oge1stqtr10.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q

(Mark One)
 
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2010

 
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.  Yes  þ  No  o  

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).   o  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).
Yes  o  No  þ  

At March 31, 2010, there were 97,205,073 shares of common stock, par value $0.01 per share, outstanding.
 


 
 

 

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2010

TABLE OF CONTENTS

     
   
Page
     
 
1
     
     
   
     
Item 1. Financial Statements (Unaudited)
   
Condensed Consolidated Statements of Income
 
2
Condensed Consolidated Balance Sheets
 
3
Condensed Consolidated Statements of Changes in Stockholders’ Equity
 
5
Condensed Consolidated Statements of Cash Flows
 
6
Notes to Condensed Consolidated Financial Statements
 
7
     
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
26
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk
 
47
     
Item 4. Controls and Procedures
 
48
     
     
   
     
Item 1. Legal Proceedings
 
48
     
Item 1A. Risk Factors
 
50
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
 
50
     
Item 6. Exhibits
 
50
     
 
51
     


i
 
 

 

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. In addition to the specific risk factors discussed in “Item 1A. Risk Factors” in OGE Energy Corp.’s Annual Report on Form   10-K for the year ended December 31, 2009 (“2009 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:
 
Ÿ  
general economic conditions, including the availability of credit, access to existing lines of credit, actions of rating agencies and their impact on capital expenditures;
Ÿ  
the ability of OGE Energy Corp. (collectively, with its subsidiaries, the “Company”) and its subsidiaries to access the capital markets and obtain financing on favorable terms;
Ÿ  
prices and availability of electricity, coal, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other;
Ÿ  
business conditions in the energy and natural gas midstream industries;
Ÿ  
competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;
Ÿ  
unusual weather;
Ÿ  
availability and prices of raw materials for current and future construction projects;
Ÿ  
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;
Ÿ  
environmental laws and regulations that may impact the Company’s operations;
Ÿ  
changes in accounting standards, rules or guidelines;
Ÿ  
the discontinuance of accounting principles for certain types of rate-regulated activities;
Ÿ  
creditworthiness of suppliers, customers and other contractual parties;
Ÿ  
the higher degree of risk associated with the Company’s nonregulated business compared with the Company’s regulated utility business; and
Ÿ  
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 2009 Form 10-K.

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

 
1

 

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.


   
OGE ENERGY CORP.
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
(Unaudited)
 
   
 
Three Months Ended
 
 
March 31,
 
 (In millions, except per share data)
2010
         2009
 
OPERATING REVENUES
             
Electric Utility operating revenues
$   
444.0 
 
$
336.7 
   
Natural Gas Pipeline operating revenues
 
431.8 
   
269.9 
   
Total operating revenues
 
875.8 
   
606.6 
   
COST OF GOODS SOLD (exclusive of depreciation and amortization
             
shown below)
             
Electric Utility cost of goods sold
 
238.9 
   
159.1 
   
Natural Gas Pipeline cost of goods sold
 
331.2 
   
194.1 
   
Total cost of goods sold
 
570.1 
   
353.2 
   
Gross margin on revenues
 
305.7 
   
253.4 
   
Other operation and maintenance
 
123.6 
   
116.5 
   
Depreciation and amortization
 
70.3 
   
62.6 
   
Taxes other than income
 
25.0 
   
22.3 
   
OPERATING INCOME
 
86.8 
   
52.0 
   
OTHER INCOME (EXPENSE)
             
Interest income
 
--- 
   
0.7 
   
Allowance for equity funds used during construction
 
2.3 
   
1.3 
   
Other income
 
3.1 
   
6.5 
   
Other expense
 
(2.4)
   
(2.3)
   
Net other income
 
3.0 
   
6.2 
   
INTEREST EXPENSE
             
Interest on long-term debt
 
33.6 
   
31.4 
   
Allowance for borrowed funds used during construction
 
(1.2)
   
 (1.1)
   
Interest on short-term debt and other interest charges
 
1.7 
   
2.4 
   
Interest expense
 
34.1 
   
32.7 
   
INCOME BEFORE TAXES
 
55.7 
   
25.5 
   
INCOME TAX EXPENSE
 
30.5 
   
7.9 
   
NET INCOME
 
25.2 
   
17.6 
   
Less: Net income attributable to noncontrolling interest
 
1.0 
   
0.8 
   
NET INCOME ATTRIBUTABLE TO OGE ENERGY
$   
24.2 
 
$
16.8 
   
BASIC AVERAGE COMMON SHARES OUTSTANDING
 
97.1 
   
94.7 
   
DILUTED AVERAGE COMMON SHARES OUTSTANDING
 
98.5 
   
95.3 
   
BASIC EARNINGS PER AVERAGE COMMON SHARE
             
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
$   
0.25 
 
$
0.18 
   
DILUTED EARNINGS PER AVERAGE COMMON SHARE
             
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
$   
0.25 
 
$
0.18 
   
DIVIDENDS DECLARED PER SHARE
$   
0.3625 
 
$
0.3550 
   
             







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

 
2

 


OGE ENERGY CORP.
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
       
       
 
March 31,
December 31,
 
 
2010
2009
 
 (In millions)
(Unaudited)
   
