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EX-32.01 - EXHIBIT 32.01 - OGE ENERGY CORP.q12017oge10-qxex3201.htm
EX-31.01 - EXHIBIT 31.01 - OGE ENERGY CORP.q12017oge10-qxex3101.htm


 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2017

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____

Commission File Number: 1-12579
OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)
Oklahoma
 
73-1481638
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)

321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer  þ
Accelerated filer  o
Non-accelerated filer    o (Do not check if a smaller reporting company)
Smaller reporting company  o
 
Emerging growth company o

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

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

At March 31, 2017, there were 199,704,099 shares of common stock, par value $0.01 per share, outstanding.
 



OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2017

TABLE OF CONTENTS

 
Page
 
 
Part I - FINANCIAL INFORMATION
 
 
 
 
 
 
 
 
 
 
Part II - OTHER INFORMATION
 
 
 
 
 
 
 
 
 


i


GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations that are found throughout this Form 10-Q.
Abbreviation
Definition
2016 Form 10-K
Annual Report on Form 10-K for the year ended December 31, 2016
ALJ
Administrative Law Judge
APSC
Arkansas Public Service Commission
ArcLight group
Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC, collectively
ASU
Financial Accounting Standards Board Accounting Standards Update
CenterPoint
CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO2
Carbon dioxide
Company
OGE Energy Corp., collectively with its subsidiaries
CSAPR
Cross-State Air Pollution Rule
Dry Scrubbers
Dry flue gas desulfurization units with spray dryer absorber
ECP
Environmental Compliance Plan
Enable
Enable Midstream Partners, LP, a partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
Enogex Holdings
Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex LLC
Enogex LLC, collectively with its subsidiaries (effective July 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EPA
U.S. Environmental Protection Agency
FASB
Financial Accounting Standards Board
Federal Clean Water Act
Federal Water Pollution Control Act of 1972, as amended
FERC
Federal Energy Regulatory Commission
FIP
Federal implementation plan
GAAP
Accounting principles generally accepted in the United States
IRP
Integrated Resource Plan
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
MWh
Megawatt-hour
NAAQS
National Ambient Air Quality Standards
NGLs
Natural gas liquids
NOX
Nitrogen oxide
OCC
Oklahoma Corporation Commission
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 25.7 percent owner of Enable Midstream Partners
Pension Plan
Qualified defined benefit retirement plan
ppb
Parts per billion
PUD
Public Utility Division of the Oklahoma Corporation Commission
Regional Haze Rule
The EPA's regional haze rule
Restoration of Retirement Income Plan
Supplemental retirement plan to the Pension Plan
SIP
State implementation plan
SO2
Sulfur dioxide
SPP
Southwest Power Pool
System sales
Sales to OG&E's customers
TBtu/d
Trillion British thermal units per day

ii


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 2016 Form 10-K and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
the ability of the Company and its subsidiaries to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;
the ability to obtain timely and sufficient rate relief to allow for recovery of items such as capital expenditures, fuel costs, operating costs, transmission costs and deferred expenditures;
prices and availability of electricity, coal, natural gas and NGLs;
the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions Enable serves, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable's interstate pipelines;
the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering by Enable's gathering and processing business and transporting by Enable's interstate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regions Enable serves;
business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;
competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;
the impact on demand for our services resulting from cost-competitive advances in technology, such as distributed electricity generation and customer energy efficiency programs;
technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;
factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;
availability and prices of raw materials for current and future construction projects;
the effect of retroactive pricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;
Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company's markets;
environmental laws, safety laws or regulations that may impact the cost of operations or restrict or change the way the Company operates its facilities;
changes in accounting standards, rules or guidelines;
the discontinuance of accounting principles for certain types of rate-regulated activities;
the cost of protecting assets against, or damage due to, terrorism or cyber-attacks and other catastrophic events;
creditworthiness of suppliers, customers and other contractual parties;
social attitudes regarding the utility, natural gas and power industries;
identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions and divestitures;
increased pension and healthcare costs;
costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including, but not limited to, those described in this Form 10-Q;
difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment in Enable that the Company does not control; and
other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in "Item 1A. Risk Factors" in the Company's 2016 Form 10-K.

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

1


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
 
Three Months Ended March 31,
(In millions except per share data)
2017
2016
OPERATING REVENUES
$
456.0

$
433.1

COST OF SALES
208.7

177.9

OPERATING EXPENSES
 
 
Other operation and maintenance
124.0

113.9

Depreciation and amortization
55.6

78.5

Taxes other than income
23.9

24.9

Total operating expenses
203.5

217.3

OPERATING INCOME
43.8

37.9

OTHER INCOME (EXPENSE)
 
 
Equity in earnings of unconsolidated affiliates
35.6

28.3

Allowance for equity funds used during construction
6.9

1.6

Other income
8.8

5.6

Other expense
(4.1
)
(1.7
)
Net other income (expense)
47.2

33.8

INTEREST EXPENSE
 
 
Interest on long-term debt
35.9

35.8

Allowance for borrowed funds used during construction
(3.3
)
(0.9
)
Interest on short-term debt and other interest charges
2.4

1.4

Interest expense
35.0

36.3

INCOME BEFORE TAXES
56.0

35.4

INCOME TAX EXPENSE
20.0

10.2

NET INCOME
$
36.0

$
25.2

BASIC AVERAGE COMMON SHARES OUTSTANDING
199.7

199.7

DILUTED AVERAGE COMMON SHARES OUTSTANDING
200.0

199.7

BASIC EARNINGS PER AVERAGE COMMON SHARE
$
0.18

$
0.13

DILUTED EARNINGS PER AVERAGE COMMON SHARE
$
0.18

$
0.13

DIVIDENDS DECLARED PER COMMON SHARE
$
0.30250

$
0.27500
















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

2


OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended March 31,
(In millions)
2017
2016
Net income
$
36.0

$
25.2

Other comprehensive income (loss), net of tax
 
 
Pension Plan and Restoration of Retirement Income Plan:
 
 
Amortization of deferred net loss, net of tax of $0.4 and $0.4, respectively
0.6

0.8

Postretirement Benefit Plans:
 
 
Amortization of prior service cost, net of tax of ($0.0) and ($0.2), respectively

(0.4
)
Other comprehensive income, net of tax
0.6

0.4

Comprehensive income
$
36.6

$
25.6





































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

3



OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Three Months Ended March 31,
(In millions)
2017
2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$
36.0

$
25.2

Adjustments to reconcile net income to net cash provided from operating activities


Depreciation and amortization
55.6

78.5

Deferred income taxes and investment tax credits, net
20.4

10.4

Equity in earnings of unconsolidated affiliates
(35.6
)
(28.3
)
Distributions from unconsolidated affiliates
35.3

