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EX-32.01 - EXHIBIT 32.01 - OGE ENERGY CORP.q32016oge10-qxex3201.htm
EX-31.01 - EXHIBIT 31.01 - OGE ENERGY CORP.q32016oge10-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 September 30, 2016

OR

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

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

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

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

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

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

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

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

At September 30, 2016, there were 199,702,959 shares of common stock, par value $0.01 per share, outstanding.

 



OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2016

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
2015 Form 10-K
Annual Report on Form 10-K for the year ended December 31, 2015
ALJ
Administrative Law Judge
APSC
Arkansas Public Service Commission
ArcLight group
Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC, collectively
ASU
Financial Accounting Standards Board Accounting Standards Update
AVEC
Arkansas Valley Electric Cooperative Corporation
CenterPoint
CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO2
Carbon dioxide
Company
OGE Energy, collectively with its subsidiaries
CSAPR
Cross-State Air Pollution Rule
Dry Scrubbers
Dry flue gas desulfurization units with spray dryer absorber
ECP
Environmental Compliance Plan
Enable
Enable Midstream Partners, LP, 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
NAAQS
National Ambient Air Quality Standards
NGLs
Natural gas liquids
NOX
Nitrogen oxide
OCC
Oklahoma Corporation Commission
ODEQ
Oklahoma Department of Environmental Quality
OG&E
Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Holdings
OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy, parent company of Enogex Holdings (prior to May 1, 2013) and 26.3 percent owner of Enable Midstream Partners
Pension Plan
Qualified defined benefit retirement plan
Ppb
Parts per billion
PUD
Public Utility Division of the Oklahoma Corporation Commission
Restoration of Retirement Income Plan
Supplemental retirement plan to the Pension Plan
SESH
Southeast Supply Header, LLC
SIP
State implementation plan
SO2
Sulfur dioxide
SPP
Southwest Power Pool
System sales
Sales to OG&E's customers
TBtu/d
Trillion British thermal units per day

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 2015 Form 10-K and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
the ability of the Company and its subsidiaries to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;
prices and availability of electricity, coal, natural gas and NGLs;
the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions Enable serves, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable's interstate pipelines;
the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering by Enable's gathering and processing business and transporting by Enable's interstate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regions Enable serves;
business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;
competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;
unusual weather;
availability and prices of raw materials for current and future construction projects;
the effect of retroactive repricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;
Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company's markets;
environmental laws and regulations that may impact the Company's operations;
changes in accounting standards, rules or guidelines;
the discontinuance of accounting principles for certain types of rate-regulated activities;
the cost of protecting assets against, or damage due to, terrorism or cyber-attacks and other catastrophic events;
advances in technology;
creditworthiness of suppliers, customers and other contractual parties;
difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment in Enable that the Company does not control; and
other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in "Item 1A. Risk Factors" and in Exhibit 99.01 to the Company's 2015 Form 10-K.

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

1


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
 
Three Months Ended September 30,
Nine Months Ended September 30,
(In millions except per share data)
2016
2015
2016
2015
OPERATING REVENUES
$
743.9

$
719.8

$
1,728.4

$
1,749.8

COST OF SALES
269.8

259.8

645.4

682.3

OPERATING EXPENSES
 
 


Other operation and maintenance
113.1

109.4

354.6

334.3

Depreciation and amortization
82.2

77.9

240.8

230.0

Taxes other than income
21.5

21.9

66.5

68.8

Total operating expenses
216.8

209.2

661.9

633.1

OPERATING INCOME
257.3

250.8

421.1

434.4

OTHER INCOME (EXPENSE)
 
 


Equity in earnings of unconsolidated affiliates
34.5

(71.9
)
79.5

(12.0
)
Allowance for equity funds used during construction
3.9

2.2

9.2

5.4

Other income
5.7

8.9

18.9

19.4

Other expense
(3.3
)
(5.3
)
(10.8
)
(8.5
)
Net other income (expense)
40.8

(66.1
)
96.8

4.3

INTEREST EXPENSE
 
 


Interest on long-term debt
35.8

37.0

107.3

110.9

Allowance for borrowed funds used during construction
(2.0
)
(1.1
)
(4.7
)
(2.7
)
Interest on short-term debt and other interest charges
1.6

1.1

5.1

4.2

Interest expense
35.4

37.0

107.7

112.4

INCOME BEFORE TAXES
262.7

147.7

410.2

326.3

INCOME TAX EXPENSE
79.1

36.5

129.9

84.4

NET INCOME
$
183.6

$
111.2

$
280.3

$
241.9

BASIC AVERAGE COMMON SHARES OUTSTANDING
199.7

199.7

199.7

199.6

DILUTED AVERAGE COMMON SHARES OUTSTANDING
199.9

199.7

199.8

199.6

BASIC EARNINGS PER AVERAGE COMMON SHARE
$
0.92

$
0.55

$
1.40

$
1.21

DILUTED EARNINGS PER AVERAGE COMMON SHARE
$
0.92

$
0.55

$
1.40

$
1.21

DIVIDENDS DECLARED PER COMMON SHARE
$
0.30250

$
0.27500

$
0.85250

$
0.77500
















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 September 30,
Nine Months Ended September 30,
(In millions)
2016
2015
2016
2015
Net income
$
183.6

