UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2019

OR

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

For the transition period from _____to_____

Commission File Number: 1-1097

OKLAHOMA GAS AND ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Oklahoma	73-0382390
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

321 North Harvey

P.O. Box 321

Oklahoma City, Oklahoma 73101-0321

(Address of principal executive offices)

(Zip Code)

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

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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
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.

þ  Yes   o  No

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

o  Yes   þ  No

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

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

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☑	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

At June 28, 2019, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $0. As of such date, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp.

At January 31, 2020, there were 40,378,745 shares of 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

None

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).

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2019

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS	ii
FORWARD-LOOKING STATEMENTS	1
Part I
Item 1. Business	2
OG&E	2
Environmental Matters	8
Information About Our Executive Officers	9
Item 1A. Risk Factors	10
Item 1B. Unresolved Staff Comments	16
Item 2. Properties	17
Item 3. Legal Proceedings	18
Item 4. Mine Safety Disclosures	18
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
Item 6. Selected Financial Data	19
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	35
Item 8. Financial Statements and Supplementary Data	37
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	80
Item 9A. Controls and Procedures	80
Item 9B. Other Information	83
Part III
Item 10. Directors, Executive Officers and Corporate Governance	83
Item 11. Executive Compensation	83
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	83
Item 13. Certain Relationships and Related Transactions, and Director Independence	83
Item 14. Principal Accountant Fees and Services	84
Part IV
Item 15. Exhibits, Financial Statement Schedules	85
Item 16. Form 10-K Summary	89
Signatures	90

i

GLOSSARY OF TERMS

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

Abbreviation	Definition
2017 Tax Act	Tax Cuts and Jobs Act of 2017
2018 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2018
401(k) Plan	Qualified defined contribution retirement plan
AES	AES-Shady Point, Inc.
APSC	Arkansas Public Service Commission
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
CO2	Carbon dioxide
Code	Internal Revenue Code of 1986
Dry Scrubber	Dry flue gas desulfurization unit with spray dryer absorber
Enable	Enable Midstream Partners, LP, a midstream partnership formed between OGE Energy and CenterPoint Energy, Inc.
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
Federal Clean Air Act	Federal Clean Air Act of 1970, as amended
Federal Clean Water Act	Federal Water Pollution Control Act of 1972, as amended
FERC	Federal Energy Regulatory Commission
FIP	Federal Implementation Plan
GAAP	Accounting principles generally accepted in the U.S.
kV	Kilovolt
MATS	Mercury and Air Toxics Standards
MMBtu	Million British thermal unit
MW	Megawatt
MWh	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NOX	Nitrogen oxide
OCC	Oklahoma Corporation Commission
OG&E	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Energy	OGE Energy Corp., parent company of OG&E
OSHA	Federal Occupational Safety and Health Act of 1970
Pension Plan	Qualified defined benefit retirement plan
QF	Qualified cogeneration facility
QF contract	Contract with QFs and small power production producers
Regional Haze Rule	The EPA's Regional Haze Rule
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SIP	State Implementation Plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
Stock Incentive Plan	2013 Stock Incentive Plan
System sales	Sales to OG&E's customers
U.S.	United States of America

ii

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed within this Form 10-K, including those matters discussed within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "intend," "objective," "plan," "possible," "potential," "project" and similar expressions. Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed within "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

•general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;

•the ability of OG&E and OGE Energy to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;

•the ability to obtain timely and sufficient rate relief to allow for recovery of items such as capital expenditures, fuel costs, operating costs, transmission costs and deferred expenditures;

•prices and availability of electricity, coal and natural gas;

•business conditions in the energy industry;

•competitive factors, including the extent and timing of the entry of additional competition in the markets served by OG&E;

•the impact on demand for OG&E's services resulting from cost-competitive advances in technology, such as distributed electricity generation and customer energy efficiency programs;

•technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;

•factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;

•availability and prices of raw materials for current and future construction projects;

•the effect of retroactive pricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;

•federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters OG&E's markets;

•environmental laws, safety laws or other regulations that may impact the cost of operations or restrict or change the way OG&E operates its facilities;

•changes in accounting standards, rules or guidelines;

•the discontinuance of accounting principles for certain types of rate-regulated activities;

•the cost of protecting assets against, or damage due to, terrorism or cyberattacks and other catastrophic events;

•creditworthiness of suppliers, customers and other contractual parties;

•social attitudes regarding the utility industry;

•identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions and divestitures;

•increased pension and healthcare costs;

•costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including, but not limited to, those described in this Form 10-K; and

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

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

1

PART I

Item 1. Business.

Introduction

OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations 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. 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. OG&E is a wholly-owned subsidiary of OGE Energy, a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S.

OG&E's principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321 (telephone 405-553-3000). At December 31, 2019, OG&E had 1,927 employees. OGE Energy's website address is www.ogeenergy.com. Through OGE Energy's website under the heading "Investors," "SEC Filings," OGE Energy makes available, free of charge, OGE Energy's and OG&E's annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. 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.

OG&E Mission and Focus

OGE Energy's mission, through OG&E and OGE Energy's equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customer's needs for energy and related services, focusing on safety, efficiency, reliability, customer service and risk management.

OG&E is focused on:

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

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

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

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

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

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

General

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

2

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

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

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

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

3

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

4

Regulation and Rates

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

The OCC and the APSC require that, among other things, (i) 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 15 within "Item 8. Financial Statements and Supplementary Data."

Regulatory Assets and Liabilities

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

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

Rate Structures

Oklahoma

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

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

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

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

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

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

5

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

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

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

Arkansas

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

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

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

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

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

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

Fuel Supply and Generation

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

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

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

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

6

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

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

Coal

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

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

Natural Gas

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

Wind

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

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

Solar

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

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

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

7

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.

Environmental Matters

General

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 its operations are in substantial compliance with current federal, state and local environmental standards.  

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

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

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Information About Our Executive Officers

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

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

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Item 1A. Risk Factors.

In the discussion of risk factors set forth below, unless the context otherwise requires, the terms "we," "our" and "us" refer to OG&E. In addition to the other information in this Form 10-K and other documents filed by us with the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OG&E. 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. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.

REGULATORY RISKS

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

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

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

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

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

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

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

Costs of compliance with environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, 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

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relating to greenhouse gas emissions. No rules are currently in effect that require us to reduce our greenhouse gas emissions, but if such rules were to become effective, they could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

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

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

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

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

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

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

Increased competition resulting from restructuring efforts could have a significant financial impact on OG&E 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.

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

As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, 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.

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

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

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

OPERATIONAL RISKS

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

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

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

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

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

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

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

•operator error or safety related stoppages;

•disruptions in the delivery of electricity; and

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

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

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

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

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

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

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

Economic conditions may 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.

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We are subject to financial risks associated with climate change.

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

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

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

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

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

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

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

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

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

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

FINANCIAL RISKS

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

OGE Energy has a Pension Plan that covers a significant amount of our employees hired before December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover a significant amount of our employees hired prior to February 1, 2000. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our results of operations and funding requirements. Based on our assumptions at December 31, 2019, OGE Energy expects to make future contributions to maintain required funding levels. It has been OGE Energy's practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. OGE Energy 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.

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

Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Over the next three years, 29 percent of our current employees will meet the eligibility requirements to retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.

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

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

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

We cannot assure you that any of our current credit ratings 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 OGE Energy's and OG&E'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 our short-term borrowings, but a reduction in our credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require us to post collateral or letters of credit.

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

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

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

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

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

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

We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our 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.

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Item 2. Properties.

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

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

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

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(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.

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

During the three years ended December 31, 2019, OG&E's gross property, plant and equipment (excluding construction work in progress) additions were $2.5 billion, and gross retirements were $403.6 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy), long-term borrowings and permanent financings. The additions during this three-year period amounted to 19.5 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 2019.

Item 3. Legal Proceedings.

In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on currently available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows.

Item 4. Mine Safety Disclosures.

Not Applicable.

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PART II

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

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.

Item 6. Selected Financial Data.

HISTORICAL DATA

Year Ended December 31 (In millions)	2019			2018			2017			2016			2015
SELECTED FINANCIAL DATA
Results of Operations Data
Operating revenues	$	2,231.6		$	2,270.3		$	2,261.1		$	2,259.2		$	2,196.9
Cost of sales	786.9			892.5			897.6			880.1			865.0
Operating expenses	937.0			883.6			835.5			851.6			814.5
Operating income	507.7			494.2			528.0			527.5			517.4
Allowance for equity funds used during construction	4.5			23.8			39.7			14.2			8.3
Other net periodic benefit expense	1.2			8.9			16.3			18.6			17.0
Other income	6.7			14.1			36.6			16.4			13.3
Other expense	6.9			3.4			2.3			2.9			1.6
Interest expense	140.5			151.8			138.4			138.1			146.7
Income tax expense	20.1			40.0			141.8			114.4			104.8
Net income	$	350.2		$	328.0		$	305.5		$	284.1		$	268.9
Balance Sheet Data (at period end)
Property, plant and equipment, net	$	9,038.5		$	8,637.7		$	8,333.8		$	7,681.8		$	7,296.1
Total assets	$	10,076.6		$	9,704.5		$	9,255.6		$	8,669.4		$	8,525.5
Long-term debt (including Long-term debt due within one year)	$	3,195.2		$	3,146.9		$	2,999.4		$	2,530.8		$	2,639.3
Total stockholder's equity	$	3,958.3		$	3,603.3		$	3,455.7		$	3,252.1		$	3,155.7
Capitalization Ratios (A)
Stockholder's equity	55.3		%	53.4		%	53.5		%	56.2		%	54.3		%
Long-term debt	44.7		%	46.6		%	46.5		%	43.8		%	45.7		%

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

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

Introduction

OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations 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. 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. OG&E is a wholly-owned subsidiary of OGE Energy, a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S.

Overview

OG&E Mission and Focus

OGE Energy's mission, through OG&E and OGE Energy's equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customer's needs for energy and related services, focusing on safety, efficiency, reliability, customer service and risk management.

OG&E is focused on:

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

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

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

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

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

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

Summary of 2019 Operating Results Compared to 2018

OG&E reported net income of $350.2 million and $328.0 million, respectively, in 2019 and 2018. The increase of $22.2 million, or 6.8 percent, was primarily due to higher gross margin driven primarily by the expiration of the cogeneration credit rider, lower income tax expense and lower interest expense. This increase was partially offset by higher depreciation and amortization expense due to additional assets being placed into service, lower allowance for funds used during construction due to certain environmental projects being completed and placed into service and higher other operation and maintenance expense.

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

Recent Developments and Regulatory Matters

Further discussion can be found in Note 15 within "Item 8. Financial Statements and Supplementary Data."

Arkansas 2018 Formula Rate Plan Filing

Per OG&E's settlement in its last general rate review, OG&E filed an evaluation report under its Formula Rate Plan in October 2018. On March 6, 2019, the APSC approved a settlement agreement for a $3.3 million revenue increase, and new rates were effective as of April 1, 2019.

Arkansas 2019 Formula Rate Plan Filing

OG&E filed its second evaluation report under its Formula Rate Plan in October 2019. On January 29, 2020, OG&E, the General Staff of the APSC and the Office of the Arkansas Attorney General filed a settlement agreement requesting the

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

Approval for Acquisition of Existing Power Plants

In May 2019, OG&E received approval from both the OCC and the FERC to acquire plants from AES and Oklahoma Cogeneration LLC. The OCC approved OG&E's acquisition price of $53.5 million, the requested rider mechanism for the AES plant and regulatory asset treatment for the Oklahoma Cogeneration LLC plant that will defer non-fuel operation and maintenance expenses, depreciation and ad valorem taxes. In August 2019, the APSC issued an order finding that the plants to be acquired were used and useful and that the acquisition of the plants was in the public interest. The APSC also approved the depreciation rates to be applied to the acquired plants. The cost OG&E paid for the acquired plants was reviewed by the APSC in OG&E's 2019 Formula Rate Plan filing, and parties reached a settlement agreement requesting the APSC approve the cost of the acquisition. OG&E is awaiting a final decision from the APSC.

