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, 2016

OR

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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, or a smaller reporting company.  See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer  þ	Accelerated filer o
Non-accelerated filer    o (Do not check if a smaller reporting company)	Smaller reporting company  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

At March 31, 2016, there were 199,701,852 shares of common stock, par value $0.01 per share, outstanding.

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OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2016

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS	ii
FORWARD-LOOKING STATEMENTS	1
Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)	2
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	25
Item 3. Quantitative and Qualitative Disclosures About Market Risk	41
Item 4. Controls and Procedures	42
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	43
Item 1A. Risk Factors	43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 6. Exhibits	46
Signatures	47

i

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GLOSSARY OF TERMS

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

Abbreviation	Definition
2015 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2015
ALJ	Administrative Law Judge
APSC	Arkansas Public Service Commission
ArcLight group	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
ASU	Financial Accounting Standards Board Accounting Standards Update
AVEC	Arkansas Valley Electric Cooperative Corporation
BART	Best available retrofit technology
CSAPR	Cross-State Air Pollution Rule
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned Subsidiary of CenterPoint Energy, Inc.
CO2	Carbon dioxide
Company	OGE Energy Corp. collectively with its subsidiaries and Enable Midstream Partners
Dry Scrubbers	Dry flue gas desulfurization units with spray dryer absorber
ECP	Environmental Compliance Plan
Enable	Enable Midstream Partners, LP, partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
Enogex Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings LLC (prior to May 1, 2013)
Enogex LLC	Enogex LLC collectively with its subsidiaries (effective June 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
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 United States
IRP	Integrated Resource Plans
MATS	Mercury and Air Toxics Standards
Mustang Modernization Plan	OG&E's plan to replace the soon-to-be retired Mustang steam turbines in late 2017 with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019
MW	Megawatt
NAAQS	National Ambient Air Quality Standards
NGLs	Natural gas liquids
NOX	Nitrogen oxide
OCC	Oklahoma Corporation Commission
Off-system sales	Sales to other utilities and power marketers
OG&E	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy Corp.
OGE Holdings	OGE Enogex Holdings LLC, wholly-owned subsidiary of OGE Energy Corp., parent company of Enogex Holdings (prior to May 1, 2013) and 26.3 percent owner of Enable Midstream Partners
Pension Plan	Qualified defined benefit retirement plan
Ppb	Parts per billion
PUD	Public Utility Division of the Oklahoma Corporation Commission
Regional Haze	The EPA's regional haze rule
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
Stock Incentive Plan	2013 Stock Incentive Plan
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day

ii

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FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-Q, including those matters discussed in "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 in "Item 1A. Risk Factors" in the Company's 2015 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;

•	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;

•	unusual weather;

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

•	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 and regulations that may impact the Company's operations;

•	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 cyber attacks and other catastrophic events;

•	advances in technology;

•	creditworthiness of suppliers, customers and other contractual parties;

•	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 in "Item 1A. Risk Factors" and in Exhibit 99.01 in the Company's 2015 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.

1

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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)	2016			2015
OPERATING REVENUES	$	433.1		$	480.1
COST OF SALES	177.9			211.6
OPERATING EXPENSES
Other operation and maintenance	113.9			111.7
Depreciation and amortization	78.5			75.9
Taxes other than income	24.9			24.5
Total operating expenses	217.3			212.1
OPERATING INCOME	37.9			56.4
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	28.3			31.7
Allowance for equity funds used during construction	1.6			1.5
Other income	5.6			4.9
Other expense	(1.7		)	(1.0		)
Net other income	33.8			37.1
INTEREST EXPENSE
Interest on long-term debt	35.8			36.9
Allowance for borrowed funds used during construction	(0.9		)	(0.8		)
Interest on short-term debt and other interest charges	1.4			1.3
Interest expense	36.3			37.4
INCOME BEFORE TAXES	35.4			56.1
INCOME TAX EXPENSE	10.2			12.9
NET INCOME	$	25.2		$	43.2
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7			199.5
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.7			199.5
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	0.13		$	0.22
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	0.13		$	0.22
DIVIDENDS DECLARED PER COMMON SHARE	$	0.27500		$	0.25000

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions)	2016			2015
Net income	$	25.2		$	43.2
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.4 and $0.8, respectively	0.8			0.4
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.0 and $0.2, respectively	—			0.2
Amortization of prior service cost, net of tax of ($0.2) and ($0.3), respectively	(0.4		)	(0.4		)
Other comprehensive income, net of tax	0.4			0.2
Comprehensive income	$	25.6		$	43.4

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	25.2		$	43.2
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	78.5			75.9
Deferred income taxes and investment tax credits	10.4			13.0
Equity in earnings of unconsolidated affiliates	(28.3		)	(31.7		)
Distributions from unconsolidated affiliates	28.7			34.3
Allowance for equity funds used during construction	(1.6		)	(1.5		)
Stock-based compensation	1.7			0.5
Regulatory assets	(2.3		)	2.7
Regulatory liabilities	(4.6		)	(0.7		)
Other assets	2.5			(0.8		)
Other liabilities	2.1			(0.1		)
Change in certain current assets and liabilities
Accounts receivable, net	38.0			19.6
Accounts receivable - unconsolidated affiliates	(1.2		)	(1.0		)
Accrued unbilled revenues	2.1			9.0
Fuel, materials and supplies inventories	10.2			(23.9		)
Fuel clause under recoveries	—			41.3
Other current assets	(10.0		)	1.3
Accounts payable	(44.1		)	(15.1		)
Fuel clause over recoveries	2.0			—
Other current liabilities	(35.9		)	(26.4		)
Net Cash Provided from Operating Activities	73.4			139.6
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(177.7		)	(108.8		)
Return of capital - equity method investments	6.6			—
Proceeds from sale of assets	—			0.1
Net Cash Used in Investing Activities	(171.1		)	(108.7		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock	—			3.1
Dividends paid on common stock	(54.9		)	(49.9		)
Payment of long-term debt	(110.1		)	—
Increase in short-term debt	187.5			11.9
Net Cash Provided from (Used in) Financing Activities	22.5			(34.9		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(75.2		)	(4.0		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	75.2			5.5
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	1.5

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—		$	75.2
Accounts receivable, less reserve of $1.0 and $1.4, respectively	135.1			173.1
Accounts receivable - unconsolidated affiliates	2.9			1.7
Accrued unbilled revenues	51.4			53.5
Income taxes receivable	17.4			17.2
Fuel inventories	105.4			113.8
Materials and supplies, at average cost	78.3			80.1
Other	65.4			55.6
Total current assets	455.9			570.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,187.4			1,194.4
Other	69.5			70.7
Total other property and investments	1,256.9			1,265.1
PROPERTY, PLANT AND EQUIPMENT
In service	10,415.7			10,318.3
Construction work in progress	300.1			278.5
Total property, plant and equipment	10,715.8			10,596.8
Less accumulated depreciation	3,328.3			3,274.4
Net property, plant and equipment	7,387.5			7,322.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	402.8			402.2
Other	20.2			20.7
Total deferred charges and other assets	423.0			422.9
TOTAL ASSETS	$	9,523.3		$	9,580.6

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)

(In millions)	March 31, 2016			December 31, 2015
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	187.5		$	—
Accounts payable	172.7			262.5
Dividends payable	54.9			54.9
Customer deposits	77.9			77.0
Accrued taxes	24.7			45.9
Accrued interest	32.9			42.9
Accrued compensation	55.6			54.4
Long-term debt due within one year	—			110.0
Fuel clause over recoveries	63.2			61.3
Other	37.1			43.9
Total current liabilities	706.5			752.8
LONG-TERM DEBT	2,629.3			2,628.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	298.2			299.9
Deferred income taxes	2,188.1			2,178.2
Regulatory liabilities	278.3			273.6
Other	124.6			121.3
Total deferred credits and other liabilities	2,889.2			2,873.0
Total liabilities	6,225.0			6,254.6
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,102.9			1,101.3
Retained earnings	2,230.1			2,259.8
Accumulated other comprehensive loss, net of tax	(34.7		)	(35.1		)
Total stockholders' equity	3,298.3			3,326.0
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,523.3		$	9,580.6

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(Unaudited)

(In millions)	Common Stock			Premium on Common Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance at December 31, 2015	$	2.0		$	1,099.3		$	2,259.8		$	(35.1	)	$	3,326.0
Net income	—			—			25.2			—			25.2
Other comprehensive income, net of tax	—			—			—			0.4			0.4
Dividends declared on common stock	—			—			(54.9		)	—			(54.9		)
Stock-based compensation	—			1.6			—			—			1.6
Balance at March 31, 2016	$	2.0		$	1,100.9		$	2,230.1		$	(34.7	)	$	3,298.3

Balance at December 31, 2014	$	2.0		$	1,085.6		$	2,198.2		$	(41.4	)	$	3,244.4
Net income	—			—			43.2			—			43.2
Other comprehensive income, net of tax	—			—			—			0.2			0.2
Dividends declared on common stock	—			—			(49.9		)	—			(49.9		)
Issuance of common stock	—			3.2			—			—			3.2
Stock-based compensation	—			0.7			—			—			0.7
Balance at March 31, 2015	$	2.0		$	1,089.5		$	2,191.5		$	(41.2	)	$	3,241.8

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

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OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	Summary of Significant Accounting Policies

Organization

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. 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 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 its wholly owned subsidiary OGE Holdings. Enable is 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 from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns a crude oil gathering business in the Bakken shale formation, principally located in the Williston basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

Enable was formed effective May 1, 2013 by the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group contributed Enogex LLC to Enable and the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable. The Company's contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by CenterPoint and the Company, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.

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, 2016 and December 31, 2015, the results of its operations and cash flows for the three months ended March 31, 2016 and 2015, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company's operating results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 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 2015 Form 10-K.

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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.

