Edgar Filing: OGE ENERGY CORP.

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2016

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 June 30, 2016, there were 199,702,025 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2016

TABLE OF CONTENTS



	Page
GLOSSARY OF TERMS	ii
FORWARD-LOOKING STATEMENTS	1

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

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	27

Item 3. Quantitative and Qualitative Disclosures About Market Risk	46

Item 4. Controls and Procedures	46

Part II - OTHER INFORMATION
Item 1. Legal Proceedings	48

Item 1A. Risk Factors	48

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	50

Item 6. Exhibits	51

Signature	52

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
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO₂	Carbon dioxide
Company	OGE Energy, collectively with its subsidiaries
CSAPR	Cross-State Air Pollution Rule
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 July 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
Federal Clean Water Act	Federal Water Pollution Control Act of 1972, as amended
FERC	Federal Energy Regulatory Commission
FIP	Federal implementation plan
GAAP	Accounting principles generally accepted in the United States
IRP	Integrated Resource Plans
kV	Kilovolt
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 MWs 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
NO_X	Nitrogen oxide
OCC	Oklahoma Corporation Commission
ODEQ	Oklahoma Department of Environmental Quality
OG&E	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Holdings	OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy, 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
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SESH	Southeast Supply Header, LLC
SIP	State implementation plan
SO₂	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day

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;


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


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


•	environmental laws 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 to 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions except per share data)	2016			2015			2016			2015
OPERATING REVENUES	$	551.4		$	549.9		$	984.5		$	1,030.0
COST OF SALES	197.7			210.9			375.6			422.5
OPERATING EXPENSES
Other operation and maintenance	127.6			113.2			241.5			224.9
Depreciation and amortization	80.1			76.2			158.6			152.1
Taxes other than income	20.1			22.4			45.0			46.9
Total operating expenses	227.8			211.8			445.1			423.9
OPERATING INCOME	125.9			127.2			163.8			183.6
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	16.7			28.2			45.0			59.9
Allowance for equity funds used during construction	3.7			1.7			5.3			3.2
Other income	7.6			5.6			13.2			10.5
Other expense	(5.8		)	(2.2		)	(7.5		)	(3.2		)
Net other income	22.2			33.3			56.0			70.4
INTEREST EXPENSE
Interest on long-term debt	35.7			37.0			71.5			73.9
Allowance for borrowed funds used during construction	(1.8		)	(0.8		)	(2.7		)	(1.6		)
Interest on short-term debt and other interest charges	2.1			1.8			3.5			3.1
Interest expense	36.0			38.0			72.3			75.4
INCOME BEFORE TAXES	112.1			122.5			147.5			178.6
INCOME TAX EXPENSE	40.6			35.0			50.8			47.9
NET INCOME	$	71.5		$	87.5		$	96.7		$	130.7
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7			199.6			199.7			199.6
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.8			199.6			199.8			199.6
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	0.35		$	0.44		$	0.48		$	0.66
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	0.35		$	0.44		$	0.48		$	0.66
DIVIDENDS DECLARED PER COMMON SHARE	$	0.27500		$	0.25000		$	0.55000		$	0.50000

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Net income	$	71.5		$	87.5		$	96.7		$	130.7
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, $0.6, $0.8 and $1.4, respectively	0.7			0.8			1.5			1.2
Settlement cost, net of tax of $3.2, $0, $3.2 and $0, respectively	5.0			—			5.0			—
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0, $0.2, $0 and $0.4, respectively	—			0.4			—			0.6
Amortization of prior service cost, net of tax of ($0.3), ($0.2), ($0.5) and ($0.5), respectively	(0.4		)	(0.5		)	(0.8		)	(0.9		)
Other comprehensive income, net of tax	5.3			0.7			5.7			0.9
Comprehensive income	$	76.8		$	88.2		$	102.4		$	131.6