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

FERC - Section 206 Filing

In May 2019, OG&E and the Oklahoma Municipal Power Authority agreed to a settlement regarding OG&E's formula transmission rates under the SPP Open Access Transmission Tariff which provides for 10 percent base return on equity, plus a 50-basis point adder, and a five-year amortization period of the unprotected excess accumulated deferred income taxes associated with the 2017 Tax Act. On November 21, 2019, the FERC approved the settlement agreement.

Oklahoma Rate Review Filing - December 2018

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

In July 2019, OG&E implemented interim rates, which were subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate review. In September 2019, the OCC issued a final order which approved the settlement agreement.

APSC - Environmental Compliance Plan Rider

In May 2019, OG&E filed an environmental compliance plan rider in Arkansas to recover its investment for the environmentally mandated costs associated with the Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas. The filing is an interim surcharge, subject to refund, that began with the first billing cycle of June 2019. OG&E is reserving the amounts collected through the interim surcharge, pending APSC approval of OG&E's filing. A hearing on the merits was held on December 17, 2019. The primary question before the APSC is whether a company can utilize an environmental compliance plan rider while also regulated under a formula rate plan. OG&E is awaiting a final decision from the APSC.

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2020 Outlook

OG&E projects to earn approximately $346 million to $357 million in 2020 and is based on the following assumptions:

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

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

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

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

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

•an effective tax rate of approximately 10.0 percent.

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

Non-GAAP Financial Measures

Gross margin is defined by OG&E as operating revenues less cost of sales. Cost of sales, as reflected on the income statement, includes fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization and other operation and maintenance expenses. Expenses for fuel and purchased power are recovered through fuel adjustment clauses, and as a result, changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies. Further, gross margin is not intended to replace operating revenues as determined in accordance with GAAP as an indicator of operating performance. For a reconciliation of gross margin to revenue, which is the most directly comparable financial measure calculated and presented in accordance with GAAP, for the years ended December 31, 2019 and 2018, see "Results of Operations" below.

Detailed below is a reconciliation of gross margin to revenue included in the 2020 Outlook.

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

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

Results of Operations

The following discussion and analysis presents factors that affected OG&E's results of operations for the years ended December 31, 2019 and 2018 and OG&E's financial position at December 31, 2019 and 2018. 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.

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

(A)Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference

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

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

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

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

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

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

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

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

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

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

(C)Decreased primarily due to the expiration of the AES cogeneration contract in January 2019 and the Oklahoma Cogeneration LLC contract in August 2019, as discussed in Note 14 within "Item 8. Financial Statements and Supplementary Data."

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

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

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

*Not applicable, as prior year expenses were zero.

(A)Additional other operation and maintenance expenses related to the purchase of the River Valley plant are primarily recovered through a rider mechanism, as discussed in Note 15 within "Item 8. Financial Statements and Supplementary Data."

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

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

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Allowance for equity funds used during construction decreased $19.3 million, or 81.1 percent, primarily due to lower construction work in progress balances resulting from certain environmental projects being completed and placed into service.

Other net periodic benefit expense decreased $7.7 million, or 86.5 percent, primarily due to lower pension costs reflected in base rates as a result of a June 2018 Oklahoma rate review settlement.

Other income decreased $7.4 million, or 52.5 percent, primarily due to a decrease in the tax gross-up related to lower allowance for funds used during construction.

Interest on long-term debt decreased $19.1 million, or 12.1 percent, primarily due to the timing of higher interest rate debt maturing and being replaced with lower interest rate debt and due to the deferral of interest expense for the Sooner Dry Scrubbers to a regulatory asset, as disclosed in Note 1 within "Item 8. Financial Statements and Supplementary Data."

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

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

Off-Balance Sheet Arrangement

OG&E Railcar Lease Agreement

As of December 31, 2019, OG&E has a noncancellable operating lease with a purchase option, covering 780 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to fuel expense and are recovered through OG&E's fuel adjustment clauses. At the end of the lease term, which is February 1, 2024, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $6.8 million.

Liquidity and Capital Resources

Cash Flows

Year Ended December 31 (In millions)	2019		2018		$ Change		% Change
Net cash provided from operating activities (A)	$	573.8	$	804.0	$	(230.2)	(28.6)	%
Net cash used in investing activities (B)	$	(635.5)	$	(573.5)	$	(62.0)	10.8	%
Net cash provided from (used in) financing activities (C)	$	61.7	$	(230.5)	$	292.2	*

* Greater than a 100 percent variance.

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

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

(C)Increased primarily due to changes in cash advances with parent as well as a decrease in dividends, partially offset by the issuance of less long-term debt in 2019.

Working Capital

Working capital is defined as the difference in current assets and current liabilities. OG&E's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to and the timing of collections from customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries. The following discussion addresses changes in working capital balances at December 31, 2019 compared to December 31, 2018.

Accounts Receivable and Accrued Unbilled Revenues decreased $17.0 million, or 7.2 percent, primarily due to mutual assistance payments received in 2019 and a decrease in customer billings.

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Advances to Parent decreased $14.7 million, or 4.6 percent, primarily due to daily operational expenses, capital expenditures and the payment of long-term debt in January 2019, partially offset by an increase in cash from customers and proceeds from long-term debt in June 2019.

Fuel Inventories decreased $11.3 million, or 19.6 percent, primarily due to decreased coal inventory related to the Dry Scrubber systems on Sooner Units 1 and 2 being placed into service and decreased gas inventory.

Materials and Supplies, at Average Cost decreased $36.1 million, or 28.5 percent, primarily due to decreased inventory related to long-term service agreements.

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

Other Current Assets decreased $5.9 million, or 23.1 percent, primarily due to a decrease in under-recovered riders, partially offset by transportation and demand prepayments.

Accounts Payable decreased $40.0 million, or 18.6 percent, primarily due to the timing of vendor payments.

Accrued Interest decreased $6.6 million, or 14.8 percent, primarily due to the payment of the OG&E $250.0 million senior notes due January 15, 2019 and related interest, as well as timing of payments and accruals.

Accrued Compensation decreased $4.3 million, or 12.7 percent, primarily due to 2018 incentive compensation payouts that occurred in the first quarter of 2019, partially offset by 2019 accruals.

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

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

Other Current Liabilities decreased $21.7 million, or 25.0 percent primarily due to changes in amounts owed to customers. Included in the December 31, 2019 balance is SPP reserves of $18.9 million and reserves for tax refund and interim surcharge of $12.7 million.

2019 Capital Requirements, Sources of Financing and Financing Activities

Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $885.6 million, and contractual obligations, net of recoveries through fuel adjustment clauses, were $11.1 million, resulting in total net capital requirements and contractual obligations of $896.7 million in 2019, of which $20.9 million was to comply with environmental regulations. This compares to net capital requirements of $823.7 million and net contractual obligations of $75.6 million totaling $899.3 million in 2018, of which $139.8 million was to comply with environmental regulations.

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

The Dodd-Frank Act

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

Future Capital Requirements

OG&E's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities. Other working capital requirements are expected to be primarily related to maturing debt, operating lease

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obligations, fuel clause under and over recoveries and other general corporate purposes. OG&E generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings.

Capital Expenditures

OG&E's estimates of capital expenditures for the years 2020 through 2024 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate OG&E's business) plus capital expenditures for known and committed projects.

(In millions)	2020		2021		2022		2023		2024		Total
Transmission	$	45	$	40	$	35	$	35	$	35	$	190
Oklahoma distribution	215		225		225		225		225		1,115
Arkansas distribution	30		15		15		15		15		90
Generation	135		60		60		90		60		405
Reliability, resiliency, technology and other	90		335		335		335		335		1,430
Other	60		50		60		55		55		280
Total	$	575	$	725	$	730	$	755	$	725	$	3,510

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

Contractual Obligations

The following table summarizes OG&E's contractual obligations at December 31, 2019. See OG&E's Statements of Capitalization and Notes 4 and 14 within "Item 8. Financial Statements and Supplementary Data" for additional information.

(In millions)	2020		2021-2022		2023-2024		After 2024		Total
Maturities of long-term debt	$	—	$	—	$	—	$	3,229.9	$	3,229.9
Operating lease obligations:
Railcars	2.4		4.6		2.4		—		9.4
Wind farm land leases	2.9		5.8		5.9		34.7		49.3
Total operating lease obligations	5.3		10.4		8.3		34.7		58.7
Purchase obligations and commitments:
Minimum purchase commitments	82.6		105.5		83.3		332.0		603.4
Expected wind purchase commitments	55.7		112.4		114.3		379.8		662.2
Long-term service agreement commitments	2.4		4.8		45.9		111.1		164.2
Environmental compliance plan expenditures	0.4		—		—		—		0.4
Total purchase obligations and commitments	141.1		222.7		243.5		822.9		1,430.2
Total contractual obligations	146.4		233.1		251.8		4,087.5		4,718.8
Amounts recoverable through fuel adjustment clause (A)	(140.7)		(222.5)		(200.0)		(711.8)		(1,275.0)
Total contractual obligations, net	$	5.7	$	10.6	$	51.8	$	3,375.7	$	3,443.8

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

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

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Pension and Postretirement Benefit Plans

At December 31, 2019, 35.8 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in corporate fixed income, other securities and U.S. Treasury notes and bonds as presented in Note 13 within "Item 8. Financial Statements and Supplementary Data." During 2019, actual returns on the Pension Plan were $64.8 million, compared to expected return on plan assets of $27.6 million. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, decreased. Funding levels are dependent on returns on plan assets and future discount rates. OGE Energy made a $20.0 million and $15.0 million contribution to its Pension Plan in 2019 and 2018, respectively, of which $5.0 million is related to OG&E in both 2019 and 2018. OGE Energy has not determined whether it will need to make any contributions to the Pension Plan in 2020. 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 OG&E's portion of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 2019 and 2018. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance Sheets as discussed in Note 1 within "Item 8. Financial Statements and Supplementary Data." The regulatory asset represents 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)	2019		2018		2019		2018		2019		2018
Benefit obligations	$	462.0	$	453.6	$	6.1	$	6.0	$	104.7	$	104.8
Fair value of plan assets	399.1		387.6		—		—		41.9		40.6
Funded status at end of year	$	(62.9)	$	(66.0)	$	(6.1)	$	(6.0)	$	(62.8)	$	(64.2)

Financing Activities and Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long- and short-term debt and funds received from OGE Energy (from proceeds from the sales of OGE Energy's 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. OG&E utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

Short-Term Debt and Credit Facility

OG&E borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. OG&E has a $450.0 million revolving credit facility that matures on March 8, 2023. This facility is available to back up OG&E's commercial paper borrowings, to provide revolving credit borrowings, and can also be used as a letter of credit facility. At December 31, 2019, there were $304.8 million in advances to OGE Energy compared to $319.5 million at December 31, 2018. 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 March 8, 2023. The following table highlights OG&E's short-term debt activity as of December 31, 2019.

