash collateral	0.7		0.7		—		—
Forward contracts:
Receivable (foreign currency)	0.1		—		0.1		—

Total Pension Plan investments	583.7		$	397.1	$	152.4	$	34.2
Receivable from broker for securities sold	0.2
Interest and dividends receivable	2.2
Payable to broker for securities purchased	(15.8)
Total OGE Energy Pension Plan assets	$	570.3
Pension Plan investments attributable to affiliates	(150.0)
Total OG&E Pension Plan assets	$	420.3

(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
2022	$	95.3	$	38.8
2023	$	37.0	$	30.7
2024	$	38.4	$	30.6
2025	$	36.7	$	28.7
2026	$	35.2	$	28.3
2027-2031	$	167.4	$	126.6

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, 2021 and 2020. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2021 and 2020.


(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


(In millions)	December 31, 2020		Level 1		Level 3
Group retiree medical insurance contract	$	33.4	$	—	$	33.4

Mutual funds	14.2		14.2		—


Total OGE Energy plan investments	$	47.6	$	14.2	$	33.4
Plan investments attributable to affiliates	(4.9)
Total OG&E plan investments	$	42.7

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

100

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)	2021
Group retiree medical insurance contract:
Beginning balance	$	33.4
Claims paid	(4.9)
Net unrealized losses related to instruments held at the reporting date	(1.1)
Investment fees	(0.1)
Realized losses	(0.1)
Interest income	0.7
Dividend income	0.2
Ending balance	$	28.1

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
2022	$	12.5	$	9.6
2023	$	12.2	$	9.3
2024	$	10.6	$	8.0
2025	$	10.1	$	7.6
2026	$	9.7	$	7.2
After 2026	$	40.3	$	30.2

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 $2.0 million and $2.2 million at December 31, 2021 and 2020, respectively, of which $1.5 million and $1.8 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 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have reached age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k)

101

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 $15.4 million, $18.2 million and $14.4 million in 2021, 2020 and 2019, respectively, to the 401(k) Plan, of which $12.0 million, $14.3 million and $11.0 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 2021, 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.

102

14.Report of Business Segments

OGE Energy reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy and (ii) natural gas midstream operations segment. 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. Subsequent to December 2, 2021, OGE Energy's natural gas midstream operations segment includes its investment in Energy Transfer's equity securities and 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, 2021, 2020 and 2019.


2021	Electric Utility		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 Utility		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, as further discussed in Notes 5 and 7.

103


2019	Electric Utility		Natural Gas Midstream Operations		Other Operations		Eliminations		Total
(In millions)
Operating revenues	$	2,231.6	$	—	$	—	$	—	$	2,231.6
Fuel, purchased power and direct transmission expense	786.9		—		—		—		786.9
Other operation and maintenance	492.5		2.8		(3.5)		—		491.8
Depreciation and amortization	355.0		—		—		—		355.0
Taxes other than income	89.5		0.4		3.7		—		93.6
Operating income (loss)	507.7		(3.2)		(0.2)		—		504.3
Equity in earnings of unconsolidated affiliates	—		113.9		—		—		113.9
Other income (expense)	3.1		(8.6)		2.2		(3.6)		(6.9)
Interest expense	140.5		—		11.0		(3.6)		147.9
Income tax expense (benefit)	20.1		20.7		(11.0)		—		29.8
Net income	$	350.2	$	81.4	$	2.0	$	—	$	433.6


Investment in unconsolidated affiliates	$	—	$	1,132.9	$	—	$	—	$	1,132.9
Total assets	$	10,076.6	$	1,135.4	$	107.0	$	(294.7)	$	11,024.3
Capital expenditures	$	635.5	$	—	$	—	$	—	$	635.5

15.Commitments and Contingencies

Public Utility Regulatory Policy Act of 1978

OG&E had QF contracts with AES-Shady Point, Inc. and Oklahoma Cogeneration LLC, which expired in January and August 2019, respectively. For the 320 MW AES-Shady Point, Inc. QF contract and the 120 MW Oklahoma Cogeneration LLC QF contract, OG&E purchased 100 percent of the electricity generated by the qualified cogeneration facilities.

In 2019, OG&E acquired the plants from AES-Shady Point, Inc. and Oklahoma Cogeneration LLC. Previous to such acquisitions, OG&E made total payments to cogenerators of $14.7 million, of which $7.4 million represented capacity payments. All payments for purchased power, including cogeneration, are included in the Registrants' statements of income as Fuel, Purchased Power and Direct Transmission Expense.

Purchase Obligations and Commitments

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


(In millions)	2022		2023		2024		2025		2026		Total
Purchase obligations and commitments:
Minimum purchase commitments	$	97.7	$	50.4	$	31.2	$	24.6	$	24.6	$	228.5
Expected wind purchase commitments	55.6		56.0		56.6		56.9		57.4		282.5
Long-term service agreement commitments	2.7		2.6		15.0		24.4		9.7		54.4


Total purchase obligations and commitments	$	156.0	$	109.0	$	102.8	$	105.9	$	91.7	$	565.4

OG&E Minimum Purchase Commitments

OG&E has coal contracts for purchases through December 31, 2022, whereby OG&E has the right but not the obligation to purchase a defined quantity of coal. 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

104

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 May 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 Purchase Commitments

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

Company

Location

Original Term of Contract

Expiration of Contract

MWs

CPV Keenan

Woodward County, OK

20 years

2030

152.0

Edison Mission Energy

Dewey County, OK

20 years

2031

130.0

NextEra Energy

Blackwell, OK

20 years

2032

60.0

The following table presents a summary of OG&E's wind power purchases for the years ended December 31, 2021, 2020 and 2019.


