Q2 2012 OGE 10-Q


 

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

FORM 10-Q

(Mark One)
S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2012

OR

£ 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.  R  Yes  £  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).  R  Yes  £  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  R
Accelerated filer  £
Non-accelerated filer    £ (Do not check if a smaller reporting company)
Smaller reporting company  £

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

At June 30, 2012, there were 98,656,135 shares of common stock, par value $0.01 per share, outstanding.

 


OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2012

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
2011 Form 10-K
Annual Report on Form 10-K for the year ended December 31, 2011
APSC
Arkansas Public Service Commission
ArcLight group
Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
Atoka
Atoka Midstream LLC joint venture
BART
Best available retrofit technology
Chesapeake
Chesapeake Energy Marketing, Inc. and Chesapeake Exploration, L.L.C.
Company
OGE Energy, collectively with its subsidiaries
Dry Scrubbers
Dry flue gas desulfurization units with spray dryer absorber
EBITDA
Enogex Holdings earnings before interest, taxes, depreciation and amortization
Enogex
OGE Holdings, collectively with its subsidiaries
Enogex LLC
Enogex LLC, collectively with its subsidiaries
Enogex Holdings
Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings
EPA
U.S. Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
FIP
Federal implementation plan
GAAP
Accounting principles generally accepted in the United States
MMBtu
Million British thermal unit
MMcf/d
Million cubic feet per day
NGLs
Natural gas liquids
NOX
Nitrogen oxide
NYMEX
New York Mercantile Exchange
OCC
Oklahoma Corporation Commission
OER
OGE Energy Resources LLC, wholly-owned subsidiary of Enogex LLC (subsequent to June 30, 2012, the legal name has been changed to Enogex Energy Resources LLC)
Off-system sales
Sales to other utilities and power marketers
OG&E
Oklahoma Gas and Electric Company
OGE Holdings
OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy and parent company of Enogex Holdings
Pension Plan
Qualified defined benefit retirement plan
PRM
Price risk management
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 2011 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;
•
prices and availability of electricity, coal, natural gas and NGLs, each on a stand-alone basis and in relation to each other as well as the processing contract mix between percent-of-liquids, percent-of-proceeds, keep-whole and fixed-fee;
•
business conditions in the energy and natural gas midstream industries;
•
competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;
•
unusual weather;
•
availability and prices of raw materials for current and future construction projects;
•
Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company's markets;
•
environmental laws and regulations that may impact the Company's operations;
•
changes in accounting standards, rules or guidelines;
•
the discontinuance of accounting principles for certain types of rate-regulated activities;
•
whether OG&E can successfully implement its Smart Grid program to install meters for its customers and integrate the Smart Grid meters with its customer billing and other computer information systems;
•
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;
•
the higher degree of risk associated with the Company's nonregulated business compared with the Company's regulated utility business; 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 2011 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
Six Months Ended
 
June 30,
June 30,
(In millions except per share data)
2012
2011
2012
2011
OPERATING REVENUES
 
 
 
 
Electric Utility operating revenues
$
528.0

$
568.7

$
954.7

$
990.8

Natural Gas Midstream Operations operating revenues
327.0

409.4

741.0

827.8

Total operating revenues
855.0

978.1

1,695.7

1,818.6

COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
 
 
 
 
Electric Utility cost of goods sold
192.7

242.5

376.3

450.0

Natural Gas Midstream Operations cost of goods sold
216.6

307.6

518.3

633.3

Total cost of goods sold
409.3

550.1

894.6

1,083.3

Gross margin on revenues
445.7

428.0

801.1

735.3

OPERATING EXPENSES
 
 
 
 
Other operation and maintenance
153.0

146.6

300.6

284.9

Depreciation and amortization
90.5

74.7

177.1

148.7

Impairment of assets
0.1

—

0.3

—

Gain on insurance proceeds
—

—

(7.5
)
—

Taxes other than income
24.8

24.5

55.0

51.6

Total operating expenses
268.4

245.8

525.5

485.2

OPERATING INCOME
177.3

182.2

275.6

250.1

OTHER INCOME (EXPENSE)
 
 
 
 
Interest income
0.1

0.1

0.1

0.2

Allowance for equity funds used during construction
1.7

5.8

3.6

10.2

Other income
2.4

7.0

10.1

13.3

Other expense
(3.6
)
(3.5
)
(5.5
)
(5.8
)
Net other income
0.6

9.4

8.3

17.9

INTEREST EXPENSE
 
 
 
 
Interest on long-term debt
38.9

35.8

78.1

71.2

Allowance for borrowed funds used during construction
(0.9
)
(2.9
)
(2.0
)
(5.2
)
Interest on short-term debt and other interest charges
2.4

1.6

4.4

2.6

Interest expense
40.4

34.5

80.5

68.6

INCOME BEFORE TAXES
137.5

157.1

203.4

199.4

INCOME TAX EXPENSE
35.9

47.8

54.3

60.4

NET INCOME
101.6

109.3

149.1

139.0

Less: Net income attributable to noncontrolling interests
7.7

6.3

18.1

11.2

NET INCOME ATTRIBUTABLE TO OGE ENERGY
$
93.9

$
103.0

$
131.0

$
127.8

BASIC AVERAGE COMMON SHARES OUTSTANDING
98.6

98.0

98.4

97.8

DILUTED AVERAGE COMMON SHARES OUTSTANDING
98.9

99.3

98.8

99.2

BASIC EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
$
0.95

$
1.05

$
1.33

$
1.31

DILUTED EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
$
0.95

$
1.04

$
1.33

$
1.29

DIVIDENDS DECLARED PER COMMON SHARE
$
0.3925

$
0.3750

$
0.7850

$
0.7500




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
Six Months Ended
 
June 30,
June 30,
(In millions)
2012
2011
2012
2011
Net income
$
101.6

$
109.3

$
149.1

$
139.0

Other comprehensive income (loss), net of tax
 
 
 