$
111.2

$
280.3

$
241.9

Other comprehensive income (loss), net of tax
 
 
 
 
Pension Plan and Restoration of Retirement Income Plan:
 
 
 
 
Amortization of deferred net loss, net of tax of $0.4, $0.3, $1.2 and $1.7, respectively
0.8

0.7

2.3

1.9

Settlement cost, net of tax of $0.0, $2.4, $3.2 and $2.4, respectively

3.8

5.0

3.8

Postretirement Benefit Plans:
 
 
 
 
Amortization of deferred net loss, net of tax of $0.0, $0.2, $0.0 and $0.6, respectively

0.3


0.9

Amortization of prior service cost, net of tax of ($0.2), ($0.3), ($0.7) and ($0.8), respectively
(0.4
)
(0.4
)
(1.2
)
(1.3
)
Other comprehensive income, net of tax
0.4

4.4

6.1

5.3

Comprehensive income
$
184.0

$
115.6

$
286.4

$
247.2
































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

3



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

Nine Months Ended September 30,
(In millions)
2016
2015
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$
280.3

$
241.9

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


Depreciation and amortization
240.8

230.0

Deferred income taxes and investment tax credits
134.2

62.3

Equity in earnings of unconsolidated affiliates
(79.5
)
12.0

Distributions from unconsolidated affiliates
79.9

67.1

Allowance for equity funds used during construction
(9.2
)
(5.4
)
Stock-based compensation
3.2

3.8

Excess tax benefit on stock-based compensation

(5.2
)
Regulatory assets
(10.5
)
12.7

Regulatory liabilities
(9.8
)
(13.9
)
Other assets
18.0

12.7

Other liabilities
(19.8
)
0.1

Change in certain current assets and liabilities
 
 
Accounts receivable, net
(51.2
)
(33.8
)
Accounts receivable - unconsolidated affiliates
(0.7
)
0.5

Accrued unbilled revenues
(17.5
)
(22.4
)
Fuel, materials and supplies inventories
30.9

(25.5
)
Fuel clause under recoveries
(0.5
)
66.7

Other current assets
(13.1
)
(8.9
)
Accounts payable
(90.6
)
(57.7
)
Fuel clause over recoveries
(59.9
)
34.5

Other current liabilities
1.9

37.6

Net Cash Provided from Operating Activities
426.9

609.1

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures (less allowance for equity funds used during construction)
(466.7
)
(375.0
)
Return of capital - equity method investments
25.9

36.9

Proceeds from sale of assets
0.3

2.2

Net Cash Used in Investing Activities
(440.5
)
(335.9
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Dividends paid on common stock
(164.7
)
(149.7
)
Issuance of common stock

7.2

Excess tax benefit on stock-based compensation

5.2

Payment of long-term debt
(110.1
)
(0.1
)
Increase (decrease) in short-term debt
213.2

(98.0
)
Net Cash Used in Financing Activities
(61.6
)
(235.4
)
NET CHANGE IN CASH AND CASH EQUIVALENTS
(75.2
)
37.8

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
75.2

5.5

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$

$
43.3





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

4


OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

September 30,
December 31,
(In millions)
2016
2015
ASSETS
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
$

$
75.2

Accounts receivable, less reserve of $2.0 and $1.4, respectively
224.3

173.1

Accounts receivable - unconsolidated affiliates
2.4

1.7

Accrued unbilled revenues
71.0

53.5

Income taxes receivable
17.7

17.2

Fuel inventories
87.6

113.8

Materials and supplies, at average cost
75.4

80.1

Fuel clause under recoveries
0.5


Other
68.2

55.6

Total current assets
547.1

570.2

OTHER PROPERTY AND INVESTMENTS




Investment in unconsolidated affiliates
1,168.0

1,194.4

Other
72.0

70.7

Total other property and investments
1,240.0

1,265.1

PROPERTY, PLANT AND EQUIPMENT
 
 
In service
10,599.6

10,318.3

Construction work in progress
365.8

278.5

Total property, plant and equipment
10,965.4

10,596.8

Less accumulated depreciation
3,431.1

3,274.4

Net property, plant and equipment
7,534.3

7,322.4

DEFERRED CHARGES AND OTHER ASSETS
 
 
Regulatory assets
404.8

402.2

Other
57.8

20.7

Total deferred charges and other assets
462.6

422.9

TOTAL ASSETS
$
9,784.0

$
9,580.6





















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

5


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

September 30,
December 31,
(In millions)
2016
2015
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
CURRENT LIABILITIES
 