Year Ended December 31 (In millions)	2021		2020		2019
CPV Keenan	$	27.3	$	27.5	$	27.2
Edison Mission Energy	21.7		22.8		23.1
NextEra Energy	6.8		7.0		7.4

Total wind power purchased	$	55.8	$	57.3	$	57.7

OG&E Long-Term Service Agreement Commitments

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

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

105

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; oral arguments before the Supreme Court are scheduled for February 28, 2022. The ultimate timing and impact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO2 emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect the 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.

16.Rate Matters and Regulation

Regulation and Rates

Completed Regulatory Matters

APSC Proceedings

Arkansas 2020 Formula Rate Plan Filing

In October 2020, OG&E filed its third evaluation report under its Formula Rate Plan, and on January 28, 2021, OG&E entered into a non-unanimous settlement agreement with the APSC General Staff and the Office of the Arkansas Attorney General. The only non-signatory to the settlement agreement agreed not to oppose the settlement. The settlement agreement included a revenue increase of $6.7 million, which is the maximum amount statutorily allowed in this filing. Additionally, the settling parties did not object to OG&E's request for a finding that the Arkansas Series II grid modernization projects included in this filing are prudent in cost. On March 9, 2021, the APSC issued a final order approving the non-unanimous settlement agreement, and new rates became effective April 1, 2021.

Disconnection Procedures Related to COVID-19

In September 2020, the APSC invited comments from all jurisdictional utilities and any other interested stakeholders on specific questions related to whether a moratorium on service terminations should be lifted and if so, how the resumption of

106

disconnections should occur. The APSC also ordered utilities to submit a detailed "Transitional Plan" outlining how utilities proposed to reinstate routine service disconnection activities and collection of past due amounts once the moratorium was lifted. OG&E submitted its proposed Transitional Plan in October 2020.

On February 8, 2021, the APSC announced a target date of May 3, 2021 to lift the moratorium on disconnections and specified certain conditions and requirements that utilities must meet before disconnections may resume. Such requirements include, among other things, immediate communication to customers, notice periods for disconnections and deferred payment arrangements. On March 26, 2021, the APSC confirmed the lifting of the moratorium on disconnections on May 3, 2021 and directed utilities to take specific steps prior to resuming disconnections. OG&E resumed disconnections on May 3, 2021.

Arkansas Approval to Construct Out of State Generation

On March 3, 2021, OG&E filed an application with the APSC to request approval to construct a 5 MW solar facility in Oklahoma. The APSC issued an order on April 6, 2021, finding OG&E's application in the public interest, conditioned on Arkansas customers being held harmless and not subject to cost recovery associated with the project. OG&E expects the costs associated with constructing this solar facility to be fully recovered in Oklahoma.

Integrated Resource Plan

OG&E has conducted technical conferences for stakeholder engagement on its draft triennial system-wide IRP and, in October 2021, issued its final 2021 IRP to the APSC. This 2021 IRP identified system-wide, cumulative capacity needs of 145, 183, 417 and 514 MWs in 2023, 2024, 2025 and 2026, respectively. OG&E has issued a request for proposals to identify options to fill the solar capacity needs identified within the 2021 IRP.

OCC Proceedings

Oklahoma Grid Enhancement Plan

In February 2020, OG&E filed an application with the OCC for approval of a mechanism that allows for interim recovery of the costs associated with its grid enhancement plan. The plan includes approximately $800.0 million of strategic, data-driven investments, over five years, covering grid resiliency, grid automation, communication systems and technology platforms and applications. In November 2020, the OCC issued a final order approving a Joint Stipulation and Settlement Agreement that allows for interim recovery of OG&E's costs associated with its grid enhancement plan. The approved agreement included the following key terms: (i) cost recovery through a rider mechanism will be limited to projects placed in service in 2020 and 2021, capped at a revenue requirement of $7.0 million annually and only include communication, automation and technology systems projects; (ii) no operation and maintenance expense will be included in the rider mechanism; (iii) the rider mechanism will terminate by the issuance of a final order in OG&E's next general rate review or October 31, 2022, whichever occurs first; (iv) the rider mechanism rate of return will be capped at OG&E's current cost of capital; and (v) all cost recovery is subject to true-up and refund in OG&E's next general rate review. The rider mechanism became effective on February 1, 2021.

OG&E reports to the OCC new projects completed each quarter, and the cost recovery factor is adjusted to include those projects after a stakeholder review. OG&E has submitted its report for projects that were placed in service through December 31, 2021. The cost recovery factors that include those projects will become effective on March 1, 2022.

Any capital investment falling outside the criteria of the rider mechanism will be included in OG&E's next general rate review for recovery.