 
Pension Plan and Restoration of Retirement Income Plan:
 
 
 
 
Amortization of deferred net loss, net of tax of $0.5 million, $0.5 million, $0.9 million and $0.9 million, respectively
0.7

0.5

1.5

1.0

Amortization of prior service cost, net of tax of $0.1 million, ($0.1) million, $0.1 million and $0, respectively
0.1

—

0.1

0.2

Postretirement plans:
 
 
 
 
Amortization of deferred net loss, net of tax of $0.3 million, $0.1 million, $0.6 million and $0.6 million, respectively
0.5

0.6

1.0

0.8

Amortization of deferred net transition obligation, net of tax of $0, ($0.1) million, $0 and $0, respectively
—

—

—

0.1

Amortization of prior service cost, net of tax of ($0.2) million, ($0.3) million, ($0.5) million and ($0.6) million, respectively
(0.4
)
(0.3
)
(0.9
)
(0.9
)
Prior service credit arising during the period, net of tax of $0, $0, $0 and $6.2 million, respectively
—

—

—

10.7

Deferred commodity contracts hedging (gains) losses reclassified in net income, net of tax of $0, $3.4 million, ($1.7) million and $6.6 million, respectively
—

7.3

(3.3
)
13.9

Deferred commodity contracts hedging losses, net of tax of ($0.2) million, ($0.5) million, ($0.2) million and ($2.5) million, respectively
(0.3
)
(1.8
)
(0.3
)
(6.9
)
Deferred interest rate swaps hedging losses reclassified in net income, net of tax of $0, $0, $0.1 million and $0.1 million, respectively
—

0.1

0.1

0.2

Other comprehensive income (loss), net of tax
0.6

6.4

(1.8
)
19.1

Comprehensive income (loss)
102.2

115.7

147.3

158.1

Less:  Comprehensive income attributable to noncontrolling interest for sale of equity investment
—

—

—

(1.7
)
Less:  Comprehensive income attributable to noncontrolling interests
7.7

7.5

17.2

13.5

Total comprehensive income attributable to OGE Energy
$
94.5

$
108.2

$
130.1

$
146.3
















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

3


OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
 
June 30,
(In millions)
2012
2011
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$
149.1

$
139.0

Adjustments to reconcile net income to net cash provided from operating activities
 
 
Depreciation and amortization
177.1

148.7

Impairment of assets
0.3

—

Deferred income taxes and investment tax credits, net
63.1

60.3

Allowance for equity funds used during construction
(3.6
)
(10.2
)
(Gain) loss on disposition and abandonment of assets
0.7

(3.3
)
Gain on insurance proceeds
(7.5
)
—

Stock-based compensation
(9.4
)
0.4

Price risk management assets
2.8

1.1

Price risk management liabilities
(5.4
)
6.8

Regulatory assets
10.3

6.8

Regulatory liabilities
(7.6
)
3.3

Other assets
4.8

5.4

Other liabilities
(26.6
)
(38.3
)
Change in certain current assets and liabilities
 
 
Accounts receivable, net
19.9

(47.0
)
Accrued unbilled revenues
(25.3
)
(39.8
)
Income taxes receivable
(8.8
)
—

Fuel, materials and supplies inventories
(3.6
)
33.9

Gas imbalance assets
(8.3
)
(3.6
)
Fuel clause under recoveries
1.1

(21.4
)
Other current assets
(13.0
)
3.5

Accounts payable
(92.6
)
(6.1
)
Gas imbalance liabilities
(8.3
)
1.0

Fuel clause over recoveries
57.7

(20.6
)
Other current liabilities
14.6

26.6

Net Cash Provided from Operating Activities
281.5

246.5

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Capital expenditures (less allowance for equity funds used during construction)
(558.5
)
(571.8
)
Reimbursement of capital expenditures 
23.4

21.6

Proceeds from insurance
7.6

—

Proceeds from sale of assets
0.6

17.5

Net Cash Used in Investing Activities
(526.9
)
(532.7
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Increase in short-term debt
319.6

66.1

Issuance of common stock
7.0

7.5

Contributions from noncontrolling interest partners
1.0

73.5

Proceeds from long-term debt
—

246.3

Repayment of line of credit
—

(25.0
)
Distributions to noncontrolling interest partners
(8.0
)
(6.1
)
Dividends paid on common stock
(77.1
)
(73.3
)
Net Cash Provided from Financing Activities
242.5

289.0

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(2.9
)
2.8

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
4.6

2.3

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
1.7

$
5.1





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

4

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
June 30, 2012 (Unaudited)
December 31, 2011
ASSETS
 
 
CURRENT ASSETS
 
 
Cash and cash equivalents
$
1.7

$
4.6

Accounts receivable, less reserve of $1.5 and $3.8, respectively
302.6

322.5

Accrued unbilled revenues
84.6

59.3

Income taxes receivable
17.1

8.3

Fuel inventories
101.1

100.7

Materials and supplies, at average cost
90.4

87.2

Price risk management
0.9

3.5

Gas imbalances
10.1

1.8

Deferred income taxes
74.7

32.1

Fuel clause under recoveries
0.7

1.8

Other
43.9

30.9

Total current assets
727.8

652.7

OTHER PROPERTY AND INVESTMENTS, at cost
48.8

46.7

PROPERTY, PLANT AND EQUIPMENT
 
 
In service
10,956.3

10,315.9

Construction work in progress
363.1

499.0

Total property, plant and equipment
11,319.4

10,814.9

Less accumulated depreciation
3,455.7

3,340.9

Net property, plant and equipment
7,863.7

7,474.0

DEFERRED CHARGES AND OTHER ASSETS
 
 
Regulatory assets
494.1

507.9

Intangible assets, net
132.2

137.0

Goodwill
39.4

39.4

Price risk management
0.1

0.3

Other
45.3

48.0

Total deferred charges and other assets
711.1

732.6

TOTAL ASSETS
$
9,351.4

$
8,906.0





















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

5

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
(In millions)
June 30, 2012 (Unaudited)
December 31, 2011
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
CURRENT LIABILITIES
 
