OGE Energy Earnings 2019-03-31

OGE 10Q Quarterly Report

Balance Sheet	Income Statement	Cash Flow

10-Q 1 q12019ogeenergy10-q.htm OGE ENERGY 10-Q Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2019

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

For the transition period from _____to_____

Commission File Number: 1-12579

OGE ENERGY CORP.

(Exact name of registrant as specified in its charter)



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

321 North Harvey

P.O. Box 321

Oklahoma City, Oklahoma 73101-0321

(Address of principal executive offices)

(Zip Code)

405-553-3000

(Registrant's telephone number, including area code)

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 þ	Accelerated filer o	Emerging growth company o
Non-accelerated filer o	Smaller reporting company o

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. o

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

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



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	OGE	New York Stock Exchange

At March 31, 2019, there were 200,174,701 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2019

TABLE OF CONTENTS



	Page
GLOSSARY OF TERMS	ii
FORWARD-LOOKING STATEMENTS	1

Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income	2
Condensed Consolidated Statements of Comprehensive Income	3
Condensed Consolidated Statements of Cash Flows	4
Condensed Consolidated Balance Sheets	5
Condensed Consolidated Statements of Changes in Stockholders' Equity	7
Notes to Condensed Consolidated Financial Statements	8

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3. Quantitative and Qualitative Disclosures About Market Risk	43

Item 4. Controls and Procedures	43

Part II - OTHER INFORMATION
Item 1. Legal Proceedings	44

Item 1A. Risk Factors	44

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	44

Item 6. Exhibits	44

Signature	45

GLOSSARY OF TERMS

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



Abbreviation	Definition
2018 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2018
2017 Tax Act	Tax Cuts and Jobs Act of 2017
AES	AES-Shady Point, Inc.
APSC	Arkansas Public Service Commission
ArcLight group	Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC, collectively
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO₂	Carbon dioxide
Company	OGE Energy Corp., collectively with its subsidiaries
CSAPR	Cross-State Air Pollution Rule
Dry Scrubber	Dry flue gas desulfurization unit with spray dryer absorber
Enable	Enable Midstream Partners, LP, a partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
Enogex Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex LLC	Enogex LLC, collectively with its subsidiaries (effective July 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
Federal Clean Water Act	Federal Water Pollution Control Act of 1972, as amended
FERC	Federal Energy Regulatory Commission
FIP	Federal Implementation Plan
GAAP	Accounting principles generally accepted in the U.S.
MATS	Mercury and Air Toxics Standards
MBbl/d	Thousand barrels per day
MW	Megawatt
MWh	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NGLs	Natural gas liquids
NO_X	Nitrogen oxide
OCC	Oklahoma Corporation Commission
OG&E	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Energy	Holding company
OGE Holdings	OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy, parent company of Enogex Holdings (prior to May 1, 2013) and 25.5 percent owner of Enable
Pension Plan	Qualified defined benefit retirement plan
QF	Qualified cogeneration facility
Regional Haze Rule	The EPA's Regional Haze Rule
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SIP	State Implementation Plan
SO₂	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day
U.S.	United States of America

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-Q, including those matters discussed within "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "intend," "objective," "plan," "possible," "potential," "project" and similar expressions. Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed within "Item 1A. Risk Factors" in the Company's 2018 Form 10-K and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:


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


•	the ability of the Company and its subsidiaries to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;


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


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


•	the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions Enable serves and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable's interstate pipelines;


•	the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering by Enable's gathering and processing business and transporting by Enable's interstate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regions Enable serves;


•	business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;


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


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


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

•

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


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


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


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


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


•	changes in accounting standards, rules or guidelines;


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


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


•	creditworthiness of suppliers, customers and other contractual parties;


•	social attitudes regarding the utility, natural gas and power industries;


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


•	increased pension and healthcare costs;


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


•	difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment in Enable that the Company does not control; and


•	other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission, including those listed within "Item 1A. Risk Factors" in the Company's 2018 Form 10-K.

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended March 31,
(In millions, except per share data)	2019			2018
OPERATING REVENUES
Revenues from contracts with customers	$	477.4		$	477.9
Other revenues	12.6			14.8
Operating revenues	490.0			492.7
COST OF SALES	212.6			210.5
OPERATING EXPENSES
Other operation and maintenance	119.0			112.7
Depreciation and amortization	82.4			78.8
Taxes other than income	26.3			24.1
Operating expenses	227.7			215.6
OPERATING INCOME	49.7			66.6
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	30.7			33.9
Allowance for equity funds used during construction	1.5			7.0
Other net periodic benefit expense	(7.0		)	(4.8		)
Other income	6.7			5.4
Other expense	(5.7		)	(4.4		)
Net other income	26.2			37.1
INTEREST EXPENSE
Interest on long-term debt	32.6			39.6
Allowance for borrowed funds used during construction	(1.0		)	(3.7		)
Interest on short-term debt and other interest charges	3.0			2.7
Interest expense	34.6			38.6
INCOME BEFORE TAXES	41.3			65.1
INCOME TAX (BENEFIT) EXPENSE	(5.8		)	10.1
NET INCOME	$	47.1		$	55.0
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.9			199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.5			200.2
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	0.24		$	0.28
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	0.24		$	0.27

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended March 31,
(In millions)	2019			2018
Net income	$	47.1		$	55.0
Other comprehensive income, net of tax:
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.2 and $0.2, respectively	0.7			0.7
Settlement cost, net of tax of $2.2 and $0.0, respectively	6.6			—
Postretirement Benefit Plans:
Amortization of prior service credit, net of tax of ($0.1) and ($0.1), respectively	(0.5		)	(0.5		)
Other comprehensive income, net of tax	6.8			0.2
Comprehensive income	$	53.9		$	55.2