Integrated Resource Plan

OG&E has conducted technical conferences for stakeholder engagement on its draft triennial system-wide IRP and, in October 2021, issued its final 2021 IRP to the OCC. This 2021 IRP identified system-wide, cumulative capacity needs of 145, 183, 417 and 514 MWs in 2023, 2024, 2025 and 2026, respectively. OG&E has issued a request for proposals to identify options to fill the solar capacity needs identified within the 2021 IRP.

Winter Storm Uri

107

OCC outlining a two-step approach for regulatory treatment for the fuel and purchased power costs associated with Winter Storm Uri. The steps included: (i) an intra-year fuel clause increase to be effective April 1, 2021; and (ii) a request for regulatory asset treatment at OG&E's weighted average cost of capital for the remaining fuel and purchased power costs. On March 18, 2021, the OCC approved OG&E's filing to establish a regulatory asset. The approval allowed OG&E to create a regulatory asset for all deferred costs with an initial carrying charge based on the effective cost of the debt financing, until such time where the prudency of this event is evaluated, the amortization period is decided on and a long-term carry cost is established.

In April 2021, Oklahoma enacted legislation to allow for the securitization of costs incurred during Winter Storm Uri. The new statute authorizes the OCC to issue a financing order for the issuance of securitization bonds after consideration of certain factors, including but not limited to, mitigated impacts and savings for customers through the use of ratepayer-backed securitization bonds as compared to traditional utility financing. The OCC must issue a financing order within 180 days after receiving all necessary information required by the statute. Under the statute, the ODFA is responsible for issuing the securitization bonds within two years from the date of the financing order. Carrying costs will be included at a rate and time determined by the OCC and continue until the bonds are issued.

On April 26, 2021, OG&E filed an application pursuant to the Act seeking OCC approval to securitize its costs related to Winter Storm Uri and to receive an interim carrying charge on OG&E's regulatory asset balance at its weighted-average cost of capital for the period between April 2022 and the date when the securitized bonds are issued. On October 8, 2021, OG&E filed a settlement agreement between OG&E, the Public Utility Division Staff of the OCC, the Oklahoma Industrial Energy Consumers, the OG&E Shareholders Association and Walmart Inc. The settlement agreement was subject to approval by the OCC. The settling parties agreed the OCC should issue a financing order authorizing the securitization of $760.0 million, which includes estimated finance costs and is subject to change for carrying costs, any updates from the SPP settlement process and actual securitization issuance costs. The settling parties agree that OG&E's total extreme purchase costs (for natural gas and wholesale energy purchases) are currently estimated to be $748.9 million, of which it is agreed that $739.1 million should be deemed prudent. The OCC approved the settlement agreement in a final financing order on December 16, 2021. The ODFA has requested the Oklahoma Supreme Court to certify the proposed securitization bonds. OG&E is currently awaiting bond certification from the Oklahoma Supreme Court, which it expects to occur in the second quarter of 2022. OG&E is working with the ODFA to issue bonds consistent with the OCC's order. The securitization process is expected to be completed in mid-2022.

2020 Oklahoma Fuel Prudency

On June 28, 2021, the Public Utility Division Staff filed their application initiating the review of the 2020 fuel adjustment clause and prudence review. On December 28, 2021, the OCC issued a final order finding OG&E's 2020 electric generation, purchased power and fuel procurement practices, policies, judgments and fuel purchase costs and expenses for 2020 were fair, just and reasonable.

Demand Program Portfolio Filing

Pursuant to OCC rules, OG&E is required to propose, implement and administer a portfolio of demand programs once every three years. On July 8, 2021, OG&E filed its proposed Demand Program Three Year Portfolio for the 2022 through 2024 program cycle, and the proposed program was approved by the OCC on February 1, 2022.

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 the SPP Open Access Transmission Tariff, costs of participant-funded, or "sponsored," transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP Open Access Transmission Tariff required the SPP to charge for these upgrades beginning in 2008, but the SPP had not been charging its customers for these upgrades due to information system limitations. However, the SPP had informed participants in

108

the market that these charges would be forthcoming. In July 2016, the FERC granted the SPP's request to recover the charges not billed since 2008. The SPP subsequently billed OG&E for these charges and credited OG&E related to transmission upgrades that OG&E had sponsored, which resulted in OG&E being a net receiver of sponsored upgrade credits. The majority of these net credits were refunded to customers through OG&E's various rate riders that include SPP activity with the remaining amounts retained by OG&E.

Several companies that were net payers of Z2 charges sought rehearing of the FERC's July 2016 order; however, in November 2017, the FERC denied the rehearing requests. In January 2018, one of the impacted companies appealed the FERC's decision to the U.S. Court of Appeals for the District of Columbia Circuit. In July 2018, that court granted a motion requested by the FERC that the case be remanded back to the FERC for further examination and proceedings. In February 2019, the FERC reversed its July 2016 order and November 2017 rehearing denial, ruled that the SPP violated its tariff to charge for the 2008 through 2015 period in 2016, held that the SPP tariff provision that prohibited those charges could not be waived and 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 with the FERC, and in May 2019, OG&E filed a FERC 206 complaint against the SPP, alleging that the SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement and of the applicable tariff. OG&E's filing requested that the FERC rule that the SPP is not entitled to seek refunds or in any other way seek to unwind the revenue credit payments it had paid to OG&E pursuant to the Sponsored Upgrade Agreement. The SPP's response to OG&E's filing agreed that OG&E should be entitled to keep its Z2 payments and argued that the SPP should not be held responsible for those payments if refunds are ordered. Further, the SPP has requested the FERC to negotiate a global settlement with all impacted parties, including other project sponsors who, like OG&E, have also filed complaints at FERC contending that the payments they have received cannot properly be unwound.