28.7

Allowance for equity funds used during construction
(6.9
)
(1.6
)
Stock-based compensation
2.1

1.7

Regulatory assets
(6.4
)
(2.3
)
Regulatory liabilities
(4.6
)
(4.6
)
Other assets
(4.0
)
2.5

Other liabilities
6.2

2.1

Change in certain current assets and liabilities
 
 
Accounts receivable, net
36.4

38.0

Accounts receivable - unconsolidated affiliates
(3.3
)
(1.2
)
Accrued unbilled revenues
3.5

2.1

Fuel, materials and supplies inventories
(7.7
)
10.2

Fuel clause under recoveries
(22.1
)

Other current assets
4.3

(10.0
)
Accounts payable
24.9

(44.1
)
Fuel clause over recoveries

2.0

Other current liabilities
(43.1
)
(35.9
)
Net Cash Provided from Operating Activities
91.0

73.4

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures (less allowance for equity funds used during construction)
(219.9
)
(177.7
)
Return of capital - equity method investments

6.6

Net Cash Used in Investing Activities
(219.9
)
(171.1
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Dividends paid on common stock
(60.4
)
(54.9
)
Proceeds from long-term debt
297.1


Payment of long-term debt
(0.1
)
(110.1
)
Increase (decrease) in short-term debt
(108.0
)
187.5

Net cash provided from financing activities
128.6

22.5

NET CHANGE IN CASH AND CASH EQUIVALENTS
(0.3
)
(75.2
)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
0.3

75.2

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$

$








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

4


OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

March 31,
December 31,
(In millions)
2017
2016
ASSETS
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
$

$
0.3

Accounts receivable, less reserve of $1.1 and $1.5, respectively
136.6

173.0

Accounts receivable - unconsolidated affiliates
5.8

2.5

Accrued unbilled revenues
56.2

59.7

Income taxes receivable
13.4

19.4

Fuel inventories
86.3

79.8

Materials and supplies, at average cost
82.9

81.7

Fuel clause under recoveries
73.4

51.3

Other
83.5

81.8

Total current assets
538.1

549.5

OTHER PROPERTY AND INVESTMENTS




Investment in unconsolidated affiliates
1,158.9

1,158.6

Other
75.5

73.6

Total other property and investments
1,234.4

1,232.2

PROPERTY, PLANT AND EQUIPMENT
 
 
In service
10,730.8

10,690.0

Construction work in progress
673.3

495.1

Total property, plant and equipment
11,404.1

11,185.1

Less accumulated depreciation
3,503.8

3,488.9

Net property, plant and equipment
7,900.3

7,696.2

DEFERRED CHARGES AND OTHER ASSETS
 
 
Regulatory assets
403.1

404.8

Other
59.0

56.9

Total deferred charges and other assets
462.1

461.7

TOTAL ASSETS
$
10,134.9

$
9,939.6





















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

5


OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
(Unaudited)

March 31,
December 31,
(In millions)
2017
2016
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
CURRENT LIABILITIES
 
 
Short-term debt
$
128.2

$
236.2

Accounts payable
244.3

205.4

Dividends payable
60.4

60.4

Customer deposits
78.6

77.7

Accrued taxes
25.2

41.3

Accrued interest
33.0

40.4

Accrued compensation
25.5

45.1

Long-term debt due within one year
224.8

224.7

Other
95.0

96.0

Total current liabilities
915.0

1,027.2

LONG-TERM DEBT
2,703.2

2,405.8

DEFERRED CREDITS AND OTHER LIABILITIES
 
 
Accrued benefit obligations
276.5

274.8

Deferred income taxes
2,332.0

2,334.5

Regulatory liabilities
306.7

299.7

Other
157.1

153.8

Total deferred credits and other liabilities
3,072.3

3,062.8

Total liabilities
6,690.5

6,495.8

COMMITMENTS AND CONTINGENCIES (NOTE 12)


STOCKHOLDERS' EQUITY
 
 
Common stockholders' equity
1,107.9

1,105.8

Retained earnings
2,365.2

2,367.3

Accumulated other comprehensive loss, net of tax
(28.7
)
(29.3
)
Total stockholders' equity
3,444.4

3,443.8

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
10,134.9

$
9,939.6




















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

6


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, 2016
$
2.0

$
1,103.8

$
2,367.3

$
(29.3
)
$
3,443.8

Cumulative effect of change in accounting principle


22.3


22.3

Net income


36.0


36.0

Other comprehensive income, net of tax



0.6

0.6

Dividends declared on common stock


(60.4
)

(60.4
)
Stock-based compensation

2.1



2.1

Balance at March 31, 2017
$
2.0

$
1,105.9

$
2,365.2

$
(28.7
)
$
3,444.4

 
 
 
 
 
 
Balance at December 31, 2015
$
2.0

$
1,099.3

$
2,259.8

$
(35.1
)
$
3,326.0

Net income


25.2


25.2

Other comprehensive income, net of tax



0.4

0.4

Dividends declared on common stock


(54.9
)

(54.9
)
Stock-based compensation

1.6



1.6

Balance at March 31, 2016
$
2.0

$
1,100.9

$
2,230.1

$
(34.7
)
$
3,298.3


































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

7



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 the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.
In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at March 31, 2017 and December 31, 2016, the results of its operations for the three months ended March 31, 2017 and 2016 and its cash flows for the three months ended March 31, 2017 and 2016, have been included and are of a normal recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring after March 31, 2017 up to the date of issuance of these Condensed Consolidated Financial Statements and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

Due to seasonal fluctuations and other factors, the Company's operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 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 2016 Form 10-K.


8



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:
 
March 31,
December 31,
(In millions)
2017
2016
Regulatory Assets
 
 
Current
 
 
Fuel clause under recoveries
$
73.4

$
51.3

Oklahoma demand program rider under recovery (A)
45.6

51.0

SPP cost tracker under recovery (A)
14.6

10.0

Other (A)
8.6

9.5

Total Current Regulatory Assets
$
142.2

$
121.8

Non-Current
 

 

Benefit obligations regulatory asset
$
228.9

$
232.6

Income taxes recoverable from customers, net
65.6

62.3

Deferred storm expenses
40.5

35.7

Smart Grid
38.2

43.2

Unamortized loss on reacquired debt
13.1

13.4

Other
16.8

17.6

Total Non-Current Regulatory Assets
$
403.1

$
404.8

Regulatory Liabilities
 

 

Current
 

 

Other (B)
$
13.4

$
12.3

Total Current Regulatory Liabilities
$
13.4

$
12.3

Non-Current
 

 

Accrued removal obligations, net
$
268.6

$
262.8

Pension tracker
36.6

35.5

Other
1.5

1.4

Total Non-Current Regulatory Liabilities
$
306.7

$
299.7

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

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

9



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, therefore, the Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at March 31, 2017. 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 three months ended March 31, 2017 and 2016.
 