 
Short-term debt
$
596.7

$
277.1

Accounts payable
274.5

388.0

Dividends payable
38.7

38.5

Customer deposits
69.4

67.6

Accrued taxes
45.7

42.3

Accrued interest
54.8

54.8

Accrued compensation
37.2

47.8

Price risk management
0.4

0.4

Gas imbalances
1.5

9.8

Fuel clause over recoveries
65.4

7.7

Other
84.5

64.5

Total current liabilities
1,268.8

998.5

LONG-TERM DEBT
2,737.5

2,737.1

DEFERRED CREDITS AND OTHER LIABILITIES
 
 
Accrued benefit obligations
334.1

360.8

Deferred income taxes
1,757.2

1,651.4

Deferred investment tax credits
5.0

6.1

Regulatory liabilities
242.5

230.7

Deferred revenues
40.5

40.8

Price risk management
—

0.1

Other
87.6

61.2

Total deferred credits and other liabilities
2,466.9

2,351.1

Total liabilities
6,473.2

6,086.7

COMMITMENTS AND CONTINGENCIES (NOTE 12)


STOCKHOLDERS' EQUITY
 
 
Common stockholders' equity
1,028.2

1,035.3

Retained earnings
1,628.4

1,574.8

Accumulated other comprehensive loss, net of tax
(41.5
)
(40.6
)
Treasury stock, at cost
(0.1
)
(6.2
)
Total OGE Energy stockholders' equity
2,615.0

2,563.3

Noncontrolling interests
263.2

256.0

Total stockholders' equity
2,878.2

2,819.3

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
9,351.4

$
8,906.0















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)
Noncontrolling Interest
Treasury Stock
Total
Balance at December 31, 2011
$
1.0

$
1,034.3

$
1,574.8

$
(40.6
)
$
256.0

$
(6.2
)
$
2,819.3

Comprehensive income (loss)
 
 
 
 
 

 
 
Net income
—

—

131.0

—

18.1

—

149.1

Other comprehensive income (loss), net of tax
—

—

—

(0.9
)
(0.9
)
—

(1.8
)
Comprehensive income (loss)
—

—

131.0

(0.9
)
17.2

—

147.3

Dividends declared on common stock
—

—

(77.4
)
—

—

—

(77.4
)
Issuance of common stock
—

7.0

—

—

—

—

7.0

Stock-based compensation and other
—

(14.1
)
—

—

(3.0
)
6.1

(11.0
)
Contributions from noncontrolling interest partners
—

—

—

—

1.0

—

1.0

Distributions to noncontrolling interest partners
—

—

—

—

(8.0
)
—

(8.0
)
Balance at June 30, 2012
$
1.0

$
1,027.2

$
1,628.4

$
(41.5
)
$
263.2

$
(0.1
)
$
2,878.2

 
 
 
 
 
 
 
 
Balance at December 31, 2010
$
1.0

$
968.2

$
1,380.6

$
(60.2
)
$
110.4

$
—

$
2,400.0

Comprehensive income (loss)
 
 
 
 
 
 
 
Net income
—

—

127.8

—

11.2

—

139.0

Other comprehensive income (loss), net of tax
—

—

—

18.4

0.7

—

19.1

Comprehensive income (loss)
—

—

127.8

18.4

11.9

—

158.1

Dividends declared on common stock
—

—

(73.5
)
—

—

—

(73.5
)
Issuance of common stock
—

7.5

—

—

—

—

7.5

Stock-based compensation
—

0.1

—

—

—

—

0.1

Contributions from noncontrolling interest partners
—

29.1

—

—

44.4

—

73.5

Distributions to noncontrolling interest partners
—

—

—

—

(6.1
)
—

(6.1
)
Deferred income taxes attributable to contributions from noncontrolling interest partners
—

(11.2
)
—

—

—

—

(11.2
)
Balance at June 30, 2011
$
1.0

$
993.7

$
1,434.9

$
(41.8
)
$
160.6

$
—

$
2,548.4













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 four business segments:  (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.  All significant intercompany transactions have been eliminated in consolidation.

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.  OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.  OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Enogex is a provider of integrated natural gas midstream services.  Enogex is engaged in the business of gathering, processing, transporting, storing and marketing natural gas.  Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle.  Enogex's operations are organized into three business segments: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. At June 30, 2012, the Company indirectly owns an 81.3 percent membership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC, a Delaware single-member limited liability company.  The Company consolidates Enogex Holdings in its Condensed Consolidated Financial Statements as OGE Energy has a controlling financial interest over the operations of Enogex Holdings.  Also, Enogex LLC holds a 50 percent ownership interest in Atoka.  The Company consolidates Atoka in its Condensed Consolidated Financial Statements as Enogex acts as the managing member of Atoka and has control over the operations of Atoka.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.
In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at June 30, 2012 and December 31, 2011, the results of its operations for the three and six months ended June 30, 2012 and 2011 and the results of its cash flows for the six months ended June 30, 2012 and 2011, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company's operating results for the three and six months ended June 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012 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 2011 Form 10-K.
   
Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC.  Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain actual or anticipated 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.


8


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

The following table is a summary of OG&E's regulatory assets and liabilities at:
(In millions)
June 30, 2012
December 31, 2011
Regulatory Assets
 
 
Current
 
 
Oklahoma demand program rider under recovery (A)
$
12.3

$
8.1

Crossroads rider under recovery (A)
10.6

2.5

Fuel clause under recoveries
0.7

1.8

Other (A)
11.3

3.6

Total Current Regulatory Assets
$
34.9

$
16.0

Non-Current
 

 

Benefit obligations regulatory asset
$
345.1

$
359.2

Income taxes recoverable from customers, net
54.7

54.0

Smart Grid
42.3

37.2

Deferred storm expenses
18.9

23.8

Unamortized loss on reacquired debt
13.6

14.2

Deferred pension expenses
6.8

9.1

Other
12.7

10.4

Total Non-Current Regulatory Assets
$
494.1

$
507.9

Regulatory Liabilities
 

 

Current
 

 

Fuel clause over recoveries
$
65.4

$
7.7

Smart Grid rider over recovery (B)
25.9

24.3

Other (B)
15.4

13.7

Total Current Regulatory Liabilities
$
106.7

$
45.7

Non-Current
 

 

Accrued removal obligations, net
$
213.6

$
208.2

Pension tracker
28.9

22.5

Total Non-Current Regulatory Liabilities
$
242.5

$
230.7

(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.
             
Property, Plant and Equipment

Enogex Cox City Plant Fire

On December 8, 2010, a fire occurred at Enogex's Cox City natural gas processing plant destroying major components of one of the four processing trains, representing 120 MMcf/d of the total 180 MMcf/d of capacity, at that facility. The damaged train was replaced and the facility was returned to full service in September 2011. The total cost necessary to return the facility back to full service was $29.6 million. In the fourth quarter of 2011, Enogex received a partial insurance reimbursement of $7.4 million and recognized a gain of $3.0 million on insurance proceeds. In March 2012, Enogex reached a settlement agreement with its insurers in this matter. As a result of the settlement agreement, Enogex received additional reimbursements of $7.6 million during the six months ended June 30, 2012. Enogex recognized a gain of $7.5 million on insurance proceeds during the six months ended June 30, 2012.
   



9


Asset Retirement Obligation

The following table summarizes changes to OG&E's asset retirement obligations related to its wind farms due to a change in the assumption related to the timing of removal used in the valuation of the asset retirement obligations.
(In millions)
 
Balance at January 1, 2012
$
24.8

Accretion expense
0.9

Revisions in estimated cash flows
26.7

Balance at June 30, 2012
$
52.4


Accumulated Other Comprehensive Income (Loss)
The following table summarizes the components of accumulated other comprehensive loss at June 30, 2012 and December 31, 2011 attributable to OGE Energy. At both June 30, 2012 and December 31, 2011, there was no accumulated other comprehensive loss related to Enogex's noncontrolling interest in Atoka.
(In millions)
June 30, 2012
December 31, 2011
Pension Plan and Restoration of Retirement Income Plan:
 
 
Net loss
$
(40.6
)
$
(42.1
)
Prior service cost
—

(0.1
)
Postretirement plans:
 
 
Net loss                                                                                              
(14.4
)
(15.4
)
Prior service cost
8.1

9.0

Net transition obligation
(0.1
)
(0.1
)
Deferred commodity contracts hedging gains (losses)
(0.3
)
3.3

Deferred interest rate swaps hedging losses
(0.6
)
(0.7
)
Total accumulated other comprehensive loss
(47.9
)
(46.1
)
Less:  Accumulated other comprehensive loss attributable to noncontrolling interests
(6.4
)
(5.5
)
Accumulated other comprehensive loss, net of tax
$
(41.5
)
$
(40.6
)

2.
Noncontrolling Interests
  
Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings makes quarterly distributions to its partners. The following table summarizes the quarterly distributions during the six months ended June 30, 2012.
(In millions)
OGE Holdings Portion
ArcLight group's Portion
Total Distribution

First quarter 2012
$
24.4

$
5.6

$
30.0

Second quarter 2012
10.1

2.4

12.5

Total
$
34.5

$
8.0

$
42.5


During the six months ended June 30, 2012, Atoka's noncontrolling interest partner made contributions of $1.0 million to Atoka. Enogex LLC made no distributions during the six months ended June 30, 2012 to its Atoka partner, as there is no minimum distribution requirement related to Atoka.

3.
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 and examples

10


of each 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. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.
 
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.  Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing.
 
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 utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX published market prices, independent broker pricing data or broker/dealer valuations.  The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining.  Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk.  Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management's best estimate of fair value.  These contracts are classified as Level 3.
 
The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor's Ratings Services and/or internally generated ratings.  The fair value of derivative assets is adjusted for credit risk.  The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.
 
Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset.  The reporting entity's choice to offset or not must be applied consistently.  A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets.  The Company has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.
 
The following tables summarize the Company's assets and liabilities that are measured at fair value on a recurring basis at June 30, 2012 and December 31, 2011 as well as reconcile the Company's commodity contracts fair value to PRM Assets and Liabilities on the Company's Condensed Consolidated Balance Sheets at June 30, 2012 and December 31, 2011. The Company held no Level 3 investments at June 30, 2012 or December 31, 2011.