In February 2020, the FERC denied OG&E's request for rehearing of its February 2019 order, denying the waiver and ruling that the SPP must seek refunds from project sponsors for Z2 payments for the 2008 through 2015 period and pay them back to transmission owners. The FERC also denied the SPP's request for a stay and for institution of settlement procedures. The FERC stated it would not institute settlement procedures unless parties on both sides of the matter requested them. The FERC did not rule on OG&E's complaint or the complaints of other project sponsors, or consider the SPP's refund plan. The FERC thus has not set any date for payment of refunds. In March 2020, OG&E petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the FERC's order denying the waiver and requiring refunds. The court issued a decision on August 27, 2021, denying review and holding that the SPP was prohibited by the filed rate doctrine from imposing Z2 charges during the 2008 through 2015 historical period. The court further held that the FERC reasonably exercised its remedial authority to order the SPP to refund the retroactive upgrade charge. The court did not direct a time frame or procedures for the SPP to implement refunds. OG&E and the SPP filed a petition for rehearing of the court's decision, which was denied on October 29, 2021. The court returned the matter to the FERC for action in accordance with its opinion on November 8, 2021.

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 it made with the FERC while the appeal was pending 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 an update 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. It also urged that all pending complaint proceedings, including four complaints against the SPP, be resolved before the refund process is ordered to begin. 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, 2021, the Registrants have reserved $13.0 million plus estimated interest for a potential refund.

In January 2020, the FERC acted on 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, and rejected the proposal to the extent it would limit recovery to the amount of the upgrade sponsor's directly assigned upgrade costs with interest. The SPP resubmitted a proposal in April 2020 without this limited recovery, and with the alternative rate mechanism, and the FERC approved it in June 2020, effective July 1, 2020. No party sought rehearing of the order, and it is now final. This order 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, which includes the $13.0 million at issue in OG&E's appeal as discussed above, will continue to do so.

109

Incentive Adders for Transmission Rates

The FERC issued a NOPR on March 20, 2020, and issued a supplemental NOPR on April 15, 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. OG&E is currently evaluating the potential impacts of this proposed rule. 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

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 for Authority to Establish Special Regulatory Treatment within the Energy Cost Recovery Rider to Defer Extraordinary Fuel Costs Incurred Due to Winter Storm Uri. More specifically, OG&E's motion sought approval to defer, amortize and recover the extraordinary fuel costs over a ten-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, which is currently 0.8 percent, over a period of ten years beginning with the first billing cycle of May 2021. Recovery is subject to a true-up after the APSC determines the appropriate allocation, length of recovery and carrying charge. On May 4, 2021, OG&E filed testimony further supporting its 10-year amortization period and a carrying charge of OG&E's pre-tax rate of return of 6.60 percent.

In April 2021, Arkansas enacted legislation to amend its storm recovery securitization statute to allow for both electric and gas utilities to recover through securitization extraordinary natural gas, fuel and purchased power costs caused by storms. The amended statute authorizes the APSC to issue a financing order for the issuance of securitization bonds upon a finding it is reasonably expected to lower overall costs or mitigate rate impacts as compared with traditional utility financing. Upon the initiation of a securitization application, the APSC has 135 days to issue an order. The requesting utility has two years from the date of the financing order to issue the securitization bonds. The amended statute allows carrying costs at a utility's weighted average cost of capital from the date of when the costs were incurred until the date when bonds are ultimately issued.

On May 20, 2021, OG&E filed a motion for suspension of procedural schedule, which the APSC approved, to investigate and evaluate the potential securitization recovery of the Arkansas jurisdictional portion of the Winter Storm Uri costs. OG&E intends to apply for securitization in early 2022 if it is deemed to strike the right balance between protecting the credit strength of OG&E and providing customer savings. As of December 31, 2021, OG&E has deferred $88.9 million to a regulatory asset, as indicated in Note 1.

Arkansas 2021 Formula Rate Plan Filing

On October 1, 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 includes an annual electric revenue increase of $4.2 million. The only non-signatory to the settlement agreement has agreed not to oppose the settlement. The settlement agreement is subject to approval by the APSC. A final order is expected from the APSC in March 2022, and new rates will be effective April 1, 2022. On October 1, 2021, OG&E also filed a request to extend its Formula Rate Plan Rider for an additional five years. A hearing on the merits was held on February 23, 2022, and OG&E expects a decision from the APSC in April 2022.

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

110

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 $28.9 million to $39.3 million for all five cases, of which $2.9 million to $4.5 million would apply to the three cases where the OCC ruled in favor of the electric cooperatives.

2021 Oklahoma General Rate Review

On December 30, 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 includes recovery of $1.2 billion of capital investment since the last general rate review. A hearing on the merits is expected to be held toward the end of the second quarter of 2022.