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended March 31,
(In millions)	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	47.1		$	55.0
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	82.4			78.8
Deferred income taxes and investment tax credits, net	(0.5		)	7.3
Equity in earnings of unconsolidated affiliates	(30.7		)	(33.9		)
Distributions from unconsolidated affiliates	35.3			33.9
Allowance for equity funds used during construction	(1.5		)	(7.0		)
Stock-based compensation expense	3.0			2.7
Regulatory assets	(7.3		)	0.2
Regulatory liabilities	(7.0		)	2.6
Other assets	(3.8		)	0.6
Other liabilities	15.9			0.9
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	19.2			14.8
Fuel, materials and supplies inventories	9.1			(12.2		)
Fuel recoveries	(22.8		)	48.2
Other current assets	(11.0		)	8.3
Accounts payable	(42.6		)	(23.7		)
Other current liabilities	(55.9		)	(9.5		)
Net cash provided from operating activities	28.9			167.0
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(152.9		)	(137.4		)
Investment in unconsolidated affiliates	(1.0		)	(1.6		)
Return of capital - unconsolidated affiliates	—			1.4
Net cash used in investing activities	(153.9		)	(137.6		)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in short-term debt	366.4			25.5
Payment of long-term debt	(250.0		)	—
Dividends paid on common stock	(75.5		)	(66.6		)
Expense of common stock	(10.2		)	(0.4		)
Net cash provided from (used in) financing activities	30.7			(41.5		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(94.3		)	(12.1		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	94.3			14.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	2.3

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31,		December 31,
(In millions)	2019		2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	94.3
Accounts receivable, less reserve of $1.4 and $1.7, respectively	163.5		174.7
Accrued unbilled revenues	54.6		62.6
Income taxes receivable	15.2		9.9
Fuel inventories	48.3		57.6
Materials and supplies, at average cost	112.8		126.7
Fuel clause under recoveries	24.5		2.0
Other	35.2		29.5
Total current assets	454.1		557.3
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,173.9		1,177.5
Other	77.0		73.4
Total other property and investments	1,250.9		1,250.9
PROPERTY, PLANT AND EQUIPMENT
In service	12,326.7		11,994.8
Construction work in progress	156.6		376.4
Total property, plant and equipment	12,483.3		12,371.2
Less accumulated depreciation	3,713.9		3,727.4
Net property, plant and equipment	8,769.4		8,643.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	276.5		285.8
Other	10.7		10.8
Total deferred charges and other assets	287.2		296.6
TOTAL ASSETS	$	10,761.6	$	10,748.6

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)



	March 31,			December 31,
(In millions)	2019			2018
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	366.4		$	—
Accounts payable	194.1			239.3
Dividends payable	73.0			72.9
Customer deposits	83.7			83.6
Accrued taxes	26.2			44.0
Accrued interest	35.2			44.5
Accrued compensation	23.6			47.8
Long-term debt due within one year	—			250.0
Fuel clause over recoveries	—			0.3
Other	82.0			87.0
Total current liabilities	884.2			869.4
LONG-TERM DEBT	2,897.3			2,896.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	227.1			225.7
Deferred income taxes	1,319.5			1,310.9
Deferred investment tax credits	7.2			7.2
Regulatory liabilities	1,254.3			1,270.7
Other	195.8			162.7
Total deferred credits and other liabilities	3,003.9			2,977.2
Total liabilities	6,785.4			6,743.5
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,120.5			1,127.7
Retained earnings	2,877.8			2,906.3
Accumulated other comprehensive loss, net of tax	(22.1		)	(28.9		)
Total stockholders' equity	3,976.2			4,005.1
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	10,761.6		$	10,748.6

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(Unaudited)



(In millions)	Shares Outstanding	Common Stock		Premium on Common Stock			Retained Earnings			Accumulated Other Comprehensive (Loss) Income			Total
Balance at December 31, 2018	199.7	$	2.0	$	1,125.7		$	2,906.3		$	(28.9	)	$	4,005.1
Net income	—	—		—			47.1			—			47.1
Other comprehensive income net of tax	—	—		—			—			6.8			6.8
Dividends declared on common stock ($0.3650 per share)	—	—		—			(75.6		)	—			(75.6		)
Stock-based compensation	0.5	—		(7.2		)	—			—			(7.2		)
Balance at March 31, 2019	200.2	$	2.0	$	1,118.5		$	2,877.8		$	(22.1	)	$	3,976.2

Balance at December 31, 2017	199.7	$	2.0	$	1,112.8		$	2,759.5		$	(23.2	)	$	3,851.1
Net income	—	—		—			55.0			—			55.0
Other comprehensive income net of tax	—	—		—			—			0.2			0.2
Dividends declared on common stock ($0.3325 per share)	—	—		—			(66.5		)	—			(66.5		)
Stock-based compensation	—	—		2.3			—			—			2.3
Balance at March 31, 2018	199.7	$	2.0	$	1,115.1		$	2,748.0		$	(23.0	)	$	3,842.1

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

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.	Summary of Significant Accounting Policies

The Company's significant accounting policies are detailed in "Note 1. Summary of Significant Accounting Policies" in the Company's 2018 Form 10-K. Changes to the Company's accounting policies as a result of adopting ASU 2016-02, "Leases (Topic 842)," and the related ASU 2018-01 and ASU 2018-11 are discussed in Notes 2 and 4 in this Form 10-Q.

Organization

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

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

The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries and ultimately OGE Holdings. Enable was formed in 2013, and its general partner is equally controlled by the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company accounts for its interest in Enable using the equity method of accounting. Enable is primarily engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at March 31, 2019 and December 31, 2018, the consolidated results of its operations for the three months ended March 31, 2019 and 2018 and its consolidated cash flows for the three months ended March 31, 2019 and 2018 have been included and are of a normal, recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring after March 31, 2019 up to the date of issuance of these Condensed Consolidated Financial Statements, and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

Due to seasonal fluctuations and other factors, the Company's operating results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2018 Form 10-K.

Accounting Records

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

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

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



	March 31,		December 31,
(In millions)	2019		2018
REGULATORY ASSETS
Current:
Fuel clause under recoveries	$	24.5	$	2.0
Cogeneration credit rider over credit (A)	7.6		—
Production tax credit rider over credit (A)	6.6		6.9
Oklahoma demand program rider under recovery (A)	—		6.4
Other (A)	2.2		3.2
Total current regulatory assets	$	40.9	$	18.5
Non-current:
Benefit obligations regulatory asset	$	175.2	$	188.2
Deferred storm expenses	33.4		36.5
Smart Grid	23.8		25.6
Sooner Dry Scrubbers	12.5		4.5
Unamortized loss on reacquired debt	11.2		11.4
Arkansas deferred pension expenses	7.8		6.8
Other	12.6		12.8
Total non-current regulatory assets	$	276.5	$	285.8
REGULATORY LIABILITIES
Current:
Reserve for tax refund (B)	$	15.8	$	15.4
SPP cost tracker over recovery (B)	12.1		16.8
Oklahoma demand program rider over recovery (B)	3.3		—
Transmission cost recovery rider over recovery (B)	2.0		2.7
Fuel clause over recoveries	—		0.3
Other (B)	2.0		1.4
Total current regulatory liabilities	$	35.2	$	36.6
Non-current:
Income taxes refundable to customers, net	$	929.3	$	937.1
Accrued removal obligations, net	313.6		308.1
Pension tracker	4.9		18.7
Other	6.5		6.8
Total non-current regulatory liabilities	$	1,254.3	$	1,270.7


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


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

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

Investment in Unconsolidated Affiliates

The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable; therefore, the Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable at March 31, 2019 as presented in Note 13. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

The Company considers distributions received from Enable, which do not exceed cumulative equity in earnings subsequent to the date of investment, to be a return on investment and are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.