Three Months Ended March 31,
(In millions)
2017
2016
Balance at January 1
$
69.6

$
63.3

Accretion expense
0.7

0.7

Balance at March 31
$
70.3

$
64.0


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 three months ended March 31, 2017 and 2016. All amounts below are presented net of tax.
 
Pension Plan and Restoration of Retirement Income Plan
 
Postretirement Benefit Plans
 
(In millions)
Net income
 (loss)
Prior service cost
 
Net income (loss)
Prior service cost
Total
Balance at December 31, 2016
$
(32.1
)
$
0.1

 
$
2.7

$

$
(29.3
)
Amounts reclassified from accumulated other comprehensive income (loss)
0.6


 


0.6

Balance at March 31, 2017
$
(31.5
)
$
0.1

 
$
2.7

$

$
(28.7
)

10



 
Pension Plan and Restoration of Retirement Income Plan
 
Postretirement Benefit Plans
 
(In millions)
Net income
 (loss)
Prior service cost
 
Net income (loss)
Prior service cost
Total
Balance at December 31, 2015
$
(39.2
)
$
0.1

 
$
2.5

$
1.5

$
(35.1
)
Amounts reclassified from accumulated other comprehensive income (loss)
0.8


 

(0.4
)
0.4

Balance at March 31, 2016
$
(38.4
)
$
0.1


$
2.5

$
1.1

$
(34.7
)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three months ended March 31, 2017 and 2016.
Details about Accumulated Other Comprehensive Income (Loss) Components
Amount Reclassified from Accumulated Other Comprehensive Income (Loss)
Affected Line Item in the Statement Where Net Income is Presented
 
Three Months Ended
 
 
March 31,
 
(In millions)
2017
2016
 
Amortization of defined benefit pension and restoration of retirement income plan items
 
 
 
Actuarial losses
$
(1.0
)
$
(1.2
)
(A)
 
(0.4
)
(0.4
)
Income taxes
 
$
(0.6
)
$
(0.8
)
Net of tax
 
 
 
 
Amortization of postretirement benefit plan items
 
 
 
Prior service credit
$

$
0.6

(A)
 

0.6

Total before tax
 

0.2

Income taxes
 
$

$
0.4

Net of tax
 
 
 
 
Total reclassifications for the period
$
(0.6
)
$
(0.4
)
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).

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 Company currently expects to apply the modified retrospective transition method, but will ultimately determine its transition approach once various industry issues have been resolved. Currently, the Company is not aware of any issues that would have a material impact on the timing of revenue recognition. The Company is assessing the effect of this new guidance on its tariff-based sales, bundled arrangements and alternative revenue programs. At this time, the Company is evaluating the impact of the new standard on its results of operations and financial position, but believes that it will change the income statement presentation of revenues and will require new disclosures.

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

11



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 started evaluating its current lease contracts. The Company has not determined the amount of impact on its Condensed Consolidated Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities.

Employee Share Based Payment Accounting. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share Based Payment Accounting," which amends Accounting Standards Codification 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 requires all of the tax effects related to share based payments at settlement (or expiration) to be recorded through the income statement. Previously, tax benefits in excess of compensation cost, or windfalls, were recorded in equity, and tax deficiencies, or shortfalls, were recorded in equity to the extent of previous windfalls, and then to the income statement. Under the new guidance, the windfall tax benefit is 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 previous requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. The Company adopted this standard in the first quarter of 2017, and recorded a cumulative effect of $22.3 million as a deferred tax asset with an offset in retained earnings. Going forward, tax benefits in excess of compensation costs previously recorded in equity will be recorded within the income statement and all tax related cash flows resulting from share based payments will be recorded as an operating activity within the statement of cash flows.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In May 2017, the FASB issued ASU 2017-07, “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.”  The new guidance is designed to improve the reporting of pension and other postretirement benefit costs by bifurcating the components of net benefit expense between those that are attributed to compensation for service and those that are not.  The service cost component of benefit expense will continue to be presented within operating income, but entities will now be required to present the other components of benefit expense as non-operating within the income statement.  Additionally, the new guidance only permits the capitalization of the service cost component of net benefit expense.

The accounting change is required to be applied using a modified retrospective approach for the presentation of components of net benefit cost, and on a prospective basis for the capitalization of only the service cost component of net benefit costs.  The new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Early adoption is permitted, subject to certain conditions.

The Company believes that the impact of the change in capitalization of only the service cost component of net periodic benefit costs will be immaterial from current practice.  The Company does not intend to early adopt the new guidance and will implement the change in the first quarter of 2018.

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.
Enable completed an initial public offering resulting in Enable becoming a publicly traded Master Limited Partnership in April 2014. At March 31, 2017, the Company owned 111.0 million common units, or 25.7 percent of Enable's outstanding common units. Of the Company's 111.0 million common units, 68.2 million units were subordinated. The subordination period

12



began on the closing date of Enable's initial public offering and will extend until the first business day following the distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017. The Company anticipates that the subordination period will expire in August 2017 and will not impact future distributions that the Company receives from Enable.

On May 2, 2017, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common and subordinated units, which is unchanged from the previous quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

Distributions received from Enable were $35.3 million during the three months ended March 31, 2017 and 2016.

On January 16, 2017, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided a second 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. On February 15, 2017, under the terms of right of first offer, the Company submitted to CenterPoint another proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in Enable GP and all of the common units and subordinated units of Enable owned by CenterPoint. The Company did not receive a reply from CenterPoint within the required timeframe. In accordance with the provisions of the partnership agreement, CenterPoint has until July 15, 2017 to solicit additional offers in excess of the Company's offer.

If the Company's proposal had been accepted by CenterPoint, and if the transaction contemplated by the proposal was in fact consummated, the Company anticipated that the third party would, as a result of such transaction, become the owner of all or substantially all of the securities subject to the right of first offer. The Company's ownership interest in Enable would not have materially changed as a result of such transaction, and therefore the Company would not have been required to consolidate the financial results of Enable with the financial results of the Company.

The Company cannot predict what future actions CenterPoint will take, if any, associated with their ownership interest in Enable.

Related Party Transactions

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

In connection with the formation of Enable, 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, 2017. Under these agreements, the Company charged operating costs to Enable of $0.8 million and $1.3 million for the three months ended March 31, 2017 and 2016, 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.