 
Short-term debt
$
213.2

$

Accounts payable
129.4

262.5

Dividends payable
60.4

54.9

Customer deposits
77.4

77.0

Accrued taxes
58.7

45.9

Accrued interest
33.0

42.9

Accrued compensation
34.1

54.4

Long-term debt due within one year
124.9

110.0

Fuel clause over recoveries
1.4

61.3

Other
62.8

43.9

Total current liabilities
795.3

752.8

LONG-TERM DEBT
2,505.2

2,628.8

DEFERRED CREDITS AND OTHER LIABILITIES
 
 
Accrued benefit obligations
280.2

299.9

Deferred income taxes
2,314.5

2,178.2

Regulatory liabilities
292.0

273.6

Other
151.6

121.3

Total deferred credits and other liabilities
3,038.3

2,873.0

Total liabilities
6,338.8

6,254.6

COMMITMENTS AND CONTINGENCIES (NOTE 12)


STOCKHOLDERS' EQUITY
 
 
Common stockholders' equity
1,104.4

1,101.3

Retained earnings
2,369.8

2,259.8

Accumulated other comprehensive loss, net of tax
(29.0
)
(35.1
)
Total stockholders' equity
3,445.2

3,326.0

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
9,784.0

$
9,580.6




















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, 2015
$
2.0

$
1,099.3

$
2,259.8

$
(35.1
)
$
3,326.0

Net income


280.3


280.3

Other comprehensive income, net of tax



6.1

6.1

Dividends declared on common stock


(170.3
)

(170.3
)
Stock-based compensation

3.1



3.1

Balance at September 30, 2016
$
2.0

$
1,102.4

$
2,369.8

$
(29.0
)
$
3,445.2

 
 
 
 
 
 
Balance at December 31, 2014
$
2.0

$
1,085.6

$
2,198.2

$
(41.4
)
$
3,244.4

Net income


241.9


241.9

Other comprehensive income, net of tax



5.3

5.3

Dividends declared on common stock


(154.8
)

(154.8
)
Issuance of common stock

7.2



7.2

Stock-based compensation

9.4



9.4

Balance at September 30, 2015
$
2.0

$
1,102.2

$
2,285.3

$
(36.1
)
$
3,353.4



































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

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.
In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at September 30, 2016 and December 31, 2015, the results of its operations for the three and nine months ended September 30, 2016 and 2015 and its cash flows for the nine months ended September 30, 2016 and 2015, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company's operating results for the three and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2015 Form 10-K.


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:
 
September 30,
December 31,
(In millions)
2016
2015
Regulatory Assets
 
 
Current
 
 
Oklahoma demand program rider under recovery (A)
$
48.9

$
36.6

SPP cost tracker rider under recovery (A)
2.4

4.5

Fuel clause under recoveries
0.5


Other (A)
7.6

5.4

Total Current Regulatory Assets
$
59.4

$
46.5

Non-Current
 

 

Benefit obligations regulatory asset
$
235.0

$
242.2

Income taxes recoverable from customers, net
60.0

56.7

Smart Grid
43.4

43.6

Deferred storm expenses
35.9

27.6

Unamortized loss on reacquired debt
13.7

14.8

Other
16.8

17.3

Total Non-Current Regulatory Assets
$
404.8

$
402.2

Regulatory Liabilities
 

 

Current
 

 

Fuel clause over recoveries
$
1.4

$
61.3

Other (B)
3.8

7.5

Total Current Regulatory Liabilities
$
5.2

$
68.8

Non-Current
 

 

Accrued removal obligations, net
$
260.1

$
254.9

Pension tracker
30.9

17.7

Other (C)
1.0

1.0

Total Non-Current Regulatory Liabilities
$
292.0

$
273.6

(A)
Included in Other Current Assets on the Condensed Consolidated Balance Sheets.
(B)
Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.    
(C)
Prior year amount of $1.0 million reclassified from Deferred Other Liabilities to Non-Current Regulatory Liabilities.

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

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. 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 September 30, 2016. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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

Asset Retirement Obligations

The following table summarizes changes to the Company's asset retirement obligations during the nine months ended September 30, 2016 and 2015.
 
Nine Months Ended September 30,
(In millions)
2016
2015
Balance at January 1
$
63.3

$
58.6

Accretion expense
2.1

1.9

Liabilities settled
(0.2
)
(0.4
)
Revisions in estimated cash flows

1.6

Balance at September 30
$
65.2

$
61.7


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 nine months ended September 30, 2016 and 2015. All amounts below are presented net of tax.
 
Pension Plan and Restoration of Retirement Income Plan
 
Postretirement Benefit Plans
 
(In millions)
Net loss
Prior service cost
 
Net income
Prior service cost
Total
Balance at December 31, 2015
$
(39.2
)
$
0.1

 
$
2.5

$
1.5

$
(35.1
)
Amounts reclassified from accumulated other comprehensive income (loss)
2.3


 

(1.2
)
1.1

Settlement cost
5.0


 


5.0

Net current period other comprehensive income (loss)
7.3




(1.2
)
6.1

Balance at September 30, 2016
$
(31.9
)
$
0.1

 
$
2.5

$
0.3

$
(29.0
)

10



 
Pension Plan and Restoration of Retirement Income Plan
 
Postretirement Benefit Plans
 
(In millions)
Net loss
Prior service cost
 
Net loss
Prior service cost
Total
Balance at December 31, 2014
$
(36.8
)
$
0.1

 
$
(8.0
)
$
3.3

$
(41.4
)
Amounts reclassified from accumulated other comprehensive income (loss)
1.9