11


June 30, 2012
(In millions)
Commodity Contracts
Gas Imbalances (A)
 
Assets
Liabilities
Assets (B)
Liabilities (C)
Quoted market prices in active market for identical assets (Level 1)
$
16.3

$
18.0

$
—

$
—

Significant other observable inputs (Level 2)
1.8

0.9

6.8

—

Total fair value
18.1

18.9

6.8

—

Netting adjustments
(17.1
)
(18.5
)
—

—

Total
$
1.0

$
0.4

$
6.8

$
—

 
 
 
 
 
December 31, 2011
(In millions)
Commodity Contracts
Gas Imbalances (A)
 
Assets
Liabilities
Assets
Liabilities (C)
Quoted market prices in active market for identical assets (Level 1)
$
57.1

$
52.3

$
—

$
—

Significant other observable inputs (Level 2)
4.2

1.2

1.8

7.8

Total fair value
61.3

53.5

1.8

7.8

Netting adjustments
(57.5
)
(53.0
)
—

—

Total
$
3.8

$
0.5

$
1.8

$
7.8

(A)
The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.
(B)
Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $3.3 million at June 30, 2012 with no comparable item at December 31, 2011, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.
(C)
Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.5 million and $2.0 million at June 30, 2012 and December 31, 2011, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.
 
The following table summarizes the Company's assets that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the six months ended June 30, 2011. There were no Level 3 investments held at June 30, 2012 or December 31, 2011.
 
Commodity Contracts
(In millions)
Assets
Balance at January 1
$
13.3

Total gains or losses
 
     Included in other comprehensive income
(4.8
)
Settlements
(3.3
)
Balance at March 31
5.2

Total gains or losses
 
     Included in other comprehensive income
(1.0
)
Settlements
(1.7
)
Balance at June 30
$
2.5














12


The following table summarizes the fair value and carrying amount of the Company's financial instruments, including derivative contracts related to the Company's PRM activities, at June 30, 2012 and December 31, 2011.
 
June 30, 2012
December 31, 2011
(In millions)
Carrying Amount 
Fair
Value
Carrying Amount 
 Fair
Value
PRM Assets
 
 
 
 
Energy Derivative Contracts
$
1.0

$
1.0

$
3.8

$
3.8

PRM Liabilities
 
 
 
 
Energy Derivative Contracts
$
0.4

$
0.4

$
0.5

$
0.5

Long-Term Debt
 
 
 
 
OG&E Senior Notes
$
1,904.0

$
2,358.9

$
1,903.8

$
2,383.8

OGE Energy Senior Notes
99.8

106.3

99.8

108.5

OG&E Industrial Authority Bonds
135.4

135.4

135.4

135.4

Enogex LLC Senior Notes
448.3

497.8

448.1

497.9

Enogex LLC Revolving Credit Agreement
150.0

150.0

150.0

150.0


The carrying value of the financial instruments included in the Condensed Consolidated Balance Sheets approximates fair value except for long-term debt which is valued at the carrying amount.  The valuation of the Company's energy derivative contracts was determined generally based on quoted market prices.  However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values.  The valuation of instruments also considers the credit risk of the counterparties.  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.
 
4.
Derivative Instruments and Hedging Activities

The Company is exposed to certain risks relating to its ongoing business operations.  The primary risks managed using derivatives instruments are commodity price risk and interest rate risk. The Company is also exposed to credit risk in its business operations.
 
Commodity Price Risk
 
The Company primarily uses forward physical contracts, commodity price swap contracts and commodity price option features to manage the Company's commodity price risk exposures. Commodity derivative instruments used by the Company are as follows:

•
NGLs put options and NGLs swaps are used to manage Enogex's NGLs exposure associated with its processing agreements;
•
natural gas swaps are used to manage Enogex's keep-whole natural gas exposure associated with its processing operations and Enogex's natural gas exposure associated with operating its gathering, transportation and storage assets;
•
natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OER's natural gas exposure associated with its storage and transportation contracts; and
•
natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage OER's marketing and trading activities.
 
Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized in the period in which physical delivery of the commodity occurs.  Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by Enogex's operations, (ii) commodity contracts for the sale of NGLs produced by Enogex's gathering and processing business, (iii) electric power contracts by OG&E and (iv) fuel procurement by OG&E.
 
The Company recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement.  Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.


13


Interest Rate Risk
 
The Company's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper.  The Company manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates.  The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes.  Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Credit Risk
 
The Company is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Company money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Company may be forced to enter into alternative arrangements. In that event, the Company's financial results could be adversely affected and the Company could incur losses.

Cash Flow Hedges
 
For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings.  The ineffective portion of a derivative's change in fair value or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. The Company measures the ineffectiveness of commodity cash flow hedges using the change in fair value method whereby the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument.  Forecasted transactions, which are designated as the hedged transaction in a cash flow hedge, are regularly evaluated to assess whether they continue to be probable of occurring.  If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings.
 
The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex's NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing, pipeline and storage operations (operational gas hedges).  The Company also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions. Enogex's cash flow hedges at June 30, 2012 mature by the end of the first quarter of 2013.
 
Fair Value Hedges
 
For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedge risk are recognized currently in earnings.  The Company includes the gain or loss on the hedged items in Operating Revenues as the offsetting loss or gain on the related hedging derivative.
 
At June 30, 2012 and December 31, 2011, the Company had no derivative instruments that were designated as fair value hedges.
 
Derivatives Not Designated as Hedging Instruments

Derivative instruments not designated as hedging instruments are utilized in OER's asset management, marketing and trading activities.  For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments

At June 30, 2012, the Company had the following derivative instruments that were designated as cash flow hedges.
(In millions)
2012 Gross Notional Volume (A)
Enogex marketing hedges
 
Natural gas sales
2.6

(A) Natural gas in MMBtu's.