Accumulated Other Comprehensive Income (Loss)

The following tables summarize changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the three months ended March 31, 2019 and 2018. All amounts below are presented net of tax.



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net Income (Loss)			Prior Service Cost (Credit)		Net Income		Prior Service Cost (Credit)			Total
Balance at December 31, 2018	$	(38.8	)	$	—	$	4.6	$	5.3		$	(28.9	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.7			—		—		(0.5		)	0.2
Settlement cost	6.6			—		—		—			6.6
Balance at March 31, 2019	$	(31.5	)	$	—	$	4.6	$	4.8		$	(22.1	)



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net Income (Loss)			Prior Service Cost (Credit)		Net Income		Prior Service Cost (Credit)			Total
Balance at December 31, 2017	$	(32.7	)	$	—	$	2.5	$	7.0		$	(23.2	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.7			—		—		(0.5		)	0.2
Balance at March 31, 2018	$	(32.0	)	$	—	$	2.5	$	6.5		$	(23.0	)

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



Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)						Affected Line Item in the Condensed Consolidated Statements of Income
	Three Months Ended
	March 31,
(In millions)	2019			2018
Amortization of Pension Plan and Restoration of Retirement Income Plan items:
Actuarial losses (A)	$	(0.9	)	$	(0.9	)	Other Net Periodic Benefit Expense
Settlement cost (A)	(8.8		)	—			Other Net Periodic Benefit Expense
	(9.7		)	(0.9		)	Income Before Taxes
	(2.4		)	(0.2		)	Income Tax (Benefit) Expense
	$	(7.3	)	$	(0.7	)	Net Income

Amortization of postretirement benefit plans items:
Prior service credit (A)	$	0.6		$	0.6		Other Net Periodic Benefit Expense
	0.6			0.6			Income Before Taxes
	0.1			0.1			Income Tax (Benefit) Expense
	$	0.5		$	0.5		Net Income

Total reclassifications for the period, net of tax	$	(6.8	)	$	(0.2	)	Net Income


(A)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 12 for additional information).

Reclassifications

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


2.	Accounting Pronouncements

Recently Adopted Accounting Standards

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

The Company evaluated its current lease contracts and applied the 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. At January 1, 2019, the Company recognized $34.5 million and $39.1 million of operating lease right-of-use assets and liabilities, respectively, for railcar, wind farm land and office space leases in the

Condensed Consolidated Balance Sheet. The new standard did not have a material impact on the Company's 2019 Condensed Consolidated Statement of Income. Further, the Company evaluated its existing processes and controls regarding lease identification, accounting and presentation and implemented changes as necessary in order to adequately address the requirements of Topic 842.

In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842," which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that exist or expired before the entity's adoption of Topic 842 and that were not previously accounted for as leases under ASC 840, "Leases." Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. The Company elected this practical expedient during its adoption of Topic 842 and did not evaluate existing easement contracts under Topic 842, if these contracts had not previously been accounted for under Topic 840.

In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842): Targeted Improvements," which provides the following additional amendments to ASU 2016-02: (i) entities can elect to initially apply ASU 2016-02 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption and (ii) lessors can elect a practical expedient, by class of underlying asset, to account for nonlease components and the associated lease component as a single component, if the nonlease component otherwise would be accounted for under Topic 606 and certain conditions, as described in ASU 2018-11, are met. If an entity elects the additional (and optional) transition method, the entity will provide the required Topic 840 disclosures for all periods that continue to be reported under Topic 840. The Company elected the transition method provided by the guidance allowing for initial application at January 1, 2019.


3.	Revenue Recognition

The following table disaggregates the Company's revenues from contracts with customers by customer classification. The Company's operating revenues disaggregated by customer classification can be found in "OG&E (Electric Utility) Results of Operations" within "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations."



	Three Months Ended March 31,
(In millions)	2019			2018
Residential	$	191.2		$	196.3
Commercial	115.1			117.8
Industrial	43.1			41.7
Oilfield	38.9			33.7
Public authorities and street light	40.1			41.7
System sales revenues	428.4			431.2
Provision for rate refund	(0.1		)	(3.2		)
Integrated market	6.7			8.6
Transmission	36.1			35.8
Other	6.3			5.5
Revenues from contracts with customers	$	477.4		$	477.9


4.	Leases

The Company evaluates all contracts under Topic 842 to determine if the contract is or contains a lease and to determine classification as an operating or finance lease. If a lease is identified, the Company recognizes a right-of-use asset and a lease liability in its Consolidated Balance Sheets. The Company recognizes and measures a lease liability when it concludes the contract contains an identified asset that the Company controls through having the right to obtain substantially all of the economic benefits and the right to direct the use of the identified asset. The liability is equal to the present value of lease payments, and the asset is based on the liability, subject to adjustment, such as for initial direct costs. Further, the Company utilizes an incremental borrowing rate for purposes of measuring lease liabilities, if the discount rate is not implicit in the lease. To calculate the incremental borrowing rate, the Company starts with a current pricing report for the Company's senior unsecured notes, which indicates rates for periods reflective of the lease term, and adjusts for the effects of collateral to arrive at the secured incremental borrowing rate. As permitted

by Topic 842, the Company made an accounting policy election to not apply the balance sheet recognition requirements to short-term leases and to not separate lease components from nonlease components when recognizing and measuring lease liabilities. For income statement purposes, the Company records operating lease expense on a straight-line basis.

Based on its evaluation of all contracts under Topic 842, as described above, the Company concluded it has operating lease obligations for OG&E railcar leases, OG&E wind farm land leases and the Company's office space lease.

Operating Leases

OG&E Railcar Lease Agreement

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

OG&E Wind Farm Land Lease Agreements

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

Office Space Lease

The Company has a noncancellable office space lease agreement, with a term from September 1, 2018 to August 31, 2021, that allows for leasehold improvements.