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

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 at:

(In millions)	March 31, 2016			December 31, 2015
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	37.4		$	36.6
Other (A)	13.4			9.9
Total Current Regulatory Assets	$	50.8		$	46.5
Non-Current
Benefit obligations regulatory asset	$	240.0		$	242.2
Income taxes recoverable from customers, net	56.8			56.7
Smart Grid	43.6			43.6
Deferred storm expenses	30.9			27.6
Unamortized loss on reacquired debt	14.4			14.8
Other	17.1			17.3
Total Non-Current Regulatory Assets	$	402.8		$	402.2
Regulatory Liabilities
Current
Fuel clause over recoveries	$	63.2		$	61.3
Other (B)	3.7			7.5
Total Current Regulatory Liabilities	$	66.9		$	68.8
Non-Current
Accrued removal obligations, net	$	255.3		$	254.9
Pension tracker	22.0			17.7
Other (C)	1.0			1.0
Total Non-Current Regulatory Liabilities	$	278.3		$	273.6

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

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

(C)	Prior year amount of $1.0 million reclassified from deferred other liabilities to Non-Current Regulatory Liabilities.

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, which could have significant financial effects.

              

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Investment in Unconsolidated Affiliate

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. 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 adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheets at March 31, 2016. 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 which 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 which are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.

Asset Retirement Obligations

The following table summarizes changes to the Company's asset retirement obligations during the three months ended March 31, 2016 and 2015.

	Three Months Ended March 31,
(In millions)	2016			2015
Balance at January 1	$	63.3		$	58.6
Accretion expense	0.7			0.6
Liabilities settled	—			(0.3		)
Balance at March 31	$	64.0		$	58.9

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Accumulated Other Comprehensive Income (Loss)

 

The following tables summarize changes in the components of accumulated other comprehensive income (loss) during the three months ended March 31, 2016 and 2015. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan							Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost				Net loss			Prior service cost			Total
Balance at December 31, 2015	$	(39.2	)	$	0.1			$	2.5		$	1.5		$	(35.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.8			—				—			(0.4		)	0.4
Balance at March 31, 2016	$	(38.4	)	$	0.1			$	2.5		$	1.1		$	(34.7	)

	Pension Plan and Restoration of Retirement Income Plan							Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost				Net loss			Prior service cost			Total
Balance at December 31, 2014	$	(36.8	)	$	0.1			$	(8.0	)	$	3.3		$	(41.4	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.4			—				0.2			(0.4		)	0.2
Balance at March 31, 2015	$	(36.4	)	$	0.1			$	(7.8	)	$	2.9		$	(41.2	)

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, 2016 and 2015.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended March 31,
(In millions)	2016			2015
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.2	)	$	(1.2	)	(A)
	(0.4		)	(0.8		)	Tax benefit
	$	(0.8	)	$	(0.4	)	Net of tax
Amortization of postretirement benefit plan items
Actuarial losses	$	—		$	(0.4	)	(A)
Prior service cost	0.6			0.7			(A)
	0.6			0.3			Total before tax
	0.2			0.1			Tax expense
	$	0.4		$	0.2		Net of tax
Total reclassifications for the period	$	(0.4	)	$	(0.2	)	Net of tax

(A)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

 

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Reclassifications

Prior periods have been adjusted for the reclassification of $16.8 million of debt issuance costs from total deferred charges and other assets to Long-Term Debt in the Condensed Consolidated Balance Sheets to be consistent with the 2016 presentation due to the adoption of ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," as of March 31, 2016.

2.	Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)". The new guidance was intended to be effective for fiscal years beginning after December 15, 2016. On July 9, 2015, the FASB decided to delay the effective date of the new revenue standard by one year. Reporting entities may choose to adopt the standard as of the original effective date. The deferral results in the new revenue standard being effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has yet to select a transition method or determine the impact on its Condensed Consolidated Financial Statements, however, the impact is not expected to be material.

Consolidation. In February 2015, the FASB issued ASU 2015-02, "Consolidation (Topic 810)". The amendments in ASU 2015-02 affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. The new standard modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities along with eliminating the presumption that a general partner should consolidate a limited partnership. The new standard is effective for fiscal years beginning after December 15, 2015. The adoption of this new standard did not result in the consolidation of any non-consolidated entities.

Leases. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”. The main difference between current lease accounting and Topic 842 is the recognition of right-to-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance. Lessees, such as the Company, will need to 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 will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to current capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in current lease guidance, but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 2018. The new guidance must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company has not determined the impact on its Condensed Consolidated Financial Statements, but anticipates an increase in the recognition of right-of-use assets and lease liabilities.

Investments. In March 2016, the FASB issued ASU 2016-07, "Investments-Equity Method and Joint Ventures; Simplifying the Transition to the Equity Method of Accounting (Topic 323)." The amendments in ASU 2016-07 eliminate the requirement to retroactively adopt the equity method of accounting for a qualifying equity method investment. ASU 2016-07 requires equity method investors to add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendments in this ASU are effective for the fiscal years and interim periods within those fiscal years, beginning after December 15, 2016. The Company does not believe this ASU will have any effect on its Condensed Consolidated Financial Statements.

Employee Share Based Payment Accounting. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share Based Payment Accounting," which amends ASC Topic 718, Compensation - Stock Compensation. ASU 2016-09 includes provisions intended to simplify various aspects related to how share based payments are accounted for and presented in the financial statements. The new guidance among other requirements will require all of the tax effects related to share based payments at settlement (or expiration) to be recorded through the income statement. Currently, tax benefits in excess of compensation cost (“windfalls”) are recorded in equity, and tax deficiencies (“shortfalls”) are recorded in equity to the extent of previous windfalls, and then to the income statement. This change is required to be applied prospectively to all excess tax benefits and tax deficiencies resulting from settlements after the date of adoption of the ASU2016-09. Under the new guidance, the windfall tax benefit will be recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. Either prospective or retrospective transition of this provision is permitted. ASU 2016-09 is effective for annual reporting

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periods beginning after December 15, 2016, and interim periods within that reporting period. Early adoption will be permitted in any interim or annual period, with any adjustments reflected as of the beginning of the fiscal year of adoption. The Company has not determined the impact on its Condensed Consolidated Financial Statements, however, the impact is not expected to be material.

3.	Investment in Unconsolidated Affiliate and Related Party Transactions

On March 14, 2013, the Company entered into a Master Formation Agreement with the ArcLight group and CenterPoint pursuant to which the Company, the ArcLight group and CenterPoint, agreed to form Enable to own and operate the midstream businesses of the Company and CenterPoint that was initially structured as a private limited partnership. This transaction closed on May 1, 2013.

Pursuant to the Master Formation Agreement, 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 was recorded at historical cost.

In April 2014, Enable completed an initial public offering of 25.0 million common units resulting in Enable becoming a publicly traded Master Limited Partnership. At March 31, 2016, the Company owned 111.0 million common units, or 26.3 percent, of which 68.2 million units were subordinated.

CenterPoint and the Company also own a 40 percent and 60 percent interest, respectively, in any incentive distribution rights to be held by the general partner of Enable following the initial public offering.

Distributions received from Enable were $35.3 million and $34.3 million during the three months ended March 31, 2016 and 2015, respectively.

Related Party Transactions

Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below. The Company's interest in Enogex Holdings was deconsolidated on May 1, 2013.

On May 1, 2013, the Company and Enable entered into a Services Agreement, Employee Transition Agreement, and other agreements whereby the Company agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. Under these agreements, the Company charged operating costs to Enable of $1.3 million and $2.8 million for three months ended March 31, 2016 and 2015, respectively. The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and Enable are assigned as such. Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.  

Additionally, the Company agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, CenterPoint, the Company and Enable agreed to continue the secondment to Enable for 192 employees that participate in the Company's defined benefit and retirement plans, beyond December 31, 2014. The Company billed Enable for reimbursement of $7.1 million and $10.0 million in the three months ended March 31, 2016 and 2015, respectively, under the Transitional Seconding Agreement for employment costs.

The Company had accounts receivable from Enable of $2.9 million as of March 31, 2016 and $1.7 million as of December 31, 2015, for amounts billed for transitional services, including the cost of seconded employees.

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Related Party Transactions with Enable

OG&E entered into a contract with Enable to provide gas transportation services effective May 1, 2014. This transportation agreement 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, 2016, and 2015.

	Three Months Ended March 31,
(In millions)	2016			2015
Operating Revenues:
Electricity to power electric compression assets	$	2.3		$	3.1
Cost of Sales:
Natural gas transportation services	$	8.8		$	8.8
Natural gas purchases/(sales)	1.5			2.5

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below as of March 31, 2016 and December 31, 2015.

Balance Sheet	March 31,			December 31,
(In millions)	2016			2015
Current assets	$	379		$	381
Non-current assets	10,870			10,857
Current liabilities	279			615
Non-current liabilities	3,123			3,092

Income Statement	Three Months Ended March 31,
(In millions)	2016			2015
Operating revenues	$	509		$	616
Cost of NGLs	195			292
Operating income	103			104
Net income	86			91

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 is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value.  Enogex Holdings' assets, liabilities and equity have accordingly been adjusted to estimated fair value as of May 1, 2013, resulting in an increase to Enable's equity of $2.2 billion.  Due to the contribution of Enogex LLC to Enable meeting the requirements of being in substance real estate and the recording the initial investment 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.

The Company recorded equity in earnings of unconsolidated affiliates of $28.3 million and $31.7 million for the three months ended March 31, 2016 and 2015, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex LLC and its underlying equity in net assets of Enable. The basis difference is the result of the initial contribution of Enogex LLC to Enable in May 2013, and subsequent issuances of equity by Enable, including the initial public offering in April 2014 and the issuance of common units for the acquisition of CenterPoint's 24.95 percent interest in Southeast Supply Header, LLC. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above.

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The difference between the Company's investment in Enable and its underlying equity in the net assets of Enable was $775.5 million as of March 31, 2016.

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three months ended March 31, 2016 and 2015.

	Three Months Ended March 31,
(In millions)	2016			2015
OGE's share of Enable Net Income	$	21.3		$	23.8
Amortization of basis difference	2.9			3.5
Elimination of Enogex Holdings fair value and other adjustments	4.1			4.4
Equity in earnings of unconsolidated affiliates	$	28.3		$	31.7

4.	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, 2016 and December 31, 2015, except for long-term debt which is recorded at the carrying amount.

  The following table summarizes the fair value and carrying amount of the Company's long-term debt at March 31, 2016 and December 31, 2015.

	March 31, 2016						December 31, 2015
(In millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,384.3		$	2,748.1		$	2,493.9		$	2,754.6
OG&E Industrial Authority Bonds	135.4			135.4			135.4			135.4
OG&E Tinker Debt	10.0			9.5			10.0			9.2
OGE Energy Senior Notes	99.6			99.9			99.5			99.9

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 in which fair value was based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

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5.	Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the three months ended March 31, 2016, and 2015 related to the Company's performance units and restricted stock.