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, the Company, CenterPoint 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 $10.0 million and $8.3 million during the three months ended March 31, 2017 and 2016, respectively, under the Transitional Seconding Agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by approximately $20.9 million. Settlement and curtailment charges associated with the Enable seconded

13



employees are not reimbursable to the Company by Enable. The seconding agreement can be terminated by mutual agreement of the Company and Enable or solely by the Company upon 120 day notice.

The Company had accounts receivable from Enable for amounts billed for transitional services, including the cost of seconded employees, of $5.9 million as of March 31, 2017 and $2.7 million as of December 31, 2016, respectively.

Enable provides gas transportation services to OG&E pursuant to an agreement that expires in April 2019. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries. The following table summarizes related party transactions between OG&E and Enable during the three months ended March 31, 2017 and 2016.
 
Three Months Ended
 
March 31,
(In millions)
2017
2016
Operating Revenues:
 
 
Electricity to power electric compression assets
$
2.2

$
2.3

Cost of Sales:
 
 
Natural gas transportation services
$
8.8

$
8.8

Natural gas purchases/(sales)
(0.4
)
1.5

 
Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at March 31, 2017 and December 31, 2016 and for the three months ended March 31, 2017 and 2016.
 
March 31,
December 31,
Balance Sheet
2017
2016
(In millions)
 
Current assets
$
375

$
396

Non-current assets
10,786

10,816

Current liabilities
279

362

Non-current liabilities
3,111

3,056


 
Three Months Ended
 
March 31,
Income Statement
2017
2016
(In millions)
 
Operating revenues
$
666

$
509

Cost of natural gas and natural gas liquids
308

195

Operating income
140

103

Net income
111

86


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.


14



The Company recorded equity in earnings of unconsolidated affiliates of $35.6 million and $28.3 million for the three months ended March 31, 2017 and 2016, 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 the net assets of Enable. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed, beginning in May 2013. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described below.

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three months ended March 31, 2017 and 2016.

Three Months Ended

March 31,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates
2017
2016
(In millions)

Enable net income
$
110.8

$
86.0

Differences due to timing of OGE Energy and Enable accounting close

(11.7
)
Enable net income used to calculate OGE Energy's equity in earnings
$
110.8

$
74.3

OGE Energy’s percent ownership at period end
25.7
%
26.3
%
OGE Energy’s portion of Enable net income
$
28.5

$
19.5

Impairments recognized by Enable associated with OGE Energy’s basis differences

1.8

OGE Energy's share of Enable net income
$
28.5

$
21.3

Amortization of basis difference
2.8

2.9

Elimination of Enable fair value step up
4.3

4.1

Equity in earnings of unconsolidated affiliates
$
35.6

$
28.3


The difference between the OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $736.6 million as of March 31, 2017. The following table reconciles the basis difference in Enable from December 31, 2016 to March 31, 2017.
(In millions)
 
 
Basis difference as of December 31, 2016
 
$
743.7

Amortization of basis difference
 
(2.8
)
Elimination of Enable fair value step up
 
(4.3
)
Basis difference as of March 31, 2017
 
$
736.6


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

15



reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). 
 
The Company had no financial instruments measured at fair value on a recurring basis at March 31, 2017 and December 31, 2016.
 
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.

The following table summarizes the fair value and carrying amount of the Company's financial instruments at March 31, 2017 and December 31, 2016.
 
March 31,
December 31,
 
2017
2016
(In millions)
Carrying Amount 
Fair
Value
Carrying Amount 
 Fair
Value
Long-Term Debt (including Long-Term Debt due within one year)
 
 
 
 
Senior Notes
$
2,683.0

$
2,941.5

$
2,385.5

$
2,657.2

OG&E Industrial Authority Bonds
135.4

135.4

135.4

135.4

Tinker Debt
9.8

9.3

9.9

9.5

OGE Energy Senior Notes
99.8

100.0

99.7

99.9


5.
Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three months ended March 31, 2017 and 2016 related to the Company's performance units and restricted stock.
 
Three Months Ended March 31,
(In millions)
2017
2016
Performance units
 
 
Total shareholder return
$
1.5

$
1.1

Earnings per share
0.6

0.6

Total performance units
2.1

1.7

Restricted stock


Total compensation expense
2.1

1.7

Income tax benefit
$
0.8

$
0.6


During the three months ended March 31, 2017, the Company issued an immaterial number of shares to satisfy restricted stock grants.

The following table summarizes the activity of the Company's stock-based compensation during the three months ended March 31, 2017.
 
Units/Shares
Fair Value
Per Share
Grants
 
 
Performance units (Total shareholder return)
260,570

$
41.77

Performance units (Earnings per share)
86,857

$
34.95


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 2013 or state and local tax examinations by tax authorities for years prior to 2012.  Income taxes are generally allocated to each company

16



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 months ended March 31, 2017.  

Earnings Per Share
 
Basic earnings per share is calculated by dividing net income attributable to the Company by the weighted average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units and restricted stock units. Basic and diluted earnings per share for the Company were calculated as follows:
 
Three Months Ended March 31,
(In millions except per share data)
2017
2016
Net income
$
36.0

$
25.2

Average Common Shares Outstanding
 
 
Basic average common shares outstanding
199.7

199.7

Effect of dilutive securities:
 
 
Contingently issuable shares (performance and restricted stock units)
0.3


Diluted average common shares outstanding
200.0

199.7

Basic Earnings Per Average Common Share
$
0.18

$
0.13

Diluted Earnings Per Average Common Share
$
0.18

$
0.13

Anti-dilutive shares excluded from earnings per share calculation



8.
Long-Term Debt
 
At March 31, 2017, 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)
0.65%
-
0.95%
Garfield Industrial Authority, January 1, 2025
$
47.0

0.65%
-
0.90%
Muskogee Industrial Authority, January 1, 2025
32.4

0.66%
-
0.95%
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

17



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.

Issuance of New Long-Term Debt

In March 2017, OG&E issued $300.0 million of 4.15 percent senior notes due April 1, 2047. The proceeds from the issuance were used to repay short-term debt and were added to OG&E's general funds to be used for general corporate purposes, including to repay borrowings under the revolving credit facility, to fund the payment at maturity of OG&E's $125.0 million of 6.5 percent senior notes due July 15, 2017, and to fund ongoing capital expenditures and working capital.

Expected Issuance of Long-Term Debt

OG&E expects to issue up to $300.0 million of long-term debt during the second half of 2017, depending on market conditions, to fund capital expenditures, to repay short or long-term borrowings and for general corporate purposes.