             
ASSETS
           
CURRENT ASSETS
           
Cash and cash equivalents
$
5.7
 
$
58.1
 
Accounts receivable, less reserve of $1.9 and $2.4, respectively
 
262.1
   
291.4
 
Accrued unbilled revenues
 
46.3
   
57.2
 
Income taxes receivable
 
76.0
   
157.7
 
Fuel inventories
 
129.3
   
118.5
 
Materials and supplies, at average cost
 
81.7
   
78.4
 
Price risk management
 
4.9
   
1.8
 
Gas imbalances
 
4.4
   
3.2
 
Accumulated deferred tax assets
 
41.4
   
39.8
 
Fuel clause under recoveries
 
0.9
   
0.3
 
Prepayments
 
8.4
   
8.7
 
Other
 
8.7
   
11.0
 
Total current assets
 
669.8
   
826.1
 
             
OTHER PROPERTY AND INVESTMENTS, at cost
 
43.3
   
43.7
 
             
PROPERTY, PLANT AND EQUIPMENT
           
In service
 
8,846.1
   
8,617.8
 
Construction work in progress
 
188.0
   
335.4
 
Total property, plant and equipment
 
9,034.1
   
8,953.2
 
Less accumulated depreciation
 
3,074.5
   
3,041.6
 
Net property, plant and equipment
 
5,959.6
   
5,911.6
 
             
DEFERRED CHARGES AND OTHER ASSETS
           
Income taxes recoverable from customers, net
 
38.8
   
19.1
 
Benefit obligations regulatory asset
 
350.3
   
357.8
 
Price risk management
 
0.4
   
4.3
 
Unamortized loss on reacquired debt
 
16.2
   
16.5
 
Unamortized debt issuance costs
 
14.9
   
15.3
 
Other
 
76.0
   
72.3
 
Total deferred charges and other assets
 
496.6
   
485.3
 
             
TOTAL ASSETS
$
7,169.3
 
$
7,266.7
 
















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

 
3

 

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
     
     
 
March 31,
December 31,
 
2010
2009
 (In millions)
(Unaudited)
 
             
LIABILITIES AND STOCKHOLDERS’ EQUITY
           
CURRENT LIABILITIES
           
Short-term debt
$
341.6 
 
$
175.0 
 
Accounts payable
 
242.0 
   
297.0 
 
Dividends payable
 
35.2 
   
35.1 
 
Customer deposits
 
83.3 
   
85.6 
 
Accrued taxes
 
35.7 
   
37.0 
 
Accrued interest
 
25.7 
   
60.6 
 
Accrued compensation
 
35.4 
   
50.1 
 
Long-term debt due within one year
 
--- 
   
289.2 
 
Price risk management
 
20.1 
   
14.2 
 
Gas imbalances
 
12.1 
   
12.0 
 
Fuel clause over recoveries
 
157.0 
   
187.5 
 
Other
 
32.0 
   
32.4 
 
Total current liabilities
 
1,020.1 
   
1,275.7 
 
             
LONG-TERM DEBT
 
2,204.0 
   
2,088.9 
 
             
DEFERRED CREDITS AND OTHER LIABILITIES
           
Accrued benefit obligations
 
373.0 
   
369.3 
 
Accumulated deferred income taxes
 
1,280.1 
   
1,246.6 
 
Accumulated deferred investment tax credits
 
12.2 
   
13.1 
 
Accrued removal obligations, net
 
173.0 
   
168.2 
 
Price risk management
 
1.4 
   
0.1 
 
Other
 
49.8 
   
44.0 
 
Total deferred credits and other liabilities
 
1,889.5 
   
1,841.3 
 
             
Total liabilities
 
5,113.6 
   
5,205.9 
 
             
COMMITMENTS AND CONTINGENCIES (NOTE 13)
           
             
STOCKHOLDERS’ EQUITY
           
Common stockholders’ equity
 
894.2 
   
887.7 
 
Retained earnings
 
1,216.7 
   
1,227.8 
 
Accumulated other comprehensive loss, net of tax
 
(76.2)
   
(74.7)
 
Total OGE Energy stockholders’ equity
 
2,034.7 
   
2,040.8 
 
Noncontrolling interest
 
21.0 
   
20.0 
 
Total stockholders’ equity
 
2,055.7 
   
2,060.8 
 
             
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
7,169.3 
 
$
7,266.7 
 









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

 
4

 

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS EQUITY
(Unaudited)
             
   
Premium
 
Accumulated
   
   
on
 
Other
   
 
Common
Capital
Retained
Comprehensive
Noncontrolling
 
 
Stock
Stock
Earnings
Income (Loss)
Interest
Total
Balance at December 31, 2008
$         0.9
$     802.0
$   1,107.6 
$              (13.7)
$                17.2
$  1,914.0 
Comprehensive income (loss)
           
Net income for first quarter of 2009
---
---
16.8 
--- 
0.8
17.6 
Other comprehensive income (loss), net of tax
           
 Defined benefit pension plan and restoration of
           
retirement income plan:
           
Amortization of deferred net loss, net of tax ($1.3 pre-
    tax)
 
---
 
---
 
--- 
 
0.8 
 
---
 
0.8 
 Defined benefit postretirement plans:
           
Amortization of deferred net loss, net of tax ($0.2 pre-
    tax)
 
---
 
---
 
--- 
 
0.1 
 
---
 
0.1 
 Deferred hedging losses, net of tax (($46.2) pre-tax)
---
---
--- 
(28.3)
---
(28.3)
 Amortization of cash flow hedge, net of tax ($0.2 pre-tax)
---
---
--- 
0.1 
---
0.1 
Other comprehensive loss
---
---
--- 
(27.3)
---
(27.3)
Comprehensive income (loss)
---
---
16.8 
(27.3)
0.8
(9.7)
Dividends declared on common stock
---
---
(34.2)
--- 
---
(34.2)
Issuance of common stock
0.1
55.7
--- 
--- 
---
55.8 
Balance at March 31, 2009
$         1.0
$     857.7
$   1,090.2 
$              (41.0)
$                18.0
$  1,925.9 
             
Balance at December 31, 2009
$         1.0
$     886.7
$   1,227.8 
$              (74.7)
$                20.0
$  2,060.8 
Comprehensive income
           
Net income for first quarter of 2010
---
---
24.2 
--- 
1.0
25.2 
Other comprehensive income (loss), net of tax
           
 Defined benefit pension plan and restoration of
           
    retirement income plan:
           
Amortization of deferred net loss, net of tax ($1.2 pre-
       tax)
 