	Three Months Ended March 31,
(In millions)	2016			2015
Performance units
Total shareholder return	$	1.1		$	1.9
Earnings per share	0.6			0.5
Total performance units	1.7			2.4
Restricted stock	—			—
Total compensation expense	1.7			2.4
Less: Amount paid by unconsolidated affiliates	—			0.3
Net compensation expense	$	1.7		$	2.1
Income tax benefit	$	0.6		$	0.8

The Company has issued new shares to satisfy restricted stock grants and payouts of earned performance units.  During the three months ended March 31, 2016, there were no shares of new common stock issued pursuant to the Company's Stock Incentive Plan related to restricted stock grants (net of forfeitures) and payouts of earned performance units. During the three months ended March 31, 2016, there were 901 shares of restricted stock returned to the Company to satisfy tax liabilities.

The following table summarizes the activity of the Company's stock-based compensation during the three months ended March 31, 2016.

	Units/Shares		Fair Value Per Share
Grants
Performance units (Total shareholder return)	280,604		$	20.84
Performance units (Earnings per share)	93,533		$	26.59

6.	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 tax examinations by tax authorities for years prior to 2012 or state and local tax examinations by tax authorities for years prior to 2011.  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 are being 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.  In addition, OG&E and Enable earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.

7.	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, 2016.  The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan or purchase shares traded on the open market. At March 31, 2016, there were 4,774,442 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

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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. Basic and diluted earnings per share for the Company were calculated as follows:

	Three Months Ended March 31,
(In millions)	2016			2015
Net Income	$	25.2		$	43.2
Average Common Shares Outstanding
Basic average common shares outstanding	199.7			199.5
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	—			—
Diluted average common shares outstanding	199.7			199.5
Basic Earnings Per Average Common Share	$	0.13		$	0.22
Diluted Earnings Per Average Common Share	$	0.13		$	0.22
Anti-dilutive shares excluded from earnings per share calculation	—			—

 

8.	Long-Term Debt

 

At March 31, 2016, 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 as follows:

SERIES			DATE DUE	AMOUNT
				(In millions)
0.05%	-	0.39%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.07%	-	0.43%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.40%	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 Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

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9.	Short-Term Debt and Credit Facilities

 

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement.  As of March 31, 2016, the Company had $187.5 million of short-term debt compared to no short-term debt at December 31, 2015, at a weighted-average interest rate of 0.74 percent.  The following table provides information regarding the Company's revolving credit agreements and available cash at March 31, 2016.

	Aggregate			Amount			Weighted-Average
Entity	Commitment			Outstanding (A)			Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0		$	187.5		0.74	%	(D)	December 13, 2018	(E)
OG&E (C)	400.0			1.7			0.95	%	(D)	December 13, 2018	(E)
Total	$	1,150.0		$	189.2		0.95	%

(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2016.

(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.

(E)	As of March 31, 2016, commitments of $16.3 million and $8.7 million of the Company's and OG&E's credit facilities, respectively, were not extended and unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire December 13, 2017.

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, 2015 and ending December 31, 2016.

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10.	Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost, before consideration of capitalized amounts, of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Consolidated Financial Statements are as follows:

 

Net Periodic Benefit Cost

	Pension Plan						Restoration of Retirement Income Plan						Postretirement Benefit Plans
	Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,
(In millions)	2016			2015			2016			2015			2016			2015
Service cost	$	4.4		$	4.5		$	0.1		$	0.4		$	0.3		$	0.5
Interest cost	6.6			6.4			0.1			0.2			2.3			2.6
Expected return on plan assets	(10.5		)	(11.8		)	—			—			(0.6		)	(0.6		)
Amortization of net loss	4.2			4.3			0.2			0.1			0.5			3.4
Amortization of unrecognized prior service cost (A)	—			0.1			—			—			(2.2		)	(4.1		)
Total net periodic benefit cost	4.7			3.5			0.4			0.7			0.3			1.8
Less: Amount paid by unconsolidated affiliates	1.3			1.1			—			—			0.1			0.3
Net periodic benefit cost (B)	$	3.4		$	2.4		$	0.4		$	0.7		$	0.2		$	1.5

(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 $4.0 million and $4.6 million of net periodic benefit cost recognized during the three months ended March 31, 2016 and 2015, respectively, the Company recognized the following:

•	an increase in pension expense in the three months ended March 31, 2016 and 2015 of $2.3 million and $3.0 million, 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); and

•	an increase in postretirement medical expense in the three months ended March 31, 2016 and 2015 of $2.0 million and $1.4 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).

	Three Months Ended
	March 31,
(In millions)	2016			2015
Capitalized portion of net periodic pension benefit cost	$	1.2		$	0.8
Capitalized portion of net periodic postretirement benefit cost	0.1			0.5

  

11.	Report of Business Segments

The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy, and (ii) natural gas midstream operations segment.

Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations.

The following tables summarize the results of the Company's business segments for the three months ended March 31, 2016 and 2015.

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Three Months Ended March 31, 2016	Electric Utility			Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	433.1		$	—		$	—		$	—		$	433.1
Cost of sales	177.9			—			—			—			177.9
Other operation and maintenance	116.3			0.2			(2.6		)	—			113.9
Depreciation and amortization	76.7			—			1.8			—			78.5
Taxes other than income	23.6			—			1.3			—			24.9
Operating income (loss)	38.6			(0.2		)	(0.5		)	—			37.9
Equity in earnings of unconsolidated affiliates	—			28.3			—			—			28.3
Other income (expense)	5.3			—			0.3			(0.1		)	5.5
Interest expense	35.5			—			0.9			(0.1		)	36.3
Income tax expense (benefit)	2.3			10.1			(2.2		)	—			10.2
Net income	$	6.1		$	18.0		$	1.1		$	—		$	25.2
Investment in unconsolidated affiliates	$	—		$	1,187.4		$	—		$	—		$	1,187.4
Total assets	$	8,288.5		$	1,467.9		$	98.7		$	(331.8	)	$	9,523.3

Three Months Ended March 31, 2015	Electric Utility			Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	480.1		$	—		$	—		$	—		$	480.1
Cost of sales	211.6			—			—			—			211.6
Other operation and maintenance	114.3			0.8			(3.4		)	—			111.7
Depreciation and amortization	73.8			—			2.1			—			75.9
Taxes other than income	23.1			—			1.4			—			24.5
Operating income (loss)	57.3			(0.8		)	(0.1		)	—			56.4
Equity in earnings of unconsolidated affiliates	—			31.7			—			—			31.7
Other income (expense)	2.9			—			2.5			—			5.4
Interest expense	36.8			—			0.6			—			37.4
Income tax expense (benefit)	6.3			8.1			(1.5		)	—			12.9
Net income	$	17.1		$	22.8		$	3.3		$	—		$	43.2
Investment in unconsolidated affiliates	$	—		$	1,315.7		$	—		$	—		$	1,315.7
Total assets	$	8,217.7		$	1,476.7		$	122.3		$	(332.4	)	$	9,484.3

12.	Commitments and Contingencies

Except as set forth below, in Note 13 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 Company's Consolidated Financial Statements included in the Company's 2015 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

 

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. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards.

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Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to its condensed financial position or results of operations.  The Company believes, however, that it is likely that the trend in environmental legislation and regulations will continue towards more restrictive standards.  Compliance with these standards is expected to increase the cost of conducting business. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.

 

OG&E is managing several significant uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time.

Federal Clean Air Act New Source Review Litigation

As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants.

On July 8, 2013, the U.S. Department of Justice filed a complaint against OG&E in United States District Court for the Western District of Oklahoma alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint sought to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club intervened in this proceeding. On August 30, 2013, the government filed a Motion for Summary Judgment and on September 6, 2013, OG&E filed a Motion to Dismiss the case. On January 15, 2015, the Court dismissed the complaints filed by the EPA and the Sierra Club. The Court held that it lacked subject matter jurisdiction over plaintiffs’ claims because plaintiffs failed to present an actual “case or controversy” as required by Article III of the Constitution. The court also ruled in the alternative that, even if plaintiffs had presented a case or controversy, it would have nonetheless “decline[d] to exercise jurisdiction.” The EPA and the Sierra Club did not file an appeal of the Court's ruling.

On August 12, 2013, the Sierra Club filed a separate complaint against OG&E in the United States District Court for the Eastern District of Oklahoma alleging that OG&E projects at Muskogee Unit 6 in 2008 were made without obtaining a prevention of significant deterioration permit and that the plant had exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the District Court dismissed the prevention of significant deterioration permit claim based on the statute of limitations, but allowed the opacity and particulate matter claims to proceed. To obtain the right to appeal this decision, the Sierra Club subsequently withdrew a Notice of Intent to Sue for additional Clean Air Act violations and asked the District Court to dismiss its remaining claims with prejudice. On August 27, 2014, the District Court granted the Sierra Club's request. The Sierra Club appealed the District Court's dismissal of its prevention of significant deterioration claim to the United States Court of Appeals for the Tenth Circuit. On March 8, 2016, the Tenth Circuit affirmed the trial court's decision dismissing the Sierra Club's case. On March 21, 2016, the Sierra Club filed a request for rehearing en banc with the Tenth Circuit. On April 13, 2016, the Tenth Circuit denied the request for rehearing. OG&E cannot predict whether the Sierra Club will seek review of the case by the United States Supreme Court.

 

Air Quality Control System

On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating dry scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015, to install the dry scrubber systems. The dry scrubbers are scheduled to be completed by 2019. More detail regarding the dry scrubber project can be found under the “Pending Regulatory Matters” in Note 13.

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

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13.	Rate Matters and Regulation

 

Regulation and Rates

Except as set forth below, the circumstances set forth in Note 15 to the Company's Consolidated Financial Statements included in the Company's 2015 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Pending Regulatory Matters

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

FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation

On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid along with the corresponding process for allocating the costs of such expansions. Order No. 1000 requires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.

Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariff and agreement provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities or to alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a "right of first refusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300kV that interconnect to those incumbent owners' existing facilities.