111

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, 2021 and 2020, 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, 2021, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "consolidated financial statements"). In our opinion, based on our audits and the report of other auditors, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 and $91.8 million in 2019. 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 and 2019, 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, 2021, 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 23, 2022, 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.

112

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 23, 2022

113

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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

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.

114

Regulatory Assets and Liabilities


Description of the Matter			As discussed in Note 1 to the financial statements, the Company 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. The Company 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 23, 2022

115

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).

116

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, 2021. 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, 2021, 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

117

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, 2021, 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, 2021, 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, 2021 and 2020, 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, 2021, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 23, 2022 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 23, 2022

118

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, 2021, 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, 2021, 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, 2021 and 2020, 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, 2021, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 23, 2022 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 23, 2022

119

Item 9B. Other Information.

On February 23, 2022, the Board of Directors approved and adopted the OGE Energy Corp. 2022 Annual Executive Incentive Compensation Plan (the "Annual Plan"). The Annual Plan replaces the OGE Energy Corp. 2013 Annual Incentive Compensation Plan (the "current annual plan"). The Annual Plan is very similar to the current annual plan, with the major difference being the elimination of certain provisions that were intended to comply with the "performance-based compensation" exception under Section 162(m) of the Code. That exception was eliminated by the 2017 Tax Cuts and Jobs Act.

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 10.13 to this 2021 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 2022 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 4, 2022. 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 2022 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 4, 2022. 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 2022 Annual Meeting of Shareholders, which is expected to be filed

120

with the Securities and Exchange Commission on or about April 4, 2022. 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 2022 Annual Meeting of Shareholders, which is expected to be filed with the Securities and Exchange Commission on or about April 4, 2022. 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	2021		2020
Integrated audit of OGE Energy and its subsidiaries financial statements and internal control over financial reporting	$	1,209,000	$	1,136,800
Services in support of debt and stock offerings	65,000		65,000
Other (A)	361,000		325,000
Total audit fees (B)	1,635,000		1,526,800
Employee benefit plan audits	133,000		128,000

Total audit-related fees	133,000		128,000
Assistance with examinations and other return issues	237,481		65,948
Review of federal and state tax returns	32,000		32,000
Total tax preparation and compliance fees	269,481		97,948
Total tax fees	269,481		97,948
Total fees	$	2,037,481	$	1,752,748

(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 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 2021, this amount includes estimated billings for the completion of the 2021 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 2021 and 2020 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

121

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 2021, 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.

122

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, 2021, 2020 and 2019

•Consolidated Statements of Comprehensive Income for the years ended December 31, 2021, 2020 and 2019

•Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019

•Consolidated Balance Sheets at December 31, 2021 and 2020

•Consolidated Statements of Capitalization at December 31, 2021 and 2020

•Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2021, 2020 and 2019

•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, 2021, 2020 and 2019

•Statements of Comprehensive Income for the years ended December 31, 2021, 2020 and 2019

•Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019

•Balance Sheets at December 31, 2021 and 2020

•Statements of Capitalization at December 31, 2021 and 2020

•Statements of Changes in Stockholder's Equity for the years ended December 31, 2021, 2020 and 2019

•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 years ending December 31, 2020 and 2019 required pursuant to Rule 3-09 of Regulation S-X are filed as Exhibit 99.01.

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 99.01. 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 99.02.

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.

123

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 4.29 to OG&E's Registration Statement No. 33-61821 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

124


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	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
4.23	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
4.24	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
4.25	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
4.26+	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

125


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 20 22 Annual Executive Incentive Compensation Plan.	X	X









10.14*	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
10.15*	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
10.16*	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
10.17	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

10.18*	Employment Arrangement between OGE Energy and W. Bryan Buckler, OGE Energy's and OG&E's Chief Financial Office r (Filed as Exhibit 10.2 7 to OGE Energy's Form 10-K for the year ended December 31, 2020 (File No. 1-12579) and incorporated by reference herein ).	X	X






10.19	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
10.20	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
10.21	Registration Rights Agreement dated as of December 2, 2021 by and among Energy Transfer LP, OGE Energy Corp., and CenterPoint Energy Inc. (Filed as Exhibit 10.01 to OGE Energy's Form 8-K filed December 3, 2021 (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 99.01 .	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

126


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+	Audited F inancial Statements of Enable Midstream Partners, LP as of and for the three years ended December 31, 2020 .	X


99.02+	Financial Statements of Enable Midstream Partners, LP as of and for the nine months ended September 30, 2021 (unaudited).	X
99.03	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
99.04	Copy of the Settlement Agreement filed with the OCC on May 24, 2019. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed May 30, 2019 (File No. 1-12579) and incorporated by reference herein).	X	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.

127

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, 2019
Reserve for Uncollectible Accounts	$	1.7	$	2.2	$	2.4	$	1.5
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

(A)Uncollectible accounts receivable written off, net of recoveries.

Item 16. Form 10-K Summary.

None.

128

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 23rd, 2022.