---
 
---
 
--- 
 
0.5 
 
---
 
0.5 
 Defined benefit postretirement plans:
           
Amortization of deferred net loss, net of tax ($1.0 pre-
    tax)
 
---
 
---
 
--- 
 
0.6 
 
---
 
0.6 
Amortization of deferred net transition obligation,
    net of tax ($0.2 pre-tax)
 
---
 
---
 
--- 
 
0.2 
 
---
 
0.2 
   Amortization of prior service cost, net of tax (($0.2)
       pre-tax)
 
---
 
---
 
--- 
 
(0.2)
 
---
 
(0.2)
 Deferred hedging losses, net of tax (($4.3) pre-tax)
---
---
--- 
(2.7)
---
(2.7)
 Amortization of cash flow hedge, net of tax ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Other comprehensive loss
---
---
--- 
(1.5)
---
(1.5)
Comprehensive income (loss)
---
---
24.2 
(1.5)
1.0
23.7 
Dividends declared on common stock
---
---
(35.3)
---  
---
(35.3)
Issuance of common stock
---
6.5
--- 
---  
---
6.5 
Balance at March 31, 2010
$         1.0
$     893.2
$   1,216.7 
$              (76.2)
$                21.0
$  2,055.7 
             

 


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


 
5

 


OGE ENERGY CORP.
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
       
 
Three Months Ended
 
 
March 31,
 
 (In millions)
2010
2009
CASH FLOWS FROM OPERATING ACTIVITIES
           
Net income
$
25.2 
 
$
17.6 
 
Adjustments to reconcile net income to net cash provided from
           
operating activities
           
Depreciation and amortization
 
70.3 
   
62.6 
 
Deferred income taxes and investment tax credits, net
 
15.6 
   
18.9 
 
Allowance for equity funds used during construction
 
(2.3)
   
(1.3)
 
Loss on disposition and abandonment of assets
 
0.8 
   
0.2 
 
Stock-based compensation expense
 
2.0 
   
1.4 
 
Stock-based compensation converted to cash for tax withholding
 
(1.6)
   
(1.8)
 
Price risk management assets
 
0.7 
   
(1.3)
 
Price risk management liabilities
 
3.1 
   
(30.4)
 
Other assets
 
4.4 
   
10.6 
 
Other liabilities
 
0.6 
   
(5.0)
 
Change in certain current assets and liabilities
           
Accounts receivable, net
 
29.3 
   
48.7 
 
Accrued unbilled revenues
 
10.9 
   
5.9 
 
Income taxes receivable
 
81.7 
   
--- 
 
Fuel, materials and supplies inventories
 
(14.1)
   
(10.0)
 
Gas imbalance assets
 
(1.2)
   
4.7 
 
Fuel clause under recoveries
 
(0.6)
   
24.0 
 
Other current assets
 
1.8 
   
2.5 
 
Accounts payable
 
(30.4)
   
(60.0)
 
Customer deposits
 
0.4 
   
0.9 
 
Accrued taxes
 
(0.2)
   
(25.9)
 
Accrued interest
 
(34.9)
   
(16.2)
 
Accrued compensation
 
(14.7)
   
(16.0)
 
Gas imbalance liabilities
 
0.1 
   
(8.3)
 
Fuel clause over recoveries
 
(30.5)
   
64.4 
 
Other current liabilities
 
(0.4)
   
(24.8)
 
Net Cash Provided from Operating Activities
 
116.0 
   
61.4 
 
CASH FLOWS FROM INVESTING ACTIVITIES
           
Capital expenditures (less allowance for equity funds used during
           
construction)
 
(135.0)
   
(247.8)
 
Construction reimbursement
 
3.3 
   
2.0 
 
Proceeds from sale of assets
 
1.0 
   
0.1 
 
Other investing activities
 
0.1 
   
--- 
 
Net Cash Used in Investing Activities
 
(130.6)
   
(245.7)
 
CASH FLOWS FROM FINANCING ACTIVITIES
           
Retirement of long-term debt
 
(289.2)
   
---  
 
Dividends paid on common stock
 
(35.1)
   
(33.3)
 
Issuance of common stock
 
4.9 
   
56.1 
 
Proceeds from line of credit
 
115.0 
   
80.0 
 
Increase in short-term debt, net
 
166.6 
   
53.5 
 
Net Cash (Used in) Provided from Financing Activities
 
(37.8)
   
156.3 
 
NET DECREASE IN CASH AND CASH EQUIVALENTS
 
(52.4)
   
(28.0)
 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
 
58.1 
   
174.4 
 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
5.7 
 
$
146.4 
 

 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
 
6

 
OGE ENERGY CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.          Summary of Significant Accounting Policies
 
Organization
 
OGE Energy Corp. (“OGE Energy” and collectively, with its subsidiaries, 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 Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“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 LLC and its subsidiaries (“Enogex”) are providers of integrated natural gas midstream services.  Enogex is engaged in the business of gathering, processing, transporting and storing 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 two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.  Also, Enogex holds a 50 percent ownership interest in the Atoka Midstream, LLC joint venture (“Atoka”) through Enogex Atoka LLC, a wholly-owned subsidiary of Enogex Gathering & Processing LLC.  The Company has consolidated 100 percent of Atoka in its consolidated financial statements as Enogex acts as the managing member of Atoka and has control over the operations of Atoka with a separate presentation for the noncontrolling interest.  Enogex is a Delaware single-member limited liability company.
 
In July 2008, OGE Energy and Electric Transmission America, a joint venture of subsidiaries of American Electric Power and MidAmerican Energy Holdings Co., formed a transmission joint venture, conducting business as Tallgrass Transmission L.L.C. (“Tallgrass”), to construct high-capacity transmission line projects.  The Company owns 50 percent of Tallgrass.  Tallgrass is intended to allow the participating companies to lead development of renewable wind by sharing capital costs associated with transmission construction.
 