Financial Statement Information

The following table presents amounts recognized for operating leases in the Company's Condensed Consolidated Financial Statements and supplemental information related to those amounts recognized.



Three Months Ended March 31 (Dollars in millions)	2019
LEASE COST
Operating lease cost	$	1.4

OTHER INFORMATION
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	3.2
Right-of-use assets obtained in exchange for new operating lease liabilities	$	10.7
Right-of-use assets at period end (A)	$	44.1
Operating lease liabilities at period end (B)	$	48.8
Operating lease weighted-average remaining lease term (in years)	13.5
Operating lease weighted-average discount rate	3.8		%

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

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

Maturity Analysis of Lease Liabilities

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



Three Months Ended March 31, 2019 (In millions)	Operating Lease Payments
2019 (excluding three months ended March 31)	$	2.5
2020	6.2
2021	5.9
2022	5.2
2023	5.1
Thereafter	37.8
Total lease payments	62.7
Less: imputed interest	13.9
Total	$	48.8

Comparative Period Disclosures

As discussed in Note 2, ASU 2018-11 permits entities who apply the optional Topic 842 transition method at adoption date to provide Topic 840 disclosures for all periods that continue to be reported in accordance with Topic 840. The Company elected to apply Topic 842 as of January 1, 2019; therefore, Topic 840 disclosures for the 2018 comparative period are included below. As disclosed in the Company's 2018 10-K, the Company's operating lease obligations included OG&E railcar leases, OG&E wind farm land leases and the Company's office space lease. As of December 31, 2018, future minimum payments for noncancellable operating leases were as follows:



Year Ended December 31 (In millions)	2019		2020		2021		2022		2023		Thereafter		Total
Operating lease obligations:
Railcars (A)	$	18.6	$	—	$	—	$	—	$	—	$	—	$	18.6
Wind farm land leases	2.5		2.9		2.9		2.9		2.9		37.6		51.7
Office space lease	1.0		1.0		0.6		—		—		—		2.6
Total operating lease obligations	$	22.1	$	3.9	$	3.5	$	2.9	$	2.9	$	37.6	$	72.9

(A) 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.

Payments for operating lease obligations were $4.9 million, $6.2 million and $9.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.


5.	Investment in Unconsolidated Affiliates and Related Party Transactions

In 2013, the Company, CenterPoint and the ArcLight group formed Enable as a private limited partnership, and the Company and the ArcLight group indirectly contributed 100 percent of the equity interests in Enogex LLC to Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and recorded the contribution at historical cost. The formation of Enable was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings was allocated to the assets acquired and liabilities assumed based on their fair value. Enogex Holdings' assets, liabilities and equity were accordingly adjusted to estimated fair value, resulting in an increase to Enable's equity of $2.2 billion. Since the contribution of Enogex LLC to Enable was recorded at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in the Company's recording of its equity in earnings of Enable.

At March 31, 2019, the Company owned 111.0 million common units, or 25.5 percent, of Enable's outstanding common units. On March 29, 2019, Enable's common unit price closed at $14.32. The Company recorded equity in earnings of

unconsolidated affiliates of $30.7 million and $33.9 million for the three months ended March 31, 2019 and 2018, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex LLC and its underlying equity in the net assets of Enable. The basis difference is being amortized, beginning in 2013, over the average life of the assets to which the basis difference is attributed, which is approximately 30 years. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above.

Summarized unaudited financial information for 100 percent of Enable is presented below at March 31, 2019 and December 31, 2018 and for the three months ended March 31, 2019 and 2018.



	March 31,		December 31,
Balance Sheet	2019		2018
(In millions)
Current assets	$	402	$	449
Non-current assets	$	12,045	$	11,995
Current liabilities	$	1,941	$	1,615
Non-current liabilities	$	2,923	$	3,211



	Three Months Ended
	March 31,
Income Statement	2019		2018
(In millions)
Total revenues	$	795	$	748
Cost of natural gas and NGLs	$	378	$	375
Operating income	$	165	$	139
Net income	$	113	$	105

The following table reconciles the Company's equity in earnings of unconsolidated affiliates for the three months ended March 31, 2019 and 2018.



	Three Months Ended
	March 31,
(In millions)	2019			2018
Enable net income	$	113.2		$	104.6
Differences due to timing of OGE Energy and Enable accounting close	0.1			—
Enable net income used to calculate OGE Energy's equity in earnings	$	113.3		$	104.6
OGE Energy's percent ownership at period end	25.5		%	25.6		%
OGE Energy's portion of Enable net income	$	28.9		$	26.8
Amortization of basis difference (A)	1.8			7.1
Equity in earnings of unconsolidated affiliates	$	30.7		$	33.9

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

The following table reconciles the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference) from December 31, 2018 to March 31, 2019.



(In millions)
Basis difference at December 31, 2018	$	680.3
Amortization of basis difference (A)	(9.9		)
Basis difference at March 31, 2019	$	670.4

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

On April 29, 2019, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common units, which is unchanged from the previous quarter. If cash distributions to Enable's unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of

that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable's cash distributions at the time of the exercise of this reset election.

Distributions received from Enable were $35.3 million during both the three months ended March 31, 2019 and 2018.

Related Party Transactions

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

The Company and Enable

The Company and Enable are currently parties to several agreements whereby the Company provides specified support services to Enable, such as certain information technology, payroll and benefits administration. Under these agreements, the Company charged operating costs to Enable of $0.1 million for both the three months ended March 31, 2019 and 2018.

Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of March 31, 2019, 88 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $12.4 million and $11.6 million during the three months ended March 31, 2019 and 2018, respectively, under the seconding agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by $12.7 million. Settlement and curtailment charges associated with the Enable seconded employees are not reimbursable to the Company by Enable. The seconding agreement can be terminated by mutual agreement of the Company and Enable or solely by the Company upon 120 days' notice.

The Company had accounts receivable from Enable for amounts billed for support services, including the cost of seconded employees, of $9.4 million as of March 31, 2019 and $1.7 million as of December 31, 2018, which are included in Accounts Receivable on the Company's Condensed Consolidated Balance Sheets.

OG&E and Enable

As discussed in the Company's 2018 Form 10-K, Enable provides gas transportation services to OG&E pursuant to an agreement that grants Enable the responsibility of delivering natural gas to OG&E's generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable's deliveries exceed OG&E's pipeline receipts. Enable purchases gas from OG&E when OG&E's pipeline receipts exceed Enable's deliveries. The following table summarizes related party transactions between OG&E and Enable during the three months ended March 31, 2019 and 2018.