			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 23, 2022

/s/ W. Bryan Buckler
W. Bryan Buckler	Principal Financial Officer;	February 23, 2022

/s/ Sarah R. Stafford
Sarah R. Stafford	Principal Accounting Officer.	February 23, 2022

Frank A. Bozich	Director;

Peter D. Clarke	Director;
Luke R. Corbett	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 23, 2022

129

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 23, 2022

/s/ W. Bryan Buckler
W. Bryan Buckler	Principal Financial Officer;	February 23, 2022

/s/ Sarah R. Stafford
Sarah R. Stafford	Principal Accounting Officer.	February 23, 2022

Frank A. Bozich	Director;

Peter D. Clarke	Director;
Luke R. Corbett	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 23, 2022

130

Document

Exhibit 4.26

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 200,201,818 shares were outstanding on January 31, 2022. We are also authorized to issue 5,000,000 shares of preferred stock, par value $0.01 per share. No shares of preferred stock are currently outstanding. Our common stock is our only security registered under Section 12 of the Securities Exchange Act of 1934.

Without shareholder approval, we may issue preferred stock in the future in such series as may be designated by our board of directors. In creating any such series, our board of directors has the authority to fix the rights and preferences of each series with respect to, among other things, the dividend rate, redemption provisions, liquidation preferences, sinking fund provisions, conversion rights and voting rights. The terms of any series of preferred stock that we may issue in the future may provide the holders of such preferred stock with rights that are senior to the rights of the holders of our common stock.

Dividend Rights

Before we can pay any dividends on our common stock, the holders of our preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. Currently, there are no shares of our preferred stock outstanding. Because we are a holding company and conduct all of our operations through our subsidiary and through our investment in Energy Transfer, LP’s (“Energy Transfer”) equity securities, our cash flow and ability to pay dividends will be dependent on the earnings and cash flows of our subsidiary and Energy Transfer and the distribution or other payment of those earnings to us in the form of dividends or distributions, or in the form of repayments of loans or advances to us. We expect to derive principally all of the funds required by us to enable us to pay dividends on our common stock from dividends paid by Oklahoma Gas and Electric Company (“OG&E”), on OG&E's common stock, and from distributions paid by OGE Holdings on its interest in Energy Transfer. Our ability to receive dividends on OG&E’s common stock is subject to the prior rights of the holders of any OG&E preferred stock that may be outstanding, any covenants of OG&E's certificate of incorporation and OG&E's debt instruments limiting the ability of OG&E to pay dividends and the ability of public utility commissions that regulate OG&E to effectively restrict the payment of dividends by OG&E. Our ability to receive distributions from Energy Transfer through our interest in OGE Holdings is dependent upon the cash flow of Energy Transfer and is subject to the prior rights of the holders of any Energy Transfer preferred units and any covenants of Energy Transfer’s debt instruments limiting the ability of Energy Transfer to pay distributions.

Voting Rights

Each holder of common stock is entitled to one vote per share upon all matters upon which shareowners have the right to vote and generally will vote together as one class. Our board of directors has the authority to fix conversion and voting rights for any new series of preferred stock (including the right to elect directors upon a failure to pay dividends), provided that no share of preferred stock can have more than one vote per share.

Our Restated Certificate of Incorporation also contains “fair price” provisions, which require the approval by the holders of at least 80 percent of the voting power of our outstanding voting stock as a condition for mergers,

consolidations, sales of substantial assets, issuances of capital stock and certain other business combinations and transactions involving us and any substantial (10 percent or more) holder of our voting stock unless the transaction is either approved by a majority of the members of our board of directors who are unaffiliated with the substantial holder or specified minimum price and procedural requirements are met. The provisions summarized in the foregoing sentence may be amended only by the approval of the holders of at least 80 percent of the voting power of our outstanding voting stock. Our voting stock consists of all outstanding shares entitled to vote generally in the election of directors and currently consists of our common stock.

Our voting stock does not have cumulative voting rights for the election of directors. Our Restated Certificate of Incorporation and By- Laws currently contain provisions stating that: (1) directors may be removed 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.

Document

Exhibit 10.10

OGE Energy Corp.

Director Compensation

Compensation of non-management directors of OGE Energy Corp. ("OGE Energy") in 2021 included an annual retainer fee of $240,000, of which $105,000 was payable in cash in quarterly installments and $135,000 was deposited in the director's account under OGE Energy's Deferred Compensation Plan and converted to 3,744.8 common stock units based on the closing price of OGE Energy's Common Stock on December 7, 2021. In 2021, 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 2021 received an additional $30,000 cash retainer in 2021. The chair of each of the Compensation, Nominating, Corporate Governance and Stewardship and Audit Committees that served in 2021 received an additional $15,000 annual cash retainer in 2021. 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 2021.

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 2021 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 2021, 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 November 30, 2021, the Compensation Committee met to consider director compensation. At that meeting, the annual cash retainer was increased from $105,000 in 2021 to $110,000 for 2022 and the annual equity retainer, noted above, credited on December 7, 2021 was increased from $130,000 to $135,000.

Document

Exhibit 10.11

OGE Energy Corp.

Executive Officer Compensation

Executive Compensation

In November 2021, 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 2022. In February 2022, the Compensation Committee took action setting executives' target amounts of long-term compensation awards for 2022. 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 2022 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 2022 for the OGE Energy officers who are expected to be named in the Summary Compensation Table in OGE Energy's 2022 Proxy Statement are listed in the table below.