The Company charges operating costs to its subsidiaries based on several factors.  Operating costs directly related to specific subsidiaries are assigned to those subsidiaries.  Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits.  Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, based primarily upon head-count, occupancy, usage or the “Distrigas” method.  The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment.  The Company adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff.  The Company believes this method provides a reasonable basis for allocating common expenses.
 
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 (“SEC”).  Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.
 
In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at March 31, 2010 and December 31, 2009 and the results of its operations and cash flows for the three months ended March 31, 2010 and 2009, have been included and are of a normal recurring nature except as otherwise disclosed.
 

 
7

 

Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010 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 Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 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.
 
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:
 
 
March 31,
December 31,
 (In millions)
2010
2009
Regulatory Assets
           
Benefit obligations regulatory asset
$
350.3
 
$
357.8
 
Income taxes recoverable from customers, net
 
38.8
   
19.1
 
Deferred storm expenses
 
30.5
   
28.0
 
Deferred pension plan expenses
 
17.0
   
18.1
 
Unamortized loss on reacquired debt
 
16.2
   
16.5
 
Red Rock deferred expenses
 
7.6
   
7.7
 
Fuel clause under recoveries
 
0.9
   
0.3
 
Miscellaneous
 
2.3
   
3.9
 
Total Regulatory Assets
$
463.6
 
$
451.4
 
             
Regulatory Liabilities
           
Accrued removal obligations, net
$
173.0
 
$
168.2
 
Fuel clause over recoveries
 
157.0
   
187.5
 
Miscellaneous
 
6.6
   
7.3
 
Total Regulatory Liabilities
$
336.6
 
$
363.0
 
 
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 the Company 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; the financial effects of which could be significant.
 
Reclassifications
 
Certain prior year amounts have been reclassified on the Condensed Consolidated Statement of Cash Flows to conform to the 2010 presentation related to a customer’s reimbursement of Enogex’s costs related to the ongoing construction of a transportation pipeline in 2009 and 2010.
 
2.          Accounting Pronouncements
 
In December 2009, the Financial Accounting Standards Board (“FASB”) issued “Consolidations – Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which amends previously issued accounting guidance in this area.  The new standard applies to entities involved with variable interest entities (“VIE”). The new standard changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a reporting entity is required to consolidate another entity is based on, among other things, the other entity’s purpose and design and the reporting entity’s ability to direct the activities of the other entity that most significantly impact the other entity’s economic performance. The new standard
 

 
8

 

requires additional disclosures related to: (i) an entity’s involvement with VIE’s and (ii) any significant changes in risk exposure due to that involvement.  The new standard was effective for fiscal years beginning after November 15, 2009, and interim periods following initial adoption, with earlier application prohibited.  Upon initial application, prior periods are not required to be presented for comparative purposes.  The Company adopted this new standard effective January 1, 2010.  The adoption of this new standard did not have a material impact on the Company’s consolidated financial position or results of operations.
 
In January 2010, the FASB issued “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements,” which requires new disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in previously issued accounting guidance in this area.  The new standard requires additional disclosures related to: (i) the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers and (ii) presenting separate information about purchases, sales, issuances and settlements (on a gross basis) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3).  Also, the new standard clarifies the requirements of previously issued accounting guidance in this area related to: (i) a reporting entity’s need to use judgment in determining the appropriate classes of assets and liabilities and (ii) a reporting entity’s disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements.  The new standard was effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted.  The Company adopted this new standard effective January 1, 2010 and has included the required disclosures in Note 3.
 
In February 2010, the FASB issued “Subsequent Events,” which amends previously issued guidance in this area.  The new standard is applicable to all entities.  The new standard: (i) updates the glossary to include the definition of an SEC filer and to remove the definition of a public entity, (ii) removes the requirement for an SEC filer to disclose the date through which subsequent events have been evaluated and (iii) clarifies that the scope of the reissuance disclosure requirements will include revised financial statements only, which are financial statements revised either as a result of the correction of an error or retrospective application of GAAP.  The new standard does not change the guidance provided in the previous statement related to disclosure requirements for non-SEC filers.  This new standard was effective upon issuance on February 24, 2010, at which time the Company adopted this new standard.
 
3.          Fair Value Measurements
 
The following tables are a summary of the Company’s assets and liabilities that are measured at fair value on a recurring basis at March 31, 2010 and December 31, 2009.
 
 
March 31,
       
(In millions)
2010
Level 1
Level 2
Level 3
 
Assets
                       
Gross commodity contracts
$
87.0
 
$
35.2
 
$
10.8
 
$
41.0
 
Gas imbalance assets (A)
 
4.4
   
---
   
4.4
   
---
 
Total
$
91.4
 
$
35.2
 
$
15.2
 
$
41.0
 
                         
Liabilities
                       
Gross commodity contracts
$
101.0
 
$
32.9
 
$
59.9
 
$
8.2
 
Gas imbalance liabilities (A)(B)
 
8.4
   
---
   
8.4
   
---
 
Total
$
109.4
 
$
32.9
 
$
68.3
 
$
8.2
 
(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 liabilities exclude fuel reserves for over retained fuel due to shippers of approximately $3.7 million, 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.
 
 
 
9

 
 
December 31,
     
(In millions)
2009
Level 1
Level 2
Level 3
Assets
                       
Gross commodity contracts
$
71.3
 
$
16.1
 
$
6.2
 
$
49.0
 
Gas imbalance assets (C)
 
3.2
   
---
   
3.2
   
---
 
Total
$
74.5
 
$
16.1
 
$
9.4
 
$
49.0
 
                         
Liabilities
                       
Gross commodity contracts
$
77.8
 
$
13.3
 
$
49.8
 
$
14.7
 
Gas imbalance liabilities (C)(D)
 
8.0
   
---
   
8.0
   
---
 
Total
$
85.8
 
$
13.3
 
$
57.8
 
$
14.7
 
(C) 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.
(D) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of approximately $4.0 million, 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 three levels defined in the fair value hierarchy and examples of each are as follows:
 
Level 1 inputs are quoted prices in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. An active market for the asset or liability is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.  An example of instruments that may be classified as Level 1 are futures transactions for energy commodities traded on the New York Mercantile Exchange (“NYMEX”).
 
Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in markets that are not active, (iii) inputs other than quoted prices that are observable for the asset or liability or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. An example of instruments that may be classified as Level 2 includes energy commodity purchase or sales transactions in a market such that the pricing is closely related to the NYMEX pricing.
 
Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that observable inputs are not available.  Unobservable inputs shall 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). Unobservable inputs shall be developed based on the best information available in the circumstances, which might include the reporting entity’s own data. The reporting entity’s own data used to develop unobservable inputs shall be adjusted if information is reasonably available that indicates that market participants would use different assumptions. An example of instruments that may be classified as Level 3 includes energy commodity purchase or sales transactions of a longer duration or in an inactive market such that there are no closely related markets in which quoted prices are available.
 
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. Otherwise, they are considered 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 (“Standard & Poor’s”) 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.
 
The following table is a reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at March 31, 2010 and December 31, 2009.
 
 
10

 
 
March 31,
December 31,
(In millions)
2010
2009
Assets
             
Gross commodity contracts
$
87.0
 
$
71.3
   
Less:  Amounts held in clearing broker accounts reflected in Other Current Assets
 
35.6
   
17.3
   
Less:  Amounts offset under master netting agreements
 
46.1
   
47.9
   
  Net Price Risk Management Assets 
$
5.3
 
$
6.1
   
               
Liabilities
             
Gross commodity contracts
$
101.0
 
$
77.8
   
Less:  Amounts held in clearing broker accounts reflected in Other Current Assets
 
33.4
   
15.6
   
Less:  Amounts offset under master netting agreements
 
46.1
   
47.9
   
  Net Price Risk Management Liabilities 
$
21.5
 
$
14.3
   
 
The following table is a summary of the Company’s assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).
 
Assets
Commodity Contracts
(In millions)
2010
2009
Balance at January 1
$
49.0 
 
$
121.2 
 
Transfers into Level 3
 
--- 
   
--- 
 
Transfers out of Level 3
 
--- 
   
--- 
 
Total gains or losses
           
Included in earnings
 
--- 
   
--- 
 
Included in other comprehensive income
 
(3.9)
   
(11.1) 
 
Purchases, issuances, sales and settlements
           
Purchases
 
--- 
   
--- 
 
Issuances
 
--- 
   
--- 
 
Sales
 
--- 
   
--- 
 
Settlements
 
(4.1)
   
(4.5)  
 
Balance at March 31
$
41.0 
 
$
105.6 
 
The amount of total gains or losses for the period included in earnings attributable
           
to the change in unrealized gains or losses relating to assets held at March 31
$
--- 
 
$
---   
 

Liabilities
Commodity Contracts
(In millions)
2010
2009
Balance at January 1
$
14.7 
 
$
--- 
 
Transfers into Level 3
 
--- 
   
--- 
 
Transfers out of Level 3
 
--- 
   
--- 
 
Total gains or losses
           
Included in earnings
 
--- 
   
--- 
 
Included in other comprehensive income
 
(5.1)
   
--- 
 
Purchases, issuances, sales and settlements
           
Purchases
 
--- 
   
--- 
 
Issuances
 
--- 
   
--- 
 
Sales
 
--- 
   
--- 
 
Settlements
 
(1.4)
   
--- 
 
Balance at March 31
$
8.2 
 
$
--- 
 
The amount of total gains or losses for the period included in earnings attributable
           
to the change in unrealized gains or losses relating to liabilities held at March 31
$
--- 
 
$
--- 
 
 
Gains and losses (realized and unrealized) included in earnings for the three months ended March 31, 2010 and 2009 attributable to the change in unrealized gains or losses relating to assets and liabilities held at March 31, 2010 and 2009, if any, are reported in Operating Revenues.
 

 
11

 

 
The following table is a summary of the fair value and carrying amount of the Company’s financial instruments, including derivative contracts related to the Company’s Price Risk Management (“PRM”) activities at March 31, 2010 and December 31, 2009.
 
   
March 31, 2010
 
December 31, 2009
 
   
Carrying
Fair
 
Carrying
Fair
 
(In millions)
Amount
Value
 
Amount
Value
 
                           
Price Risk Management Assets
                         
Energy Derivative Contracts
$
5.3
 
$
5.3
   
$
6.1
 
$
6.1
 
                           
Price Risk Management Liabilities
                         
Energy Derivative Contracts
$
21.5
 
$
21.5
   
$
14.3
 
$
14.3
 
                           
Long-Term Debt
                         
OG&E Senior Notes
$
1,406.4
 
$
1,477.2
   
$
1,406.4
 
$
1,492.1
 
OGE Energy Senior Notes
 
99.6
   
104.8
     
99.5
   
102.6
 
OG&E Industrial Authority Bonds
 
135.4
   
135.4
     
135.4
   
135.4
 
Enogex Senior Notes
 
447.6
   
462.6
     
736.8
   
746.7
 
Enogex Revolving Credit Agreement
 
115.0
   
115.0
     
---
   
---
 

The carrying value of the financial instruments on the Condensed Consolidated Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount.  The valuation of the Company’s hedging and 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 management’s estimate of current rates available for similar issues with similar maturities.
 
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. The commodity price swap contracts involve the exchange of fixed price or rate payments for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity.  The commodity price option contracts involve the payment of a premium for the right, but not the obligation, to exchange fixed price or rate payments for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity.  Commodity derivative instruments used by the Company are as follows:
 
Ÿ  
natural gas liquids (“NGL”) put options and NGLs swaps are used to manage Enogex’s NGLs exposure associated with its processing agreements;
Ÿ  
natural gas swaps are used to manage Enogex’s keep-whole natural gas exposure associated with its processing agreements and Enogex’s natural gas exposure associated with operating its gathering, transportation and storage assets;
Ÿ  
natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OGE Energy’s natural gas marketing subsidiary, OGE Energy Resources, Inc.’s (“OERI”), natural gas exposure associated with its storage and transportation contracts; and
Ÿ  
natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage OERI’s marketing and trading activities.
 