14


 At June 30, 2012, the Company had the following derivative instruments that were not designated as hedging instruments.
(In millions)
Gross Notional Volume (A)
 
Purchases
Sales
Natural gas (B)
 
 
Physical (C)(D)
7.7

31.0

Fixed Swaps/Futures
57.9

59.7

Options
13.3

12.3

Basis Swaps
15.1

21.6

(A)
Natural gas in MMBtu's.  
(B)
96.9 percent of the natural gas contracts have durations of one year or less, 1.8 percent have durations of more than one year and less than two years and 1.3 percent have durations of more than two years.
(C)
Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.
(D)
Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex's processing contracts, which are not derivative instruments and are excluded from the table above.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at June 30, 2012 are as follows:
 
 
Fair Value
Instrument
Balance Sheet Location
Assets       
Liabilities
 
 
(In millions)
Derivatives Designated as Hedging Instruments 
 
 
 
Natural Gas
 
 
 
Financial Futures/Swaps
Other Current Assets
$
—

$
0.5

Total
$
—

$
0.5

 
 
 
 
Derivatives Not Designated as Hedging Instruments 
 
 
 
Natural Gas
 
 
 
Financial Futures/Swaps
Current PRM
$
0.2

$
0.1

 
Other Current Assets
16.5

17.4

Physical Purchases/Sales
Current PRM
0.8

0.4

 
Non-Current PRM
0.1

—

Financial Options                                       
Other Current Assets
0.5

0.5

Total
$
18.1

$
18.4

Total Gross Derivatives (A)
$
18.1

$
18.9

(A)
See Note 3 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at June 30, 2012.


15


The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at December 31, 2011 are as follows:
 
 
Fair Value
Instrument
Balance Sheet Location
Assets       
Liabilities
 
 
(In millions)
Derivatives Designated as Hedging Instruments 
 
 
 
Natural Gas
 
 
 
Financial Futures/Swaps
Other Current Assets
$
5.2

$
0.3

Total
$
5.2

$
0.3

 
 
 
 
Derivatives Not Designated as Hedging Instruments 
 
 
 
Natural Gas
 
 
 
Financial Futures/Swaps
Current PRM
$
0.4

$
—

 
Other Current Assets
49.9

49.9

Physical Purchases/Sales
Current PRM
3.1

0.4

 
Non-Current PRM
0.3

0.1

Financial Options
Other Current Assets
2.4

2.8

Total
$
56.1

$
53.2

Total Gross Derivatives (A)
$
61.3

$
53.5

(A)
See Note 3 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at December 31, 2011.
       
Income Statement Presentation Related to Derivative Instruments
 
The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months ended June 30, 2012.
 
Derivatives in Cash Flow Hedging Relationships
(In millions)
Amount Recognized in Other Comprehensive Income (A)
Amount Reclassified from Accumulated Other Comprehensive Income into Income


Amount Recognized in Income
Natural Gas Financial Futures/Swaps
$
(0.5
)
$
—

$
—

Total
$
(0.5
)
$
—

$
—

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2012 that is expected to be reclassified into income within the next 12 months is a loss of $0.5 million.

Derivatives Not Designated as Hedging Instruments

(In millions)
Amount Recognized in Income
Natural Gas Physical Purchases/Sales
$
(3.7
)
Natural Gas Financial Futures/Swaps
0.6

Total
$
(3.1
)
     

16


The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months ended June 30, 2011.
 
Derivatives in Cash Flow Hedging Relationships
(In millions)
Amount Recognized in Other Comprehensive Income
Amount Reclassified from Accumulated Other Comprehensive Income into Income


Amount Recognized in Income
NGLs Financial Options
$
(2.4
)
$
(3.3
)
$
—

Natural Gas Financial Futures/Swaps
0.1

(7.4
)
—

Total
$
(2.3
)
$
(10.7
)
$
—


Derivatives Not Designated as Hedging Instruments
(In millions)
Amount Recognized in Income
Natural Gas Physical Purchases/Sales
$
(2.9
)
Natural Gas Financial Futures/Swaps
(0.2
)
Total
$
(3.1
)
 
The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the six months ended June 30, 2012.
 
Derivatives in Cash Flow Hedging Relationships
(In millions)
Amount Recognized in Other Comprehensive Income (A)
Amount Reclassified from Accumulated Other Comprehensive Income into Income


Amount Recognized in Income
Natural Gas Financial Futures/Swaps
$
(0.2
)
$
5.2

$
—

Total
$
(0.2
)
$
5.2

$
—

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2012 that is expected to be reclassified into income within the next 12 months is a loss of $0.5 million.

Derivatives Not Designated as Hedging Instruments

(In millions)
Amount Recognized in Income
Natural Gas Physical Purchases/Sales
$
(6.1
)
Natural Gas Financial Futures/Swaps
1.0

Total
$
(5.1
)
     
The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the six months ended June 30, 2011.
 
Derivatives in Cash Flow Hedging Relationships
(In millions)
Amount Recognized in Other Comprehensive Income
Amount Reclassified from Accumulated Other Comprehensive Income into Income


Amount Recognized in Income
NGLs Financial Options
$
(9.2
)
$
(5.8
)
$
—

Natural Gas Financial Futures/Swaps
(0.1
)
(14.7
)
—

Total
$
(9.3
)
$
(20.5
)
$
—



17


Derivatives Not Designated as Hedging Instruments
(In millions)
Amount Recognized in Income
Natural Gas Physical Purchases/Sales
$
(5.0
)
Natural Gas Financial Futures/Swaps
(0.4
)
Total
$
(5.4
)
             
For derivatives designated as cash flow hedges in the tables above, amounts reclassified from Accumulated Other Comprehensive Income into income (effective portion) and amounts recognized in income (ineffective portion) for the three and six months ended June 30, 2012 and 2011, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the three and six months ended June 30, 2012 and 2011, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody's Investors Services or Standard & Poor's Ratings Services were to lower the Company's senior unsecured debt rating to a below investment grade rating, at June 30, 2012, the Company would have been required to post $0.1 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at June 30, 2012.  In addition, the Company could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.
                     