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	96.7		$	130.7
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	158.6			152.1
Deferred income taxes and investment tax credits	52.2			48.1
Equity in earnings of unconsolidated affiliates	(45.0		)	(59.9		)
Distributions from unconsolidated affiliates	45.4			68.9
Allowance for equity funds used during construction	(5.3		)	(3.2		)
Stock-based compensation	3.2			2.4
Regulatory assets	(4.0		)	2.5
Regulatory liabilities	(8.4		)	(2.0		)
Other assets	6.8			4.5
Other liabilities	5.7			(2.4		)
Change in certain current assets and liabilities
Accounts receivable, net	10.0			2.9
Accounts receivable - unconsolidated affiliates	3.1			3.2
Accrued unbilled revenues	(37.4		)	(30.8		)
Fuel, materials and supplies inventories	11.2			(29.7		)
Fuel clause under recoveries	—			64.6
Other current assets	(17.7		)	(10.2		)
Accounts payable	(56.8		)	(40.7		)
Fuel clause over recoveries	(20.0		)	1.6
Other current liabilities	(32.3		)	3.2
Net Cash Provided from Operating Activities	166.0			305.8
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(331.1		)	(227.7		)
Return of capital - equity method investments	25.2			—
Proceeds from sale of assets	0.2			2.0
Net Cash Used in Investing Activities	(305.7		)	(225.7		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(109.8		)	(99.8		)
Issuance of common stock	—			6.8
Payment of long-term debt	(110.1		)	(0.1		)
Increase in short-term debt	284.4			7.5
Net Cash Provided from (Used in) Financing Activities	64.5			(85.6		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(75.2		)	(5.5		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	75.2			5.5
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	—

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30,		December 31,
(In millions)	2016		2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	75.2
Accounts receivable, less reserve of $1.5 and $1.4, respectively	163.1		173.1
Accounts receivable - unconsolidated affiliates	—		1.7
Accrued unbilled revenues	90.9		53.5
Income taxes receivable	14.6		17.2
Fuel inventories	107.1		113.8
Materials and supplies, at average cost	75.6		80.1
Other	75.9		55.6
Total current assets	527.2		570.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,168.8		1,194.4
Other	72.4		70.7
Total other property and investments	1,241.2		1,265.1
PROPERTY, PLANT AND EQUIPMENT
In service	10,522.7		10,318.3
Construction work in progress	319.4		278.5
Total property, plant and equipment	10,842.1		10,596.8
Less accumulated depreciation	3,372.2		3,274.4
Net property, plant and equipment	7,469.9		7,322.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	401.9		402.2
Other	19.0		20.7
Total deferred charges and other assets	420.9		422.9
TOTAL ASSETS	$	9,659.2	$	9,580.6

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)



	June 30,			December 31,
(In millions)	2016			2015
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	284.4		$	—
Accounts payable - unconsolidated affiliates	1.4			—
Accounts payable	159.7			262.5
Dividends payable	54.9			54.9
Customer deposits	77.5			77.0
Accrued taxes	39.4			45.9
Accrued interest	40.3			42.9
Accrued compensation	35.7			54.4
Long-term debt due within one year	—			110.0
Fuel clause over recoveries	41.3			61.3
Other	38.9			43.9
Total current liabilities	773.5			752.8
LONG-TERM DEBT	2,629.7			2,628.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	300.1			299.9
Deferred income taxes	2,232.6			2,178.2
Regulatory liabilities	283.9			273.6
Other	117.6			121.3
Total deferred credits and other liabilities	2,934.2			2,873.0
Total liabilities	6,337.4			6,254.6
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,104.5			1,101.3
Retained earnings	2,246.7			2,259.8
Accumulated other comprehensive loss, net of tax	(29.4		)	(35.1		)
Total stockholders' equity	3,321.8			3,326.0
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,659.2		$	9,580.6

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(Unaudited)



(In millions)	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	—		—		96.7			—			96.7
Other comprehensive income, net of tax	—		—		—			5.7			5.7
Dividends declared on common stock	—		—		(109.8		)	—			(109.8		)
Stock-based compensation	—		3.2		—			—			3.2
Balance at June 30, 2016	$	2.0	$	1,102.5	$	2,246.7		$	(29.4	)	$	3,321.8

Balance at December 31, 2014	$	2.0	$	1,085.6	$	2,198.2		$	(41.4	)	$	3,244.4
Net income	—		—		130.7			—			130.7
Other comprehensive income, net of tax	—		—		—			0.9			0.9
Dividends declared on common stock	—		—		(99.8		)	—			(99.8		)
Issuance of common stock	—		6.8		—			—			6.8
Stock-based compensation	—		3.0		—			—			3.0
Balance at June 30, 2015	$	2.0	$	1,095.4	$	2,229.1		$	(40.5	)	$	3,286.0

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

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.	Summary of Significant Accounting Policies

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 an emerging 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 determined that its 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 June 30, 2016 and December 31, 2015, the results of its operations for the three and six months ended June 30, 2016 and 2015 and its cash flows for the six months ended June 30, 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 and six months ended June 30, 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.