Management may designate certain derivative instruments for the purchase or sale of physical commodities, purchase or sale of electric power and fuel procurement discussed above as normal purchases and normal sales contracts.  Normal purchases and normal sales contracts are not recorded in PRM assets or liabilities in the Condensed Consolidated Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs.
 

 
12

 

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 its 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.
 
Interest Rate Risk
 
The Company’s exposure to changes in interest rates primarily relates to short-term variable debt, treasury lock agreements and commercial paper.  The Company from time to time uses treasury lock agreements to manage its interest rate risk exposure on new debt issuances. Additionally, the Company manages its interest rate exposure by limiting its variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates.  The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce interest expense related to existing debt issues.  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.  Under the change in fair value method, 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. The ineffectiveness of treasury lock cash flow hedges is measured using the hypothetical derivative method.  Under the hypothetical derivative method, the Company designates that the critical terms of the hedging instrument are the same as the critical terms of the hypothetical derivative used to value the forecasted transaction, and, as a result, no ineffectiveness is expected.  Forecasted transactions 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.  If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.
 
At March 31, 2010 and December 31, 2009, the Company had no outstanding treasury lock agreements that were designated as cash flow hedges.
 

 
13

 

The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex’s contractual long/short positions and operational storage natural gas, keep-whole natural gas and NGLs hedges.  Enogex’s cash flow hedging activity at March 31, 2010 covers the period from April 1, 2010 through December 31, 2011.  The Company also designates certain derivatives used to manage commodity exposure for certain transportation and natural gas inventory positions at OERI. OERI does not have any derivative instruments designated as cash flow hedges at March 31, 2010.  At March 31, 2010, the Company had the following outstanding commodity derivative instruments that were designated as cash flow hedges.
 
   
Notional
 
 
Commodity
Volume (A)
Maturity
 
(volumes in millions)
Short Financial Swaps/Futures (fixed)
NGLs
 
0.4
 
Current
           
Purchased Financial Options
NGLs
 
1.3
 
Current
Purchased Financial Options
NGLs
 
1.0
 
Non-Current
Total Purchased Financial Options
   
2.3
   
           
Long Financial Swaps/Futures (fixed)
Natural Gas
 
6.0
 
Current
Long Financial Swaps/Futures (fixed)
Natural Gas
 
3.9
 
Non-Current
Total Long Financial Swaps/Futures (fixed)
   
9.9
   
           
Short Financial Swaps/Futures (fixed)
Natural Gas
 
1.4
 
Current
           
Short Financial Basis Swaps
Natural Gas
 
1.4
 
Current
(A) Natural gas in million British thermal unit (“MMBtu”); NGLs in barrels. All volumes are presented on a gross basis.
 
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 March 31, 2010 and December 31, 2009, the Company had no outstanding commodity derivative instruments or treasury lock agreements that were designated as fair value hedges.
 
Derivatives Not Designated As Hedging Instruments
 
For derivative instruments not designated as either a cash flow or fair value hedge, the gain or loss on the derivative is recognized currently in earnings. Derivative instruments not designated as either a cash flow or a fair value hedge are utilized in OERI’s asset management, marketing and trading activities.  Derivative instruments not designated as either cash flow or fair value hedges also include contracts formerly designated as cash flow hedges of Enogex’s NGLs, keep-whole natural gas and operational storage natural gas exposures.  A portion of Enogex’s processing agreements, which were previously under keep-whole arrangements, were converted to fee-based arrangements.  As a result, effective June 30, 2009 Enogex de-designated a portion of these derivatives and entered into offsetting derivatives to close the positions. Also, effective November 12, 2009, in response to market opportunities Enogex elected to de-designate its operational storage hedges and entered into offsetting derivatives to close the positions.
 
At March 31, 2010, the Company had the following outstanding commodity derivative instruments that were not designated as either a cash flow or fair value hedge.
 
 
14

 
   
Notional
 
 
Commodity
Volume (A)
Maturity
 
(volumes in millions)
Short Financial Swaps/Futures (fixed)
NGLs
 
0.6
 
Current
           
Long Financial Swaps/Futures (fixed)
NGLs
 
0.6
 
Current
           
Physical Purchases (B)
Natural Gas
 
26.0
 
Current
Physical Purchases (B)
Natural Gas
 
4.0
 
Non-Current
Total Physical Purchases
   
30.0
   
           
Physical Sales (B)
Natural Gas
 
26.9
 
Current
Physical Sales (B)
Natural Gas
 
 9.6
 
Non-Current
Total Physical Sales
   
36.5
   
           
Long Financial Swaps/Futures (fixed)
Natural Gas
 
31.5
 
Current
Long Financial Swaps/Futures (fixed)
Natural Gas
 
1.0
 
Non-Current
Total Long Financial Swaps/Futures (fixed)
   
32.5
   
           
Short Financial Swaps/Futures (fixed)
Natural Gas
 
30.6
 
Current
Short Financial Swaps/Futures (fixed)
Natural Gas
 
2.7
 
Non-Current
Total Short Financial Swaps/Futures (fixed)
   
33.3
   
           
Purchased Financial Option
Natural Gas
 
22.0
 
Current
           
Sold Financial Option
Natural Gas
 
21.5
 
Current
           
Long Financial Basis Swaps
Natural Gas
 
11.6
 
Current
Long Financial Basis Swaps
Natural Gas
 
 1.0
 
Non-Current
Total Long Financial Basis Swaps
   
12.6
   
           
Short Financial Basis Swaps
Natural Gas
 
8.7
 
Current
Short Financial Basis Swaps
Natural Gas
 
1.0
 
Non-Current
Total Short Financial Basis Swaps
   
9.7
   
(A) Natural gas in MMBtu; NGLs in barrels. All volumes are presented on a gross basis.
(B) Of the natural gas physical purchases and sales volumes not designated as cash flow or fair value 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.
 