 
0.9

(1.3
)
1.5

Settlement cost
3.8


 


3.8

Net current period other comprehensive income (loss)
5.7


 
0.9

(1.3
)
5.3

Balance at September 30, 2015
$
(31.1
)
$
0.1


$
(7.1
)
$
2.0

$
(36.1
)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and nine months ended September 30, 2016 and 2015.
Details about Accumulated Other Comprehensive Income (Loss) Components
Amount Reclassified from Accumulated Other Comprehensive Income (Loss)
Affected Line Item in the Statement Where Net Income is Presented
 
Three Months Ended
Nine Months Ended
 
 
September 30,
September 30,
 
(In millions)
2016
2015
2016
2015
 
Amortization of defined benefit pension and restoration of retirement income plan items
 
 
 
 
 
Actuarial losses
$
(1.2
)
$
(1.0
)
$
(3.5
)
$
(3.6
)
(A)
Settlement

(6.2
)
(8.2
)
(6.2
)
(A)
 
(1.2
)
(7.2
)
(11.7
)
(9.8
)
Total before tax
 
(0.4
)
(2.7
)
(4.4
)
(4.1
)
Tax benefit
 
$
(0.8
)
$
(4.5
)
$
(7.3
)
$
(5.7
)
Net of tax
 
 
 
 
 
 
Amortization of postretirement benefit plan items
 
 
 
 
 
Actuarial losses
$

$
(0.5
)
$

$
(1.5
)
(A)
Prior service credit
0.6

0.7

1.9

2.1

(A)
 
0.6

0.2

1.9

0.6

Total before tax
 
0.2

0.1

0.7

0.2

Tax expense
 
$
0.4

$
0.1

$
1.2

$
0.4

Net of tax
 
 
 
 
 
 
Total reclassifications for the period
$
(0.4
)
$
(4.4
)
$
(6.1
)
$
(5.3
)
Net of tax
(A)
These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Reclassifications

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

The December 31, 2015 Condensed Consolidated Balance Sheet has been adjusted for the reclassification of $16.8 million of debt issuance costs from Total Deferred Charges and Other Assets to Long-Term Debt to be consistent with the 2016 presentation due to the adoption of ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," in 2016.


11



2.
Accounting Pronouncements

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

Consolidation. In February 2015, the FASB issued ASU 2015-02, "Consolidation (Topic 810)". The amendments in ASU 2015-02 affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. The new standard modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities along with eliminating the presumption that a general partner should consolidate a limited partnership. The new standard is effective for fiscal years beginning after December 15, 2015. The adoption of this new standard did not result in the consolidation of any non-consolidated entities.
Leases. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”. The main difference between current lease accounting and Topic 842 is the recognition of right-to-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance. Lessees, such as the Company, will need to recognize a right-of-use asset and a lease liability for virtually all of their leases, other than leases that meet the definition of a short-term lease. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to current capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in current lease guidance, but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 2018. The new guidance must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company has 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.

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

Employee Share Based Payment Accounting. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share Based Payment Accounting," which amends ASC Topic 718, Compensation - Stock Compensation. ASU 2016-09 includes provisions intended to simplify various aspects related to how share based payments are accounted for and presented in the financial statements. The new guidance among other requirements will require all of the tax effects related to share based payments at settlement (or expiration) to be recorded through the income statement. Currently, tax benefits in excess of compensation cost (“windfalls”) are recorded in equity, and tax deficiencies (“shortfalls”) are recorded in equity to the extent of previous windfalls, and then to the income statement. This change is required to be applied prospectively to all excess tax benefits and tax deficiencies resulting from settlements after the date of adoption of the ASU 2016-09. Under the new guidance, the windfall tax benefit will be recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. Either prospective or retrospective transition of this provision is permitted. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016, and interim periods within that reporting period. Early adoption will be permitted in any interim or annual period, with any adjustments reflected as of the beginning of the fiscal year of adoption. The Company has not determined the impact on its Condensed Consolidated Financial Statements, however, the impact is not expected to be material.


12



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

3.
Investment in Unconsolidated Affiliate and Related Party Transactions

On March 14, 2013, the Company entered into a Master Formation Agreement with the ArcLight group and CenterPoint pursuant to which the Company, the ArcLight group and CenterPoint agreed to form Enable to own and operate the midstream businesses of the Company and CenterPoint that was initially structured as a private limited partnership. This transaction closed on May 1, 2013.
Pursuant to the Master Formation Agreement, the Company and the ArcLight group indirectly contributed 100 percent of the equity interests in Enogex LLC to Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost.
In April 2014, Enable completed an initial public offering of 25.0 million common units resulting in Enable becoming a publicly traded Master Limited Partnership. At September 30, 2016, the Company owned 111.0 million common units, or 26.3 percent of which 68.2 million units were subordinated.

The Company and CenterPoint also own a 60 percent and 40 percent interest, respectively, in the incentive distribution rights held by the general partner of Enable.