	Three Months Ended
	March 31,
(In millions)	2019			2018
Operating revenues:
Electricity to power electric compression assets	$	3.8		$	4.0
Cost of sales:
Natural gas transportation services	$	14.8		$	8.8
Natural gas (sales) purchases	$	(1.0	)	$	0.3


6.	Fair Value Measurements

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

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

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

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

The Company had no financial instruments measured at fair value on a recurring basis at March 31, 2019 and December 31, 2018. The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy, with the exception of the Tinker Debt which is classified as Level 3 in the fair value hierarchy as its fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate. The following table summarizes the fair value and carrying amount of the Company's financial instruments at March 31, 2019 and December 31, 2018.



	March 31,				December 31,
	2019				2018
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term Debt (including Long-term Debt due within one year):
Senior Notes	$	2,752.3	$	2,989.5	$	3,001.9	$	3,178.2
OG&E Industrial Authority Bonds	$	135.4	$	135.4	$	135.4	$	135.4
Tinker Debt	$	9.6	$	9.1	$	9.6	$	8.7


7.	Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three months ended March 31, 2019 and 2018 related to the Company's performance units and restricted stock.



	Three Months Ended March 31,
(In millions)	2019		2018
Performance units:
Total shareholder return	$	2.2	$	2.0
Earnings per share	0.5		0.7
Total performance units	2.7		2.7
Restricted stock	0.3		—
Total compensation expense	$	3.0	$	2.7
Income tax benefit	$	0.8	$	0.7

During the three months ended March 31, 2019, the Company issued 442,386 shares of new common stock pursuant to the Company's Stock Incentive Plan to satisfy restricted stock grants and payouts of earned performance units.

During the three months ended March 31, 2019, the Company granted 206,139 performance units (based on total shareholder return over a three-year period) and 73,330 restricted stock units (three-year cliff vesting period) at $47.00 and $41.68 fair value per share, respectively.


8.	Income Taxes

The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local tax examinations by tax authorities for years prior to 2015. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and will be amortized to income over the life of the related property. OG&E earns both federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.


9.	Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three months ended March 31, 2019.

Earnings Per Share

Basic earnings per share is calculated by dividing net income attributable to the Company by the weighted-average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted-average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units and restricted stock units. The following table calculates basic and diluted earnings per share for the Company.



	Three Months Ended March 31,
(In millions except per share data)	2019		2018
Net income	$	47.1	$	55.0
Average common shares outstanding:
Basic average common shares outstanding	199.9		199.7
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.6		0.5
Diluted average common shares outstanding	200.5		200.2
Basic earnings per average common share	$	0.24	$	0.28
Diluted earnings per average common share	$	0.24	$	0.27
Anti-dilutive shares excluded from earnings per share calculation	—		—


10.	Long-Term Debt

At March 31, 2019, the Company was in compliance with all of its debt agreements.

OG&E Industrial Authority Bonds

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



SERIES			DATE DUE	AMOUNT
				(In millions)
1.43%	-	1.88%	Garfield Industrial Authority, January 1, 2025	$	47.0
1.35%	-	1.85%	Muskogee Industrial Authority, January 1, 2025	32.4
1.36%	-	1.86%	Muskogee Industrial Authority, June 1, 2027	56.0
Total (redeemable during next 12 months)				$	135.4

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


11.	Short-Term Debt and Credit Facilities

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. As of March 31, 2019, the Company had $366.4 million of short-term debt as compared to no short-term debt at December 31, 2018. The following table provides information regarding the Company's revolving credit agreements at March 31, 2019.



	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
(In millions)
OGE Energy (B)	$	450.0	$	366.4	2.76	%	(D)	March 8, 2023
OG&E (C)	450.0		0.3		1.05	%	(D)	March 8, 2023
Total	$	900.0	$	366.7	2.76	%


(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2019.


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


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


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

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or

accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit.

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


12.	Retirement Plans and Postretirement Benefit Plans

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during the plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During the first quarter of 2019, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement, which resulted in the Company recording a pension settlement charge of $19.7 million. The pension settlement charge did not require a cash outlay by the Company and did not increase the Company's total pension expense over time, as the charge was an acceleration of costs that otherwise would be recognized as pension expense in future periods.

Net Periodic Benefit Cost

The following table presents the net periodic benefit cost components, before consideration of capitalized amounts, of the Company's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the Condensed Consolidated Financial Statements. Service cost is presented within Other Operation and Maintenance, and interest cost, expected return on plan assets, amortization of net loss, amortization of unrecognized prior service cost and settlement cost are presented within Other Net Periodic Benefit Expense in the Company's Condensed Consolidated Statements of Income. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table in Note 1 and within Other Net Periodic Benefit Expense in the Company's Condensed Consolidated Statements of Income.



	Pension Plan						Restoration of Retirement Income Plan				Postretirement Benefit Plans
	Three Months Ended						Three Months Ended				Three Months Ended
	March 31,						March 31,				March 31,
(In millions)	2019 (B)			2018 (B)			2019 (B)		2018 (B)		2019 (B)			2018 (B)
Service cost	$	3.5		$	4.1		$	0.1	$	0.1	$	0.1		$	0.1
Interest cost	5.7			5.9			0.1		0.1		1.4			1.3
Expected return on plan assets	(8.7		)	(11.3		)	—		—		(0.5		)	(0.5		)
Amortization of net loss	3.8			3.9			0.1		0.1		0.6			1.0
Amortization of unrecognized prior service cost (A)	—			—			—		—		(2.1		)	(2.1		)
Settlement cost	19.7			—			—		—		—			—
Total net periodic benefit cost	24.0			2.6			0.3		0.3		(0.5		)	(0.2		)
Less: Amount paid by unconsolidated affiliates	0.9			0.5			—		—		(0.2		)	(0.1		)
Net periodic benefit cost	$	23.1		$	2.1		$	0.3	$	0.3	$	(0.3	)	$	(0.1	)


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


(B)	In addition to the $23.1 million and $2.3 million of net periodic benefit cost recognized during the three months ended March 31, 2019 and 2018, respectively, the Company recognized the following:


•	a decrease of pension expense of $1.0 million and an increase of $4.0 million during the three months ended March 31, 2019 and 2018, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1);


•	an increase in postretirement medical expense during the three months ended March 31, 2019 and 2018 of $0.3 million and $2.1 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1);


•	a deferral of pension expense during the three months ended March 31, 2019 of $11.2 million related to the pension settlement charge of $19.7 million in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and


•	a deferral of pension expense during the three months ended March 31, 2019 of $1.0 million related to the Arkansas jurisdictional portion of the pension settlement charge of $19.7 million (see Note 1).