The fair value of the derivative instruments that are presented in the Company’s Condensed Consolidated Balance Sheet at March 31, 2010 are as follows:
 
 
Fair Value
     
Balance Sheet
       
Instrument
Commodity
 
Location
 
Assets
 
Liabilities
(dollars in millions)
Derivatives Designated as Hedging Instruments 
                   
Financial Options                                          
NGLs
 
Current PRM
$
18.5
 
$
---
 
     
Non-Current PRM
 
17.0
   
---
 
Financial Futures/Swaps                                         
NGLs
 
Current PRM
 
---
   
2.4
 
Financial Futures/Swaps                                         
Natural Gas
 
Current PRM
 
---
   
24.1
 
     
Non-Current PRM
 
---
   
18.4
 
     
Other Current Assets
 
5.3
   
0.2
 
Total Gross Derivatives Designated as Hedging Instruments
$
40.8
 
$
45.1
 
(A)  
 

 
15

 


Derivatives Not Designated as Hedging Instruments 
               
Financial Futures/Swaps (A)
NGLs
 
Current PRM
$
5.5
 
$
5.8
 
Financial Futures/Swaps (B)
Natural Gas
 
Current PRM
 
5.1
   
14.9
 
     
Other Current Assets
 
28.4
   
31.6
 
Physical Purchases/Sales                                         
Natural Gas
 
Current PRM
 
4.9
   
2.0
 
     
Non-Current PRM
 
0.4
   
---
 
Financial Options                                         
Natural Gas
 
Other Current Assets
 
1.9
   
1.6
 
Total Gross Derivatives Not Designated as Hedging Instruments
$
46.2
 
$
55.9
 
Total Gross Derivatives (C)
$
87.0
 
$
101.0
 
(A)
The fair value of Financial Futures/Swaps – NGLs not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated and off-setting derivatives were entered to close the hedge positions.  The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $5.5 million and Current Liabilities of approximately $5.8 million.
(B)
The fair value of Financial Futures/Swaps – Natural Gas not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated and off-setting derivatives were entered to close the hedge positions.  The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $4.7 million and Current Liabilities of approximately $14.0 million.
(C)
See reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at March 31, 2010 (see Note 3).
 
Credit-Risk Related Contingent Features in Derivative Instruments
 
In the event Moody’s Investors Service or Standard & Poor’s were to lower the Company’s senior unsecured debt rating to a below investment grade rating, at March 31, 2010, the Company would have been required to post approximately $18.0 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 March 31, 2010.  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.
 
The following table presents the effect of derivative instruments on the Company’s Condensed Consolidated Statement of Income for the three months ended March 31, 2010.
 
         
Amount of
         
Gain or Loss
     
Amount of
Location of Gain or
Recognized
     
Gain or Loss
Loss Recognized in
in Income on
 
Amount of Gain
 
Reclassified
Income on
Derivative
 
 
or Loss
 
from
Derivative
(Ineffective
 
 
Recognized in
Location of Gain or
Accumulated
(Ineffective Portion
Portion and
 
 
OCI on
Loss Reclassified
OCI into
and Amount
Amount
 
 
Derivative
from Accumulated
Income
Excluded from
Excluded from
 
 
(Effective
OCI into Income
(Effective
Effectiveness
Effectiveness
 
Instrument
Portion)(A)
(Effective Portion)
Portion)
Testing)
Testing)
 
(dollars in millions)
 
Derivatives in Cash Flow Hedging Relationships
 
NGLs Financial Options
$
0.5
 
Operating Revenues
$
(0.6)
 
Operating Revenues
$
---
   
NGLs Financial
                       
Futures/Swaps
 
1.3
 
Operating Revenues
 
(1.4)
 
Operating Revenues
 
---
   
Natural Gas Financial
                       
Futures/Swaps
 
(9.9)
 
Operating Revenues
 
(3.3)
 
Operating Revenues
 
0.1
   
Total
$
(8.1)
 
Total
$
(5.3)
 
Total
$
0.1
   
(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at March 31, 2010 that is expected to be reclassified into  earnings within the next 12 months is a loss of approximately $25.9 million.

 
16

 


   
Amount of Gain or
 
Location of Gain or
Loss Recognized in
 
Loss Recognized in
Income of
 
Income on Derivative
Derivative
   
(dollars in millions)
Derivatives Not Designated as Hedging Instruments
     
       
Natural Gas Physical Purchases/Sales
Operating Revenues
$
(0.1)
 
Natural Gas Financial Futures/Swaps
Operating Revenues
 
0.7 
 
Total
$
0.6 
 
 
Contracts with Master Netting Arrangements
 
Fair value amounts recognized for forward, interest rate swap, currency 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, currency 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.
 
5.          Stock-Based Compensation
 
On January 21, 1998, the Company adopted a Stock Incentive Plan (the “1998 Plan”) and in 2003, the Company adopted another Stock Incentive Plan (the “2003 Plan” that replaced the 1998 Plan).  In 2008, the Company adopted, and its shareowners approved, a new Stock Incentive Plan (the “2008 Plan” and together with the 1998 Plan and the 2003 Plan, the “Plans”).  The 2008 Plan replaced the 2003 Plan and no further awards will be granted under the 2003 Plan or the 1998 Plan. As under the 2003 Plan and the 1998 Plan, under the 2008 Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of the Company and its subsidiaries.  The Company has authorized the issuance of up to 2,750,000 shares under the 2008 Plan.
 
The Company recorded compensation expense of approximately $2.1 million pre-tax ($1.3 million after tax, or $0.01 per basic and diluted share) and approximately $1.4 million pre-tax ($0.8 million after tax, or $0.01 per basic and diluted share) during the three months ended March 31, 2010 and 2009, respectively, related to the Company’s share-based payments.
 