(Dollars in millions)	December 31, 2019
Balance of outstanding supporting letters of credit	$	0.3
Weighted-average interest rate of outstanding supporting letters of credit	1.0		%
Balance of outstanding commercial paper borrowings	$	—
Net available liquidity under revolving credit agreements	$	499.7
Balance of outstanding intercompany borrowings with OGE Energy	$	—

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

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Issuance of Long-Term Debt

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

Security Ratings

	Moody's Investors Service	Outlook	S&P's Global Ratings	Outlook	Fitch Ratings	Outlook
Senior Notes	A3	Stable	A-	Stable	A	Stable
Commercial Paper	P2	Stable	A2	Stable	F2	Stable

Access to reasonably priced capital is dependent in part on credit and security ratings. Generally, lower ratings lead to higher financing costs. Pricing grids associated with OGE Energy's and OG&E'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 and OG&E's short-term borrowings, but a reduction in OGE Energy's and OG&E's credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require OG&E to post collateral or letters of credit.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency, and each rating should be evaluated independently of any other rating.

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

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

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

Critical Accounting Policies and Estimates

The Financial Statements and Notes to Financial Statements 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 OG&E's Financial Statements. However, OG&E believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to OG&E that could result if actual results vary from the assumptions and estimates. 

In management's opinion, the areas of OG&E where the most significant judgment is exercised include the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, depreciable lives of property, plant and equipment, regulatory assets and liabilities and unbilled revenues. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Audit Committee of OGE Energy's Board

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of Directors. OG&E discusses its significant accounting policies, including those that do not require management to make difficult, subjective or complex judgments or estimates, in Note 1 within "Item 8. Financial Statements and Supplementary Data."

Pension and Postretirement Benefit Plans

OGE Energy has a Pension Plan that covers a significant amount of 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. Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The Pension Plan rate assumptions are shown in Note 13 within "Item 8. Financial Statements and Supplementary Data." The assumed return on plan assets is based on management's expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. Funding levels are dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the Pension Plan. The following table indicates the sensitivity of OGE Energy's Pension Plan funded status to these variables.

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

Income Taxes

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

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

Asset Retirement Obligations

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

Regulatory Assets and Liabilities

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

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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 judgement future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate.

Unbilled Revenues

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

Allowance for Uncollectible Accounts Receivable

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

Accounting Pronouncements

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

Commitments and Contingencies

In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows. See Notes 14 and 15 within "Item 8. Financial Statements and Supplementary Data" and "Item 3. Legal Proceedings" for a discussion of OG&E's 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 its operations are in substantial compliance with current federal, state and local environmental standards.

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Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.

Air

Federal Clean Air Act Overview

OG&E's operations are subject to the Federal Clean Air Act as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. OG&E likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.

Cross-State Air Pollution Rule

On September 7, 2016, the EPA finalized an update to the 2011 Cross-State Air Pollution Rule. The new rule applies to ozone-season NO_X emissions from power plants in 22 eastern states (including Oklahoma). The rule utilizes a cap and trade program for NO_X emissions and went into effect on May 1, 2017 in Oklahoma. The 2016 rule reduces the 2011 Cross-State Air Pollution Rule emissions cap for all of OG&E's coal and gas facilities (except the River Valley and Frontier facilities which were not owned by OG&E until 2019) by 47 percent combined. OG&E and numerous other parties filed petitions for judicial and administrative review of the 2016 rule. On September 13, 2019, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion that deferred a decision on our challenges to the rule pending an EPA review and decision on a separate administrative petition that we filed. Subsequently, all of OG&E's judicial challenges were voluntarily dismissed, but the administrative petitions for reconsideration remain pending at the EPA.

OG&E is in compliance with the 2016 rule requirements which remain in effect. OG&E does not anticipate, at this time, additional capital expenditures for compliance with the 2016 rule.

Hazardous Air Pollutants Emission Standards

On February 16, 2012, the EPA published the final MATS rule regulating the emissions of certain hazardous air pollutants from electric generating units. OG&E complied with the MATS rule by the April 16, 2016 deadline that applied to OG&E by installing activated carbon injection for all coal units (not including the River Valley facility which was not owned by OG&E until 2019). There is continuing litigation, to which OG&E is not a party, challenging whether the EPA had statutory authority to issue the MATS rule. On December 27, 2018, the EPA released a proposed rule reconsidering certain elements of the 2012 rule in response to lengthy litigation in the D.C. Circuit Court. OG&E cannot predict the outcome of this litigation or regulatory proposal or how it will affect OG&E.

National Ambient Air Quality Standards

The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, OG&E could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of December 31, 2019, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect OG&E's operations. Several processes are under way to designate areas in Oklahoma as attaining or not attaining revised NAAQS.

The EPA proposed to designate part of Muskogee County, in which OG&E's Muskogee Power Plant is located, as non-attainment for the 2010 SO₂ NAAQS on March 1, 2016, even though nearby monitors indicated compliance with the NAAQS. The proposed designation was based on modeling that did not reflect the conversion of two of the coal units at Muskogee to natural gas. The State of Oklahoma's monitoring preliminarily indicates that ambient SO₂ emissions in the area are well within the NAAQS. The EPA has indicated that it anticipates finalizing a designation at the end of 2020. At this time, OG&E cannot determine with any certainty whether the proposed designation of Muskogee County will cause a material impact to OG&E's financial results.

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OG&E continues to monitor these processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to OG&E's financial results.

Climate Change and Greenhouse Gas Emissions

There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including CO_2, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the earth's atmosphere. On November 4, 2019, President Trump announced that the U.S. has officially notified the United Nations that the U.S. will withdraw from the "Paris Agreement" on climate change after having announced in 2017 that the U.S. would begin negotiations to re-enter the agreement with different terms. A new agreement may result in future additional emissions reductions in the U.S.; however, it is not possible to determine what the international legal standards for greenhouse gas emissions will be in the future and the extent to which these commitments will be implemented through the Clean Air Act or any other existing statutes and new legislation.

If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of CO₂ and other greenhouse gases on 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. Several states outside the area where OG&E operates have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.

OG&E's current business strategy has resulted in reduced carbon dioxide emissions by over 40 percent compared to 2005 levels, and during the same period, emissions of ozone-forming NO_x have been reduced by approximately 75 percent and emissions of SO₂ have been reduced by approximately 90 percent. OG&E expects to further reduce carbon dioxide emissions to 50 percent of 2005 levels by 2030. To comply with the EPA's MATS rule and Regional Haze Rule FIP, OG&E converted two coal-fired generating units at the Muskogee Station to natural gas, among other measures. OG&E's deployment of Smart Grid technology helps to reduce the peak load demand. OG&E is also deploying more renewable energy sources that do not emit greenhouse gases. OG&E's service territory borders one of the nation's best wind resource areas, and OG&E has leveraged its geographic position to develop renewable energy resources and completed transmission investments to deliver the renewable energy. The SPP has authorized the construction of transmission lines capable of bringing renewable energy out of the wind resource areas in western Oklahoma, the Texas Panhandle and western Kansas to load centers by planning for more transmission to be built in the area. In addition to increasing overall system reliability, these new transmission resources should provide greater access to additional wind resources that are currently constrained due to existing transmission delivery limitations.

On July 8, 2019, the EPA published the Affordable Clean Energy rule. Numerous parties, not including OG&E, have filed petitions for judicial review of the Affordable Clean Energy rule in the U.S. Court of Appeals for the District of Columbia Circuit. The Affordable Clean Energy rule requires states, including Oklahoma, to develop emission limitations for carbon dioxide for each existing coal-fired utility boiler within the state, including all of OG&E's coal units, and submit a compliance and implementation plan to the EPA by July 2022. The EPA will approve or disapprove the proposed state plan within 18 months of submittal and develop a federal implementation plan if the proposed state plan is disapproved. At this time, OG&E cannot determine with any certainty whether the implementation plan will cause a material impact to its financial results.

EPA Startup, Shutdown and Malfunction Policy

On May 22, 2015, the EPA issued a final rule to address the provisions in the SIPs of 36 states (including Oklahoma) regarding the treatment of emissions that occur during startup, shutdown and malfunction operations. The final rule clarifies the EPA's Startup, Shutdown and Malfunction Policy. Although judicial challenges to the rule are ongoing, the Oklahoma Department of Environmental Quality submitted a SIP revision for the EPA's approval on November 7, 2016 to comply with this rule. This rule has resulted in permit modifications for certain OG&E units and applications remain pending for other units. OG&E does not anticipate capital expenditures, or a material impact to its financial position, results of operations or cash flows, as a result of adoption of this rule.

Regional Haze Regulation - Second Planning Period

In January 2017, the EPA finalized a rule that would revise certain provisions of the Regional Haze Rule. Notably, the EPA extended the due date for the second Regional Haze implementation period by three years to 2021 and made changes to the provisions for impacts to national parks and other protected wilderness areas. Petitions for Reconsideration to the EPA were

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filed by industry groups. While not acting on the petitions, the EPA announced on January 17, 2018 that it intends to commence a notice-and-comment rulemaking revisiting certain aspects of the rule. During 2019, the EPA released technical resources to assist states in developing SIPs, including a significant non-binding guidance document and updated atmospheric modeling which will allow states to better account for international emissions affecting regional haze in the U.S. At this time, OG&E cannot predict the outcome of this rulemaking or SIP development or how it will affect OG&E.

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.

Waste

OG&E's operations generate wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of waste.

In 2015, the EPA finalized a rule under the Federal Resource Conservation and Recovery Act for the handling and disposal of coal combustion residuals or coal ash. The rule regulates coal ash as a solid waste rather than a hazardous waste, which would have made the management of coal ash more costly. In August 2019, the EPA proposed revisions to the 2015 coal ash rule in response to the D.C. Circuit Court of Appeals issuing a decision regarding the ongoing Coal Combustion Residuals litigation. The proposed changes do not appear to be material to OG&E at this time. OG&E completed the clean closure of one regulated inactive coal ash impoundment in August 2019.

On June 28, 2018, the EPA approved the State of Oklahoma's application for a state coal ash permitting program that will operate in lieu of the federal coal ash program promulgated under the Federal Resource Conservation and Recovery Act. On September 26, 2018, a citizen suit was filed against the EPA in the U.S. District Court in the District of Columbia concerning the final approval. OG&E and others have moved to intervene on behalf of the EPA. OG&E is monitoring regulatory developments relating to this rule, none of which appear to be material to OG&E at this time. OG&E is in compliance with this rule at this time.

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

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 2019, OG&E obtained refunds of $2.8 million from the recycling of scrap metal, salvaged transformers and used transformer oil. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years.

Water

OG&E's operations are subject to the Federal Clean Water Act and comparable state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters.

The EPA issued a final rule on May 19, 2014 to implement Section 316(b) of the Federal Clean Water Act, which requires that power plant cooling water intake structure location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. The Oklahoma Department of Environmental Quality issued final permits on December 22, 2017 and August 22, 2018 for Muskogee Power Plant and Seminole Power Plant, respectively, in compliance with the final 316(b) rule, and OG&E did not incur any material costs associated with the rule's implementation at either location. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation at other facilities following the future issuance of permits from the State of Oklahoma.

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In 2015, the EPA issued a final rule addressing the effluent limitation guidelines for power plants under the Federal Clean Water Act. The final rule establishes technology- and performance-based standards that may apply to discharges of six waste streams including bottom ash transport water. Compliance with this rule will occur by 2023; however, on April 12, 2017, the EPA granted a Petition for Reconsideration of the 2015 Rule. On November 22, 2019, the EPA published a proposed rule to revise the technology-based effluent limitations for flue gas desulfurization waste water and bottom ash transport water. OG&E is evaluating what, if any, compliance actions are needed but is not able to quantify with any certainty what costs may be incurred. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation following issuance of the permits from the State of Oklahoma.