Distributions received from Enable were $35.3 million and $35.1 million during the three months ended September 30, 2016 and 2015, respectively, and $105.9 million and $104.0 million for the nine months ended September 30, 2016 and 2015, respectively. On November 1, 2016, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common and subordinated units, representing the same dividend distribution as the previous quarter.

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

Related Party Transactions

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

On May 1, 2013, the Company and Enable entered into a Services Agreement, an Employee Transition Agreement, and other agreements whereby the Company agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. The remaining services automatically extended for another year on May 1, 2016. Under these agreements, the Company charged operating costs to Enable of $1.0 million and $2.6 million for the three months ended September 30, 2016 and 2015, respectively, and $3.6 million and $7.9 million for the nine months ended September 30, 2016 and 2015, respectively. The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and/or Enable are assigned as

13



such.  Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.

Additionally, the Company agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, 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 $6.6 million and $7.0 million during the three months ended September 30, 2016 and 2015, respectively, and $20.7 million and $25.1 million during the nine months ended September 30, 2016 and 2015, respectively, under the Transitional Seconding Agreement for employment costs.

The Company had accounts receivable from Enable for amounts billed for transitional services, including the cost of seconded employees, of $3.7 million and $3.4 million as of September 30, 2016 and December 31, 2015, respectively.

Related Party Transactions with Enable

OG&E entered into a contract with Enable to provide gas transportation services effective May 1, 2014. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries. The following table summarizes related party transactions between OG&E and Enable during the three and nine months ended September 30, 2016 and 2015.
 
Three Months Ended
Nine Months Ended
 
September 30,
September 30,
(In millions)
2016
2015
2016
2015
Operating Revenues:
 
 
 
 
Electricity to power electric compression assets
$
3.7

$
4.4

$
9.0

$
11.1

Cost of Sales:
 
 
 
 
Natural gas transportation services
$
8.8

$
8.8

$
26.3

$
26.3

Natural gas purchases/(sales)
4.4

2.5

11.3

7.1

 
Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at September 30, 2016 and December 31, 2015 and for the three and nine months ended September 30, 2016 and 2015.
 
September 30,
December 31,
Balance Sheet
2016
2015
(In millions)
 
Current assets
$
408

$
381

Non-current assets
10,833

10,845

Current liabilities
338

615

Non-current liabilities
3,174

3,080


 
Three Months Ended
Nine Months Ended
 
September 30,
September 30,
Income Statement
2016
2015
2016
2015
(In millions)
 
Operating revenues
$
620

$
646

$
1,658

$
1,852

Cost of natural gas and natural gas liquids
268

287

717

856

Operating income
139

(975
)
299

(778
)
Net income
110

(985
)
231

(817
)


14



The formation of Enable was considered a business combination and CenterPoint was the acquirer of Enogex Holdings for accounting purposes.  Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value.  Enogex Holdings' assets, liabilities and equity have accordingly been adjusted to estimated fair value as of May 1, 2013, resulting in an increase to equity of $2.2 billion. Due to the contribution of Enogex LLC to Enable, meeting the requirements of being in substance real estate and thus recording the initial investment at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in the Company's recording of its equity in earnings of Enable.

The Company recorded equity in earnings of unconsolidated affiliates of $34.5 million and $79.5 million for the three and nine months ended September 30, 2016, respectively, and a loss in equity in earnings of $71.9 million and $12.0 million for the three and nine months ended September 30, 2015, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex and its underlying equity in the net assets of Enable. The basis difference is the result of the initial contribution of Enogex to Enable in May 2013, and subsequent issuances of equity by Enable, including the initial public offering in April 2014 and the issuance of common units for the acquisition of CenterPoint's 24.95 percent interest in SESH. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described below.

2015 Goodwill Impairment. Enable tested its goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicated that the carrying value of goodwill may not be recoverable. Goodwill was assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. Subsequent to the completion of the October 1, 2014 annual test, the crude oil and natural gas industry was impacted by further commodity price declines, which consequently resulted in decreased producer activity in certain regions in which Enable operates. Based on the decline in producer activity and the forecasted impact on future periods, in addition to an increase in the weighted average cost of capital, Enable determined that the impact on its forecasted operating profits and cash flows for its gathering and processing and transportation and storage segments for the next five years would be significantly reduced. As a result, when Enable performed the first step of its annual goodwill impairment analysis as of October 1, 2015, it determined that the carrying value of the gathering and processing and transportation and storage segments exceeded fair value. Enable completed the second step of the goodwill impairment analysis comparing the implied fair value for those reporting units to the carrying amount of that goodwill and determined that goodwill for those units was completely impaired in the amount of $1,086.4 million as of September 30, 2015, and wrote off all of its goodwill in the third quarter of 2015.

The following table reconciles the Company's equity in earnings (loss) of its unconsolidated affiliates for the three and nine months ended September 30, 2016 and 2015.