	Three Months Ended
	March 31,
(In millions)	2019		2018
Capitalized portion of net periodic pension benefit cost	$	1.0	$	1.0
Capitalized portion of net periodic postretirement benefit cost	$	0.1	$	—


13.	Report of Business Segments

The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy and (ii) the natural gas midstream operations segment. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. The following tables summarize the results of the Company's business segments during the three months ended March 31, 2019 and 2018.



Three Months Ended March 31, 2019	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	490.0	$	—		$	—		$	—		$	490.0
Cost of sales	212.6		—			—			—			212.6
Other operation and maintenance	120.3		0.4			(1.7		)	—			119.0
Depreciation and amortization	82.4		—			—			—			82.4
Taxes other than income	24.4		0.2			1.7			—			26.3
Operating income (loss)	50.3		(0.6		)	—			—			49.7
Equity in earnings of unconsolidated affiliates	—		30.7			—			—			30.7
Other income (expense)	2.6		(7.4		)	0.7			(0.4		)	(4.5		)
Interest expense	32.4		—			2.6			(0.4		)	34.6
Income tax expense (benefit)	0.9		1.4			(8.1		)	—			(5.8		)
Net income	$	19.6	$	21.3		$	6.2		$	—		$	47.1
Investment in unconsolidated affiliates	$	—	$	1,162.0		$	11.9		$	—		$	1,173.9
Total assets	$	9,478.5	$	1,173.0		$	200.5		$	(90.4	)	$	10,761.6



Three Months Ended March 31, 2018	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	492.7	$	—		$	—		$	—		$	492.7
Cost of sales	210.5		—			—			—			210.5
Other operation and maintenance	113.6		0.3			(1.2		)	—			112.7
Depreciation and amortization	78.8		—			—			—			78.8
Taxes other than income	22.7		0.2			1.2			—			24.1
Operating income (loss)	67.1		(0.5		)	—			—			66.6
Equity in earnings of unconsolidated affiliates	—		33.9			—			—			33.9
Other income (expense)	4.5		—			(0.7		)	(0.6		)	3.2
Interest expense	37.3		—			1.9			(0.6		)	38.6
Income tax expense (benefit)	3.0		9.8			(2.7		)	—			10.1
Net income	$	31.3	$	23.6		$	0.1		$	—		$	55.0
Investment in unconsolidated affiliates	$	—	$	1,150.6		$	10.0		$	—		$	1,160.6
Total assets	$	9,303.3	$	1,159.0		$	98.3		$	(124.2	)	$	10,436.4


14.	Commitments and Contingencies

Except as set forth below, in Note 15 and under "Environmental Laws and Regulations" in Item 2 of Part I and in Item 1 of Part II of this Form 10-Q, the circumstances set forth in Notes 14 and 15 to the Consolidated Financial Statements included in the Company's 2018 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

Public Utility Regulatory Policy Act of 1978

As previously disclosed in the Company's 2018 Form 10-K, OG&E has a QF contract with Oklahoma Cogeneration LLC which expires on August 31, 2019. For this 120 MW contract, OG&E purchases 100 percent of the electricity generated. OG&E also had a 320 MW contract that expired on January 15, 2019, through which OG&E purchased 100 percent of the electricity generated.

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. Further discussion can be found in Note 15 under "Pre-Approval for Acquisition of Existing Power Plants."

Environmental Laws and Regulations

The activities of OG&E are subject to numerous stringent and complex federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways, including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of its operations are in substantial compliance with current federal, state and local environmental standards.

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

Other

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


15.	Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 15 to the Consolidated Financial Statements included in the Company's 2018 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

Arkansas Formula Rate Plan Filing

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

Pending Regulatory Matters

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

FERC - Section 206 Filing

In January 2018, the Oklahoma Municipal Power Authority filed a complaint at the FERC stating that the base return on common equity used by OG&E in calculating formula transmission rates under the SPP Open Access Transmission Tariff is unjust and unreasonable and should be reduced from 10.60 percent to 7.85 percent, effective upon the date of the complaint. In addition to the request to reduce the return on equity, the Oklahoma Municipal Power Authority's complaint also requests that modifications be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act, including the 2017 Tax Act's impact on accumulated deferred income tax balances. Pending resolution of this complaint at the FERC, OG&E is reserving amounts within this return on equity range as well as any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act.

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. Oral arguments on exceptions were heard by the OCC on April 16, 2019, and a final order from the OCC is expected to be forthcoming.

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. The filing also seeks 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. A hearing on the merits is scheduled for May 29, 2019.

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. As of March 31, 2019, OG&E has invested $511.3 million in the Dry Scrubbers and $56.2 million in the Muskogee natural gas conversion.

Pre-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 coal- and natural gas-fired plant from AES and a 146 MW natural gas-fired combined-cycle plant from Oklahoma Cogeneration LLC in 2019 for $53.5 million. The purchase of these assets is intended to replace capacity provided by power purchase contracts that have expired or are expiring in 2019 and to help OG&E satisfy its customers' energy needs and load obligations to the SPP. In addition, the filing seeks approval of a rider mechanism to collect costs associated with the purchase of these generating facilities. The Administrative Law Judge issued a supportive report on April 22, 2019. Oral arguments on exceptions are scheduled to be heard on May 8, 2019.

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. The application also requested an order by May 13, 2019. If approved, these plants would be included in OG&E's next formula rate filing on October 1, 2019.

On January 23, 2019, OG&E filed an application for Federal Power Act Section 203 approval with a request for expedited consideration. This application requests FERC's prior authorization to acquire the AES plant and the Oklahoma Cogeneration LLC plant. No parties have intervened in opposition to the application. On April 22, 2019, OG&E filed a supplement to its application with the FERC requesting an order by May 13, 2019.

FERC Order for Sponsored Transmission Upgrades within SPP

Under the SPP Open Access Transmission Tariff, costs of participant-funded, or "sponsored," transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP Open Access Transmission Tariff allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades due to 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 shared with customers through OG&E's various rate riders that include SPP activity with the remaining amounts retained by OG&E.