The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP filings that required the SPP to remove certain "right of first refusal" language from the SPP Tariff and the SPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in the District of Columbia Court of Appeals challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement. The court has not yet acted on OG&E's appeal.

The Company cannot, at this time, determine the precise impact of Order No. 1000 on OG&E. The Company has no reason to believe that the implementation of Order No. 1000 will impact those transmission projects for which OG&E has received a notice to proceed from the SPP.

Oklahoma Demand Program Rider Review - SmartHours Program

In July 2012, OG&E filed an application with the OCC to recover certain costs associated with Demand Programs through the Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off-peak hours during the months of May through October, by offering lower rates to those customers in the off-peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates. Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers by the reduction of more costly on-peak generation and the delay in adding new on-peak generation.

In December 2012, the OCC issued an order approving the recovery of costs associated with the Demand Programs, including the lost revenues associated with the SmartHours program, subject to the Oklahoma PUD staff review.

In March 2014, the Oklahoma PUD staff began their review of the Demand Program cost, including the lost revenues associated with the SmartHours program. In November 2014, OG&E believed that it had reached an agreement with the Oklahoma PUD staff on the methodology to be used to calculate lost revenues associated with the SmartHours program and the amount of

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lost revenue for 2013, which totaled $10.1 million. The agreement also included utilizing the same methodology for calculating lost revenues for 2014 and beyond.

In January 2015, OG&E implemented rates that began recovering the 2013 lost revenues (approximately $10.0 million annually), in accordance with the agreement that it believed had been reached with the Oklahoma PUD staff.

In April 2015, the Oklahoma PUD staff filed an application, seeking an order from the OCC, for determining the proper methodology for calculating lost revenues pursuant to OG&E’s Demand Program Rider, primarily affecting the SmartHours program lost revenues.  In the application, the Oklahoma PUD staff recommends the OCC approve the Oklahoma PUD staff methodology for calculating lost revenues associated with the SmartHours program, which differs from the methodology that OG&E believes it agreed upon and which would result in recovery of lost revenue for 2013 of $2.6 million, a reduction of $7.5 million from the amount recorded by OG&E for 2013.

OG&E believes the methodology agreed to in November 2014 was consistent with the 2012 OCC order and it is probable that OG&E will recover $10.1 million of lost revenues associated with 2013, $11.6 million associated with 2014 and $14.9 million associated with 2015. Through March 31, 2016, OG&E had collected from its customers approximately $12.6 million of the $36.6 million of lost revenues for 2013, 2014 and 2015.

A hearing on the Oklahoma PUD staff’s application was heard by the ALJ on June 30, 2015 and July 1, 2015. On March 28, 2016, the ALJ issued her recommendation in the case. She found, among other things, that OG&E and the Oklahoma PUD staff had not reached an agreement on all aspects of the calculation of lost revenues, that OG&E’s methodology for calculating lost revenues was not consistent with the provisions of OG&E’s tariff, and that the PUD staff’s methodology for calculating lost revenues was proper. The ALJ recommended that the OCC order OG&E to adjust its calculation of SmartHours lost revenue for 2013 through 2015 consistent with the PUD staff’s methodology, but that such adjustment should only be applied on a prospective basis following the issuance of an order by the OCC. The ALJ’s recommendation is not clear on whether the phrase “on a prospective basis” would allow OG&E to recover the remaining $24.0 million of 2013, 2014 and 2015 lost revenues that OG&E recorded pursuant to its methodology, or only the amounts that OG&E has collected at the time of an OCC order.

The OCC can accept, modify or reject in whole or in part the ALJ’s recommendation. To the extent the OCC does not authorize OG&E to collect and retain the remaining lost revenue that it has recorded, OG&E will incur an impairment charge. OG&E is unable to predict what actions the OCC will take, or when the OCC will rule in this case.

Environmental Compliance Plan

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the OCC to predetermine the prudence of its Mustang Modernization Plan which calls for replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 with 400 MWs of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance plan to be approximately $1.1 billion. Approximately seven months after OG&E filed its application, the OCC hearing on OG&E's application before an ALJ began on March 3, 2015 and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding.

On June 8, 2015, the ALJ issued his report on OG&E's application. While the ALJ in his report agreed that the installation of dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas pursuant to OG&E’s ECP is the best approach, the ALJ's report included several recommendations. OG&E filed exceptions to the ALJ's report and on July 21, 2015, Commissioner Bob Anthony issued his deliberation statement that was consistent with many parts of the ALJ's report, including the ALJ’s support of OG&E’s ECP, the ALJ’s recommendation to pre-approve certain estimated costs of the environmental recovery plan, and the ALJ’s recommendation to defer all other cost recovery issues until the next general rate case.

On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.

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On December 11, 2015, OG&E filed a motion requesting modification of the OCC order for the purposes of approving only the ECP. OG&E did not seek modification to any other provisions of the OCC order, including cost recovery. OG&E also agreed that it would not implement a rider for recovery of the costs of the ECP until and unless authorized by the OCC in a subsequent proceeding. On December 23, 2015, the OCC rejected, by a two to one vote, a proposal by Commissioner Dana Murphy to grant OG&E's December 11, 2015 motion.

On February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install dry scrubbers at the Sooner facility on or before May 2, 2016. OG&E's application does not seek approval of the costs of the dry scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates. At the hearing on OG&E's application to approve OG&E's decision to install dry scrubbers and in testimony filed in support of its application, OG&E stated that it would cancel the dry scrubber project if the OCC did not approve OG&E's application on or before May 2, 2016. On April 28, 2016, the OCC approved the dry scrubber project and OG&E is proceeding with the project. Other parties to the proceeding have the opportunity to appeal the OCC's decision to the Oklahoma Supreme Court.

As of March 31, 2016, OG&E had incurred $107.3 million of construction work in progress on the dry scrubbers.

Fuel Adjustment Clause Review for Calendar Year 2014

On July 28, 2015, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs.

On April 7, 2016, a hearing was held in this matter, at which time the ALJ said she would recommend that the OCC find that for the calendar year 2014 OG&E’s electric generation, purchased power and fuel procurement processes and costs were prudent.  The Company expects to receive an order from the OCC by the end of the second quarter 2016.

Integrated Resource Plans

In August 2015, OG&E initiated the process to update its IRP pursuant to the OCC rules. After engaging interested stakeholders in August and September, OG&E finalized the 2015 IRP and submitted it to the OCC on October 1, 2015. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the ECP and other parts of the action plan contained in the IRP submitted in 2014.

Oklahoma Rate Case Filing

As previously reported in the Company's 2015 Form 10-K, on December 18, 2015, OG&E filed a general rate case with the OCC requesting a rate increase of $92.5 million and a 10.25 percent return on equity based on a common equity percentage of 53 percent. The rate case was based on a June 30, 2015 test year, and included recovery of $1.6 billion of electric infrastructure additions since its last general rate case in Oklahoma, the impact of the expiration of OG&E's wholesale contracts, increased operating costs such as vegetation management and increased recovery of depreciation and plant dismantlement of approximately $8.0 million. Each 0.25 percent change in the requested return on equity affects the requested rate increase by approximately $9.0 million.

In late March 2016, the PUD Staff and other intervenors filed testimony in the case.  The PUD Staff recommended a $6.1 million annual rate increase based on a return on equity of 9.25 percent and a common equity percentage of 53 percent.  Included in the PUD Staff recommendation is a reduction of $33.0 million to OG&E’s requested increase for depreciation and plant dismantlement.

The staff of the Oklahoma Attorney General made a recommendation to reduce rates $10.8 million based on a return on equity of 9.25 percent and a common equity percentage of 50 percent, as well as a recommendation to reduce rates $13.7 million based on a return on equity of 8.90 percent and a common equity percentage of 53 percent.   Included in the Attorney General's recommendation is a reduction of $20.9 million to OG&E’s requested increase for depreciation and plant dismantlement.

The Oklahoma Industrial Electric Consumers recommended a $47.9 million annual rate decrease based on a return on equity of 9.00 percent and a common equity percentage of 53 percent.  Included in the Oklahoma Industrial Electric Consumers' recommendation is a reduction of $52.5 million to OG&E’s requested increase for depreciation and plant dismantlement.

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The hearings in this matter began on May 3, 2016.  While there is no statutory deadline for the ALJ to make a recommendation or for the commission to issue a final order, OG&E is allowed to implement increased rates subject to refund, 180 days after the filing of its application on December 18, 2015.

Arkansas Rate Case Filing

OG&E intends to file a general rate case with the APSC by August 15, 2016.

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

 

Introduction

 

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. 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 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 its wholly owned subsidiary OGE Holdings. Enable is 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 from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns a crude oil gathering business in the Bakken shale formation, principally located in the Williston basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

On April 26, 2016, Enable announced a quarterly dividend distribution of $0.3180 per unit on its outstanding common and subordinated units, which is unchanged from the previous quarter.

Overview

 

Company Strategy

 

The Company's mission, through OG&E and its 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 customers' 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 three to five 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 targeted annual dividend increase has been determined after consideration of numerous factors, including the largely retail composition of the Company's shareholder base, the Company's financial position, the Company's growth targets and the composition of the Company's assets and investment opportunities.  The Company also relies on cash distributions from its investment in Enable to 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.

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Summary of Operating Results

Three Months Ended March 31, 2016 as compared to Three Months Ended March 31, 2015.

Net income $25.2 million, or $0.13 per diluted share, during the three months ended March 31, 2016 as compared to $43.2 million, or $0.22 per diluted share, during the same period in 2015. The decrease in net income of $18.0 million, or 41.7 percent, or $0.09 per diluted share, during the three months ended March 31, 2016 as compared to the same period in 2015 was primarily due to:

    

•

a decrease in net income at OG&E of $11.0 million, or 64.3 percent, or $0.06 per diluted share of the Company's common stock, primarily due to lower usage related to milder weather and the expiration of the AVEC contract, higher depreciation and amortization expense and higher operation and maintenance expense partially offset by lower income tax expense and increased other income due to the guaranteed flat bill tariff;

•	a decrease in net income at OGE Holdings of $4.8 million, or 21.1 percent, or $0.02 per diluted share of the Company's common stock, primarily due to a decrease in earnings of unconsolidated affiliates and an increase in income tax expense due to a tax benefit received in 2015; and

•	a decrease in net income at OGE Energy of $2.2 million, or 66.7 percent, or $0.01 per diluted share of the Company's common stock, primarily due to a decrease in gains associated with the deferred compensation plan.