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

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generates wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E.

For further discussion regarding contingencies relating to environmental laws and regulations, see Note 14 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. OG&E's exposure to changes in interest rates relates primarily to short-term variable-rate debt and commercial paper. OG&E is exposed to commodity prices in its operations.

Risk Oversight Committee

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

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

Risk Policies

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

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Interest Rate Risk

OG&E's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper. OG&E manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates. OG&E 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 OG&E has no intent at this time to utilize interest rate derivatives.

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

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

(A)Prior to or when these debt obligations mature, OG&E 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.

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Item 8. Financial Statements and Supplementary Data.

OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF INCOME

Year Ended December 31 (In millions)	2019		2018		2017
OPERATING REVENUES
Revenues from contracts with customers	$	2,175.5	$	2,211.7	$	—
Other revenues	56.1		58.6		—
Operating revenues	2,231.6		2,270.3		2,261.1
COST OF SALES	786.9		892.5		897.6
OPERATING EXPENSES
Other operation and maintenance	492.5		473.8		469.8
Depreciation and amortization	355.0		321.6		280.9
Taxes other than income	89.5		88.2		84.8
Operating expenses	937.0		883.6		835.5
OPERATING INCOME	507.7		494.2		528.0
OTHER INCOME (EXPENSE)
Allowance for equity funds used during construction	4.5		23.8		39.7
Other net periodic benefit expense	(1.2)		(8.9)		(16.3)
Other income	6.7		14.1		36.6
Other expense	(6.9)		(3.4)		(2.3)
Net other income	3.1		25.6		57.7
INTEREST EXPENSE
Interest on long-term debt	138.3		157.4		151.9
Allowance for borrowed funds used during construction	(2.8)		(11.7)		(18.0)
Interest on short-term debt and other interest charges	5.0		6.1		4.5
Interest expense	140.5		151.8		138.4
INCOME BEFORE TAXES	370.3		368.0		447.3
INCOME TAX EXPENSE	20.1		40.0		141.8
NET INCOME	350.2		328.0		305.5
Other comprehensive income, net of tax	—		—		—
COMPREHENSIVE INCOME	$	350.2	$	328.0	$	305.5

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

Year Ended December 31 (In millions)	2019		2018		2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	350.2	$	328.0	$	305.5
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	355.0		321.6		280.9
Deferred income taxes and investment tax credits, net	20.4		56.6		119.8
Allowance for equity funds used during construction	(4.5)		(23.8)		(39.7)
Stock-based compensation expense	4.9		4.6		3.1
Regulatory assets	(47.1)		(10.8)		3.7
Regulatory liabilities	(45.6)		(16.5)		(3.7)
Other assets	3.8		1.9		1.6
Other liabilities	8.4		—		(59.9)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	17.0		19.5		(22.2)
Fuel, materials and supplies inventories	4.2		27.3		(5.0)
Fuel recoveries	(33.0)		(3.4)		53.0
Other current assets	5.9		23.1		29.7
Accounts payable	(30.0)		19.0		22.5
Income taxes payable - parent	(0.7)		(15.6)		92.0
Other current liabilities	(35.1)		72.5		(65.6)
Net cash provided from operating activities	573.8		804.0		715.7
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(635.5)		(573.6)		(824.1)
Proceeds from sale of assets	—		0.1		0.7
Net cash used in investing activities	(635.5)		(573.5)		(823.4)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	296.5		396.0		592.1
Payment of long-term debt	(250.1)		(250.1)		(125.1)
Dividends paid on common stock	—		(185.0)		(170.0)
Changes in advances with parent	15.3		(191.4)		(189.3)
Net cash provided from (used in) financing activities	61.7		(230.5)		107.7
NET CHANGE IN CASH AND CASH EQUIVALENTS	—		—		—
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	—		—		—
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	—	$	—	$	—

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

BALANCE SHEETS

December 31 (In millions)	2019		2018
ASSETS
CURRENT ASSETS
Accounts receivable, less reserve of $1.5 and $1.7, respectively	$	153.8	$	172.9
Accrued unbilled revenues	64.7		62.6
Advances to parent	304.8		319.5
Fuel inventories	46.3		57.6
Materials and supplies, at average cost	90.6		126.7
Fuel clause under recoveries	39.5		2.0
Other	19.6		25.5
Total current assets	719.3		766.8
OTHER PROPERTY AND INVESTMENTS	4.7		5.0
PROPERTY, PLANT AND EQUIPMENT
In service	12,765.0		11,988.7
Construction work in progress	141.6		376.4
Total property, plant and equipment	12,906.6		12,365.1
Less: accumulated depreciation	3,868.1		3,727.4
Net property, plant and equipment	9,038.5		8,637.7
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	306.0		285.8
Other	8.1		9.2
Total deferred charges and other assets	314.1		295.0
TOTAL ASSETS	$	10,076.6	$	9,704.5

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

BALANCE SHEETS (Continued)

December 31 (In millions)	2019		2018
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES
Accounts payable	$	175.0	$	215.0
Customer deposits	83.0		83.6
Accrued taxes	41.9		44.0
Accrued interest	37.9		44.5
Accrued compensation	29.5		33.8
Long-term debt due within one year	—		250.0
Fuel clause over recoveries	4.8		0.3
Other	65.1		86.8
Total current liabilities	437.2		758.0
LONG-TERM DEBT	3,195.2		2,896.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	133.3		137.9
Deferred income taxes	951.4		892.7
Deferred investment tax credits	7.1		7.2
Regulatory liabilities	1,223.5		1,270.7
Other	170.6		137.8
Total deferred credits and other liabilities	2,485.9		2,446.3
Total liabilities	6,118.3		6,101.2
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDER'S EQUITY
Common stockholder's equity	1,036.6		1,031.8
Retained earnings	2,921.7		2,571.5
Total stockholder's equity	3,958.3		3,603.3
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	10,076.6	$	9,704.5

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

STATEMENTS OF CAPITALIZATION

December 31 (In millions except per share data)		2019		2018
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		935.7		930.9
Retained earnings		2,921.7		2,571.5
Total stockholder's equity		3,958.3		3,603.3
LONG-TERM DEBT
SERIES	DUE DATE
Senior Notes
8.25%	Senior Notes, Series Due January 15, 2019	—		250.0
6.65%	Senior Notes, Series Due July 15, 2027	125.0		125.0
6.50%	Senior Notes, Series Due April 15, 2028	100.0		100.0
3.80%	Senior Notes, Series Due August 15, 2028	400.0		400.0
3.30%	Senior Notes, Series Due March, 15, 2030	300.0		—
5.75%	Senior Notes, Series Due January 15, 2036	110.0		110.0
6.45%	Senior Notes, Series Due February 1, 2038	200.0		200.0
5.85%	Senior Notes, Series Due June 1, 2040	250.0		250.0
5.25%	Senior Notes, Series Due May 15, 2041	250.0		250.0
3.90%	Senior Notes, Series Due May 1, 2043	250.0		250.0
4.55%	Senior Notes, Series Due March 15, 2044	250.0		250.0
4.00%	Senior Notes, Series Due December 15, 2044	250.0		250.0
4.15%	Senior Notes, Series Due April 1, 2047	300.0		300.0
3.85%	Senior Notes, Series Due August 15, 2047	300.0		300.0
3.80%	Tinker Debt, Due August 31, 2062	9.5		9.6
Other Bonds
1.20% - 2.50%	Garfield Industrial Authority, January 1, 2025	47.0		47.0
1.19% - 2.35%	Muskogee Industrial Authority, January 1, 2025	32.4		32.4
1.20% - 2.48%	Muskogee Industrial Authority, June 1, 2027	56.0		56.0
Unamortized debt expense		(24.2)		(22.9)
Unamortized discount		(10.5)		(10.2)
Total long-term debt		3,195.2		3,146.9
Less: long-term debt due within one year		—		(250.0)
Total long-term debt (excluding long-term debt due within one year)		3,195.2		2,896.9
Total capitalization (including long-term debt due within one year)		$	7,153.5	$	6,750.2

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

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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, 2016	40.4	$	100.9	$	923.2	$	2,228.0	$	3,252.1
Net income	—	—		—		305.5		305.5
Dividends declared on common stock	—	—		—		(105.0)		(105.0)
Stock-based compensation	—	—		3.1		—		3.1
Balance at December 31, 2017	40.4	$	100.9	$	926.3	$	2,428.5	$	3,455.7
Net income	—	—		—		328.0		328.0
Dividends declared on common stock	—	—		—		(185.0)		(185.0)
Stock-based compensation	—	—		4.6		—		4.6
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

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

1.Summary of Significant Accounting Policies

Organization

OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations 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. 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. OG&E is a wholly-owned subsidiary of OGE Energy, a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S.

Accounting Records

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

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

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

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

(A)Included in Other Current Assets in the 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.

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

OG&E recovers program costs related to the Demand and Energy Efficiency Program in Oklahoma through the Demand Program Rider, which operates on a three-year program cycle. The current program cycle, which runs through 2021, includes recovery of (i) energy efficiency program costs, (ii) lost revenues associated with certain achieved energy efficiency and demand savings, (iii) performance-based incentives and (iv) costs associated with research and development investments.

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

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

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

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

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

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

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

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

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

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

OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical

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expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker regulatory asset in the table above.

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

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

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

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

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

Use of Estimates

In preparing the 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 OG&E's Financial Statements. However, OG&E believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to OG&E that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of OG&E where the most significant judgment is exercised include the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, depreciable lives of property, plant and equipment, regulatory assets and liabilities and unbilled revenues.

Cash and Cash Equivalents

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

Allowance for Uncollectible Accounts Receivable

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

New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers whose outside credit scores indicate an elevated risk are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the

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APSC. The payment behavior of all existing customers is continuously monitored, and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.

Fuel Inventories

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

Property, Plant and Equipment

All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances, and the cost of such property net of any salvage proceeds is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation, and the remaining balance net of any salvage proceeds is recorded as a loss in the 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 tables below present OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant, such as fuel, maintenance expense and other operating expenses, are included in the applicable financial statement captions in the Statements of Income.

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

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

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

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

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

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

OG&E's property, plant and equipment and related accumulated depreciation are divided into the following major classes: 

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

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

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

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

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

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

OG&E's unamortized computer software costs, included in intangible plant above, were $71.3 million and $44.3 million at December 31, 2019 and 2018, respectively. In 2019, 2018 and 2017, amortization expense for computer software costs was $11.0 million, $9.6 million and $8.8 million, respectively.

Depreciation and Amortization

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

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

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

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 ten to 68 years. 

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

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

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

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

Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are

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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 $18.7 million and $23.4 million in accrued environmental liabilities at December 31, 2019 and 2018, 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 7.6 percent, 7.6 percent and 8.2 percent for the years ended December 31, 2019, 2018 and 2017, respectively. 

Collection of Sales Tax

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

Revenue Recognition

General

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

Integrated Market and Transmission

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

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

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

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Other Revenues

Revenues from Alternative Revenue Programs

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 passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC.

Leases

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

Income Taxes

OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and will be amortized to income over the life of the related property. OG&E uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. OG&E recognizes interest related to unrecognized tax benefits in Interest Expense and recognizes penalties in Other Expense in the Statements of Income.