Several impacted companies sought rehearing of the FERC's July 2016 order; however, in November 2017, the FERC denied the rehearing requests. In January 2018, one of the impacted companies appealed the FERC's decision to the U.S. Court of Appeals for the District of Columbia. In July 2018, the U.S. Court of Appeals for the District of Columbia granted a motion requested by the FERC that the case be remanded back to the FERC for further examination and proceedings. In February 2019, the FERC reversed its July 2016 order and ordered SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, on April 1, 2019, OG&E filed a request for rehearing with the FERC. The Company cannot predict the outcome of this proceeding based on currently available information, and as of March 31, 2019 and at present time, the Company has not reserved an amount for a potential refund. If the reversal of the July 2016 FERC order remains intact, OG&E estimates it would be required to refund $21.0 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 $21.0 million, the Company would be impacted by $5.5 million in expense that initially benefited the Company in 2016, and OG&E customers would incur $15.5 million in expense through rider mechanisms.

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

Introduction

Overview

Company Strategy

The Company's mission, through OG&E and the Company's equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customer's needs for energy and related services, focusing on safety, efficiency, reliability, customer service and risk management. The Company's corporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and interest in a publicly traded midstream company, while providing competitive energy products and services to customers as well as seeking growth opportunities in both businesses.

Additionally, the Company wants to achieve a premium valuation of its businesses relative to its peers, grow earnings per share with a stable earnings pattern, create a high performance culture and achieve desired outcomes with target stakeholders. The Company's financial objectives include a long-term annual earnings growth rate for OG&E of four to six percent on a weather-normalized basis, maintaining a strong credit rating as well as targeting dividend increases of approximately 10 percent annually through 2019. The Company also utilizes cash distributions from its investment in Enable to help fund its capital needs and support future dividend growth. The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and having strong regulatory and legislative relationships.

Summary of Operating Results

Net income was $47.1 million, or $0.24 per diluted share, during the three months ended March 31, 2019 as compared to $55.0 million, or $0.27 per diluted share, during the same period in 2018. The decrease in net income of $7.9 million, or $0.03 per diluted share, is further discussed below.

•

A decrease in net income at OG&E of $11.7 million, or $0.06 per diluted share of the Company's common stock, was primarily due to increased other operation and maintenance expense, lower gross margin (driven by lower rates primarily resulting from lower income tax expense, partially offset by favorable weather) and increased depreciation and amortization expense due to additional assets being placed into service. This decrease was partially offset by lower interest expense driven by decreased long-term debt outstanding during 2019 and lower income tax expense.


•	A decrease in net income at OGE Holdings of $2.3 million was primarily due to higher other expense due to higher pension settlement charges for seconded Enable employees, partially offset by lower income tax expense due to favorable state tax rate adjustments.


•	An increase in net income of other operations of $6.1 million, or $0.03 per diluted share of the Company's common stock, was primarily due to higher income tax benefit related to higher stock-based compensation payouts in 2019 and higher other income, partially offset by higher interest expense.

Recent Developments and Regulatory Matters

Oklahoma Rate Review Filing - December 2018

Pre-Approval for Acquisition of Existing Power Plants

FERC Order for Sponsored Transmission Upgrades within SPP

In July 2016, the FERC granted SPP's request to recover the charges not billed for participant-funded transmission upgrades 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 shared with customers through OG&E's various rate riders that include SPP activity with the remaining amounts retained by OG&E. Several impacted companies sought rehearing of the FERC's July 2016 order, ultimately through the U.S. Court of Appeals for the District of Columbia, and in February 2019, the FERC reversed its July 2016 order and ordered SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, on April 1, 2019, OG&E filed a request for rehearing with the FERC. The Company cannot predict the outcome of this proceeding based on currently available information, and as of March 31, 2019 and at present time, the Company has not reserved an amount for a potential refund. If the reversal of the July 2016 FERC order remains intact, OG&E estimates it would be required to refund $21.0 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 $21.0 million, the Company would be impacted by $5.5 million in expense that initially benefited the Company in 2016, and OG&E customers would incur $15.5 million in expense through rider mechanisms.

Further discussion can be found in Note 15 within "Item 1. Financial Statements."

2019 Outlook

The Company's 2019 earnings guidance remains unchanged and is between $412 million to $442 million of net income, or $2.05 to $2.20 per average diluted share. The guidance assumes, among other things, approximately 201 million average diluted shares outstanding and normal weather for the year. See the Company's 2018 Form 10-K for other key factors and assumptions underlying its 2019 earnings guidance.

OG&E's Non-GAAP Financial Measures

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

Enable's Non-GAAP Financial Measures

Gross margin is defined by Enable as total revenues minus costs of natural gas and NGLs, excluding depreciation and amortization. Total revenues consist of the fees that Enable charges its customers and the sales price of natural gas and NGLs that Enable sells. The cost of natural gas and NGLs consists of the purchase price of natural gas and NGLs that Enable purchases. Enable deducts the cost of natural gas and NGLs from total revenues to arrive at a measure of the core profitability of their mix of fee-based and commodity-based customer arrangements. Gross margin allows for meaningful comparison of the operating results between Enable's fee-based revenues and Enable's commodity-based contracts which involve the purchase or sale of natural gas, NGLs and/or crude oil. In addition, the Company believes gross margin allows for a meaningful comparison of the results of Enable's commodity-based activities across different commodity price environments because it measures the spread between the product sales price and cost of products sold. Enable's definition of gross margin may be different from similar terms used by other companies. Further, gross margin is not intended to replace operating revenues as determined in accordance with GAAP as an indicator of operating performance. For a reconciliation of gross margin to revenue, which is the most directly comparable financial measure calculated and presented in accordance with GAAP, for the three months ended March 31, 2019 and 2018, see "OGE Holdings (Natural Gas Midstream Operations) Results of Operations" below.

Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the three months ended March 31, 2019 as compared to the same period in 2018 and the Company's consolidated financial position at March 31, 2019. Due to seasonal fluctuations and other factors, the Company's operating results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 or for any future period. The following information should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.