2016 Outlook

 

The Company's 2016 earnings guidance is between approximately $344.0 million to $366.0 million of net income, or $1.72 to $1.83 per average diluted share. The guidance assumes, among other things, approximately 200 million average diluted shares outstanding, normal weather for the year and full recovery of the lost revenues associated with the Smart Hours program as described in Note 13 to the Notes to Condensed Consolidated Financial Statements. See the Company's 2015 Form 10-K for other factors and assumptions underlying its 2016 earnings guidance.

Non-GAAP Financial Measures

Ongoing Earnings and Ongoing Earnings per Average Diluted Share are defined by the Company as GAAP Earnings and GAAP Earnings per Average Diluted Share adjusted to exclude non-cash charges. The Company’s management believes that ongoing earnings and ongoing earnings per average diluted share provide a more meaningful comparison of earnings results and are more representative of the Company’s fundamental core earnings power. The Company’s management uses ongoing earnings and ongoing earnings per average diluted share internally for financial planning and analysis, for reporting of results to the Board of Directors, and when communicating its earnings outlook to analysts and investors. For the three months ended March 31, 2016 and 2015, ongoing earnings and GAAP Earnings are the same.

Gross margin is defined by OG&E as operating revenues less 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.

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, 2016 and 2015 and the Company's consolidated financial position at March 31, 2016.  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.

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	Three Months Ended   March 31,
(In millions except per share data)	2016			2015
Net income	$	25.2		$	43.2
Basic average common shares outstanding	199.7			199.5
Diluted average common shares outstanding	199.7			199.5
Basic earnings per average common share	$	0.13		$	0.22
Diluted earnings per average common share	$	0.13		$	0.22
Dividends declared per common share	$	0.27500		$	0.25000

 

Results by Business Segment

	Three Months Ended   March 31,
(In millions)	2016			2015
Net Income
OG&E (Electric Utility)	$	6.1		$	17.1
OGE Holdings (Natural Gas Midstream Operations)	18.0			22.8
Other Operations (A)	1.1			3.3
Consolidated net income	$	25.2		$	43.2

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

The following operating results analysis by business segment includes intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements. 

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OG&E (Electric Utility)

	Three Months Ended March 31,
(Dollars in millions)	2016			2015
Operating revenues	$	433.1		$	480.1
Cost of sales	177.9			211.6
Other operation and maintenance	116.3			114.3
Depreciation and amortization	76.7			73.8
Taxes other than income	23.6			23.1
Operating income	38.6			57.3
Allowance for equity funds used during construction	1.6			1.5
Other income	4.0			1.7
Other expense	0.3			0.3
Interest expense	35.5			36.8
Income tax expense	2.3			6.3
Net income	$	6.1		$	17.1
Operating revenues by classification
Residential	$	178.5		$	194.6
Commercial	102.7			105.9
Industrial	38.2			41.7
Oilfield	32.3			37.0
Public authorities and street light	36.1			39.4
Sales for resale	0.1			11.8
System sales revenues	387.9			430.4
Off-system sales revenues	9.1			10.3
Other	36.1			39.4
Total operating revenues	$	433.1		$	480.1
Reconciliation of gross margin to revenue:
Operating revenues	$	433.1		$	480.1
Cost of sales	177.9			211.6
Gross Margin	$	255.2		$	268.5
MWh sales by classification (In millions)
Residential	2.1			2.3
Commercial	1.6			1.6
Industrial	0.9			0.9
Oilfield	0.8			0.9
Public authorities and street light	0.7			0.7
Sales for resale	—			0.3
System sales	6.1			6.7
Off-system sales	0.4			0.2
Total sales	6.5			6.9
Number of customers	827,685			817,781
Weighted-average cost of energy per kilowatt-hour - cents
Natural gas	2.038			2.629
Coal	2.288			2.115
Total fuel	1.945			2.200
Total fuel and purchased power	2.611			2.901
Degree days (A)
Heating - Actual	1,552			1,841
Heating - Normal	1,798			1,798
Cooling - Actual	12			11
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.

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Three Months Ended March 31, 2016 as compared to Three Months Ended March 31, 2015.

OG&E's net income decreased $11.0 million, or 64.3 percent, in the three months ended March 31, 2016 as compared to the same period in 2015 primarily due to lower gross margin, higher depreciation expense, higher other operations expense and higher taxes other than income partially offset by lower income tax expense, higher other income and lower interest expense.

Gross Margin

Operating revenues were $433.1 million during the three months ended March 31, 2016 as compared to $480.1 million during the same period in 2015, a decrease of $47.0 million, or 9.8 percent. Cost of sales were $177.9 million during the three months ended March 31, 2016 as compared to $211.6 million during the same period in 2015, a decrease of $33.7 million, or 15.9 percent. Gross margin was $255.2 million during the three months ended March 31, 2016 as compared to $268.5 million during the same period in 2015, a decrease of $13.3 million, or five percent. The below factors contributed to the change in gross margin:

(In millions)	$ Change
Quantity variance (primarily weather) (A)	$	(8.8	)
Expiration of AVEC contract (B)	(5.2		)
Non-residential demand and related revenues	(1.6		)
Wholesale transmission revenue	(1.4		)
Other	(1.4		)
New customer growth	0.5
Price variance (C)	4.6
Change in gross margin	$	(13.3	)

(A)	The overall heating degree days decreased 16 percent in 2016 compared to 2015.

(B)	On June 30, 2015, the wholesale power contract with AVEC expired.

(C)	Increased primarily due to sales and customer mix.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $78.6 million during the three months ended March 31, 2016 as compared to $113.8 million during the same period in 2015, a decrease of $35.2 million, or 30.9 percent, primarily due to lower natural gas prices. Purchased power costs were $86.3 million during the three months ended March 31, 2016 as compared to $86.5 million during the same period in 2015, a decrease of $0.2 million, or 0.2 percent, primarily due to the lower cost of purchases from the SPP. Transmission related charges were $13.0 million during the three months ended March 31, 2016 as compared to $11.3 million during the same period in 2015, an increase of $1.7 million, or 15.0 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

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, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable.

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Operating Expenses

Other operation and maintenance expenses were $116.3 million during the three months ended March 31, 2016 as compared to $114.3 million during the same period in 2015, an increase of $2.0 million, or 1.7 percent. The below factors contributed to the change in other operations and maintenance expense:

(In millions)	$ Change
Salaries and wages (A)	$	2.5
Vegetation management (B)	1.4
Other	(0.2		)
Employee benefits (C)	(0.5		)
Software expense (D)	(1.2		)
Change in other operation and maintenance expense	$	2.0

(A)	Increased primarily due to annual salary increases and increased overtime related to storms.

(B)	Increased primarily due to timing of vegetation management driven by the availability of resources during the period.

(C)	Decreased primarily due to lower medical costs incurred partially offset by higher pension costs.

(D)	Decreased primarily due to timing of software related expenses and favorable price renegotiations.

Depreciation and amortization expense was $76.7 million during the three months ended March 31, 2016 as compared to $73.8 million during the same period in 2015, an increase of $2.9 million, or 3.9 percent, primarily due to additional assets being placed in service in 2015.

Additional Information

Other Income. Other income was $4.0 million during the three months ended March 31, 2016 as compared to $1.7 million during the same period in 2015, an increase of $2.3 million, primarily due to increased guaranteed flat bill margins.

Income Tax Expense. Income tax expense was $2.3 million during the three months ended March 31, 2016 as compared to $6.3 million during the same period in 2015, a decrease of $4.0 million, or 63.5 percent, primarily due to lower pretax income partially offset by decreased production tax credit utilization.

OGE Holdings (Natural Gas Midstream Operations)

	Three Months Ended March 31,
(In millions)	2016			2015
Operating revenues	$	—		$	—
Cost of sales	—			—
Other operation and maintenance	0.2			0.8
Depreciation and amortization	—			—
Taxes other than income	—			—
Operating income (loss)	(0.2		)	(0.8		)
Equity in earnings of unconsolidated affiliates	28.3			31.7
Income before taxes	28.1			30.9
Income tax expense	10.1			8.1
Net income attributable to OGE Holdings	$	18.0		$	22.8

OGE Holdings' income before taxes decreased $2.8 million, or 9.1 percent, for the three months ended March 31, 2016 as compared to the same period of 2015 primarily due to a decrease in equity in earnings of Enable. Enable reported lower gross margins due to lower commodity prices, lower firm transportation revenues and a decrease in storage demand fees. In addition to lower gross margins, Enable reported increased depreciation and amortization expense and increased interest expense partially offset by lower operating and maintenance expense.

Income Tax Expense. Income tax expense was $10.1 million during the three months ended March 31, 2016 as compared to an expense of $8.1 million during the same period in 2015, an increase in expense of $2.0 million primarily due to lower pre-

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tax operating income and a benefit associated with a remeasurement of state deferred taxes related to the Company's investment in Enable in the first quarter 2015.

Reconciliation of Equity in Earnings of Unconsolidated Affiliates

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three months ended March 31, 2016 and 2015.

	Three Months Ended March 31,
(In millions)	2016			2015
OGE's share of Enable Net Income	$	21.3		$	23.8
Amortization of basis difference	2.9			3.5
Elimination of Enogex Holdings fair value and other adjustments	4.1			4.4
Equity in earnings of unconsolidated affiliates	$	28.3		$	31.7

Enable Results of Operations

The following table represents summarized financial information of Enable for the three months ended March 31, 2016 and 2015.

	Three Months Ended March 31,
(In millions)	2016			2015
Operating revenues	$	509		$	616
Cost of NGLs	195			292
Operating income	103			104
Net income	$	86		$	91

Enable Operating Data

The following table presents Enable's operating data for the three months ended March 31, 2016 and 2015.

	Three Months Ended March 31,
	2016		2015
Gathered volumes - TBtu/d	3.05		3.18
Transportation volumes - TBtu/d	5.11		5.72
Natural gas processed volumes - TBtu/d	1.78		1.65
NGLs sold - million gallons/d (A)(B)	76.31		67.62

(A)	Excludes condensate.

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

Off-Balance Sheet Arrangement 

There have been no significant changes in the Company's off-balance sheet arrangement from that discussed in the Company's 2015 Form 10-K. The Company has no off-balance sheet arrangements with equity method investments that would affect its liquidity.