Executive Officer			2022 Base Salary
Sean Trauschke, Chairman, President and Chief Executive Officer			$1,103,135
W. Bryan Buckler, Chief Financial Officer			$466,400
William H. Sultemeier, General Counsel and Chief Compliance Officer			$473,800
Donnie O. Jones, Vice President - Utility Operations of OG&E			$404,700
Cristina F. McQuistion, Vice President - Corporate Responsibility and Stewardship			$334,750

Establishment of 2022 Annual Incentive Awards

As stated above, at its November 2021 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 2022 corporate goals to receive from 0 percent to 150 percent of such targeted amount. For 2022, the targeted amount ranged from 45 percent to 110 percent of the approved 2022 base salary for the executive officers in the above table.

Establishment of Long-Term Awards

At its February 2022 meeting, the Compensation Committee approved the level of target long-term incentive awards, expressed as a percentage of salary. For 2022, the targeted amount ranged from 75 percent to 360 percent of the approved 2022 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 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attained age 50 before the close of a year are allowed to

make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof; (ii) an after-tax Roth contribution; or (iii) a contribution made on a non-Roth after-tax basis. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or her future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, 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 2021, 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.

Document

Exhibit 10.13

OGE ENERGY CORP.

2022 ANNUAL EXECUTIVE INCENTIVE COMPENSATION PLAN

I. PURPOSE

The purpose of the 2022 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 23, 2022.

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 23, 2022, 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 23, 2022, 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 2022 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

4.1Eligibility. 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.

4.2Participation. 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.

4.3Partial 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.

4.4Termination 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.

V. INDIVIDUAL AWARDS

5.1Award 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.

5.2Individual 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 150% of such Participant's Target Individual Award.

5.3Adjustment 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.

5.4Earned 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.

6.1Award 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 150%) of the Participant's Target Company Award.

6.2Company 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.

6.3Payment 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 150%) 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

8.1Separation 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.

8.2Separation 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.

X. CHANGE OF CONTROL

10.1Termination 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.

10.2Termination 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

11.1Nontransferability. 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.

11.2No 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.

11.3No 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.

11.4Participation. 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.

11.5All 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.

11.6Executive 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.

11.7Successors. This Executive STI Plan shall be binding on the successors and assigns of Energy Corp.

11.8Section 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.

11.9Tax 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.

Document

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.

Document

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. and,

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

of our reports dated February 23, 2022, 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, 2021.


/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

February 23, 2022

Document

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 23, 2022, 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, 2021.


/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

February 23, 2022

Document

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, and 333-190405 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, 2021.


/s/ DELOITTE & TOUCHE LLP

Oklahoma City, Oklahoma
February 23, 2022

Document

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, 2021; 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 23rd day of February, 2022.


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
Luke R. Corbett, Director	/s/	Luke R. Corbett
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 23rd day of February, 2022.


/s/ Kelly G. Hamilton-Coyer
By: Kelly G. Hamilton-Coyer
Notary Public

My commission expires:

July 6, 2025

Document

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, 2021; 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 23rd day of February, 2022.


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
Luke R. Corbett, Director	/s/	Luke R. Corbett
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 23rd day of February, 2022.


/s/ Kelly G. Hamilton-Coyer
By: Kelly G. Hamilton-Coyer
Notary Public

My commission expires:

July 6, 2025

Document

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 23, 2022


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

Exhibit 31.01

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 23, 2022


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

Document

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 23, 2022


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

Exhibit 31.02

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 23, 2022


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

Document

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, 2021, 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 23, 2022


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


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

Document

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, 2021, 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 23, 2022


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


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

Document

Exhibit 99.01

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Enable GP, LLC and

Unitholders of Enable Midstream Partners, LP

Oklahoma City, Oklahoma

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Enable Midstream Partners, LP and subsidiaries (the “Partnership”) as of December 31, 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.

Exhibit 99.01

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.

Exhibit 99.01

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.

Exhibit 99.01

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

See Notes to the Consolidated Financial Statements

Exhibit 99.01

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

See Notes to the Consolidated Financial Statements

Exhibit 99.01

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

See Notes to the Consolidated Financial Statements

Exhibit 99.01

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

See Notes to the Consolidated Financial Statements

Exhibit 99.01

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

See Notes to the Consolidated Financial Statements

Exhibit 99.01

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

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.

Exhibit 99.01

Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil, condensate and produced water gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. The Partnership reflects revenue as Product sales and Service revenues on the Consolidated Statements of Income as follows:

Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership’s midstream services.

Service revenues: Service revenues represent all other revenue generated as a result of performing the Partnership’s midstream services.

The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil, condensate and water gathering services to third parties in accordance with ASU No. 2014-09 “Revenue from Contracts with Customers” (Topic 606). 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

Exhibit 99.01

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.

Exhibit 99.01

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

Exhibit 99.01

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.

Exhibit 99.01

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.

Exhibit 99.01

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.