5.
Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three and six months ended June 30, 2012 and 2011 related to the Company's performance units and restricted stock.
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
(In millions)
2012
2011
2012
2011
Performance units
 
 
 
 
Total shareholder return
$
2.0

$
1.9

$
3.8

$
3.7

Earnings per share
0.6

0.8

1.3

3.0

Total performance units
2.6

2.7

5.1

6.7

Restricted stock
0.2

0.2

0.4

0.5

Total compensation expense
$
2.8

$
2.9

$
5.5

$
7.2

Income tax benefit
$
1.1

$
1.1

$
2.2

$
2.8


During the three and six months ended June 30, 2012, there were 4,113 shares and 392,700 shares, respectively, of new common stock issued pursuant to the Company's stock incentive plans related to exercised stock options, restricted stock grants (net of forfeitures) and payouts of earned performance units. In November 2011, the Company purchased 120,000 shares of its common stock on the open market. During the three months ended March 31, 2012, 114,949 of these shares were used to payout Enogex's portion of earned performance units and during the three months ended June 30, 2012, 2,419 of these shares (net of forfeitures) were used to satisfy restricted stock grants. During the three and six months ended June 30, 2012, there were 2,587 and 2,932 shares of restricted stock, respectively, returned to the Company to satisfy tax liabilities. The Company received $0.1 million during each of the three and six months ended June 30, 2012 related to exercised stock options. The Company did not realize an income tax benefit for the tax deductions from the exercised stock options during the three and six months ended June 30, 2012 due to the Company being in a tax net operating loss position in 2012.

The following table summarizes the activity of the Company's stock-based compensation during the three months ended June 30, 2012.
 
Shares
Fair Value
Grants
 
 
Restricted stock
358

$51.73



18


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 2007 or state and local tax examinations by tax authorities for years prior to 2002.  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 continues to amortize its Federal investment tax credits on a ratable basis throughout the year.  OG&E earns both Federal and Oklahoma state tax credits associated with the production from its wind farms.  In addition, OG&E and Enogex earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.

7.
Common Equity
 
Automatic Dividend Reinvestment and Stock Purchase Plan
 
The Company issued 60,779 shares and 129,112 shares, respectively, of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and six months ended June 30, 2012 and received proceeds of $3.3 million and $6.9 million, respectively.  The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan to fund capital requirements or working capital needs.  At June 30, 2012, there were 2,239,931 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

Earnings Per Share
 
Basic earnings per share is calculated by dividing net income attributable to OGE Energy 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. Basic and diluted earnings per share for the Company were calculated as follows:
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
(In millions)
2012
2011
2012
2011
Net Income Attributable to OGE Energy
$
93.9

$
103.0

$
131.0

$
127.8

Average Common Shares Outstanding
 
 
 
 
Basic average common shares outstanding
98.6

98.0

98.4

97.8

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

1.3

0.4

1.4

Diluted average common shares outstanding
98.9

99.3

98.8

99.2

Basic Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders
$
0.95

$
1.05

$
1.33

$
1.31

Diluted Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders
$
0.95

$
1.04

$
1.33

$
1.29

Anti-dilutive shares excluded from earnings per share calculation
—

—

—

—

 
8.
Long-Term Debt
 
At June 30, 2012, the Company was in compliance with all of its debt agreements.
 
OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds at various dates prior to the maturity.  The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows:

19


SERIES
DATE DUE
AMOUNT
 
 
(In millions)
0.22% - 0.40%
Garfield Industrial Authority, January 1, 2025
$
47.0

0.21% - 0.41%
Muskogee Industrial Authority, January 1, 2025
32.4

0.20% - 0.38%
Muskogee Industrial Authority, June 1, 2027
56.0

Total (redeemable during next 12 months)
$
135.4


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

9.
Short-Term Debt and Credit Facilities
 
The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements.  The short-term debt balance was $596.7 million and $277.1 million at June 30, 2012 and December 31, 2011, respectively. The following table provides information regarding the Company's revolving credit agreements and available cash at June 30, 2012.
Revolving Credit Agreements and Available Cash 
 
Aggregate
Amount
Weighted-Average
 
 
Entity
Commitment 
Outstanding (A)
Interest Rate
 
Maturity
 
(In millions)
 
 
 
OGE Energy (B)
$
750.0

$
596.7

0.46
%
(E)
December 13, 2016
OG&E (C)
400.0

2.2

0.53
%
(E)
December 13, 2016
Enogex LLC (D)
400.0

150.0

1.62
%
(E)
December 13, 2016
 
1,550.0

748.9

0.69
%
 
 
Cash
1.7

N/A

N/A

 
N/A
Total
$
1,551.7

$
748.9

0.69
%
 
 
(A)
Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2012.
(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.  At June 30, 2012, there was $596.7 million in outstanding commercial paper borrowings.
(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.  At June 30, 2012, there was $2.2 million in letters of credit.
(D)
This bank facility is available to provide revolving credit borrowings for Enogex LLC.  As Enogex LLC's credit agreement matures on December 13, 2016, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company's Condensed Consolidated Balance Sheets.
(E)
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 ratings 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 of the Company could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash collateral or letters of credit.
 

20


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 million in short-term borrowings at any one time for a two-year period beginning January 1, 2011 and ending December 31, 2012.