Liquidity and Capital Resources

Working Capital

 

Working capital is defined as the difference in current assets and current liabilities. The Company's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries.

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Cash and Cash Equivalents. There was no balance in Cash and Cash Equivalents at March 31, 2016 compared to a balance of $75.2 million at December 31, 2015, primarily due to the use of cash and payment of long-term debt of $110.0 million that matured in January 2016.

Accounts Receivable and Accrued Unbilled Revenues. The balance of Accounts Receivable and Accrued Unbilled Revenues was $189.4 million and $228.3 million at March 31, 2016 and December 31, 2015, respectively, a decrease of $38.9 million, or 17.0 percent, primarily due to a decrease in billings to OG&E's retail customers reflecting lower usage due to milder weather in March 2016 as compared to December 2015.

Short-Term Debt. The balance of Short-Term Debt was $187.5 million at March 31, 2016 and no balance at December 31, 2015. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements.

Accounts Payable. The balance of Accounts Payable was $172.7 million and $262.5 million at March 31, 2016 and December 31, 2015, respectively, a decrease of $89.8 million, or 34.2 percent, primarily due to the timing of vendor payments and a decrease in accruals.

Accrued Taxes. The balance of Accrued Taxes was $24.7 million and $45.9 million at March 31, 2016 and December 31, 2015, respectively, a decrease of $21.2 million, or 46.2 percent, primarily resulting from payments of $42.4 million partially offset by ad valorem tax accruals of $21.0 million.

Accrued Interest. The balance of Accrued Interest was $32.9 million and $42.9 million at March 31, 2016 and December 31, 2015, respectively, a decrease of $10.0 million, or 23.3 percent, primarily due to interest accrued on long-term debt that matured in January 2016.

Long-Term Debt Due Within One Year. There was no balance in Long-Term Debt Due Within One Year at March 31, 2016 compared to a balance of $110.0 million at December 31, 2015 due to long-term debt that matured in January 2016.

Cash Flows

	Three Months Ended March 31,						2016 vs. 2015
(In millions)	2016			2015			$ Change			% Change
Net cash provided from operating activities	$	73.4		$	139.6		$	(66.2	)	(47.4	)%
Net cash used in investing activities	(171.1		)	(108.7		)	(62.4		)	(57.4	)%
Net Cash Provided from (Used in) Financing Activities	22.5			(34.9		)	57.4			*

* Greater than a 100 percent variance.

Operating Activities

The decrease of $66.2 million, or 47.4 percent, in net cash provided from operating activities during the three months ended March 31, 2016 as compared to the same period in 2015 was primarily due to an increase in vendor payments and higher fuel refunds at OG&E during the three months ended March 31, 2016 as compared to higher fuel recoveries in the same period in 2015.

    

Investing Activities

The increase of $62.4 million, or 57.4 percent, in net cash used in investing activities during the three months ended March 31, 2016 as compared to the same period in 2015 was primarily due to an increase in capital expenditures related to environmental projects at OG&E.

Financing Activities

The increase of $57.4 million in net cash provided from financing activities during the three months ended March 31, 2016 as compared to the same period in 2015 was primarily due to an increase in short-term debt partially offset by the payment of long-term debt in January of 2016.

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Future Capital Requirements and Financing Activities

The Company's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E.  Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes.  The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.

Capital Expenditures

 

The Company's consolidated estimates of capital expenditures for the years 2016 through 2020 are shown in the following table.  These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company's businesses) plus capital expenditures for known and committed projects. Estimated capital expenditures for Enable are not included in the table below.

(In millions)	2016			2017			2018			2019			2020
OG&E Base Transmission	$	50		$	30		$	30		$	30		$	30
OG&E Base Distribution	190			175			175			175			175
OG&E Base Generation	60			75			75			75			75
OG&E Other	40			25			25			25			25
Total Base Transmission, Distribution, Generation and Other	340			305			305			305			305
OG&E Known and Committed Projects:
Transmission Projects:
Other Regionally Allocated Projects (A)	45			30			20			20			20
Large SPP Integrated Transmission Projects (B) (C)	20			150			20			—			—
Total Transmission Projects	65			180			40			20			20
Other Projects:
Environmental - low NOX burners (D)	25			10			—			—			—
Environmental - natural gas conversion (D)	—			20			35			25			—
Environmental - dry scrubbers (D)	100			190			90			20			—
Combustion turbines - Mustang	175			135			25			—			—
Total Other Projects	300			355			150			45			—
Total Known and Committed Projects	365			535			190			65			20
Total	$	705		$	840		$	495		$	370		$	325

(A)	Typically 100kV to 299kV projects. Approximately 30 percent of revenue requirement allocated to SPP members other than OG&E.

(B)	Typically 300kV and above projects. Approximately 85 percent of revenue requirement allocated to SPP members other than OG&E.

(C)	Project Type	Project Description	Estimated Cost (In millions)	Projected In-Service Date
	Integrated Transmission Project	30 miles of transmission line from OG&E's Gracemont substation to an AEP companion transmission line to its Elk City substation.	$45	Late 2017
	Integrated Transmission Project	126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation; construction of the Mathewson substation on this transmission line. Approximately $55.0 million of the estimated cost associated with the Mathewson to Cimarron line and substations will go into service in 2016; $35.0 million had been spent prior to 2016.	$190	Mid 2018

(D)	Represents capital costs associated with OG&E’s ECP to comply with the EPA’s MATS and Regional Haze rules. More detailed discussion regarding Regional Haze and OG&E’s ECP can be found in Note 13 of Notes to Condensed Consolidated

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Financial Statements under "Environmental Compliance Plan" in Item 1 of Part I of this Form 10-Q and under “Environmental Laws and Regulations” within “Management's Discussion and Analysis of Financial Condition and Results of Operations” under Part I, Item 2 of this Form 10-Q.

 

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

Security Ratings

	Moody’s Investors Services	Standard & Poor's Ratings Services	Fitch Ratings
OG&E Senior Notes	A1	A-	A+
OGE Energy Senior Notes	A3	BBB+	A-
OGE Energy Commercial Paper	P2	A2	F2

Access to reasonably priced capital is dependent in part on credit and security ratings. Generally, lower ratings lead to higher financing costs. Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit.

 

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

Future Sources of Financing

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

Short-Term Debt and Credit Facilities

 

Short-term borrowings generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. The Company has revolving credit facilities totaling in the aggregate $1,150.0 million. These bank facilities can also be used as letter of credit facilities. The balance at March 31, 2016 was $187.5 million compared to no balance at December 31, 2015. The average balance of short-term debt in 2016 was $146.4 million at a weighted-average interest rate of 0.74 percent. The maximum month-end balance of short-term debt in 2016 was $209.2 million. At March 31, 2016, the Company had $960.8 million of net available liquidity under its revolving credit agreements.  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, 2015 and ending December 31, 2016.  At March 31, 2016, the Company had no balance in cash and cash equivalents.  See Note 9 of Notes to Condensed Consolidated Financial Statements for a discussion of the Company's short-term debt activity.

Distributions by Enable

 

Pursuant to the Enable limited partnership agreement, the amount of distributions the Company received from Enable was $35.3 million during the three months ended March 31, 2016.

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Critical Accounting Policies and Estimates

 

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements contain information that is pertinent to Management's Discussion and Analysis.  In preparing the Condensed Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.  Changes to these assumptions and estimates could have a material effect on the Company's Condensed Consolidated Financial Statements.  However, the Company believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates.  

In management's opinion, the areas of the Company where the most significant judgment is exercised for all Company segments includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations and depreciable lives of property, plant and equipment. For the electric utility segment, significant judgment is also exercised in the determination of regulatory assets and liabilities and unbilled revenues. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company's Audit Committee and are discussed in detail in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in the Company's 2015 Form 10-K.

Commitments and Contingencies

 

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability.  These generally relate to lawsuits or claims made by third parties, including governmental agencies.  When appropriate, management consults with legal counsel and other experts to assess the claim.  If, in management's opinion, the Company has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company's Condensed Consolidated Financial Statements. At the present time, based on available information, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.  See Notes 12 and 13 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q for a discussion of the Company's commitments and contingencies.

 

Environmental Laws and Regulations

 

The activities of the Company are subject to numerous stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact 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. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards. These environmental laws and regulations are discussed in detail in Management's Discussion and Analysis of Financial Condition and Results of Operations in the Company's 2015 10-K. Except as set forth below, there have been no material changes to such items.

OG&E expects that environmental expenditures necessary to comply with the environmental laws and regulations discussed below will qualify as part of a pre-approval plan to handle state and Federally mandated environmental upgrades and, upon approval of the plan by the OCC, OG&E would be entitled to recover through a rate rider the costs of the environmental upgrades from its Oklahoma retail customers when the upgrades were placed in service under House Bill 1910, which was enacted into law in May 2005.

 

Air

 

Federal Clean Air Act Overview

OG&E’s operations are subject to the Federal Clean Air Act as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, and also impose various monitoring and reporting requirements.  Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install

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emission control equipment. OG&E will likely be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.

Regional Haze Control Measures

The EPA's 2005 regional haze rule is intended to protect visibility in certain national parks and wilderness areas throughout the United States that may be impacted by air pollutant emissions.

 

On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with the Federal regional haze rule. The SIP was subject to the EPA's review and approval.

The Oklahoma SIP included requirements for reducing emissions of NO_X and SO₂ from OG&E's seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations. The SIP also included a waiver from BART requirements for all eligible units at the Horseshoe Lake generating station based on air modeling that showed no significant impact on visibility in nearby national parks and wilderness areas. The SIP concluded that BART for reducing NO_X emissions at all of the subject units should be the installation of low NO_X burners with overfired air (flue gas recirculation was also required on two of the units) and set forth associated NO_X emission rates and limits.

 

On December 28, 2011, the EPA issued a final rule in which it rejected the SO₂ portion of the Oklahoma SIP and issued a FIP in its place. OG&E and the State of Oklahoma's subsequent appeal of the FIP with the Tenth Circuit of Appeals and the U.S. Supreme Court ended on May 27, 2014 when the Supreme Court denied OG&E's Petition for Certiorari, upholding the EPA's FIP for SO₂. The FIP compliance date is now January 4, 2019.