Accrued Vacation

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

Reclassifications

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

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2. Accounting Pronouncements

Recently Adopted Accounting Standards

Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between prior lease accounting and ASC 842 is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance. Lessees, such as OG&E, recognize a right-of-use asset and a lease liability for virtually all of their leases, other than leases that meet the definition of a short-term lease. The liability is equal to the present value of lease payments. The asset is based on the liability, subject to adjustment for items such as initial direct costs. For income statement purposes, ASC 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases result in straight-line expense, while finance leases result in a front-loaded expense pattern, similar to prior capital leases. Classification of operating and finance leases is based on criteria that are largely similar to those applied in prior lease guidance but without the explicit thresholds. OG&E adopted this standard in the first quarter of 2019 utilizing the modified retrospective transition method.

Various practical expedients for the application of ASC 842 were approved, and OG&E elected to apply the below:

•a package of practical expedients allowing entities to not reassess (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases and (iii) initial direct costs for any existing leases;

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

•an option that permits an entity to elect to initially apply ASC 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, provided that if an entity elects this additional (and optional) transition method, the entity will provide the required ASC 840 disclosures for all periods that continue to be reported under ASC 840.

OG&E evaluated its current lease contracts and, at January 1, 2019, recognized $32.3 million and $36.9 million of operating lease right-of-use assets and liabilities, respectively, for railcar, wind farm land and office space leases in the Balance Sheet. The new standard did not have a material impact on OG&E's 2019 Statement of Income. Further, OG&E evaluated its existing processes and controls regarding lease identification, accounting and presentation and implemented changes as necessary in order to adequately address the requirements of ASC 842.

Financial Instruments-Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, "Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Information." The amendments in this update require entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions and reasonable and supportable forecasts in order to record credit losses in a more timely manner. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. ASU 2016-13 is effective for fiscal years beginning after December 2019 and is applied utilizing a modified-retrospective approach. OG&E determined the only financial instrument that OG&E currently holds and is required to measure under ASU 2016-13 is its trade receivables. Upon adoption of this ASU, OG&E considers forecasts of future economic conditions in addition to the historical data utilized prior to ASU 2016-13 when measuring the reserve for trade receivables. OG&E evaluated its reserve for trade receivables in light of the new guidance and determined that no adjustment was necessary to the amount recorded as of January 1, 2020.

Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. In August 2018, the FASB issued ASU 2018-15, "Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract." The new guidance aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. ASU 2018-15 is effective for fiscal years beginning after December 2019 and can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. OG&E adopted and prospectively applied the new guidance beginning in the first quarter of 2020, which did not have a material effect on the Financial Statements upon adoption.

Issued Accounting Standards Not Yet Adopted

Simplifying the Accounting for Income Taxes. In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740)." The new guidance simplifies the accounting for income taxes by removing certain exceptions to the general

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principles in ASC 740 and improves consistent application of existing guidance. ASU 2019-12 will be effective for OG&E as of January 1, 2021 and can be early adopted. OG&E is currently assessing the impact of these rule changes on its Financial Statements.

3.Revenue Recognition

The following table disaggregates OG&E's revenues from contracts with customers 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)	2019		2018
Residential	$	865.8	$	877.8
Commercial	486.6		500.0
Industrial	217.8		228.9
Oilfield	200.4		190.4
Public authorities and street light	190.3		197.4
System sales revenues	1,960.9		1,994.5
Provision for rate refund	(0.9)		(6.0)
Integrated market	38.4		48.7
Transmission	148.0		147.4
Other	29.1		27.1
Revenues from contracts with customers	$	2,175.5	$	2,211.7

4.Leases

Based on its evaluation of all contracts under ASC 842, as described in Note 1, OG&E concluded it has operating lease obligations for railcar leases and wind farm land leases.

Operating Leases

OG&E Railcar Lease Agreement

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

OG&E Wind Farm Land Lease Agreements

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

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Financial Statement Information and Maturity Analysis of Lease Liabilities

Operating lease cost was $5.1 million, $4.1 million and $5.4 million for the years ended December 31, 2019, 2018 and 2017, respectively. The following table presents amounts recognized for operating leases in OG&E's 2019 Cash Flow Statement and Balance Sheet and supplemental information related to those amounts recognized, as well as a maturity analysis of OG&E's operating lease liabilities.

(In millions)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	4.8
Right-of-use assets obtained in exchange for new operating lease liabilities	$	10.7
(Dollars in millions)	December 31, 2019
Right-of-use assets at period end (A)	$	39.6
Operating lease liabilities at period end (B)	$	44.3
Operating lease weighted-average remaining lease term (in years)	13.5
Operating lease weighted-average discount rate	3.9		%

	December 31,
Future minimum operating lease payments as of:	2019		2018(C)(D)
(In millions)
2019	$	—	$	21.1
2020	5.3		2.9
2021	5.2		2.9
2022	5.2		2.9
2023	5.2		2.9
2024	3.1		3.0
Thereafter	34.7		34.6
Total future minimum lease payments	58.7		$	70.3
Less: Imputed interest	14.4
Present value of net minimum lease payments	$	44.3

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

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

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

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

5.Related Party Transactions

OGE Energy charged operating costs to OG&E of $149.8 million, $140.9 million and $134.4 million in 2019, 2018 and 2017, respectively. OGE Energy charges operating costs to OG&E based on several factors. Operating costs directly related to OG&E are assigned as such. Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.  

In 2019, no dividends were declared from OG&E to OGE Energy, compared to $185.0 million and $105.0 million in 2018 and 2017, respectively.

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Enable provides gas transportation services to OG&E pursuant to an agreement, which expires in May 2024, that grants Enable the responsibility of delivering natural gas to OG&E's generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable's deliveries exceed OG&E's pipeline receipts. Enable purchases gas from OG&E when OG&E's pipeline receipts exceed Enable's deliveries. Further, an additional gas transportation services contract with Enable became effective in December 2018 related to the project to convert Muskogee Units 4 and 5 from coal to natural gas. The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2019, 2018 and 2017.

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

6.Fair Value Measurements

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

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

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

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

OG&E had no financial instruments measured at fair value on a recurring basis at December 31, 2019 and 2018. The following table summarizes the carrying amount and fair value of OG&E's financial instruments at December 31, 2019 and 2018, as well as the classification level within the fair value hierarchy.

	2019				2018
December 31 (In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Classification
Long-term Debt (including Long-term Debt due within one year):
Senior Notes	$	3,050.3	$	3,500.4	$	3,001.9	$	3,178.2	Level 2
Industrial Authority Bonds	$	135.4	$	135.4	$	135.4	$	135.4	Level 2
Tinker Debt	$	9.5	$	10.0	$	9.6	$	8.7	Level 3

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7. Stock-Based Compensation

In 2013, 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. OGE Energy has authorized the issuance of up to 7,400,000 shares under the Stock Incentive Plan.

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

Year Ended December 31 (In millions)	2019		2018		2017
Performance units:
Total shareholder return	$	3.0	$	2.8	$	2.5
Earnings per share	1.5		1.8		0.5
Total performance units	4.5		4.6		3.0
Restricted stock units	0.4		—		—
Total compensation expense	$	4.9	$	4.6	$	3.0
Income tax benefit	$	1.3	$	1.2	$	1.2

OGE Energy has issued new shares of common stock to satisfy restricted stock unit grants and payouts of earned performance units. In 2019, 2018 and 2017, there were 164,794 shares, 8,599 shares and 965 shares, respectively, of new common stock issued to OG&E's employees pursuant to OGE Energy's Stock Incentive Plan related to restricted stock unit grants and payouts of earned performance units.

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. OG&E estimates expected forfeitures in accounting for performance unit compensation expense.

The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of 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 are 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 OGE Energy's Consolidated Balance Sheets. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of 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.

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Performance Units – Total Shareholder Return

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

	2019			2018			2017
Number of units granted to OG&E employees	68,396			91,940			85,501
Fair value of units granted	$	47.00		$	36.86		$	41.76
Expected dividend yield	4.0		%	3.6		%	3.8		%
Expected price volatility	17.0		%	19.0		%	19.8		%
Risk-free interest rate	2.47		%	2.38		%	1.46		%
Expected life of units (in years)	2.86			2.86			2.86

Performance Units – Earnings Per Share

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

	2018		2017
Number of units granted to OG&E employees	30,649		28,499
Fair value of units granted	$	31.03	$	34.83

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 for the 2019 grant cycle, restricted stock units were granted in lieu of performance units based on earnings per share. The restricted stock units vest primarily in a three-year award cycle (i.e., three-year cliff vesting period). Prior to vesting, each restricted stock unit is subject to forfeiture if the recipient ceases to render substantial services to 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, OG&E treats its restricted stock units as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period.

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Dividends will only be paid on restricted stock unit awards that vest; therefore, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock units is based on the non-vested period since inception of the primarily three-year award cycle. There are no post-vesting restrictions related to OGE Energy's restricted stock units. In 2019, 26,141 restricted stock units were granted to OG&E employees at a fair value of $41.63. There were no restricted stock unit grants made to OG&E employees during 2018 or 2017.

Performance Units and Restricted Stock Units Activity

A summary of the activity for OGE Energy's performance units and restricted stock units applicable to OG&E's employees at December 31, 2019 and changes in 2019 are shown in the following table.

	Performance Units								Restricted Stock Units
	Total Shareholder Return				Earnings Per Share
(Dollars in millions)	Number of Units		Aggregate Intrinsic Value		Number of Units		Aggregate Intrinsic Value		Number of Shares		Aggregate Intrinsic Value
Units/shares outstanding at 12/31/18	261,423				87,143				312
Granted	68,396	(A)			—				26,141
Converted	(95,593)	(B)	$	7.0	(31,865)	(B)	$	2.5	N/A
Vested	N/A				N/A				(312)		$	—
Forfeited	(10,360)				(2,207)				(1,500)
Employee migration	3,813	(C)			906	(C)			364	(C)
Units/shares outstanding at 12/31/19	227,679		$	12.2	53,977		$	4.0	25,005		$	1.1
Units/shares fully vested at 12/31/19	77,799		$	4.0	25,931		$	2.3

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

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

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

A summary of the activity for OGE Energy's non-vested performance units and restricted stock units applicable to OG&E's employees at December 31, 2019 and changes in 2019 are shown in the following table. 

	Performance Units								Restricted Stock Units
	Total Shareholder Return				Earnings Per Share
	Number of Units		Weighted-Average Grant Date Fair Value		Number of Units		Weighted-Average Grant Date Fair Value		Number of Shares		Weighted-Average Grant Date Fair Value
Units/shares non-vested at 12/31/18	165,830		$	39.17	55,278		$	32.82	312		$	31.88
Granted	68,396	(A)	$	47.00	—		$	—	26,141		$	41.63
Vested	(77,799)		$	41.76	(25,931)		$	34.83	(312)		$	31.88
Forfeited	(10,360)		$	41.33	(2,207)		$	32.02	(1,500)		$	41.78
Employee migration	3,813	(B)	$	41.43	906	(B)	$	32.84	364	(B)	$	41.78
Units/shares non-vested at 12/31/19	149,880		$	41.31	28,046		$	31.03	25,005		$	41.62
Units/shares expected to vest	145,790	(C)			28,006	(C)			20,251	(C)

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

(C)The intrinsic value of the performance units based on total shareholder return and earnings per share is $8.1 million and $1.7 million, respectively. The intrinsic value of restricted stock units is $0.9 million.