Accounting Records

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

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

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



	June 30,		December 31,
(In millions)	2016		2015
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	43.9	$	36.6
SPP cost tracker rider under recovery (A)	7.5		4.5
Other (A)	11.8		5.4
Total Current Regulatory Assets	$	63.2	$	46.5
Non-Current
Benefit obligations regulatory asset	$	237.3	$	242.2
Income taxes recoverable from customers, net	58.3		56.7
Smart Grid	43.5		43.6
Deferred storm expenses	31.8		27.6
Unamortized loss on reacquired debt	14.1		14.8
Other	16.9		17.3
Total Non-Current Regulatory Assets	$	401.9	$	402.2
Regulatory Liabilities
Current
Fuel clause over recoveries	$	41.3	$	61.3
Other (B)	4.5		7.5
Total Current Regulatory Liabilities	$	45.8	$	68.8
Non-Current
Accrued removal obligations, net	$	256.2	$	254.9
Pension tracker	26.7		17.7
Other (C)	1.0		1.0
Total Non-Current Regulatory Liabilities	$	283.9	$	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.

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 as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at June 30, 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 and are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.

Asset Retirement Obligations

The following table summarizes changes to the Company's asset retirement obligations during the six months ended June 30, 2016 and 2015.



	Six Months Ended June 30,
(In millions)	2016		2015
Balance at January 1	$	63.3	$	58.6
Accretion expense	1.4		1.3
Liabilities settled	—		(0.5		)
Balance at June 30	$	64.7	$	59.4

Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the six months ended June 30, 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 income		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)	1.5			—		—		(0.8		)	0.7
Settlement cost	5.0			—		—		—			5.0
Net current period other comprehensive income (loss)	6.5			—		—		(0.8		)	5.7
Balance at June 30, 2016	$	(32.7	)	$	0.1	$	2.5	$	0.7		$	(29.4	)



	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)	1.2			—		0.6			(0.9		)	0.9
Balance at June 30, 2015	$	(35.6	)	$	0.1	$	(7.4	)	$	2.4		$	(40.5	)

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 and six months ended June 30, 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						Six Months Ended
	June 30,						June 30,
(In millions)	2016			2015			2016			2015
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.1	)	$	(1.4	)	$	(2.3	)	$	(2.6	)	(A)
Settlement	(8.2		)	—			(8.2		)	—			(A)
	(9.3		)	(1.4		)	(10.5		)	(2.6		)	Total before tax
	(3.6		)	(0.6		)	(4.0		)	(1.4		)	Tax benefit
	$	(5.7	)	$	(0.8	)	$	(6.5	)	$	(1.2	)	Net of tax

Amortization of postretirement benefit plan items
Actuarial losses	$	—		$	(0.6	)	$	—		$	(1.0	)	(A)
Prior service credit	0.7			0.7			1.3			1.4			(A)
	0.7			0.1			1.3			0.4			Total before tax
	0.3			—			0.5			0.1			Tax expense
	$	0.4		$	0.1		$	0.8		$	0.3		Net of tax

Total reclassifications for the period	$	(5.3	)	$	(0.7	)	$	(5.7	)	$	(0.9	)	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).

Reclassifications

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

The December 31, 2015 Balance Sheet has been adjusted for the reclassification of $16.8 million of debt issuance costs from total deferred charges and other assets to long-term debt to be consistent with the 2016 presentation due to the adoption of ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," in 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 ASU 2016-09. 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 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.

Financial Instruments-Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments.” The amendment in this update requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Company does not believe this ASU will have any effect on its Condensed Consolidated Financial Statements.


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 June 30, 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 $34.6 million during the three months ended June 30, 2016 and 2015, respectively, and $70.6 million and $68.9 million for the six months ended June 30, 2016 and 2015, respectively. On August 3, 2016, Enable announced a quarterly dividend distribution of $0.3180 per unit on its outstanding common and subordinated units, representing the same dividend distribution as the previous quarter.