Exhibit 99.01

(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

Exhibit 99.01


	Year Ended December 31, 2018
	Gathering and Processing		Transportation and Storage		Eliminations		Total

	(In millions)
Revenues:
Product sales:
Natural gas	$	480	$	590	$	(506)	$	564
Natural gas liquids	1,405		30		(30)		1,405
Condensate	126		—		—		126
Total revenues from natural gas, natural gas liquids, and condensate	2,011		620		(536)		2,095
Gain on derivative activity	5		5		1		11
Total Product sales	$	2,016	$	625	$	(535)	$	2,106
Service revenues:
Demand revenues	$	252	$	472	$	—	$	724
Volume-dependent revenues	550		65		(14)		601
Total Service revenues	$	802	$	537	$	(14)	$	1,325
Total Revenues	$	2,818	$	1,162	$	(549)	$	3,431

Product Sales

Natural Gas, NGLs or Condensate

We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue at the point in time when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index-based price received.

Gain (Loss) on Derivative Activity

Included in Product sales are gains and losses on natural gas, natural gas liquids, and crude oil (for condensate) derivatives that are accounted for under guidance in ASC 815. See Note 13 for further discussion of our derivative and hedging activity.

Service Revenues

Service revenues include demand revenues and volume-dependent revenues, both of which include contracts with customers that typically contain a series of distinct services performed on discrete volumes. For these types of contracts with customers, we typically have a right to consideration from our customers in an amount that corresponds directly with the value to the customer of our performance completed to date and recognize service revenues in accordance with our election to use the right to invoice practical expedient.

Demand revenues

Our demand revenue arrangements are generally structured in one of the following ways:

•Under a firm arrangement, a customer agrees to pay a fixed fee for a contractually agreed upon pipeline or storage capacity, which results in performance obligations for each individual period of reservation. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized.

•Under a minimum volume commitment arrangement, a customer agrees to pay the contractually agreed upon gathering, compressing and treating fees for a minimum volume of natural gas or crude oil irrespective of whether or not the minimum volume of natural gas or crude oil is delivered, which results in performance obligations for each individual unit of volume. If the actual volumes exceed the minimum volume of natural gas or crude oil, the customer pays the contractually agreed upon gathering, compressing and treating fees for the excess volumes in addition to the fees paid for the minimum volume of natural gas or crude oil. Once the services have been completed, or the customer no longer has the ability to utilize the services, the performance obligation is met, and revenue is recognized. In addition, when certain minimum volume commitment fee

Exhibit 99.01

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.

Exhibit 99.01

•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

Exhibit 99.01

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.

Exhibit 99.01

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

Exhibit 99.01

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.

Exhibit 99.01

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.

Exhibit 99.01

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.

Exhibit 99.01

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

Exhibit 99.01

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,
		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

Exhibit 99.01

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.

Exhibit 99.01

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.

Exhibit 99.01

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.

Exhibit 99.01


	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

Exhibit 99.01

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,

Exhibit 99.01

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;

Exhibit 99.01

•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.

Exhibit 99.01

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

Exhibit 99.01

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets at December 31, 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.

Exhibit 99.01

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.

Exhibit 99.01

(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.

Exhibit 99.01

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.

Exhibit 99.01

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)		—		—

Exhibit 99.01

(16) Related Party Transactions

The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.

Transportation and Storage Agreements

Transportation and Storage Agreements with CenterPoint Energy

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.

Exhibit 99.01

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

Exhibit 99.01

(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.

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 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).

Exhibit 99.01

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

Exhibit 99.01

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.

Exhibit 99.01


	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

_____________________

Exhibit 99.01

(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.

Exhibit 99.01

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

The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies described in Note 1. The Partnership uses operating income as the measure of profit or loss for its reportable segments.

The Partnership’s assets and operations are organized into two 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.

Exhibit 99.01

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

Exhibit 99.01


Year Ended December 31, 2018	Gathering and Processing		Transportation and Storage (1)		Eliminations		Total

	(In millions)
Product sales	$	2,016	$	625	$	(535)	$	2,106
Service revenues	802		537		(14)		1,325
Total Revenues	2,818		1,162		(549)		3,431
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	1,741		628		(550)		1,819
Operation and maintenance, General and administrative	312		189		—		501
Depreciation and amortization	263		135		—		398

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)

Exhibit 99.01

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.

Document

Exhibit 99.02

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)

See Notes to the Unaudited Condensed Consolidated Financial Statements

Exhibit 99.02

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)

See Notes to the Unaudited Condensed Consolidated Financial Statements

Exhibit 99.02

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	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
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

Exhibit 99.02

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	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)



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

Exhibit 99.02

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


	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

Exhibit 99.02

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.

Exhibit 99.02

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

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

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 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.

Exhibit 99.02


	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

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

Exhibit 99.02

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.

Exhibit 99.02

(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

Exhibit 99.02


	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

Exhibit 99.02

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.

Exhibit 99.02

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.

Exhibit 99.02

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.

Exhibit 99.02

(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

Exhibit 99.02

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,

Exhibit 99.02

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

Exhibit 99.02

(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.

Exhibit 99.02

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

Exhibit 99.02

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

Exhibit 99.02

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.

Exhibit 99.02

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

Exhibit 99.02

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.

Exhibit 99.02

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

______________________

(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)

Exhibit 99.02

(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

Exhibit 99.02

(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

Exhibit 99.02

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.

Exhibit 99.02

(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.

Exhibit 99.02

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

Exhibit 99.02


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.