On December 9, 2015, the EPA released a final rule partially disapproving the revisions to the 2010 Oklahoma SIP for Regional Haze and promulgated FIPs in their place for Oklahoma and Texas. The EPA disapproved portions of the Oklahoma SIP related to the establishment of Reasonable Progress Goals for the Class I area located within the state and promulgated revised Reasonable Progress Goals based on the FIP implementation in Texas. As a result, no further requirements are required in Oklahoma to meet the 2018 Reasonable Progress Goals for Oklahoma.

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The ECP includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asked the OCC to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 with 400 MWs of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance plan included in this application to be approximately $1.1 billion. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015 and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding.

On June 8, 2015, the ALJ issued his report on OG&E's application. While the ALJ in his report agreed that the installation of dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas pursuant to OG&E’s ECP is the best approach, the ALJ's report included several recommendations. OG&E filed exceptions to the ALJ's report and on July 21, 2015, Commissioner Bob Anthony issued his deliberation statement that was consistent with many parts of the ALJ's report, including the ALJ’s support of OG&E’s ECP, the ALJ’s recommendation to pre-approve certain estimated costs of the environmental recovery plan, and the ALJ’s recommendation to defer all other cost recovery issues until the next general rate case.

On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.

On December 11, 2015, OG&E filed a motion requesting modification of the OCC order for the purposes of approving only the ECP. OG&E did not seek modification to any other provisions of the OCC order, including cost recovery. OG&E also agreed that it would not implement a rider for recovery of the costs of the ECP until and unless authorized by the OCC in a subsequent proceeding.

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On December 23, 2015, the OCC rejected, by a two to one vote, a proposal by Commissioner Dana Murphy to grant OG&E's December 11, 2015 motion.

On February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install dry scrubbers at the Sooner facility on or before May 2, 2016. OG&E's application does not seek approval of the costs of the dry scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates. At the hearing on OG&E's application to approve OG&E's decision to install dry scrubbers and in testimony filed in support of its application, OG&E stated that it would cancel the dry scrubber project if the OCC did not approve OG&E's application on or before May 2, 2016. On April 28, 2016, the OCC approved the dry scrubber project and OG&E is proceeding with the project. Other parties to the proceeding have the opportunity to appeal the OCC's decision to the Oklahoma Supreme Court.

As of March 31, 2016, OG&E had incurred $107.3 million of construction work in progress on the dry scrubbers.

 

Cross-State Air Pollution Rule

In August 2011, the EPA finalized its CSAPR that required 27 states in the eastern half of the United States to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. In December 2011, the EPA published a supplemental CSAPR, which would make six additional states, including Oklahoma, subject to the CSAPR for NO_X emissions during the ozone-season from May 1 through September 30. Under the rule, OG&E would have been required to reduce ozone-season NO_X emissions from its electrical generating units within the state beginning in 2012. In response to legal challenges of the final rule on December 30, 2011, the U.S. Court of Appeals issued a stay of the rule, which includes the supplemental rule, pending a decision on the merits. By order dated August 21, 2012, the Court of Appeals vacated the CSAPR and ordered the EPA to promulgate a replacement rule. On April 29, 2014, the U.S. Supreme Court reversed the decision by the Court of Appeals. On October 23, 2014, the Court of Appeals for the District of Columbia Circuit granted the EPA's request that the court lift the stay of the CSAPR. The EPA subsequently clarified that compliance with the CSAPR would begin in 2015 using the amount of allowances originally scheduled to be available in 2012. As of December 31, 2015, OG&E has installed five low NO_X burner systems on two Muskogee units, two Sooner units and one Seminole unit and is in compliance with the final rule. In the meantime, the petitions for review of the supplemental rule remain pending before the D.C. Circuit Court of Appeals for consideration of issues that are not addressed by the Supreme Court's decision.

On December 3, 2015, the EPA proposed an update to CSAPR finding that ozone-season NO_X emissions in 23 eastern states including Oklahoma affect the ability of downwind states to attain and maintain ozone standards and proposing to issue FIPs to update the existing NO_X ozone-season emission budgets for electrical generating units. The proposed rule reduces OG&E's NO_X emissions requirements under the current CSAPR by 25 percent. Compliance is proposed to begin in May 2017. OG&E continues to evaluate what additional measures, if any, will be needed for compliance with the new rule.

Hazardous Air Pollutants Emission Standards

On February 16, 2012, the EPA published the final MATS rule regulating the emissions of certain hazardous air pollutants from electric generating units, which became effective April 16, 2012. The final rule uses a numerical standard to establish limits for particulate matter (as a surrogate for toxic metals), hydrogen chloride and mercury emissions from coal-fired boilers. Compliance was required within three years of the rule's effective date. Based on OG&E's request for a one-year extension, the deadline for compliance was extended to April 16, 2016. To comply with this rule, OG&E utilized activated carbon injections at each of its five coal-fired units during 2015.

 

The final MATS rule was appealed by several parties, but OG&E was not a party to the appeals.  After withstanding judicial scrutiny at the District of Columbia Circuit Court of Appeals, the MATS rule was challenged at the U.S. Supreme Court.  On June 29, 2015, the U.S. Supreme Court found that the EPA should have considered the compliance costs imposed on utilities at the first stage of the EPA’s regulatory analysis.  The U.S. Supreme Court did not vacate the rule, but reversed the D.C. Circuit's decision and remanded to the D.C. Circuit for further proceedings. The Company believes that it is in compliance with the existing MATS rule.

Federal Clean Air Act New Source Review Litigation

As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants.

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On July 8, 2013, the U.S. Department of Justice filed a complaint against OG&E in United States District Court for the Western District of Oklahoma alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint sought to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club intervened in this proceeding. On August 30, 2013, the government filed a Motion for Summary Judgment and on September 6, 2013, OG&E filed a Motion to Dismiss the case. On January 15, 2015, the Court dismissed the complaints filed by the EPA and the Sierra Club. The Court held that it lacked subject matter jurisdiction over plaintiffs’ claims because plaintiffs failed to present an actual “case or controversy” as required by Article III of the Constitution. The court also ruled in the alternative that, even if plaintiffs had presented a case or controversy, it would have nonetheless “decline[d] to exercise jurisdiction.” The EPA and the Sierra Club did not file an appeal of the Court's ruling.

On August 12, 2013, the Sierra Club filed a separate complaint against OG&E in the United States District Court for the Eastern District of Oklahoma alleging that OG&E projects at Muskogee Unit 6 in 2008 were made without obtaining a prevention of significant deterioration permit and that the plant had exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the District Court dismissed the prevention of significant deterioration permit claim based on the statute of limitations, but allowed the opacity and particulate matter claims to proceed. To obtain the right to appeal this decision, the Sierra Club subsequently withdrew a Notice of Intent to Sue for additional Clean Air Act violations and asked the District Court to dismiss its remaining claims with prejudice. On August 27, 2014, the District Court granted the Sierra Club's request. The Sierra Club appealed the District Court's dismissal of its prevention of significant deterioration claim to the United States Court of Appeals for the Tenth Circuit. On March 8, 2016, the Tenth Circuit affirmed the trial court's decision dismissing the Sierra Club's case. On March 21, 2016, the Sierra Club filed a request for rehearing en banc with the Tenth Circuit. On April 13, 2016, the Tenth Circuit denied the request for rehearing. OG&E cannot predict whether the Sierra Club will seek review of the case by the United States Supreme Court.

National Ambient Air Quality Standards

The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, the Company could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of the end of 2015, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect the Company's operations. Several processes are under way to designate areas in Oklahoma as attaining or not attaining revised NAAQS. The Company is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to the Company's financial results.

In August of 2013, the Sierra Club and the Natural Resources Defense Council filed a complaint under the citizen suit provision of the Clean Air Act based on the EPA's failure to promulgate and publish designations for the 2010 revised primary SO₂ NAAQS. On March 2, 2015, the U.S. District Court for the Northern District of California issued an order granting the EPA and the Sierra Club's joint motion to approve and enter a consent decree that set forth mandatory deadlines for the EPA to issue designations for all areas of the country that remained undesignated. On September 18, 2015 the Oklahoma Department of Environmental Quality reported to the EPA that no areas in Oklahoma should be designated as non-attainment for the 2010 SO₂ standard.  In a letter dated February 11, 2016, EPA Region 6 notified Oklahoma of their intent to designate part of Muskogee County in which OG&E’s Muskogee Power Plant is located, as non-attainment for the 2010 SO₂ NAAQS. EPA is expected to finalize this designation in July, 2016 following public comment.  This could require additional controls on the affected units. On August 21, 2015, EPA finalized a data requirements rule for implementing the 2010 SO₂ standard requiring air agencies to characterize air quality around sources that emit 2,000 tons per year or more of SO₂ via air quality modeling or ambient air monitoring.  In July 2016, air agencies will be required to identify either ambient monitoring or air quality modeling as a method for characterizing air quality for 2,000 tons per year or larger sources.  At this time, OG&E cannot determine with any certainty whether this determination will cause a material impact to the Company's financial results.

On September 30, 2015 the EPA finalized a new ambient standard for ozone at 70 Ppb which is more stringent than the current standard of 75 Ppb, set in 2008. States must submit non-attainment designations as appropriate based on existing ambient data before October 2016 for the EPA’s approval. Compliance with the new standard begins in 2020 or later depending on the degree of the area’s non-attainment designation. All areas in Oklahoma currently meet the new standard.

The Company is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to the Company's financial results.

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Clean Power Plan

On October 23, 2015, the EPA published the final Clean Power Plan that established standards of performance for CO₂ emissions from existing fossil-fuel-fired power plants along with state-specific CO₂ reduction standards expressed as both rate-based (lbs/MWh) and mass-based (tons/yr) goals. The 2030 rate-based reduction requirement for all existing generating units in Oklahoma has decreased from a proposed 43 percent reduction to 32 percent in the final rule.  The mass-based approach for existing units calls for a 24 percent reduction by 2030 in Oklahoma. The Clean Power Plan requires that states submit to the EPA plans for achieving the state-specific CO₂ reduction goals by September 6, 2016 or submit an extension request for up to two years. The compliance period was to begin in 2022, and emission reductions were to be phased in by 2030. The EPA also proposed a federal compliance plan to implement the Clean Power Plan in the event that an approvable state plan was not submitted to the EPA by the required deadline.