CenterPoint had previously announced that it was evaluating strategic alternatives for its investment in Enable. On July 18, 2016, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided notice to the Company of CenterPoint’s solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. This notice also constituted a notice pursuant to the right of first offer held by the Company under the Partnership Agreement and the Third Amended and Restated Limited Liability Company Agreement of the general partner. Under the terms of the right of first offer, the Company has 30 days from receipt of the notice from CenterPoint to make an offer to buy all of CenterPoint’s membership interests in the general partner and all or any portion of CenterPoint Energy Resources Corp. common units and subordinated units. If the Company were to make an offer under the right of first offer, then CenterPoint would have 30 days to accept such offer. The Company is currently evaluating its options with respect to the right of first offer.

Related Party Transactions

Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below.

On May 1, 2013, the Company and Enable entered into a Services Agreement, an 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. The remaining services automatically extended for another year on May 1, 2016. Under these agreements, the Company charged operating costs to Enable of $1.3 million and $2.5 million for the three months ended June 30, 2016 and 2015, respectively, and $2.6 million and $5.3 million for the six months ended June 30, 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/or Enable are assigned as such. Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.

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 of 192 employees that participate in the Company's defined benefit and retirement plans beyond December 31, 2014. The Company billed Enable for reimbursement of $7.0 million and $8.1 million during the three months ended June 30, 2016 and June 30, 2015, respectively, and $14.1 million and $18.1 million during the six months ended June 30, 2016 and June 30, 2015, respectively, under the Transitional Seconding Agreement for employment costs.

The Company had accounts receivable from Enable of $2.8 million and $3.4 million as of June 30, 2016 and December 31, 2015, respectively, for amounts billed for transitional services, including the cost of seconded employees. Fuel purchases from Enable are excluded.

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 and six months ended June 30, 2016 and 2015.



	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
Operating Revenues:
Electricity to power electric compression assets	$	3.0	$	3.6	$	5.3	$	6.7
Cost of Sales:
Natural gas transportation services	$	8.8	$	8.7	$	17.5	$	17.5
Natural gas purchases/(sales)	5.4		2.1		6.9		4.6

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2016 and December 31, 2015 and for the three and six months ended June 30, 2016 and 2015.



	June 30,		December 31,
Balance Sheet	2016		2015
(In millions)
Current assets	$	349	$	381
Non-current assets	10,851		10,845
Current liabilities	301		615
Non-current liabilities	3,150		3,080



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Income Statement	2016		2015		2016		2015
(In millions)
Operating revenues	$	529	$	590	$	1,038	$	1,206
Cost of natural gas and natural gas liquids	254		277		449		569
Operating income	57		93		160		197
Net income	35		77		121		168

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 equity of $2.2 billion. Due to the contribution of Enogex LLC to Enable, meeting the requirements of being in substance real estate and thus 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 $16.7 million and $45.0 million for the three and six months ended June 30, 2016, respectively, and $28.2 million and $59.9 million for the three and six months ended June 30, 2015, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex and its underlying equity in net assets

of Enable. The basis difference is the result of the initial contribution of Enogex 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 SESH. 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.

The difference between the Company's investment in Enable and its underlying equity in the net assets of Enable was $768.7 million as of June 30, 2016.

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three and six months ended June 30, 2016 and 2015.



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2016		2015		2016		2015
(In millions)
OGE's share of Enable net income	$	9.1	$	20.6	$	30.4	$	44.4
Amortization of basis difference	3.0		3.6		5.9		7.1
Elimination of Enogex Holdings fair value and other adjustments	4.6		4.0		8.7		8.4
Equity in earnings of unconsolidated affiliates	$	16.7	$	28.2	$	45.0	$	59.9


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 June 30, 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 financial instruments at June 30, 2016 and December 31, 2015.



	June 30,				December 31,
	2016				2015
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
Senior Notes	$	2,384.7	$	2,812.5	$	2,493.9	$	2,754.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Tinker Debt	9.9		10.3		10.0		9.2
OGE Energy Senior Notes	99.7		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 which fair value is 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.


5.	Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three and six months ended June 30, 2016 and 2015 related to the Company's performance units and restricted stock.



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015
Performance units
Total shareholder return	$	1.1	$	1.9	$	2.2	$	3.8
Earnings per share	0.4		0.6		1.0		1.1
Total performance units	1.5		2.5		3.2		4.9
Restricted stock	0.1		0.1		0.1		0.1
Total compensation expense	1.6		2.6		3.3		5.0
Less: Amount paid by unconsolidated affiliates	—		0.2		—		0.5
Net compensation expense	$	1.6	$	2.4	$	3.3	$	4.5
Income tax benefit	$	0.7	$	1.0	$	1.3	$	1.8

During the three and six months ended June 30, 2016, the Company issued an immaterial number of shares to satisfy restricted stock grants.