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Fair Value of Vested Performance Units and Restricted Stock Units

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

Year Ended December 31 (In millions)	2019		2018		2017
Performance units:
Total shareholder return	$	3.2	$	2.1	$	2.3
Earnings per share	$	0.9	$	1.7	$	0.4
Restricted stock units	$	—	$	—	$	0.1

Unrecognized Compensation Cost

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

December 31, 2019	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance units:
Total shareholder return	$	3.0	1.68
Earnings per share	0.3		1.00
Total performance units	3.3
Restricted stock units	0.7		2.00
Total unrecognized compensation cost	$	4.0

8.Supplemental Cash Flow Information

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

Year Ended December 31 (In millions)	2019		2018		2017
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement	$	28.9	$	(9.2)	$	(2.6)
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of interest capitalized) (A)	$	144.6	$	149.7	$	133.1
Income taxes (net of income tax refunds)	$	1.3	$	0.9	$	(71.5)

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

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9.Income Taxes

Income Tax Expense (Benefit)

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

Year Ended December 31 (In millions)	2019		2018		2017
Provision (benefit) for current income taxes:
Federal	$	(7.9)	$	(12.4)	$	26.3
State	4.1		(4.1)		(4.3)
Total provision (benefit) for current income taxes	(3.8)		(16.5)		22.0
Provision (benefit) for deferred income taxes, net:
Federal	37.7		53.7		100.0
State	(13.8)		2.7		19.9
Total provision for deferred income taxes, net	23.9		56.4		119.9
Deferred federal investment tax credits, net	—		0.1		(0.1)
Total income tax expense	$	20.1	$	40.0	$	141.8

OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, OG&E is no longer subject to U.S. federal tax or state and local examinations by tax authorities for years prior to 2016. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and will be amortized to income over the life of the related property. Additionally, OG&E earns federal tax credits associated with production from its wind facilities. Oklahoma production and investment state tax credits are also earned on investments in electric and solar generating facilities which further reduce OG&E's effective tax rate.

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

Year Ended December 31	2019		2018		2017
Statutory federal tax rate	21.0	%	21.0	%	35.0	%
Federal renewable energy credit (A)	(7.6)		(6.9)		(6.1)
Amortization of net unfunded deferred taxes	(5.6)		(2.9)		0.9
State income taxes, net of federal income tax benefit	(1.8)		(0.2)		2.2
Other	(0.6)		(0.1)		(0.3)
Effective income tax rate	5.4	%	10.9	%	31.7	%

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

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

December 31 (In millions)	2019		2018
Deferred income tax liabilities, net:
Accelerated depreciation and other property related differences	$	1,656.8	$	1,605.3
Regulatory assets	28.4		17.4
OG&E Pension Plan	24.5		26.0
Bond redemption-unamortized costs	2.2		2.4
Federal tax credits	(238.0)		(237.5)
Income taxes recoverable from customers, net	(229.9)		(239.6)
State tax credits	(170.8)		(142.3)
Regulatory liabilities	(68.1)		(78.8)
Asset retirement obligations	(19.2)		(21.5)
Postretirement medical and life insurance benefits	(16.0)		(16.2)
Net operating losses	(5.7)		(10.0)
Other	(4.7)		(2.4)
Accrued liabilities	(4.3)		(6.1)
Deferred federal investment tax credits	(1.8)		(1.9)
Accrued vacation	(1.6)		(1.7)
Uncollectible accounts	(0.4)		(0.4)
Total deferred income tax liabilities, net	$	951.4	$	892.7

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

Following is a reconciliation of OG&E’s total gross unrecognized tax benefits as of the years ended December 31, 2019, 2018 and 2017.

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

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

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

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

(In millions)	Carry Forward Amount		Deferred Tax Asset		Earliest Expiration Date
State operating loss	$	127.3	$	5.7	2030
Federal tax credits	$	238.0	$	238.0	2032
State tax credits:
Oklahoma investment tax credits	$	165.1	$	130.4	N/A
Oklahoma capital investment board credits	$	12.4	$	12.4	N/A
Oklahoma zero emission tax credits	$	34.9	$	28.0	2020

N/A - not applicable

10.Common Stock and Cumulative Preferred Stock

There were no new shares of common stock issued in 2019, 2018 or 2017.  

11.Long-Term Debt

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

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

Industrial Authority Bonds

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows:

Series			Date Due	Amount
				(In millions)
1.20%	-	2.50%	Garfield Industrial Authority, January 1, 2025	$	47.0
1.19%	-	2.35%	Muskogee Industrial Authority, January 1, 2025	32.4
1.20%	-	2.48%	Muskogee Industrial Authority, June 1, 2027	56.0
Total (redeemable during next 12 months)				$	135.4

All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third-party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as Long-Term Debt in OG&E's Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

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Issuance of Long-Term Debt

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

12.Short-Term Debt and Credit Facility

OG&E has a $450.0 million revolving credit facility that matures on March 8, 2023. This facility is available to back up OG&E's commercial paper borrowings, to provide revolving credit borrowings and can also be used as a letter of credit facility. At December 31, 2019, there were $0.3 million supporting letters of credit at a weighted-average interest rate of 1.00 percent. There were no outstanding commercial paper borrowings at December 31, 2019.

OG&E's credit facility has a financial covenant requiring that OG&E maintain a maximum debt to capitalization ratio of 65 percent, as defined in the facility. OG&E's facility also contains covenants which restrict, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. OG&E's facility is subject to acceleration upon the occurrence of any default, 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 $100.0 million or more in the aggregate, change of control (as defined in the 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.

At December 31, 2019, there were $304.8 million in advances to OGE Energy compared to $319.5 million at December 31, 2018. 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 March 8, 2023. At December 31, 2019, there were no intercompany borrowings under this agreement. 

OGE Energy's and OG&E's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with OGE Energy's and OG&E'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 and OG&E's short-term borrowings, but a reduction in OGE Energy's and OG&E's credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require OG&E to post collateral or letters of credit.

OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2019 and ending December 31, 2020.

13.Retirement Plans and Postretirement Benefit Plans

Pension Plan and Restoration of Retirement Income Plan

OG&E's employees participate in OGE Energy's 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 $20.0 million and $15.0 million contribution to its Pension Plan in 2019 and 2018, of which $5.0 million is related to OG&E in both 2019 and 2018. OGE Energy has not determined whether it will need to make any contributions to the Pension Plan in 2020. Any contribution to the Pension Plan during 2020 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. 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

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responsibility for the pension benefit obligation during the plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During 2019, 2018 and 2017, OG&E 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 OG&E recording pension plan settlement charges as presented in the net periodic benefit cost table below. The pension settlement charges did not require a cash outlay by OG&E and did not increase OG&E's total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.

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.

Obligations and Funded Status

The following table presents the status of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 2019 and 2018. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance Sheets as discussed in Note 1. The regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods. OG&E's portion of 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 OG&E's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2019 was $425.8 million and $4.8 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2018 was $417.6 million and $5.0 million, respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Balance Sheets are included in the following table.

	Pension Plan				Restoration of Retirement Income Plan				Postretirement Benefit Plans
December 31 (In millions)	2019		2018		2019		2018		2019		2018
Change in benefit obligation
Beginning obligations	$	453.6	$	510.6	$	6.0	$	4.2	$	104.8	$	115.8
Service cost	9.0		9.8		0.2		0.2		0.2		0.2
Interest cost	15.6		17.6		0.2		0.2		4.3		4.2
Plan settlements	(45.6)		(52.6)		(0.9)		(0.6)		—		—
Participants' contributions	—		—		—		—		3.0		2.9
Actuarial losses (gains)	42.1		(19.0)		0.6		2.0		2.2		(6.5)
Benefits paid	(12.7)		(12.8)		—		—		(9.8)		(11.8)
Ending obligations	$	462.0	$	453.6	$	6.1	$	6.0	$	104.7	$	104.8
Change in plans' assets
Beginning fair value	$	387.6	$	477.2	$	—	$	—	$	40.6	$	45.2
Actual return on plans' assets	64.8		(29.2)		—		—		4.0		(0.5)
Employer contributions	5.0		5.0		0.9		0.6		4.1		4.8
Plan settlements	(45.6)		(52.6)		(0.9)		(0.6)		—		—
Participants' contributions	—		—		—		—		3.0		2.9
Benefits paid	(12.7)		(12.8)		—		—		(9.8)		(11.8)
Ending fair value	$	399.1	$	387.6	$	—	$	—	$	41.9	$	40.6
Funded status at end of year	$	(62.9)	$	(66.0)	$	(6.1)	$	(6.0)	$	(62.8)	$	(64.2)

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Net Periodic Benefit Cost

The following table presents the net periodic benefit cost components, before consideration of capitalized amounts, of OG&E'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, and interest cost, expected return on plan assets, amortization of net loss, amortization of unrecognized prior service cost and settlement cost are presented within Other Net Periodic Benefit Expense in OG&E's 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 OG&E's Statements of Income.

	Pension Plan						Restoration of Retirement Income Plan						Postretirement Benefit Plans
Year Ended December 31 (In millions)	2019		2018		2017		2019		2018		2017		2019		2018		2017
Service cost	$	9.0	$	9.8	$	10.1	$	0.2	$	0.2	$	0.1	$	0.2	$	0.2	$	0.4
Interest cost	15.6		17.6		19.5		0.2		0.2		0.2		4.3		4.2		5.6
Expected return on plan assets	(27.6)		(33.1)		(32.8)		—		—		—		(1.7)		(1.8)		(2.0)
Amortization of net loss	12.9		12.1		13.0		0.3		0.5		0.4		2.1		3.8		1.9
Amortization of unrecognized prior service cost (A)	—		—		—		—		—		—		(6.1)		(6.1)		(2.5)
Settlement cost	16.4		19.4		11.7		0.5		0.4		—		—		—		0.4
Total net periodic benefit cost	26.3		25.8		21.5		1.2		1.3		0.7		(1.2)		0.3		3.8
Plus: Amount allocated from OGE Energy	4.5		5.7		—		0.5		1.2		—		(0.6)		(0.7)		—
Net periodic benefit cost	$	30.8	$	31.5	$	21.5	$	1.7	$	2.5	$	0.7	$	(1.8)	$	(0.4)	$	3.8

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

In addition to the net periodic benefit cost amounts recognized, as presented in the table above, for the Pension and Restoration of Retirement Income Plans in 2019, 2018 and 2017, OG&E recognized the following:

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

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

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

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

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

(In millions)	2019		2018		2017
Capitalized portion of net periodic pension benefit cost	$	3.0	$	3.2	$	3.4
Capitalized portion of net periodic postretirement benefit cost	$	0.1	$	0.1	$	1.1

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Rate Assumptions

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

N/A - not applicable

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

The overall expected rate of return on plan assets assumption was 7.50 percent in both 2019 and 2018, which was used in determining net periodic benefit cost due to recent returns on 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 7.00 percent in 2020 with the rates trending downward to 4.50 percent by 2030. The effects of a one-percentage point change in the assumed health care cost trend rate are presented in the following tables.

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

ONE-PERCENTAGE POINT DECREASE
Year Ended December 31 (In millions)	2019		2018		2017
Effect on aggregate of the service and interest cost components	$	—	$	—	$	—
Effect on accumulated postretirement benefit obligations	$	0.2	$	0.2	$	0.2

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Pension Plan

Pension Plan Investments, Policies and Strategies

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

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

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

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

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 OG&E's 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. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:

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

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The fixed income managers are expected to use discretion over the asset mix of the trust assets in their efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies or its instrumentalities (which have no limits), is limited to five percent of the fixed income portfolio as measured by market value. At least 75 percent of the invested assets must possess an investment-grade rating at or above Baa3 or BBB- by Moody's Investors Service, S&P's Global Ratings or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 15 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. The purchase of any of OGE Energy's equity, debt or other securities is prohibited.