9.
Short-Term Debt and Credit Facilities
 
On March 8, 2017 the Company and OG&E each entered into new $450.0 million unsecured five-year revolving credit facilities to replace existing facilities. Each of these new facilities is scheduled to terminate on March 8, 2022. However, the Company and OG&E have the right to request an extension of the revolving credit facility termination date under their respective facility for an additional one-year period, which can be exercised up to two times. All such extension requests are subject to majority lender group approval (and only the commitments of those lenders that consent to such extension (or that agree to replace any non-consenting lender) will be extended for such additional period).

Borrowings under the new facilities bear interest at rates equal to either the eurodollar base rate (reserve adjusted, if applicable), plus a margin of 0.69 percent to 1.275 percent, or an alternate base rate, plus a margin of 0.0 percent to 0.275 percent. The new facilities have a facility fee that ranges from 0.06 percent to 0.225 percent. Interest rate margins and facility fees are based on the Company's and OG&E's then-current senior unsecured credit ratings, as applicable.

Each of the facilities provides for issuance of letters of credit, provided that (i) the aggregate outstanding credit exposure shall not exceed the amount of the revolving credit facility and (ii) the aggregate outstanding stated amount of letters of credit issued under such facility shall not exceed a specified maximum sublimit ($100 million for each of the Company and OG&E). Advances under the facilities may be used to refinance existing indebtedness and for working capital and general corporate purposes of the respective borrower and its subsidiaries, including commercial paper liquidity support, letters of credit, acquisitions and distributions.

Each of the facilities is unsecured and, under certain circumstances, may be increased (by up to $150 million in each case for the Company and OG&E), to a maximum revolving commitment limit of $600 million. Advances of revolving loans and letters of credit under the facilities are subject to certain conditions precedent, including the accuracy of certain representations and warranties and the absence of any default or unmatured default.

The Company and OG&E's facilities each has a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent, as defined in each such facility. The Company and OG&E's facilities each also contains covenants which restrict the respective borrower and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. The Company and OG&E's facilities are each subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facilities, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in each such facility), nonpayment of uninsured judgments in excess of $100.0 million, and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods.

18




As of March 31, 2017, the Company had $128.2 million of short-term debt as compared to $236.2 million at December 31, 2016. The following table provides information regarding the Company's revolving credit agreements at March 31, 2017.
 
Aggregate
Amount
Weighted-Average
 
 
Entity
Commitment 
Outstanding (A)
Interest Rate
 
Expiration
(In millions)
 
 
 
 
OGE Energy (B)
$
450.0

$
128.2

1.219
%
(D)
March 8, 2022
OG&E (C)
450.0

1.8

0.95
%
(D)
March 8, 2022
Total
$
900.0

$
130.0

1.214
%
 
 
(A)
Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2017.
(B)
This bank facility is available to back up the Company's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  
(C)
This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.   
(D)
Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions.  Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations.  Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit.
 
OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis.  OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2017 and ending December 31, 2018.

10.
Retirement Plans and Postretirement Benefit Plans

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

Net Periodic Benefit Cost
 
Pension Plan
 
Restoration of Retirement
Income Plan
 
Postretirement Benefit Plans
 
Three Months Ended
 
Three Months Ended
 
Three Months Ended
 
March 31,
 
March 31,
 
March 31,
(In millions)
2017 (B)
2016 (B)
 
2017 (B)
2016 (B)
 
2017 (B)
2016 (B)
Service cost
$
4.2

$
4.4

 
$
0.1

$
0.1

 
$
0.2

$
0.3

Interest cost
6.5

6.6

 
0.1

0.1

 
2.2

2.3

Expected return on plan assets
(10.7
)
(10.5
)
 


 
(0.6
)
(0.6
)
Amortization of net loss
4.0

4.2

 
0.1

0.2

 
0.6

0.5

Amortization of unrecognized prior service cost (A)


 


 

(2.2
)
Total net periodic benefit cost
4.0

4.7


0.3

0.4

 
2.4

0.3

Less: Amount paid by unconsolidated affiliates
0.8

1.3

 


 
0.4

0.1

Net periodic benefit cost (net of unconsolidated affiliates)
$
3.2

$
3.4

 
$
0.3

$
0.4

 
$
2.0

$
0.2


19



(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 $5.5 million and $4.0 million of net periodic benefit cost recognized during the three months ended March 31, 2017 and 2016, respectively, OG&E recognized the following:

an increase in pension expense during the three months ended March 31, 2017 and 2016 of $2.9 million and $2.3 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1); and
an increase in postretirement medical expense in the three months ended March 31, 2017 and 2016 of $1.1 million and $2.0 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 for regulatory liability (see Note 1).

 
Three Months Ended
 
March 31,
(In millions)
2017
2016
Capitalized portion of net periodic pension benefit cost
$
1.0

$
1.2

Capitalized portion of net periodic postretirement benefit cost
0.7

0.1


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 months ended March 31, 2017 and 2016.
Three Months Ended March 31, 2017
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
456.0

$

$

$

$
456.0

Cost of sales
208.7




208.7

Other operation and maintenance
126.1

0.1

(2.2
)

124.0

Depreciation and amortization
54.7


0.9


55.6

Taxes other than income
22.3

0.2

1.4


23.9

Operating income (loss)
44.2

(0.3
)
(0.1
)

43.8

Equity in earnings of unconsolidated affiliates

35.6



35.6

Other income (expense)
12.9

0.1

(1.3
)
(0.1
)
11.6

Interest expense
33.6


1.5

(0.1
)
35.0

Income tax expense (benefit)
7.3

15.4

(2.7
)

20.0

Net income (loss)
$
16.2

$
20.0

$
(0.2
)
$

$
36.0

Investment in unconsolidated affiliates
$

$
1,158.9

$

$

$
1,158.9

Total assets
$
8,950.9

$
1,521.2

$
91.1

$
(428.3
)
$
10,134.9


20


Three Months Ended March 31, 2016
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
433.1

$

$

$

$
433.1

Cost of sales
177.9




177.9

Other operation and maintenance
116.3

0.2

(2.6
)

113.9

Depreciation and amortization
76.7


1.8


78.5

Taxes other than income
23.6


1.3


24.9

Operating income (loss)
38.6

(0.2
)
(0.5
)

37.9

Equity in earnings of unconsolidated affiliates

28.3



28.3

Other income (expense)
5.3


0.3

(0.1
)
5.5

Interest expense
35.5


0.9

(0.1
)
36.3

Income tax expense (benefit)
2.3

10.1

(2.2
)

10.2

Net income
$
6.1

$
18.0

$
1.1

$

$
25.2

Investment in unconsolidated affiliates
$

$
1,187.4

$

$

$
1,187.4

Total assets
$
8,288.5

$
1,467.9

$
98.7

$
(331.8
)
$
9,523.3



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 13 and 14 to the Company's Consolidated Financial Statements included in the Company's 2016 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. Management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards.

Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. 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.

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 ECP can be found under “Pending Regulatory Matters” in Note 13.


21



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 14 to the Company's Consolidated Financial Statements included in the Company's 2016 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

Oklahoma Rate Case Filing

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.

On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million, subject to refund for amounts in excess of the rates approved by the OCC. As of March 31, 2017 OG&E has fully reserved all of the interim rate increase pending resolution of the refund methodology.

In December 2016, the ALJ issued a report and recommendations in the case. The ALJ's recommendations included, among other things, the use of OG&E's actual capital structure of 53.0 percent equity and 47.0 percent long-term debt and a return on equity of 9.87 percent resulting in an annual increase in OG&E's revenues of $40.7 million.

On March 20, 2017, the OCC held hearings and issued a final order. The final order results in an annual net increase of approximately $8.8 million in OG&E's rates to its Oklahoma retail customers. Although the final order adopted certain of the recommendations set forth in the ALJ Report, it differs in certain key respects.

The primary adjustments to the ALJ report consist of: (i) Oklahoma retail authorized rate of return on equity of 9.50 percent, (ii) depreciation expense is reduced by approximately $28.6 million from the ALJ report or $36.4 million from current rates on an annual basis, (iii) recovery of only 50.0 percent of short-term incentive compensation and no recovery of long-term incentive compensation, (iv) recovery of OG&E's requested vegetation management expenses and (v) recovery of production tax credits expiring in 2017 and air quality control systems consumable costs through the fuel adjustment clause.

As a result of the final order, OG&E recorded in the first quarter of 2017, adjustments to depreciation expense, amortization of regulatory assets and liabilities, and impacts to the fuel adjustment clause effective July 1, 2016. On May 1, 2017, OG&E implemented new rates and began refunding excess amounts that it had collected in interim rates.

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.

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 asked

22



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 with 400 MWs of new, efficient combustion turbines at the Mustang site and approval for a recovery mechanism for the associated costs.

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 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. 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.

Two parties appealed the OCC's decision to the Oklahoma Supreme Court. The Company is unable to predict what action the Oklahoma Supreme Court may take or the timing of any such action.

OG&E anticipates the total cost of Dry Scrubbers will be $547.5 million, including allowance for funds used during construction and capitalized ad valorem taxes. As of March 31, 2017, OG&E had invested $281.6 million of construction work in progress on the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $424.9 million, including allowance for funds used during construction and capitalized ad valorem taxes, and expects the project to be completed in late 2017. As of March 31, 2017, OG&E had invested $231.8 million on the Mustang Modernization Plan.

Integrated Resource Plans

In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. 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 plan. Currently, OG&E is scheduled to update its IRP in Arkansas by October 1, 2017 and in Oklahoma by October 1, 2018.

Arkansas Rate Case Filing

On August 25, 2016, OG&E filed a general rate case with the APSC. The rate filing requested a $16.5 million rate increase based on a 10.25 percent return on equity. The rate increase was based on a June 30, 2016 test year and included a recovery of over $3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The increase also reflects increases in operation and maintenance expenses, including vegetation management, and increased recovery of depreciation and dismantlement costs.

In April 2017, OG&E entered into a settlement with the staff of the APSC and other intervenors. The settlement provides for a $7.1 million annual rate increase and a 9.5 percent return on equity on a 50.0 percent equity capital structure. The settlement is subject to approval of the APSC. Hearings are scheduled for the APSC to review the settlement on May 2, 2017. OG&E expects to receive an order from the APSC in the second quarter of 2017.

The settlement also provides that OG&E will be regulated under a formula rate rider, which should result in a more efficient process as the return on equity, depreciation rates and capital structure should not change from what is approved by the APSC in the current rate case proceeding unless differences of plus or minus 50 basis points in return on equity were to occur. Adjustments are limited to plus or minus four percent of revenue for each rate class for the 12 months preceding the projected year. The initial term for the formula rate rider is not to exceed five years, unless additional approval is obtained from the APSC. OG&E expects to make its first filing under the Arkansas Formula Rate Rider in October 2018.

Fuel Adjustment Clause Review for Calendar Year 2015

On September 8, 2016, the OCC staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2015, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. At a hearing on March 30, 2017, the PUD staff recommended to the OCC that the 2015 fuel costs be found prudent. The Company expects to receive an OCC order in the second quarter of 2017.




23





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

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

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

The natural gas midstream operations segment represents the Company's investment in Enable through its wholly owned subsidiary OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns 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. As disclosed in the Company's 2016 Form 10-K, Enable is subject to a number of risks, including contract renewal risk, the reliance on the drilling and production decisions of others and the volatility of natural gas, NGL and crude oil prices. If any of those risks were to occur, the Company's business, financial condition, results of operations or cash flows could be materially adversely affected.
 
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 utilizes cash distributions from its investment in Enable to help fund its capital needs and support future dividend growth. The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and having strong regulatory and legislative relationships.


24



Summary of Operating Results
Three Months Ended March 31, 2017 as Compared to Three Months Ended March 31, 2016

Net income was $36.0 million, or $0.18 per diluted share, during the three months ended March 31, 2017 as compared to $25.2 million, or $0.13 per diluted share, during the same period in 2016. The increase in net income of $10.8 million, or $0.05 per diluted share, during the three months ended March 31, 2017 as compared to the same period in 2016 was primarily due to:

an increase in net income at OG&E of $10.1 million, or $0.05 per diluted share of the Company's common stock, primarily due to lower depreciation expense related to the reduction in depreciation rates approved in the OCC's final order, as discussed in Note 13, and higher other income related to increased allowance for equity funds used during construction. These increases were partially offset by an increase in other operation and maintenance expense, a decrease in gross margin and higher income tax expense; and
an increase in net income at OGE Holdings of $2.0 million, or $0.01 per diluted share of the Company's common stock, primarily due to an increase of equity in earnings of Enable partially offset by an increase in income tax expense; partially offset by
a decrease in net income at OGE Energy of $1.3 million, or $0.01 per diluted share of the Company's common stock, primarily due to an increase in other expenses associated with the deferred compensation plan and an increase in interest expense related to higher commercial paper borrowings.

Recent Developments and Regulatory Matters

As discussed in Note 13, on March 20, 2017, the OCC issued a final order in OG&E's general rate case. The final order results in an annual net increase of approximately $8.8 million in OG&E's rates to its Oklahoma retail customers. Although the final order adopted certain of the recommendations set forth in the ALJ Report, it differs in certain key respects.