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 and earns Oklahoma state tax credits associated with its investments in electric generating 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 and six months ended June 30, 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 June 30, 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.

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 June 30,				Six Months Ended June 30,
(In millions except per share data)	2016		2015		2016		2015
Net income	$	71.5	$	87.5	$	96.7	$	130.7
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.6		199.7		199.6
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.1		—		0.1		—
Diluted average common shares outstanding	199.8		199.6		199.8		199.6
Basic Earnings Per Average Common Share	$	0.35	$	0.44	$	0.48	$	0.66
Diluted Earnings Per Average Common Share	$	0.35	$	0.44	$	0.48	$	0.66
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—


8.	Long-Term Debt

At June 30, 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%	-	0.45%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.07%	-	0.45%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.45%	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.


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 June 30, 2016, the Company had $284.4 million of short-term debt as compared to no balance at December 31, 2015. The following table provides information regarding the Company's revolving credit agreement at June 30, 2016.



	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
(In millions)
OGE Energy (B)	$	750.0	$	284.4	0.76	%	(D)	December 13, 2018	(E)
OG&E (C)	400.0		1.7		0.95	%	(D)	December 13, 2018	(E)
Total	$	1,150.0	$	286.1	0.76	%


(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2016.


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


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


(D)	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 June 30, 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.


10.	Retirement Plans and Postretirement Benefit Plans

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During the quarter ended June 30, 2016, the Company experienced a settlement of its Supplemental Executive Retirement Plan, and its non-qualified Restoration of Retirement Income Plan. As a result, the Company recorded pension settlement charges of $8.7 million during the six months ended June 30, 2016. The pension settlement charge did not increase the Company’s total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.

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
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
(In millions)	2016 (B)			2015 (B)			2016 (C)			2015 (C)			2016 (B)		2015 (B)		2016 (C)		2015 (C)
Service cost	$	3.5		$	3.4		$	7.9		$	7.9		$	0.1	$	0.2	$	0.2	$	0.6
Interest cost	6.1			6.6			12.7			13.0			0.1		0.1		0.2		0.3
Expected return on plan assets	(10.2		)	(11.7		)	(20.7		)	(23.5		)	—		—		—		—
Amortization of net loss	4.0			5.4			8.2			9.7			0.1		0.2		0.3		0.3
Amortization of unrecognized prior service cost (A)	—			0.1			—			0.2			—		0.1		—		0.1
Settlement	—			—			—			—			8.7		—		8.7		—
Total net periodic benefit cost	3.4			3.8			8.1			7.3			9.0		0.6		9.4		1.3
Less: Amount paid by unconsolidated affiliates	1.2			1.0			2.5			2.1			0.2		0.1		0.2		0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	2.2		$	2.8		$	5.6		$	5.2		$	8.8	$	0.5	$	9.2	$	1.2


(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 $11.0 million and $3.3 million of net periodic benefit cost recognized during the three months ended June 30, 2016 and 2015, respectively, OG&E recognized the following:


•	an increase in pension expense during the three months ended June 30, 2016 and 2015 of $2.6 million and $2.4 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);


•	a deferral of pension expense during the three months ended June 30, 2016 of $0.6 million related to the pension settlement charge of $8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and


•	a deferral of pension expense during the three months ended June 30, 2016 of $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million.


(C)	In addition to the $14.8 million and $6.4 million of net periodic benefit cost recognized during the six months ended June 30, 2016 and 2015, respectively, OG&E recognized the following:


•	an increase in pension expense during the six months ended June 30, 2016 and 2015 of $4.9 million and $5.4 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);


•	a deferral of pension expense during the six months ended June 30, 2016 of $0.6 million related to the pension settlement charge of $8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and


•	a deferral of pension expense during the six months ended June 30, 2016 of $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million.