Three Months Ended
Nine Months Ended

September 30,
September 30,
Reconciliation of Equity in Earnings (Loss) of Unconsolidated Affiliates
2016
2015
2016
2015
(In millions)


Enable net income (loss)
$
110.1

$
(985.1
)
$
230.8

$
(817.3
)
Distributions senior to limited partners
(9.1
)

(9.1
)

Differences due to timing of OGE Energy and Enable accounting close and permanent items
3.0

4.2

(3.6
)
9.9

Enable net income (loss) used to calculate OGE Energy's equity in earnings
$
104.0

$
(980.9
)
$
218.1

$
(807.4
)
OGE Energy’s percent ownership
26.3
%
26.3
%
26.3
%
26.3
%
OGE Energy’s portion of Enable net income (loss)
$
27.3

$
(257.2
)
$
57.5

$
(212.0
)
Impairments recognized by Enable associated with OGE Energy’s basis differences

177.7

0.6

177.7

OGE Energy's share of Enable net income (loss)
$
27.3

$
(79.5
)
$
58.1

$
(34.3
)
Amortization of basis difference
2.9

3.5

8.8

10.6

Elimination of Enable fair value step up
4.3

4.1

12.6

11.7

Equity in earnings (loss) of unconsolidated affiliates
$
34.5

$
(71.9
)
$
79.5

$
(12.0
)


15



The difference between the Company's investment in Enable and its underlying equity in the net assets of Enable was $761.5 million as of September 30, 2016. The following table reconciles the basis difference in Enable from December 31, 2015 to September 30, 2016.
(In millions)
 
 
Basis difference as of December 31, 2015
 
$
783.5

Impairments recognized by Enable associated with OGE Energy’s basis difference
 
(0.6
)
Amortization of basis difference
 
(8.8
)
Elimination of Enable fair value step up and other adjustments
 
(12.6
)
Basis difference as of September 30, 2016
 
$
761.5


4.
Fair Value Measurements
 
The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3).  Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  The three levels defined in the fair value hierarchy are as follows:
 
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.
 
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability.  Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.  

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). 
 
The Company had no financial instruments measured at fair value on a recurring basis at September 30, 2016 and December 31, 2015.
 
The following table summarizes the fair value and carrying amount of the Company's financial instruments at September 30, 2016 and December 31, 2015.
 
September 30,
December 31,
 
2016
2015
(In millions)
Carrying Amount 
Fair
Value
Carrying Amount 
 Fair
Value
Long-Term Debt
 
 
 
 
Senior Notes
$
2,385.0

$
2,818.2

$
2,493.9

$
2,754.6

OG&E Industrial Authority Bonds
135.4

135.4

135.4

135.4

Tinker Debt
9.9

10.0

10.0

9.2

OGE Energy Senior Notes
99.8

99.9

99.5

99.9


The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt which fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.


16



5.
Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three and nine months ended September 30, 2016 and 2015 related to the Company's performance units and restricted stock.
 
Three Months Ended September 30,
Nine Months Ended September 30,
(In millions)
2016
2015
2016
2015
Performance units
 
 
 
 
Total shareholder return
$
1.2

$
1.9

$
3.4

$
5.7

Earnings per share
(1.3
)
(0.8
)
(0.3
)
0.3

Total performance units
(0.1
)
1.1

3.1

6.0

Restricted stock


0.1

0.1

Total compensation expense
(0.1
)
1.1

3.2

6.1

Less: Amount paid by unconsolidated affiliates

(0.2
)

0.3

Net compensation expense
$
(0.1
)
$
1.3

$
3.2

$
5.8

Income tax benefit
$

$
0.5

$
1.3

$
2.3


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

6.
Income Taxes

The Company files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 2013 or state and local tax examinations by tax authorities for years prior to 2012.  Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss.  Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property.  OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.

7.
Common Equity
 
Automatic Dividend Reinvestment and Stock Purchase Plan
 
The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and nine months ended September 30, 2016.  


17



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 September 30,
Nine Months Ended September 30,
(In millions except per share data)
2016
2015
2016
2015
Net income
$
183.6

$
111.2

$
280.3

$
241.9

Average Common Shares Outstanding
 
 
 
 
Basic average common shares outstanding
199.7

199.7

199.7

199.6

Effect of dilutive securities:
 
 
 
 
Contingently issuable shares (performance and restricted stock units)
0.2


0.1


Diluted average common shares outstanding
199.9

199.7

199.8

199.6

Basic Earnings Per Average Common Share
$
0.92

$
0.55

$
1.40

$
1.21

Diluted Earnings Per Average Common Share
$
0.92

$
0.55

$
1.40

$
1.21

Anti-dilutive shares excluded from earnings per share calculation





8.
Long-Term Debt
 
At September 30, 2016, the Company was in compliance with all of its debt agreements.
 
OG&E Industrial Authority Bonds

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day.  The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows:
SERIES
DATE DUE
AMOUNT
 
 
 
 
(In millions)
0.05%
-
0.84%
Garfield Industrial Authority, January 1, 2025
$
47.0

0.07%
-
0.80%
Muskogee Industrial Authority, January 1, 2025
32.4

0.05%
-
0.82%
Muskogee Industrial Authority, June 1, 2027
56.0

Total (redeemable during next 12 months)
$
135.4


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


18



9.
Short-Term Debt and Credit Facilities
 
The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement.  As of September 30, 2016, the Company had $213.2 million of short-term debt as compared to no balance at December 31, 2015. The following table provides information regarding the Company's revolving credit agreements at September 30, 2016.
 