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

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

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Pension Plan Investments

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

(In millions)	December 31, 2019		Level 1		Level 2		Net Asset Value (A)
Common stocks	$	202.0	$	202.0	$	—	$	—
U.S. Treasury notes and bonds (B)	134.8		134.8		—		—
Mortgage- and asset-backed securities	45.8		—		45.8		—
Corporate fixed income and other securities	130.5		—		130.5		—
Commingled fund (C)	23.9		—		—		23.9
Foreign government bonds	3.0		—		3.0		—
U.S. municipal bonds	1.1		—		1.1		—
Money market fund	7.5		—		—		7.5
Mutual fund	2.4		2.4		—		—
Preferred stocks	0.7		0.7		—		—
Futures:
U.S. Treasury futures (receivable)	22.9		—		22.9		—
U.S. Treasury futures (payable)	(10.9)		—		(10.9)		—
Cash collateral	0.6		0.6		—		—
Forward contracts:
Receivable (foreign currency)	0.1		—		0.1		—
Total Pension Plan investments	564.4		$	340.5	$	192.5	$	31.4
Interest and dividends receivable	2.4
Payable to broker for securities purchased	(36.5)
Pension Plan investments attributable to affiliates	(131.2)
Total Pension Plan assets	$	399.1

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

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

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

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(In millions)	December 31, 2018		Level 1		Level 2		Net Asset Value (A)
Common stocks	$	169.3	$	169.3	$	—	$	—
U.S. Treasury notes and bonds (B)	137.9		137.9		—		—
Mortgage- and asset-backed securities	65.9		—		65.9		—
Corporate fixed income and other securities	143.2		—		143.2		—
Commingled fund (C)	19.7		—		—		19.7
Foreign government bonds	4.4		—		4.4		—
U.S. municipal bonds	0.6		—		0.6		—
Money market fund	0.3		—		—		0.3
Mutual fund	8.0		8.0		—		—
Futures:
U.S. Treasury futures (receivable)	27.0		—		27.0		—
U.S. Treasury futures (payable)	(20.4)		—		(20.4)		—
Cash collateral	0.7		0.7		—		—
Forward contracts:
Receivable (foreign currency)	0.1		—		0.1		—
Total Pension Plan investments	556.7		$	315.9	$	220.8	$	20.0
Interest and dividends receivable	3.0
Payable to broker for securities purchased	(36.9)
Pension Plan investments attributable to affiliates	(135.2)
Total Pension Plan assets	$	387.6

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

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

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

As defined in the fair value hierarchy, Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan at the measurement date. Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

Expected Benefit Payments

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

(In millions)	Projected Benefit Payments
2020	$	44.6
2021	$	44.2
2022	$	42.5
2023	$	42.2
2024	$	42.0
After 2024	$	179.8

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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 OGE Energy's sponsored health reimbursement arrangement. OGE Energy's Medicare-eligible retirees are able to purchase individual insurance policies supplemental to Medicare through a third-party administrator and use their health reimbursement arrangement funds for reimbursement of medical premiums and other eligible medical expenses.

Postretirement Plans Investments

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

(In millions)	December 31, 2019		Level 1		Level 3
Group retiree medical insurance contract	$	34.8	$	—	$	34.8
Mutual funds	10.9		10.9		—
Money market fund	1.2		1.2		—
Total plan investments	46.9		$	12.1	$	34.8
Plan investments attributable to affiliates	(5.0)
Total plan assets	$	41.9

(In millions)	December 31, 2018		Level 1		Level 3
Group retiree medical insurance contract	$	36.0	$	—	$	36.0
Mutual funds	8.9		8.9		—
Cash	0.9		0.9		—
Total plan investments	45.8		$	9.8	$	36.0
Plan investments attributable to affiliates	(5.2)
Total plan assets	$	40.6

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

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

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

Medicare Prescription Drug, Improvement and Modernization Act of 2003

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

(In millions)	Gross Projected Postretirement Benefit Payments
2020	$	8.9
2021	$	8.9
2022	$	8.8
2023	$	7.4
2024	$	7.3
After 2024	$	32.4

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 OGE Energy's 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. OG&E's post-employment benefit obligation was $1.7 million at both December 31, 2019 and 2018.

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. 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) 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

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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. OG&E contributed $11.0 million, $9.8 million and $9.7 million in 2019, 2018 and 2017, respectively, to the 401(k) Plan.

Deferred Compensation Plan

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 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 2019, those investment options included an OGE Energy Common Stock fund, whose value was determined based on the stock price of OGE Energy's Common Stock.

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14.Commitments and Contingencies

Public Utility Regulatory Policy Act of 1978

OG&E had a QF contract with AES which expired on January 15, 2019 and a QF contract with Oklahoma Cogeneration LLC which expired on August 31, 2019. For the 320 MW AES QF contract and the 120 MW Oklahoma Cogeneration LLC QF contract, OG&E purchased 100 percent of the electricity generated by the QFs. In December 2018, OG&E announced its plan to acquire power plants from AES and Oklahoma Cogeneration LLC, pending regulatory approval, to meet customers' energy needs. In May 2019, OG&E received the necessary approval from the OCC and the FERC and conditional approval from the APSC to acquire both plants. In May 2019, OG&E acquired the power plant from AES, and in August 2019, OG&E acquired the power plant from Oklahoma Cogeneration LLC. In August 2019, OG&E received final approval from the APSC to acquire both plants. Further discussion can be found in Note 15.

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

Purchase Obligations and Commitments

OG&E's future purchase obligations and commitments estimated for the next five years are as follows: 

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

Minimum Purchase Commitments

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

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

Wind Purchase Commitments

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

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

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

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

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

Long-Term Service Agreement Commitments

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

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

Environmental Laws and Regulations

The activities of 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 its operations are in substantial compliance with current federal, state and local environmental standards.

Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.

Affordable Clean Energy Rule

On July 8, 2019, the EPA published the Affordable Clean Energy rule. Numerous parties, not including OG&E, have filed petitions for judicial review of the Affordable Clean Energy rule in the U.S. Court of Appeals for the District of Columbia Circuit. The Affordable Clean Energy rule requires states, including Oklahoma, to develop emission limitations for carbon dioxide for each existing coal-fired utility boiler within the state, including all of OG&E's coal units, and submit a compliance and implementation plan to the EPA by July 2022. The EPA will approve or disapprove the proposed state plan within 18 months of submittal and develop a federal implementation plan if the proposed state plan is disapproved. The ultimate timing and impact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO₂ emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect OG&E's 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, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, OG&E has incurred

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a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on currently available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows.

15.Rate Matters and Regulation

Regulation and Rates

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

The OCC and the APSC require that, among other things, (i) 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.

Completed Regulatory Matters

Arkansas 2018 Formula Rate Plan Filing

Per OG&E's settlement in its last general rate review, OG&E filed an evaluation report under its Formula Rate Plan in October 2018. On March 6, 2019, the APSC approved a settlement agreement for a $3.3 million revenue increase, and new rates were effective as of April 1, 2019.

Approval for Acquisition of Existing Power Plants

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

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

On April 24, 2019, OG&E filed an application with the APSC requesting approval of the acquisition, as well as depreciation rates, of the AES and Oklahoma Cogeneration LLC plants, and on May 8, 2019, OG&E received conditional approval for the purchase of the generating facilities. On August 30, 2019, the APSC issued an order finding that the plants to be acquired were used and useful and that the acquisition of the plants was in the public interest. The APSC also approved the depreciation rates to be applied to the acquired plants. The cost OG&E paid for the acquired plants was reviewed by the APSC in OG&E's 2019 Formula Rate Plan filing, and parties reached a settlement agreement requesting the APSC to approve the cost of the acquisitions. OG&E is awaiting a final decision from the APSC.

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

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Fuel Adjustment Clause Review for Calendar Year 2017

In July 2018, the OCC staff filed an application to review OG&E's fuel adjustment clause for the calendar year 2017, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On February 1, 2019, the Administrative Law Judge recommended that OG&E's processes, costs, investments and decisions regarding fuel procurement for the 2017 calendar year be found prudent. On May 22, 2019, the OCC deemed OG&E's electric generation, purchased power and fuel procurement costs to be materially prudent.

Oklahoma Rate Review Filing - December 2018

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

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

On July 1, 2019, OG&E implemented interim rates, which were subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate review. On September 19, 2019, the OCC issued a final order which approved the settlement agreement.

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

Fuel Adjustment Clause Review for Calendar Year 2018

In June 2019, the OCC staff filed an application to review OG&E's fuel adjustment clause for the calendar year 2018, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On December 12, 2019, the OCC issued an order deeming OG&E's electric generation, purchased power and fuel procurement costs were prudent.

FERC - Section 206 Filing

In January 2018, the Oklahoma Municipal Power Authority filed a complaint at the FERC stating that the base return on common equity used by OG&E in calculating formula transmission rates under the SPP Open Access Transmission Tariff is unjust and unreasonable and should be reduced from 10.60 percent to 7.85 percent, effective upon the date of the complaint. In addition to the request to reduce the return on equity, the Oklahoma Municipal Power Authority's complaint also requests that modifications be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act, including the 2017 Tax Act's impact on accumulated deferred income tax balances. In May 2019, all parties agreed to a settlement which provides for 10 percent base return on equity, plus a 50-basis point adder, and a five-year amortization period of the unprotected excess accumulated deferred income taxes associated with the 2017 Tax Act. On November 21, 2019, the FERC approved the settlement agreement.

Pending Regulatory Matters

Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates.

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FERC Order for Sponsored Transmission Upgrades within SPP

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

Several companies that were net payers of Z2 charges sought rehearing of the FERC's July 2016 order; however, in November 2017, the FERC denied the rehearing requests. In January 2018, one of the impacted companies appealed the FERC's decision to the U.S. Court of Appeals for the District of Columbia Circuit. In July 2018, that court granted a motion requested by the FERC that the case be remanded back to the FERC for further examination and proceedings. In February 2019, the FERC reversed its July 2016 order and November 2017 rehearing denial, ruled that SPP violated its tariff to charge for the 2008 - 2015 period in 2016, held that the SPP tariff provision that prohibited those charges could not be waived and ordered SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, on April 1, 2019, OG&E filed a request for rehearing with the FERC, and on May 24, 2019, OG&E filed a FERC 206 complaint against SPP, alleging that SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement and of the applicable tariff. OG&E's filing requested that the FERC rule that SPP is not entitled to seek refunds or in any other way seek to unwind the revenue credit payments it had paid to OG&E pursuant to the Sponsored Upgrade Agreement. SPP's response to OG&E's filing agreed that OG&E should be entitled to keep its Z2 payments and argued that SPP should not be held responsible for those payments if refunds are ordered. Further, SPP has requested the FERC to negotiate a global settlement with all impacted parties, including other project sponsors who, like OG&E, have also filed complaints at FERC contending that the payments they have received cannot properly be unwound.

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

OG&E cannot predict the outcome of this proceeding based on currently available information, and as of December 31, 2019 and at present time, OG&E has not reserved an amount for a potential refund. If the reversal of the July 2016 FERC order remains intact, OG&E estimates it would be required to refund $13.0 million, which is net of amounts paid to other utilities for upgrades and would be subject to interest at the FERC-approved rate. If refunds were required, recovery of these upgrade credits would shift to future periods. Of the $13.0 million, OG&E would be impacted by $5.0 million in expense that initially benefited OG&E in 2016, and OG&E customers would incur a net impact of $8.0 million in expense through rider mechanisms or the FERC formula rate.

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

APSC - Environmental Compliance Plan Rider

On May 31, 2019, OG&E filed an environmental compliance plan rider in Arkansas to recover its investment for the environmentally mandated costs associated with the Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas. The filing is an interim surcharge, subject to refund, that began with the first billing cycle of June 2019. OG&E is reserving the amounts collected through the interim surcharge, pending APSC approval of OG&E's filing. A hearing on the merits was held on December 17, 2019. The primary question before the APSC is whether a company can utilize an

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environmental compliance plan rider while also regulated under a formula rate plan. OG&E is awaiting a final decision from the APSC.