10.
Retirement Plans and Postretirement Benefit Plans

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

Net Periodic Benefit Cost
 
Pension Plan
 
Restoration of Retirement
Income Plan
 
Three Months
Ended
Six Months
Ended
 
Three Months
Ended
Six Months
Ended
 
June 30,
June 30,
 
June 30,
June 30,
(In millions)
2012 (B)
2011 (B)
2012 (C)
2011 (C)
 
2012 (B)
2011 (B)
2012 (C)
2011 (C)
Service cost
$
4.5

$
4.4

$
9.0

$
8.8

 
$
0.2

$
0.2

$
0.5

$
0.5

Interest cost
7.5

8.3

15.0

16.6

 
0.2

0.2

0.3

0.3

Expected return on plan assets
(11.5
)
(11.3
)
(23.0
)
(22.7
)
 
—

—

—

—

Amortization of net loss
6.0

4.8

11.9

9.6

 
0.1

0.1

0.2

0.2

Amortization of unrecognized prior service cost (A)
0.5

0.6

1.1

1.2

 
0.1

0.2

0.3

0.4

Net periodic benefit cost
$
7.0

$
6.8

$
14.0

$
13.5

 
$
0.6

$
0.7

$
1.3

$
1.4

(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 $7.6 million and $7.5 million of net periodic benefit cost recognized by the Company during the three months ended June 30, 2012 and 2011, respectively, OG&E recognized an increase in pension expense during each of the three months ended June 30, 2012 and 2011 of $2.8 million 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).  
(C)
In addition to the $15.3 million and $14.9 million of net periodic benefit cost recognized by the Company during the six months ended June 30, 2012 and 2011, respectively, OG&E recognized an increase in pension expense during the six months ended June 30, 2012 and 2011 of $5.7 million and $5.3 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).
 
Postretirement Benefit Plans
 
Three Months
Ended
Six Months
Ended
 
June 30,
June 30,
(In millions)
2012 (B)
2011 (B)
2012 (C)
2011 (C)
Service cost
$
1.1

$
0.9

$
2.1

$
1.8

Interest cost
3.0

3.1

6.0

6.2

Expected return on plan assets
(0.7
)
(1.3
)
(1.5
)
(2.6
)
Amortization of transition obligation
0.7

0.7

1.4

1.4

Amortization of net loss
5.1

4.5

10.2

9.1

Amortization of unrecognized prior service cost (A)
(4.2
)
(4.1
)
(8.3
)
(8.2
)
Net periodic benefit cost
$
5.0

$
3.8

$
9.9

$
7.7

(A)
Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.
(B)
In addition to the $5.0 million and $3.8 million of net periodic benefit cost recognized by the Company during the three months ended June 30, 2012 and 2011, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended June 30, 2012 and 2011, of $0.4 million and $1.7 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 $9.9 million and $7.7 million of net periodic benefit cost recognized by the Company during the six months ended June 30, 2012 and 2011, respectively, OG&E recognized an increase in postretirement medical expense during the six months ended June 30, 2012 and 2011, of $0.8 million and $1.7 million, respectively, to maintain the allowable amount to be

21


recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

11.
Report of Business Segments

The Company's business is divided into four segments for financial reporting purposes as follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.  Other Operations primarily includes the operations of the holding company.  Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations.  In reviewing its segment operating results, the Company focuses on operating income as its measure of segment profit and loss, and, therefore, has presented this information below.  The following tables summarize the results of the Company's business segments during the three and six months ended June 30, 2012 and 2011.
Three Months Ended
June 30, 2012
 Electric Utility
Transportation and
Storage
Gathering and Processing
Marketing
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
 
 
Operating revenues
$
528.0

$
75.1

$
266.4

$
76.6

$
—

$
(91.1
)
$
855.0

Cost of goods sold
204.6

37.4

178.6

79.5

—

(90.8
)
409.3

Gross margin on revenues
323.4

37.7

87.8

(2.9
)
—

(0.3
)
445.7

Other operation and maintenance     
114.7

10.6

29.9

2.2

(4.4
)
—

153.0

Depreciation and amortization
62.7

5.4

18.6

0.3

3.5

—

90.5

Impairment of assets
—

—

0.1

—

—

—

0.1

Taxes other than income
18.2

3.5

2.1

0.1

0.9

—

24.8

Operating income (loss)
$
127.8

$
18.2

$
37.1

$
(5.5
)
$
—

$
(0.3
)
$
177.3

 
 
 
 
 
 
 
 
Total assets
$
6,833.2

$
2,051.8

$
1,623.0

$
47.5

$
331.4

$
(1,535.5
)
$
9,351.4

Three Months Ended
June 30, 2011
 Electric Utility
Transportation and
Storage
Gathering and Processing
Marketing
Other Operations
Eliminations
Total
(In millions)
 
 
 
 
 
 
 
Operating revenues
$
568.7

$
108.0

$
289.1

$
168.3

$
—

$
(156.0
)
$
978.1

Cost of goods sold
254.3

69.5

210.9

170.4

—

(155.0
)
550.1

Gross margin on revenues
314.4

38.5

78.2

(2.1
)
—

(1.0
)
428.0

Other operation and maintenance     
110.2

13.0

26.3

2.0

(4.2
)
(0.7
)
146.6

Depreciation and amortization
52.1

5.8

13.4

0.1

3.3

—

74.7

Taxes other than income
18.8

3.3

1.7

(0.1
)
0.8

—

24.5

Operating income (loss)
$
133.3

$
16.4

$
36.8

$
(4.1
)
$
0.1

$
(0.3
)
$
182.2

 
 
 
 
 
 
 
 
Total assets
$
6,290.5

$
1,474.8

$
1,106.7

$
80.2

$
152.4

$
(969.1
)
$
8,135.5

Six Months Ended
June 30, 2012
 Electric Utility
Transportation and
Storage
Gathering and Processing
Marketing