Aggregate
Amount
Weighted-Average
 
 
 
Entity
Commitment 
Outstanding (A)
Interest Rate
 
Maturity
 
(In millions)
 
 
 
 
 
OGE Energy (B)
$
750.0

$
213.2

0.74
%
(D)
December 13, 2018
(E)
OG&E (C)
400.0

1.7

0.95
%
(D)
December 13, 2018
(E)
Total
$
1,150.0

$
214.9

0.74
%
 
 
 
(A)
Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2016.
(B)
This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  
(C)
This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.   
(D)
Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.
(E)
As of September 30, 2016, commitments of $16.3 million and $8.7 million of the OGE Energy's and OG&E's credit facilities, respectively, were not extended and unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire December 13, 2017.

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions.  Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations.  Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit.
 
OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis.  OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016. OG&E has requested renewal of this authority for an additional two-year period and expects to receive approval prior to the expiration of its current authority.

10.
Retirement Plans and Postretirement Benefit Plans

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During the quarter ended June 30, 2016, the Company experienced a settlement of its Supplemental Executive Retirement Plan and its non-qualified Restoration of Retirement Income Plan. As a result, the Company recorded pension settlement charges of $8.7 million during the nine months ended September 30, 2016. During the first nine months of 2015, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement. As a result, the Company recorded pension settlement charges of $16.2 million in the third quarter of 2015. The pension settlement charge did not increase the Company’s total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.


19



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

Net Periodic Benefit Cost
 
Pension Plan
 
Restoration of Retirement
Income Plan
 
Three Months Ended
Nine Months Ended
 
Three Months Ended
Nine Months Ended
 
September 30,
September 30,
 
September 30,
September 30,
(In millions)
2016 (B)
2015 (B)
2016 (C)
2015 (C)
 
2016 (B)
2015 (B)
2016 (C)
2015 (C)
Service cost
$
4.0

$
4.2

$
11.9

$
12.1

 
$

$
0.4

$
0.2

$
1.0

Interest cost
6.4

6.6

19.1

19.6

 
0.1

0.2

0.3

0.5

Expected return on plan assets
(10.4
)
(11.0
)
(31.1
)
(34.5
)
 




Amortization of net loss
4.1

3.8

12.3

13.5

 
0.2

0.2

0.5

0.5

Amortization of unrecognized prior service cost (A)
(0.1
)
0.1

(0.1
)
0.3

 
0.1


0.1

0.1

Settlement

16.2


16.2

 


8.7


Total net periodic benefit cost
4.0

19.9

12.1

27.2


0.4

0.8

9.8

2.1

Less: Amount paid by unconsolidated affiliates
1.3

1.0

3.8

3.1

 
0.1


0.3

0.1

Net periodic benefit cost (net of unconsolidated affiliates)
$
2.7

$
18.9

$
8.3

$
24.1

 
$
0.3

$
0.8

$
9.5

$
2.0

(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 $3.0 million and $19.7 million of net periodic benefit cost recognized during the three months ended September 30, 2016 and 2015, respectively, OG&E recognized the following:

an increase in pension expense during the three months ended September 30, 2016 of $2.4 million and a deferral of $4.7 million for the three months ended September 30, 2015, 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
during the three months ended September 30, 2016 there were no costs relating to the deferral of pension expense compared to $1.4 million for the three months ended September 30, 2015 related to the Arkansas jurisdictional portion of the pension settlement charge of $16.2 million during the three months ended September 30, 2015.

(C)
In addition to the $17.8 million and $26.1 million of net periodic benefit cost recognized during the nine months ended September 30, 2016 and 2015, respectively, OG&E recognized the following:

an increase in pension expense during the nine months ended September 30, 2016 and 2015 of $6.7 million and $0.6 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
costs relating to the deferral of pension expense during the nine months ended September 30, 2016 and 2015 of $0.1 million and $1.4 million, respectively, related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million and $16.2 million, respectively.
 

20



 
Postretirement Benefit Plans
 
Three Months Ended
Nine Months Ended
 
September 30,
September 30,
(In millions)
2016 (B)
2015 (B)
2016 (C)
2015 (C)
Service cost
$
0.2

$
0.4

$
0.6

$
1.2

Interest cost
2.4

2.6

7.1

7.7

Expected return on plan assets
(0.6
)
(0.6
)
(1.7
)
(1.8
)
Amortization of net loss
0.6

3.5

1.9

10.4

Amortization of unrecognized prior service cost (A)
(2.1
)
(4.1
)
(6.5
)
(12.4
)
Total net periodic benefit cost
0.5

1.8

1.4

5.1

Less: Amount paid by unconsolidated affiliates

0.4

0.1

1.0

Net periodic benefit cost (net of unconsolidated affiliates)
$
0.5

$
1.4

$
1.3

$
4.1

(A)
Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.
(B)
In addition to the $0.5 million and $1.4 million of net periodic benefit cost recognized during the three months ended September 30, 2016 and 2015, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended September 30, 2016 and 2015 of $1.9 million and $1.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).
(C)
In addition to the $1.3 million and $4.1 million of net periodic benefit cost recognized during the nine months ended September 30, 2016 and 2015, respectively, OG&E recognized an increase in postretirement medical expense during the nine months ended September 30, 2016 and 2015 of $5.9 million and $4.3 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).
 