Arkansas 2019 Formula Rate Plan Filing

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

Oklahoma Grid Enhancement Plan

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

Oklahoma Retail Electric Supplier Certified Territory Act Causes

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

16.Quarterly Financial Data (Unaudited)

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

Quarter Ended (In millions)		March 31		June 30		September 30		December 31		Total
Operating revenues	2019	$	490.0	$	513.7	$	755.4	$	472.5	$	2,231.6
	2018	$	492.7	$	567.0	$	698.8	$	511.8	$	2,270.3
Operating income	2019	$	50.3	$	110.6	$	275.0	$	71.8	$	507.7
	2018	$	67.1	$	138.3	$	230.3	$	58.5	$	494.2
Net income	2019	$	19.6	$	74.5	$	227.2	$	28.9	$	350.2
	2018	$	31.3	$	92.0	$	183.9	$	20.8	$	328.0

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder and 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 & Electric Company (the Company) as of December 31, 2019 and 2018, the related statements of income, changes in stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and financial statement schedule listed in the Index at Item 15(a)(collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

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

Basis for Opinion

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

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

/s/ Ernst & Young LLP

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

Oklahoma City, Oklahoma

February 26, 2020

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

None.

Item 9A. Controls and Procedures.

OG&E maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by OG&E in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of OG&E's management, including the chief executive officer and chief financial officer, of the effectiveness of OG&E's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the chief executive officer and chief financial officer have concluded that OG&E's disclosure controls and procedures are effective.

No change in OG&E's internal control over financial reporting has occurred during OG&E's most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, OG&E's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).

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Management's Report on Internal Control Over Financial Reporting

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

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

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

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

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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, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Oklahoma Gas and Electric Company (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2019 financial statements of the Company and our report dated February 26, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

February 26, 2020

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Item 9B. Other Information.

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 address www.ogeenergy.com under the heading "Investors," "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.

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

Item 11. Executive Compensation.

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

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

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

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

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

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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	2019		2018
Integrated audit of OGE Energy and its subsidiaries financial statements and internal control over financial reporting	$	1,171,100	$	1,136,800
Services in support of debt and stock offerings	45,000		65,000
Other (A)	319,500		312,000
Total audit fees (B)	1,535,600		1,513,800
Employee benefit plan audits	149,000		144,000
Total audit-related fees	149,000		144,000
Assistance with examinations and other return issues	79,200		80,800
Review of federal and state tax returns	34,000		32,900
Total tax preparation and compliance fees	113,200		113,700
Total tax fees	113,200		113,700
Total fees	$	1,797,800	$	1,771,500

(A)Includes reviews of the financial statements included in OGE Energy's and OG&E's Quarterly Reports on Form 10-Q, audits of OGE Energy's subsidiaries, preparation for Audit Committee meetings and fees for consulting with OGE Energy's and OG&E's executives regarding accounting issues.

(B)The aggregate audit fees include fees billed for the audit of OGE Energy's and OG&E's annual financial statements and for the reviews of the financial statements included in OGE Energy's and OG&E's Quarterly Reports on Form 10-Q. For 2019, this amount includes estimated billings for the completion of the 2019 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 2019 and 2018 for other services.

Audit Committee Pre-Approval Procedures

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

For 2019, 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. 

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PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) 1. Financial Statements

The following Financial Statements are included in Part II, Item 8 of this Annual Report:

•Statements of Income for the years ended December 31, 2019, 2018 and 2017

•Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017

•Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017

•Balance Sheets at December 31, 2019 and 2018

•Statements of Capitalization at December 31, 2019 and 2018

•Statements of Changes in Stockholder's Equity for the years ended December 31, 2019, 2018 and 2017

•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)

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.

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3. Exhibits

Exhibit No.	Description
3.01	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).
3.02	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).
4.01	Trust Indenture dated October 1, 1995, from OG&E to Boatmen's First National Bank of Oklahoma, Trustee. (Filed as Exhibit 4.29 to OG&E's Registration Statement No. 33-61821 and incorporated by reference herein).
4.02	Supplemental Indenture No. 2, dated as of July 1, 1997, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed July 17, 1997 (File No. 33-1532) and incorporated by reference herein).
4.03	Supplemental Indenture No. 3, dated as of April 1, 1998, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed April 16, 1998 (File No. 33-1532) and incorporated by reference herein).
4.04	Supplemental Indenture No. 5 dated as of October 24, 2001, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.06 to OG&E's Registration Statement No. 333-104615 and incorporated by reference herein).
4.05	Supplemental Indenture No. 6 dated as of August 1, 2004, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed August 6, 2004 (File No 1-1097) and incorporated by reference herein).
4.06	Supplemental Indenture No. 7 dated as of January 1, 2006 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed January 6, 2006 (File No. 1-1097) and incorporated by reference herein).
4.07	Supplemental Indenture No. 8 dated as of January 15, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed January 31, 2008 (File No. 1-1097) and incorporated by reference herein).
4.08	Supplemental Indenture No. 9 dated as of September 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed September 9, 2008 (File No. 1-1097) and incorporated by reference herein).
4.09	Supplemental Indenture No. 10 dated as of December 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed December 11, 2008 (File No. 1-1097) and incorporated by reference herein).
4.10	Supplemental Indenture No. 11 dated as of June 1, 2010 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed June 8, 2010 (File No. 1-1097) and incorporated by reference herein).
4.11	Supplemental Indenture No. 12 dated as of May 15, 2011 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed May 27, 2011 (File No. 1-1097) and incorporated by reference herein).
4.12	Supplemental Indenture No. 13 dated as of May 1, 2013 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed May 13, 2013 (File No. 1-1097) and incorporated by reference herein).
4.13	Supplemental Indenture No. 14 dated as of March 15, 2014 being 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).
4.14	Supplemental Indenture No. 15 dated as of December 1, 2014 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed December 11, 2014 (File No. 1-1097) and incorporated by reference herein).
4.15	Supplemental Indenture No. 16 dated as of March 15, 2017 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed March 31, 2017 (File No. 1-1097) and incorporated by reference herein).
4.16	Supplemental Indenture No. 17 dated as of August 1, 2017 being 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).
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).

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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 OG&E's Form 8-K filed August 17, 2018 (File No. 1-1097) and incorporated by reference herein).
4.19	Supplemental Indenture No. 20 dated as of June 1, 2019 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed June 7, 2019 (File No. 1-01097) and incorporated by reference herein).
10.01	Amended and Restated Facility Operating Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.03 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein).
10.02	Amended and Restated Ownership and Operation Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein).
10.03	Operating and Maintenance Agreement for the Transmission Assets of the McClain Generating Facility dated as of August 25, 2003 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.05 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein).
10.04*	Form of Split Dollar Agreement. (Filed as Exhibit 10.32 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein).
10.05*	OGE Energy Supplemental Executive Retirement Plan, as amended and restated. (Filed as Exhibit 10.01 to OG&E's Form 10-Q for the quarter ended September 30, 2019 (File No. 1-01097) and incorporated by reference herein.
10.06*	OGE Energy Restoration of Retirement Income Plan, as amended and restated. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein).
10.07*	Form of Employment Agreement for all existing and future officers of OG&E relating to change of control. (Filed as Exhibit 10.28 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein).
10.08	Agreement, dated February 17, 2010, between OG&E and Oklahoma Department of Environmental Quality. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed February 23, 2010 (File No. 1-12579) and incorporated by reference herein).
10.09*	Amendment No. 1 to OGE Energy's Restoration of Retirement Income Plan. (Filed as Exhibit 10.40 to OGE Energy's Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein).
10.10*	OGE Energy's Director Compensation.
10.11*	OGE Energy's Executive Officer Compensation.
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).
10.13*	OGE Energy's 2013 Annual Incentive Compensation Plan. (Filed as Annex C to OGE Energy's Proxy Statement for the 2013 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein).
10.14*	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).
10.15*	Form of Restricted Stock Agreement under OGE Energy's 2013 Stock Incentive Plan. (Filed as Exhibit 10.01 to OG&E's Form 10-Q for the quarter ended March 31, 2019 (File No. 1-01097) and incorporated by reference herein).
10.16*	OGE Energy's Deferred Compensation Plan (As amended and restated effective October 1, 2016). (Filed as Exhibit 10.37 to OGE Energy's Form 10-K for the year ended December 31, 2016 (File No. 1-12579) and incorporated by reference herein).
10.17	Credit Agreement dated as of March 8, 2017 by and among Oklahoma Gas and Electric Company and JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Banks, Ltd., MUFG Union Bank, N.A., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to time parties thereto. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed March 8, 2017 (File No. 1-12579) and incorporated by reference herein).
10.18	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).

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10.19	Letter of extension dated as of March 9, 2018 for OG&E's and OGE Energy's credit agreements dated as March 8, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., Syndication Agent, Mizuho Bank, Ltd. MUFG Union Bank, N.A. Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, the Lenders thereto, and OG&E and OGE Energy, for their respective credit facility. (Filed as Exhibit 10.01 to OG&E's Form 10-Q for the quarter ended March 31, 2018 (File No. 1-1097) and incorporated by reference herein).
23.01	Consent of Ernst & Young LLP.
24.01	Power of Attorney.
31.01	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Copy of the APSC Settlement Agreement approval dated May 18, 2017. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed May 24, 2017 (File No. 1-12579) and incorporated by reference herein).
99.02	Copy of the Settlement Agreement filed with the OCC on May 24, 2019. (Filed as Exhibit 99.01 to OG&E's Form 8-K filed May 30, 2019 (File No. 1-01097) and incorporated by reference herein).
101.INS	Inline XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Taxonomy Schema Document.
101.PRE	Inline XBRL Taxonomy Presentation Linkbase Document.
101.LAB	Inline XBRL Taxonomy Label Linkbase Document.
101.CAL	Inline XBRL Taxonomy Calculation Linkbase Document.
101.DEF	Inline XBRL Definition Linkbase Document.
104	Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101).
* Represents executive compensation plans and arrangements.

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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, 2017
Reserve for Uncollectible Accounts	$	1.5	$	2.6	$	2.6	$	1.5
Balance at December 31, 2018
Reserve for Uncollectible Accounts	$	1.5	$	3.4	$	3.2	$	1.7
Balance at December 31, 2019
Reserve for Uncollectible Accounts	$	1.7	$	2.2	$	2.4	$	1.5

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

Item 16. Form 10-K Summary.

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on February 26th, 2020.

OKLAHOMA GAS AND ELECTRIC COMPANY
(Registrant)
By /s/	Sean Trauschke
	Sean Trauschke
	Chairman of the Board, President
	and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Sean Trauschke
Sean Trauschke	Principal Executive
	Officer and Director;	February 26, 2020
/s/ Stephen E. Merrill
Stephen E. Merrill	Principal Financial Officer;	February 26, 2020
/s/ Sarah R. Stafford
Sarah R. Stafford	Principal Accounting Officer.	February 26, 2020
Frank A. Bozich	Director;
James H. Brandi	Director;
Peter D. Clarke	Director;
Luke R. Corbett	Director;
David L. Hauser	Director;
Judy R. McReynolds	Director;
David E. Rainbolt	Director;
J. Michael Sanner	Director;
Sheila G. Talton	Director;

/s/ Sean Trauschke
By Sean Trauschke (attorney-in-fact)	February 26, 2020

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Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act.

The Registrant has not sent, and does not expect to send, an annual report or proxy statement to its security holders.

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