	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2016 (B)			2015 (B)			2016 (C)			2015 (C)
Service cost	$	0.1		$	0.3		$	0.4		$	0.8
Interest cost	2.4			2.5			4.7			5.1
Expected return on plan assets	(0.5		)	(0.6		)	(1.1		)	(1.2		)
Amortization of net loss	0.8			3.5			1.3			6.9
Amortization of unrecognized prior service cost (A)	(2.2		)	(4.2		)	(4.4		)	(8.3		)
Total net periodic benefit cost	0.6			1.5			0.9			3.3
Less: Amount paid by unconsolidated affiliates	—			0.3			0.1			0.6
Net periodic benefit cost (net of unconsolidated affiliates)	$	0.6		$	1.2		$	0.8		$	2.7


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

(B)

In addition to the $0.6 million and $1.2 million of net periodic benefit cost recognized during the three months ended June 30, 2016 and 2015, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended June 30, 2016 and 2015 of $2.0 million and $1.5 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).

(C)

In addition to the $0.8 million and $2.7 million of net periodic benefit cost recognized during the six months ended June 30, 2016 and 2015, respectively, OG&E recognized an increase in postretirement medical expense during the six months ended June 30, 2016 and 2015 of $4.0 million and $2.9 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				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
Capitalized portion of net periodic pension benefit cost	$	0.8	$	1.2	$	2.0	$	2.0
Capitalized portion of net periodic postretirement benefit cost	0.2		0.4		0.4		0.9

Pension Plan Funding

In July 2016, the Company contributed $20.0 million to its Pension Plan. No additional contributions are expected in 2016.


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) the natural gas midstream operations segment.

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

The following tables summarize the results of the Company's business segments during the three and six months ended June 30, 2016 and 2015.



Three Months Ended June 30, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	551.4	$	—		$	—		$	—		$	551.4
Cost of sales	197.7		—			—			—			197.7
Other operation and maintenance	124.8		7.8			(5.0		)	—			127.6
Depreciation and amortization	78.4		—			1.7			—			80.1
Taxes other than income	19.1		—			1.0			—			20.1
Operating income (loss)	131.4		(7.8		)	2.3			—			125.9
Equity in earnings of unconsolidated affiliates	—		16.7			—			—			16.7
Other income (expense)	7.0		—			(1.4		)	(0.1		)	5.5
Interest expense	35.0		—			1.1			(0.1		)	36.0
Income tax expense (benefit)	31.1		9.3			0.2			—			40.6
Net income (loss)	$	72.3	$	(0.4	)	$	(0.4	)	$	—		$	71.5
Investment in unconsolidated affiliates	$	—	$	1,168.8		$	—		$	—		$	1,168.8
Total assets	$	8,380.2	$	1,481.8		$	94.9		$	(297.7	)	$	9,659.2



Three Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	549.9	$	—		$	—		$	—		$	549.9
Cost of sales	210.9		—			—			—			210.9
Other operation and maintenance	115.6		0.2			(2.6		)	—			113.2
Depreciation and amortization	74.3		—			1.9			—			76.2
Taxes other than income	21.6		—			0.8			—			22.4
Operating income (loss)	127.5		(0.2		)	(0.1		)	—			127.2
Equity in earnings of unconsolidated affiliates	—		28.2			—			—			28.2
Other income (expense)	4.4		—			0.8			(0.1		)	5.1
Interest expense	37.3		—			0.8			(0.1		)	38.0
Income tax expense (benefit)	25.6		10.0			(0.6		)	—			35.0
Net income (loss)	$	69.0	$	18.0		$	0.5		$	—		$	87.5
Investment in unconsolidated affiliates	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,315.7	$	1,486.6		$	121.8		$	(348.0	)	$	9,576.1



Six Months Ended June 30, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	984.5	$	—		$	—		$	—		$	984.5
Cost of sales	375.6		—			—			—			375.6
Other operation and maintenance	241.1		8.0			(7.6		)	—			241.5
Depreciation and amortization	155.1		—			3.5			—			158.6
Taxes other than income	42.7		—			2.3			—			45.0
Operating income (loss)	170.0		(8.0		)	1.8			—			163.8
Equity in earnings of unconsolidated affiliates	—		45.0			—			—			45.0
Other income (expense)	12.3		—			(1.1		)	(0.2		)	11.0
Interest expense	70.5		—			2.0			(0.2		)	72.3
Income tax expense (benefit)	33.4		19.4			(2.0		)	—			50.8
Net income (loss)	$	78.4	$	17.6		$	0.7		$	—		$	96.7
Investment in unconsolidated affiliates	$	—	$	1,168.8		$	—		$	—		$	1,168.8
Total assets	$	8,380.2	$	1,481.8		$	94.9		$	(297.7	)	$	9,659.2