Three Months Ended
Nine Months Ended
 
September 30,
September 30,
(In millions)
2016
2015
2016
2015
Capitalized portion of net periodic pension benefit cost
$
1.0

$
2.6

$
3.0

$
4.6

Capitalized portion of net periodic postretirement benefit cost
0.2

0.5

0.6

1.4


Pension Plan Funding

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

11.
Report of Business Segments

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

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


21


The following tables summarize the results of the Company's business segments during the three and nine months ended September 30, 2016 and 2015.
Three Months Ended September 30, 2016
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
743.9

$

$

$

$
743.9

Cost of sales
269.8




269.8

Other operation and maintenance
115.2

(0.1
)
(2.0
)

113.1

Depreciation and amortization
80.8


1.4


82.2

Taxes other than income
20.9


0.6


21.5

Operating income
257.2

0.1



257.3

Equity in earnings of unconsolidated affiliates

34.5



34.5

Other income
6.0


0.3


6.3

Interest expense
34.3


1.1


35.4

Income tax expense (benefit)
69.0

12.1

(2.0
)

79.1

Net income
$
159.9

$
22.5

$
1.2

$

$
183.6

Investment in unconsolidated affiliates
$

$
1,168.0

$

$

$
1,168.0

Total assets
$
8,511.5

$
1,503.1

$
93.3

$
(323.9
)
$
9,784.0

Three Months Ended September 30, 2015
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
719.8

$

$

$

$
719.8

Cost of sales
259.8




259.8

Other operation and maintenance
107.4

4.9

(2.9
)

109.4

Depreciation and amortization
75.9


2.0


77.9

Taxes other than income
21.0


0.9


21.9

Operating income
255.7

(4.9
)


250.8

Equity in earnings of unconsolidated affiliates (A)

(71.9
)


(71.9
)
Other income
6.6


(0.7
)
(0.1
)
5.8

Interest expense
36.4


0.7

(0.1
)
37.0

Income tax expense (benefit)
63.0

(26.8
)
0.3


36.5

Net income
$
162.9

$
(50.0
)
$
(1.7
)
$

$
111.2

Investment in unconsolidated affiliates
$

$
1,202.2

$

$

$
1,202.2

Total assets
$
8,554.1

$
1,541.5

$
133.5

$
(628.4
)
$
9,600.7

(A)
The Company recorded a $108.4 million pre-tax charge during the three months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences.


22


Nine Months Ended September 30, 2016
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
1,728.4

$

$

$

$
1,728.4

Cost of sales
645.4




645.4

Other operation and maintenance
356.3

7.9

(9.6
)

354.6

Depreciation and amortization
235.9


4.9


240.8

Taxes other than income
63.6


2.9


66.5

Operating income
427.2

(7.9
)
1.8


421.1

Equity in earnings of unconsolidated affiliates

79.5



79.5

Other income
18.3


(0.8
)
(0.2
)
17.3

Interest expense
104.8


3.1

(0.2
)
107.7

Income tax expense (benefit)
102.4

31.5

(4.0
)

129.9

Net income
$
238.3

$
40.1

$
1.9

$

$
280.3

Investment in unconsolidated affiliates
$

$
1,168.0

$

$

$
1,168.0

Total assets
$
8,511.5

$
1,503.1

$
93.3

$
(323.9
)
$
9,784.0

Nine Months Ended September 30, 2015
Electric Utility
Natural Gas Midstream Operations
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
Operating revenues
$
1,749.8

$

$

$

$
1,749.8

Cost of sales
682.3




682.3

Other operation and maintenance
337.3

5.9

(8.9
)

334.3

Depreciation and amortization
224.0


6.0


230.0

Taxes other than income
65.7


3.1


68.8

Operating income
440.5

(5.9
)
(0.2
)

434.4

Equity in earnings of unconsolidated affiliates (A)

(12.0
)


(12.0
)
Other income
13.9


2.6

(0.2
)
16.3

Interest expense
110.5


2.1

(0.2
)
112.4

Income tax expense (benefit)
94.9

(8.7
)
(1.8
)

84.4

Net income
$
249.0

$
(9.2
)
$
2.1

$

$
241.9

Investment in unconsolidated affiliates
$

$
1,202.2

$

$

$
1,202.2

Total assets
$
8,554.1

$
1,541.5

$
133.5

$
(628.4
)
$
9,600.7

(A)
The Company recorded a $108.4 million pre-tax charge during the three months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences.

12.
Commitments and Contingencies
 
Except as set forth below, in Note 13 and under "Environmental Laws and Regulations" in Item 2 of Part I and in Item 1 of Part II of this Form 10-Q, the circumstances set forth in Notes 14 and 15 to the Company's Consolidated Financial Statements included in the Company's 2015 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

Environmental Laws and Regulations
The activities of OG&E are subject to numerous stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or ot