The primary adjustments to the ALJ report consist of: (i) Oklahoma retail authorized rate of return on equity of 9.50 percent, (ii) depreciation expense is reduced by approximately $28.6 million from the ALJ report or $36.4 million from current rates on an annual basis, (iii) recovery of only 50.0 percent of short-term incentive compensation and no recovery of long-term incentive compensation, (iv) recovery of OG&E's requested vegetation management expenses and (v) recovery of production tax credits expiring in 2017 and air quality control systems consumable costs through the fuel adjustment clause.

As a result of the final order, OG&E recorded in the first quarter of 2017, adjustments to depreciation expense, amortization of regulatory assets and liabilities, and impacts to the fuel adjustment clause effective July 1, 2016. On May 1, 2017, OG&E implemented new rates and began refunding excess amounts that it had collected in interim rates.

2017 Outlook

OG&E

The Company projects OG&E earnings to be at the low end of the earnings range of $316.0 million to $340.0 million of net income, or $1.58 to $1.70 per average diluted share in 2017 based on the OCC rate order and the following assumptions:

normal weather patterns are experienced for the remainder of the year;
new rates take effect in Oklahoma May 1, 2017;
new rates take effect in Arkansas in 2017;
gross margin on revenues of approximately $1.405 billion to $1.420 billion based on sales growth of approximately 1 percent on a weather adjusted basis;
approximately $110 million of gross margin is primarily attributed to regionally allocated transmission projects;
operating expenses of approximately $844 million to $865 million with operation and maintenance expenses approximately 57 percent of the total;
interest expense of approximately $144 million which assumes a $16 million allowance for borrowed funds used during construction reduction to interest expense and includes the debt issuance of $300 million on March 31, 2017;
other income of approximately $62 million including approximately $35 million of allowance for equity funds used during construction;
an effective tax rate of approximately 31 percent; and
assumes $21 million of pre-tax net income or $0.06 per average diluted share for rates implemented on July 1, 2016 through December 31, 2016 based on the rate order received for the Oklahoma General Rate Case.

25




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

OGE Enogex Holdings LLC

The Company projects the earnings contribution from its ownership interest in Enable Midstream to be approximately $70 million to $78 million of $0.35 to $0.39 per average diluted share and receive approximately $140 million in cash distributions.

Consolidated OGE

The Company projects 2017 earnings guidance to be at the lower end of the earnings range of $386 million to $418 million of net income, or $1.93 to $2.09 per average diluted share and is based on the following assumptions:

approximately 200 million average diluted shares outstanding; and
an effective tax rate of approximately 33 percent.

Non-GAAP Financial Measures

Gross margin is defined by OG&E as operating revenues less fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization, and other operation and maintenance expenses. Expenses for fuel and purchased power are recovered through fuel adjustment clauses and as a result changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies.

Detailed below is a reconciliation of gross margin to revenue included in the 2017 Outlook.
Reconciliation of Gross Margin to Revenue
 
Year Ended December 31, (Dollars in Millions)
2017
Operating revenues
$
2,096

Cost of sales
691

Gross margin
$
1,405


Enable's Non-GAAP Financial Measures

Gross margin is defined by Enable as total revenues minus costs of natural gas and NGLs, excluding depreciation and amortization. Total revenues consist of the fees that they charge their customers and the sales price of natural gas and NGLs that they sell. The cost of natural gas and NGLs consists of the purchase price of natural gas and NGLs that they purchase. Enable deducts the cost of natural gas and NGLs from total revenue to arrive at a measure of the core profitability of their mix of fee-based and commodity-based customer arrangements. Gross margin allows for meaningful comparison of the operating results between Enable's fee-based revenues and Enable's commodity-based contracts which involve the purchase or sale of natural gas, NGLs and/or crude oil. In addition, the Company believes gross margin allows for a meaningful comparison of the results of Enable's commodity-based activities across different commodity price environments because it measures the spread between the product sales price and cost of products sold.


26



Results of Operations
 
The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the three months ended March 31, 2017 as compared to the same period in 2016 and the Company's consolidated financial position at March 31, 2017. Due to seasonal fluctuations and other factors, the Company's operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 or for any future period.  The following information should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.  
 
Three Months Ended
 
March 31,
(In millions except per share data)
2017
2016
Net income
$
36.0

$
25.2

Basic average common shares outstanding
199.7

199.7

Diluted average common shares outstanding
200.0

199.7

Basic earnings per average common share
$
0.18

$
0.13

Diluted earnings per average common share
$
0.18

$
0.13

Dividends declared per common share
$
0.30250

$
0.27500


Results by Business Segment
 
Three Months Ended
 
March 31,
(In millions)
2017
2016
Net income (loss)
 
 
OG&E (Electric Utility)
$
16.2

$
6.1

OGE Holdings (Natural Gas Midstream Operations)
20.0

18.0

Other Operations (A)
(0.2
)
1.1

Consolidated net income
$
36.0

$
25.2

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

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

27



OG&E (Electric Utility)
 
Three Months Ended
 
March 31,
(Dollars in millions)
2017
2016
Operating revenues
$
456.0

$
433.1

Cost of sales
208.7

177.9

Other operation and maintenance
126.1

116.3

Depreciation and amortization
54.7

76.7

Taxes other than income
22.3

23.6

Operating income
44.2

38.6

Allowance for equity funds used during construction
6.9

1.6

Other income
6.4

4.0

Other expense
0.4

0.3

Interest expense
33.6

35.5

Income tax expense
7.3

2.3

Net income
$
16.2

$
6.1

Operating revenues by classification


Residential
$
192.3

$
178.5

Commercial
124.3

102.7

Industrial
44.3

38.2

Oilfield
38.1

32.3

Public authorities and street light
44.5

36.1

Sales for resale

0.1

System sales revenues
443.5

387.9

Provision for rate refund
(20.8
)

Integrated market
(3.5
)
9.1

Other
36.8

36.1

Total operating revenues
$
456.0

$
433.1

Reconciliation of gross margin to revenue:
 
 
Operating revenues
$
456.0

$
433.1

Cost of sales
208.7

177.9

Gross margin
$
247.3

$
255.2

MWH sales by classification (In millions)


Residential
2.0

2.1

Commercial
1.6

1.6

Industrial
0.8

0.9

Oilfield
0.8

0.8

Public authorities and street light
0.7

0.7

System sales
5.9

6.1

Integrated market
0.3

0.4

Total sales
6.2

6.5

Number of customers
836,099

827,685

Weighted-average cost of energy per kilowatt-hour - cents


Natural gas
2.817

2.038

Coal
2.110

2.288

Total fuel
2.135

1.945

Total fuel and purchased power
3.132

2.611

Degree days (A)