Six Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,030.0	$	—		$	—		$	—		$	1,030.0
Cost of sales	422.5		—			—			—			422.5
Other operation and maintenance	229.9		1.0			(6.0		)	—			224.9
Depreciation and amortization	148.1		—			4.0			—			152.1
Taxes other than income	44.7		—			2.2			—			46.9
Operating income (loss)	184.8		(1.0		)	(0.2		)	—			183.6
Equity in earnings of unconsolidated affiliates	—		59.9			—			—			59.9
Other income (expense)	7.3		—			3.3			(0.1		)	10.5
Interest expense	74.1		—			1.4			(0.1		)	75.4
Income tax expense (benefit)	31.9		18.1			(2.1		)	—			47.9
Net income (loss)	$	86.1	$	40.8		$	3.8		$	—		$	130.7
Investment in unconsolidated affiliates	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,315.7	$	1,486.6		$	121.8		$	(348.0	)	$	9,576.1


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.

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, on behalf of the EPA, 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 sought 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. The Sierra Club did not seek review of the case by the United States Supreme Court. OG&E considers this case now closed.

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


13.	Rate Matters and Regulation

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.

Completed Regulatory Matters

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 Court challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement.

On July 1, 2016, the Court upheld the FERC's decision requiring removal of the rights of first refusal for incumbent transmission providers from the SPP Membership Agreement. The Court determined that the FERC had reasonably found the rights of first refusal in the SPP Membership Agreement to be anticompetitive.

The Company does not believe the Court’s ruling will have any impact on existing transmission projects for which the Company has already received a notice to construct from the SPP. The Company intends to actively participate in the SPP planning process for competitive transmission projects that we believe apply to transmission voltage levels projects greater than 300kV.

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 May 26, 2016, the OCC issued a final order, finding that for the calendar year 2014 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent.

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.

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 PUD Staff's review.

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

In April 2015, the 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 PUD Staff recommends the OCC approve the PUD Staff's 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 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 June 30, 2016, OG&E had collected from its customers approximately $15.2 million of the $36.6 million of lost revenues for 2013, 2014 and 2015.

A hearing on the 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 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 $21.4 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 Rule 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. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015, approximately seven months after OG&E filed its application, 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 Rule 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. 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 did 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. On April 28, 2016, the OCC approved the dry scrubber project and OG&E is proceeding with the project. Two parties to the proceeding have appealed the OCC's decision to the Oklahoma Supreme Court.

OG&E anticipates the total cost of dry scrubbers will be $547.5 million. As of June 30, 2016, OG&E had incurred $116.8 million of construction work in progress on the dry scrubbers. OG&E anticipates the combustion turbines for the Mustang Modernization Plan will be $424.9 million. As of June 30, 2016, OG&E has incurred $103.6 million on the Mustang Modernization Plan.

Mustang Modernization Plan-Arkansas

On April 13, 2016, OG&E filed an application at the APSC seeking authority to construct combustion turbines at its existing Mustang generating facility. Arkansas law requires a public utility to seek approval from the APSC to construct a power-generating facility located outside the boundaries of the state of Arkansas. The application did not seek any cost recovery for the capital expenditures in the application, as cost recovery will be determined in future proceedings. On July 28, 2016, OG&E filed a motion to dismiss the APSC Mustang proceeding. OG&E intends to seek cost recovery of the Mustang combustion turbines at a later date after the Mustang facility is placed in service.

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 53.0 percent. Included in the PUD Staff's 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.

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. On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million while simultaneously reducing fuel costs billed to customers. The interim rates are subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate case.

Arkansas Rate Case Filing

OG&E intends to file a general rate case in Arkansas with the APSC during the third quarter of 2016.

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

Introduction

On August 3, 2016, Enable announced a quarterly dividend distribution of $0.3180 per unit on its outstanding common and subordinated units, representing the same dividend distribution as 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 customer's needs for energy and related services, focusing on safety, efficiency, reliability, customer service and risk management. The Company's corporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and interest in a publicly traded midstream company, while providing competitive energy products and services to customers as well as seeking growth opportunities in both businesses.

Additionally, the Company wants to achieve a premium valuation of its businesses relative to its peers, grow earnings per share with a stable earnings pattern, create a high performance culture and achieve desired outcomes with target stakeholders. The Company's financial objectives include a long-term annual earnings growth rate for OG&E of 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.