	Three Months Ended
	March 31,
(In millions except per share data)	2019		2018
Net income	$	47.1	$	55.0
Basic average common shares outstanding	199.9		199.7
Diluted average common shares outstanding	200.5		200.2
Basic earnings per average common share	$	0.24	$	0.28
Diluted earnings per average common share	$	0.24	$	0.27
Dividends declared per common share	$	0.36500	$	0.33250

Results by Business Segment



	Three Months Ended
	March 31,
(In millions)	2019		2018
Net income:
OG&E (Electric Utility)	$	19.6	$	31.3
OGE Holdings (Natural Gas Midstream Operations)	21.3		23.6
Other operations (A)	6.2		0.1
Consolidated net income	$	47.1	$	55.0


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

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

OG&E (Electric Utility)



	Three Months Ended
	March 31,
(Dollars in millions)	2019			2018
Operating revenues	$	490.0		$	492.7
Cost of sales	212.6			210.5
Other operation and maintenance	120.3			113.6
Depreciation and amortization	82.4			78.8
Taxes other than income	24.4			22.7
Operating income	50.3			67.1
Allowance for equity funds used during construction	1.5			7.0
Other net periodic benefit income (expense)	0.4			(4.8		)
Other income	1.4			3.1
Other expense	0.7			0.8
Interest expense	32.4			37.3
Income tax expense	0.9			3.0
Net income	$	19.6		$	31.3
Operating revenues by classification:
Residential	$	195.4		$	202.1
Commercial	119.9			122.7
Industrial	44.5			43.1
Oilfield	39.7			34.6
Public authorities and street light	41.5			43.5
Sales for resale	—			0.1
System sales revenues	441.0			446.1
Provision for rate refund	(0.1		)	(3.2		)
Integrated market	6.7			8.6
Transmission	36.1			35.8
Other	6.3			5.4
Total operating revenues	$	490.0		$	492.7
Reconciliation of gross margin to revenue:
Operating revenues	$	490.0		$	492.7
Cost of sales	212.6			210.5
Gross margin	$	277.4		$	282.2
MWh sales by classification (In millions)
Residential	2.4			2.4
Commercial	1.8			1.7
Industrial	0.9			0.9
Oilfield	0.9			0.8
Public authorities and street light	0.7			0.7
System sales	6.7			6.5
Integrated market	0.3			0.3
Total sales	7.0			6.8
Number of customers	852,141			843,322
Weighted-average cost of energy per kilowatt-hour (In cents)
Natural gas	3.064			2.794
Coal	1.958			2.007
Total fuel	2.306			2.072
Total fuel and purchased power	2.868			2.941
Degree days (A)
Heating - Actual	2,084			1,880
Heating - Normal	1,798			1,798
Cooling - Actual	—			10
Cooling - Normal	13			13

(A)

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

OG&E's net income decreased $11.7 million, or 37.4 percent, during the three months ended March 31, 2019, as compared to the same period in 2018. The decrease was primarily due to lower gross margin, increased other operation and maintenance expense and increased depreciation and amortization expense. This decrease was partially offset by lower interest expense.

Gross margin decreased $4.8 million, or 1.7 percent, during the three months ended March 31, 2019, as compared to the same period in 2018. The below factors contributed to the change in gross margin.



(In millions)	$ Change
Price variance (A)	$	(10.4	)
Non-residential demand and related revenue	(1.2		)
Weather (price and quantity) (B)	3.1
New customer growth	2.1
Other	1.6
Change in gross margin	$	(4.8	)


(A)	Change was primarily driven by the implementation of new rate design, which included moving production tax credits from base rates into a rider mechanism and reflecting lower income tax expense within base rates resulting from 2017 Tax Act impacts.


(B)	Increased primarily due to an 11 percent increase in heating degree days.

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 increased $2.1 million, or 1.0 percent, during the three months ended March 31, 2019, as compared to the same period in 2018. The below factors contributed to the change in cost of sales.



(In millions)	$ Change		% Change
Fuel expense (A)	$	14.0	18.2	%
Purchased power costs:
Purchases from SPP (B)	11.5		16.2	%

Closing Price ($)	Shares Out (MM)	Market Cap ($MM)
$40.65	200	$8,140

10-Q	2019-03-31	Quarter: 2019-03-31
10-Q	2019-03-31	Quarter: 2019-03-31
10-K	2018-12-31	Annual: 2018-12-31
10-K	2018-12-31	Annual: 2018-12-31
10-Q	2018-09-30	Quarter: 2018-09-30
10-Q	2018-06-30	Quarter: 2018-06-30
10-Q	2018-03-31	Quarter: 2018-03-31
10-K	2017-12-31	Annual: 2017-12-31
10-Q	2017-09-30	Quarter: 2017-09-30
10-Q	2017-06-30	Quarter: 2017-06-30
10-Q	2017-03-31	Quarter: 2017-03-31
10-K	2016-12-31	Annual: 2016-12-31
10-Q	2016-09-30	Quarter: 2016-09-30
10-Q	2016-06-30	Quarter: 2016-06-30
10-Q	2016-03-31	Quarter: 2016-03-31
10-K	2015-12-31	Annual: 2015-12-31
10-Q	2015-09-30	Quarter: 2015-09-30
10-Q	2015-06-30	Quarter: 2015-06-30
10-Q	2015-03-31	Quarter: 2015-03-31
10-K	2014-12-31	Annual: 2014-12-31
10-Q	2014-09-30	Quarter: 2014-09-30
10-Q	2014-06-30	Quarter: 2014-06-30
10-Q	2014-03-31	Quarter: 2014-03-31
10-K	2013-12-31	Annual: 2013-12-31

8-K	2019-06-07	Other Events, Exhibits
8-K	2019-06-07	Other Events, Exhibits
8-K	2019-05-30	Other Events, Exhibits
8-K	2019-05-30	Other Events, Exhibits
8-K	2019-05-16	Shareholder Vote, Other Events
8-K	2019-05-02	Earnings, Exhibits
8-K	2019-05-02	Earnings, Exhibits
8-K	2019-02-21	Earnings, Exhibits
8-K	2018-11-08	Earnings, Exhibits
8-K	2018-08-17	Other Events, Exhibits
8-K	2018-08-09	Earnings, Exhibits
8-K	2018-06-19	Other Events
8-K	2018-05-17	Other Events, Exhibits
8-K	2018-03-14	Enter Agreement

ABC	Amerisourcebergen	16,640
DBX	Dropbox	9,900
COKE	Coca Cola Bottling	3,460
FLIC	First of Long Island	559
KOPN	Kopin	104
BNGO	Bionano Genomics	40
SPS	Southwestern Public Service	0
YEWB	Yew Bio-Pharm	0
SFOR	Strikeforce Technologies	0
GLNS	Golden Star Resource	0

EX-10.01	q12019oge10-qxex1001.htm
EX-31.01	q12019oge10-qxex3101.htm
EX-32.01	q12019oge10-qxex3201.htm