Heating - Actual
1,381

1,552

Heating - Normal
1,799

1,798

Cooling - Actual
57

12

Cooling - Normal
13

13

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

28



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

Three Months Ended March 31, 2017 as Compared to Three Months Ended March 31, 2016
OG&E's net income increased $10.1 million, during the three months ended March 31, 2017 as compared to the same period in 2016 primarily due to lower depreciation and amortization expense as a result of the OCC's final order mandating a reduction in depreciation rates as discussed in Note 13 and higher other income partially offset by higher other operation and maintenance expense, lower gross margin and higher income tax expense.
Operating revenues were $456.0 million during the three months ended March 31, 2017 as compared to $433.1 million during the same period in 2016, an increase of $22.9 million, or 5.3 percent. Cost of sales were $208.7 million during the three months ended March 31, 2017 as compared to $177.9 million during the same period in 2016, an increase of $30.8 million, or 17.3 percent. Gross margin was $247.3 million during the three months ended March 31, 2017 as compared to $255.2 million during the same period in 2016, a decrease of $7.9 million, or 3.1 percent. The below factors contributed to the change in gross margin:
(In millions)
Change
Reserve for rate refund (A)
$
(20.8
)
Interim rate increase - Oklahoma (A)
15.4

Weather (price and quantity) (B)
(4.9
)
Price variance
(1.6
)
Other
1.9

New customer growth
2.1

Change in gross margin
$
(7.9
)
(A)
On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million. On March 20, 2017, the OCC issued a final order resulting in an increase of $8.8 million, as discussed in Note 13. The interim rate increase is fully reserved as of March 31, 2017.
(B)
Heating degree days decreased approximately 11 percent.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Cost of sales was $208.7 million during the three months ended March 31, 2017 as compared to $177.9 million during the same period in 2016, an increase of $30.8 million, or 17.3 percent. OG&E's change in cost of sales for the three months ended March 31, 2017 as compared to the same period in 2016 are detailed in the table below.
(In millions)
Change
Fuel expense (A)
$
13.4

Purchased power costs

Purchases from SPP (B)
17.3

Wind
0.7

Cogeneration
(5.6
)
Transmission expense (C)
5.0

Change in cost of sales
$
30.8

(A)
Increase in fuel expense was primarily due to increased utilization of company owned generation.
(B)
The cost of purchases from the SPP increased despite a 13 percent reduction in MWhs purchased. The cost per MWh increased 44 percent, due primarily to higher gas prices.
(C)
Increase in transmission related charges was primarily due to higher SPP charges for the base plan projects of other utilities.

The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC.

29



Operating Expenses

Other operation and maintenance expense was $126.1 million during the three months ended March 31, 2017 as compared to $116.3 million during the same period in 2016, an increase of $9.8 million, or 8.4 percent. The below factors contributed to the change in other operation and maintenance expense:
(In millions)
Change
Marketing (related to demand side management)
$
2.8

Payroll & benefits (A)
2.6

Corporate allocations and overheads
2.0

Contract professional services (B)
1.6

Maintenance at power plants
1.0

Other
(0.2
)
Change in other operation and maintenance expense
$
9.8

(A)
Increased primarily due to increased 401k match due to higher incentive payout, increased annual salaries, overtime and active medical and dental expenses.
(B)
Increased primarily due to increased consulting costs associated with demand side management programs.

Depreciation and amortization expense was $54.7 million during the three months ended March 31, 2017 as compared to $76.7 million during the same period in 2016, a decrease of $22.0 million, or 28.7 percent, primarily due to lower depreciation expense related to the reduction in depreciation rates approved in the OCC's final order as discussed in Note 13 partially offset by additional assets being placed into service.

Additional Information

Allowance for Equity Funds Used During Construction. Allowance for Equity Funds Used During Construction was $6.9 million during the three months ended March 31, 2017 as compared to $1.6 million during the same period in 2016, an increase of $5.3 million, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Other Income. Other income was $6.4 million during the three months ended March 31, 2017 as compared to $4.0 million during the same period in 2016, an increase of $2.4 million, or 60.0 percent, primarily due to an increase in the tax gross up related to higher allowance for funds used during construction partially offset by lower guaranteed flat bill margins.

Income Tax Expense. Income tax expense was $7.3 million during the three months ended March 31, 2017 as compared to $2.3 million during the same period in 2016, an increase of $5.0 million, primarily due to higher pre-tax income.
OGE Holdings (Natural Gas Midstream Operations)
 
Three Months Ended March 31,
(In millions)
2017
2016
Operating revenues
$

$

Cost of sales


Other operation and maintenance
0.1

0.2

Depreciation and amortization


Taxes other than income
0.2


Operating income (loss)
(0.3
)
(0.2
)
Equity in earnings of unconsolidated affiliates
35.6

28.3

Other income
0.1


Income before taxes
35.4

28.1

Income tax expense
15.4

10.1

Net income attributable to OGE Holdings
$
20.0

$
18.0



30



Reconciliation of Equity in Earnings of Unconsolidated Affiliates

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three months ended March 31, 2017 as compared to the same period in 2016:

Three Months Ended

March 31,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates
2017
2016
(In millions)

Enable net income
$
110.8

$
86.0

Differences due to timing of OGE Energy and Enable accounting close

(11.7
)
Enable net income used to calculate OGE Energy's equity in earnings
$
110.8

$
74.3

OGE Energy’s percent ownership at period end
25.7
%
26.3
%
OGE Energy’s portion of Enable net income
$
28.5

$
19.5

Impairments recognized by Enable associated with OGE Energy’s basis differences

1.8

OGE Energy's share of Enable net income
$
28.5

$
21.3

Amortization of basis difference
2.8

2.9

Elimination of Enable fair value step up
4.3

4.1

Equity in earnings of unconsolidated affiliates
$
35.6

$
28.3


Equity in earnings of unconsolidated affiliates includes the Company's share of Enable earnings adjusted for the amortization of the basis difference of the Company's investment in Enogex and its underlying equity in the net assets of Enable and is also adjusted for the elimination of the Enogex Holdings fair value adjustments.

The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $736.6 million as of March 31, 2017. The basis difference is being amortized over approximately 30 years, beginning in May 2013. The following table reconciles the basis difference in Enable from December 31, 2016 to March 31, 2017.
(In millions)
 
Basis difference as of December 31, 2016
$
743.7

Amortization of basis difference
(2.8
)
Elimination of Enable fair value step up
(4.3
)
Basis difference as of March 31, 2017
$
736.6


Enable Results of Operations

The following table represents summarized financial information of Enable for the three months ended March 31, 2017 as compared to the same period in 2016:
 
Three Months Ended
 
March 31,
(In millions)
2017
2016
Operating revenues
$
666

$
509

Cost of natural gas and natural gas liquids
308

195

Operating income
140

103

Net income