A number of states have filed lawsuits against the Clean Power Plan. On February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan pending resolution of challenges to the rule. The Company is unable to determine what impact the lawsuits will ultimately have on the Clean Power Plan or what impact the stay in implementation will have; however, if the Clean Power Plan survives judicial review and is implemented as written, it could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Significant uncertainties would remain with regards to potential implementation in Oklahoma (and the federal plan that would be imposed by the EPA for states that do not submit approvable plans), including whether states would elect an emissions standards approach versus a state measures approach, whether and what type of emissions trading would be allowed, and available cost mitigation options. Due to the pending litigation and the uncertainties in the state approaches, the ultimate timing and impact of these standards on our operations cannot be determined with certainty at this time.

Climate Change and Greenhouse Gas Emissions

There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including CO₂, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the earth's atmosphere.  In December 2015, as part of the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change, the United States committed to reduce economy wide emissions by 26 percent to 28 percent below 2005 emission levels. This multinational agreement became open for signing on April 22, 2016 and will require countries to review and "represent a progression" every five years beginning in 2020. The agreement could result in future additional emissions reductions in the United States, however, it is not possible to determine what the international legal standards for greenhouse gas emissions will be in the future and the extent to which commitments under the December 2015 Paris Agreement will be implemented through the Clean Air Act, other than existing statutes and new legislation.

Several states have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.

If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of CO₂ and other greenhouse gases on the Company's facilities, this could result in significant additional compliance costs that would affect the Company’s future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

In 2009, the EPA adopted a comprehensive national system for reporting emissions of CO₂ and other greenhouse gases produced by major sources in the United States. The reporting requirements apply to large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain OG&E facilities. OG&E also reports quarterly its CO₂ emissions from generating units subject to the Federal Acid Rain Program. OG&E has submitted the reports required by the applicable reporting rules.

Nonetheless, OG&E’s current business strategy will result in a reduced carbon emissions rate compared to current levels. As discussed in “Pending Regulatory Matters”, OG&E has filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze FIP by converting two coal-fired generating units at Muskogee Station to natural gas, among other measures. OG&E’s deployment of Smart Grid technology helps to reduce the peak load demand. OG&E also seeks to utilize renewable energy sources that do not emit greenhouse gases. OG&E's service territory borders one of the nation's best wind resource areas. OG&E has leveraged its geographic position to develop renewable energy resources and completed transmission investments to deliver the renewable energy. The SPP has begun to authorize the construction of transmission lines capable of bringing renewable energy out of the wind resource area in western Oklahoma, the Texas Panhandle and western Kansas to load centers by planning for more transmission to be built in the area. In addition to increasing overall system reliability, these new

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transmission resources should provide greater access to additional wind resources that are currently constrained due to existing transmission delivery limitations.

EPA Startup, Shutdown, and Malfunction Policy

On May 22, 2015, the EPA issued a final rule to address the outdated provisions in the SIP of 36 states, including Oklahoma, regarding the treatment of emissions that occur during startup, shutdown and malfunction operations. The final rule clarifies the EPA's Startup, Shutdown and Malfunction Policy to assure consistency with the Clean Air Act and other recent court decisions. The Oklahoma Department of Environmental Quality is in the process of developing a SIP to comply with this rule, which is to be submitted to the EPA before November 2016. Although the extent of impact is not known, this rule will impact certain OG&E units.

Endangered Species

Certain Federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats.  If such species are located in an area in which the Company conducts operations, or if additional species in those areas become subject to protection, the Company’s operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or the Company could be required to implement expensive mitigation measures.

In 2014, the Company enrolled in the Western Association of Fish and Wildlife Agencies range-wide conservation plan which consists of industry-specific conservation practices that apply to projects and activities in the impacted area. The range-wide conservation plan was approved by the U.S. Fish and Wildlife Service and incorporated as part of the agency’s final decision on March 27, 2014 to list the lesser prairie chicken as a threatened species. On September 1, 2015, the U.S. District Court Western District of Texas vacated federal protections for the lesser prairie chicken based on the U.S. Fish and Wildlife Service's failure to thoroughly consider the active conservation efforts in making the listing decision.

Air Quality Control System

On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating dry scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015, to install the dry scrubber systems. The dry scrubbers are scheduled to be completed by 2019. More detail regarding the dry scrubber project can be found under the “Pending Regulatory Matters” section of Note 13 to Notes to Condensed Consolidated Financial Statements of Part I, Item 1 of this Form 10-Q.

Waste

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

On December 19, 2014, the EPA finalized a rule under the Federal Resource Conservation and Recovery Act for the handling and disposal of coal combustion residuals or coal ash. The final rule regulates coal ash as a solid waste rather than a hazardous waste, which would have made the management of coal ash more costly. OG&E is in compliance with this rule at this time.

The Company has sought and will continue to seek pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts.  In 2015, the Company obtained refunds of $2.3 million from the recycling of scrap metal, salvaged transformers and used transformer oil.  This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials.  Similar savings are anticipated in future years.

Water

 

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

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The EPA issued a final rule on May 19, 2014 to implement Section 316(b) of the Federal Clean Water Act, which requires that power plant cooling water intake structure location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. The EPA issued a final rule on May 19, 2014. OG&E submitted compliance plans to the state in April 2015. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation following issuance of the permits from the state.

On September 30, 2015, the EPA issued a final rule addressing the effluent limitation guidelines for power plants under the Clean Water Act. The final rule establishes technology and performance based standards that may apply to discharges of six waste streams including bottom ash transport water. Compliance with this rule occurs between 2018 and 2023. OG&E is evaluating what if any compliance actions are needed but is not able to quantify with any certainty, what costs may be incurred. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation following issuance of the permits from the state.

Site Remediation

 

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

For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 12 of Notes to Condensed Consolidated Financial Statements of Part I, Item 1 of this Form 10-Q.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

 

There have been no significant changes in the market risks affecting the Company from those discussed in the Company's 2015 Form 10-K.

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Item 4.  Controls and Procedures.

 

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

 

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

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.

 

Reference is made to Item 3 of Part I of the Company's 2015 Form 10-K for a description of certain legal proceedings presently pending. Except as described above under Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations," there are no new significant cases to report against the Company or its subsidiaries and there have been no material changes in the previously reported proceedings.

Item 1A.  Risk Factors.

Except as discussed below, there have been no significant changes in the Company's risk factors from those discussed in the Company's 2015 Form 10-K, which are incorporated herein by reference.

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

Enable's 10 percent Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in Enable (Enable's “Series A Preferred Units”), issued in February 2016, rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. Enable cannot declare or pay a distribution to its common or subordinated unitholders for any quarter unless full distributions have been or contemporaneously are being paid on all outstanding Series A Preferred Units for such quarter. These preferences could adversely affect the cash distributions we receive from Enable, or could make it more difficult for Enable to sell its common units in the future.

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

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

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

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

The holders of Enable's Series A Preferred Units may request that Enable list those units for trading on the New York Stock Exchange. If Enable is unable to list the Series A Preferred Units in certain circumstances, it will be required to redeem the Series A Preferred Units. There can be no assurance that Enable would have sufficient financial resources available to satisfy its

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obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of Enable's Series A Preferred Units could have a material adverse effect on its business, financial position, results of operations and ability to make quarterly cash distributions to its unitholders.

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

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

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

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

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

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

•	cash calls and settlements of hedging positions;

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

•	the level of competition from other midstream energy companies;

•	adverse effects of governmental and environmental regulation;

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

•	prevailing economic conditions.

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

•	the level and timing of capital expenditures it makes;

•	the cost of acquisitions;

•	its debt service requirements and other liabilities;

•	fluctuations in working capital needs;

•	its ability to borrow funds and access capital markets;

•	restrictions contained in its debt agreements;

•	the amount of cash reserves established by its general partner

•	distributions paid on its Series A Preferred Units; and

•	other business risks affecting its cash levels.

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

The amount of cash Enable has available for distribution depends primarily upon its cash flows and not solely on profitability, which will be affected by non-cash items. As a result, Enable may make cash distributions during periods when it records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.

Enable is expected to pay a specified minimum quarterly distribution on its outstanding common and subordinated units, including those units that we own, to the extent it has sufficient cash from operations after establishment of cash reserves, payments of distributions on the Series A Preferred Units and payment of fees and expenses, including payments to its general partner and its affiliates. The principal difference between Enable’s common units and subordinated units is that in any quarter during the applicable subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution on common units from prior quarters. If Enable does not pay distributions on its subordinated units, its subordinated units will not accrue arrearages for those unpaid distributions.

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Enable may issue additional units without the approval of its unitholders, which would dilute unitholders' existing ownership interests.

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

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

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

•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by Enable's common unitholders will increase;

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

•	the ratio of taxable income to distributions may increase;

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

•	the market price of the common units may decline.

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

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

As of April 2016, subsidiaries of CenterPoint Energy and the Company hold an aggregate of 136,983,998 common units and 207,855,430 subordinated units, and CenterPoint Energy holds 14,520,000 Series A Preferred Units. Upon a change of control, Enable's Series A Preferred Units are convertible into common units at the option of the holders of such units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier under certain circumstances. In addition, Enable has agreed to provide CenterPoint Energy, the Company and ArcLight with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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

The following table contains information about the Company's purchases of its common stock during the first quarter of 2016.

Period	Total Number of Shares Purchased			Average Price Paid Per Share			Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
01/1/16 - 01/31/16	—			$	—		N/A	N/A
02/1/16 - 02/28/16	901		(A)	$	25.83		N/A	N/A
03/1/16 - 03/31/16	—			$	—		N/A	N/A

(A)	These shares of restricted stock were returned to the Company to satisfy tax liabilities.

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Item 6.  Exhibits

Exhibit No.	Description
31.01	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Schema Document.
101.PRE	XBRL Taxonomy Presentation Linkbase Document.
101.LAB	XBRL Taxonomy Label Linkbase Document.
101.CAL	XBRL Taxonomy Calculation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	OGE ENERGY CORP.
	(Registrant)
By:	/s/ Scott Forbes
	Scott Forbes
	Controller and Chief Accounting Officer
	(On behalf of the Registrant and in his capacity as Chief Accounting Officer)

May 5, 2016

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