During the three months ended March 31, 2010, the Company awarded 213,533 performance units based on total shareholder return and 71,179 performance units based on earnings per share with a grant date fair value of $39.43 and $32.44, respectively, to certain employees of the Company and its subsidiaries.  Also, during the three months ended March 31, 2010, the Company converted 105,103 performance units based on a payout ratio of 120.69 percent of the target number of performance units granted in February 2007.
 
The Company issues new shares to satisfy stock option exercises and payouts of earned performance units.  During the three months ended March 31, 2010, there were 138,933 shares of new common stock issued pursuant to the Company’s Plans related to exercised stock options and payouts of earned performance units. The Company received approximately $1.2 million during the three months ended March 31, 2010 related to exercised stock options.  There were no exercised stock options during the three months ended March 31, 2009.
 

 
17

 

6.          Accumulated Other Comprehensive Income (Loss)
 
The components of accumulated other comprehensive loss at March 31, 2010 and December 31, 2009 are as follows:
 
 
March 31,
December 31,
(In millions)
2010
2009
Defined benefit pension plan and restoration of retirement income plan:
           
Net loss, net of tax (($64.4) and ($65.6) pre-tax, respectively)
$
(39.5)
 
$
(40.0)
 
Prior service cost, net of tax (($1.0) and ($1.1) pre-tax, respectively)
 
(0.7)
   
(0.7)
 
Defined benefit postretirement plans:
           
Net loss, net of tax (($20.8) and ($21.2) pre-tax, respectively)
 
(10.1)
   
(10.7)
 
Net transition obligation, net of tax (($0.4) and ($0.6) pre-tax, respectively)
 
(0.2)
   
(0.4)
 
Prior service cost, net of tax (($0.3) and ($0.1) pre-tax, respectively)
 
(0.2)
   
--- 
 
Deferred hedging gains (losses), net of tax (($39.8) and ($35.5) pre-tax,
           
respectively)
 
(24.4)
   
(21.7)
 
Deferred hedging losses on interest rate swaps, net of tax (($1.8) and ($1.9) pre-
           
tax, respectively)
 
(1.1)
   
(1.2)
 
Total accumulated other comprehensive loss, net of tax
$
(76.2)
 
$
(74.7)
 
 
7.         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 2006 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.  The Company continues to amortize its Federal investment tax credits on a ratable basis throughout the year.  This ratable amortization results in a larger percentage reconciling item related to these credits during the first quarter when the Company historically experiences decreased book income.  OG&E earns both Federal and Oklahoma state tax credits associated with the production from its 120 megawatt (“MW”) wind farm in northwestern Oklahoma and its 101 MW OU Spirit wind farm in western Oklahoma (“OU Spirit”).  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.
 
The Company estimated a Federal tax net operating loss for 2009 primarily caused by the accelerated tax depreciation provisions contained within the American Recovery and Reinvestment Act of 2009 (“ARRA”).  ARRA allowed a current deduction for 50 percent of the cost of certain property placed into service during 2009.  This tax loss resulted in an approximate $68 million current income tax receivable related to the 2009 tax year.  On November 6, 2009, the Worker, Homeownership, and Business Assistance Act of 2009 was signed into law by the President.  This new law provided for a five-year carry back of net operating losses incurred in 2008 or 2009.  This expanded carryback period enabled the Company to carry back the entire 2009 tax loss. A carryback claim was filed in March 2010 and a refund of approximately $68 million was received by the Company in April 2010.
 
Medicare Part D Subsidy
 
On March 23, 2010, the Patient Protection and Affordable Care Act of 2009 (the “Patient Protection Act”) was signed into law, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (the “Reconciliation Act” and, together with Patient Protection Act, the “Acts”), which makes various amendments to certain aspects of the Patient Protection Act, was signed into law.  The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D.
 
The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Medicare Act”).  The Company has been recognizing the federal subsidy since 2005 related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the Medicare Act, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually.

 
18

 


Under the Acts, beginning in 2013 an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in earnings in the period enacted regardless of the effective date.  As retiree healthcare liabilities and related tax impacts are already reflected in the Company’s Condensed Consolidated Financial Statements, the Company recognized a one-time, non-cash charge of approximately $11.4 million, or $0.11 per diluted share, during the quarter ended March 31, 2010 for the write-off of previously recognized tax benefits relating to Medicare Part D subsidies to reflect the change in the tax treatment of the federal subsidy.
 
8.           Common Equity
 
Automatic Dividend Reinvestment and Stock Purchase Plan
 
In November 2008, the Company filed a Form S-3 Registration Statement to register 5,000,000 shares of the Company’s common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”).  The Company issued 101,745 shares of common stock under its DRIP/DSPP during the three months ended March 31, 2010 and received proceeds of approximately $3.7 million.  The Company may, from time to time, issue additional shares under its DRIP/DSPP to fund capital requirements or working capital needs.
 
At March 31, 2010, there were 2,890,999 shares of unissued common stock reserved for issuance under the Company’s DRIP/DSPP.
 
Earnings Per Share
 
Outstanding shares for purposes of basic and diluted earnings per average common share were calculated as follows:
 
 
Three Months Ended
 
March 31,
(In millions)
2010
2009
Average Common Shares Outstanding
           
Basic average common shares outstanding
 
97.1
   
94.7
 
Effect of dilutive securities:
           
Contingently issuable shares (performance units)
 
1.4
   
0.6
 
Diluted average common shares outstanding
 
98.5
   
95.3
 
Anti-dilutive shares excluded from EPS calculation
 
---
   
---
 

9.         Long-Term Debt
 
At March 31, 2010, the Company was in compliance with all of its debt agreements.
 
OG&E has three series of variable-rate industrial authority bonds (the “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 (dollars in millions):
 
SERIES
DATE DUE
AMOUNT
0.30% - 0.40%
Garfield Industrial Authority, January 1, 2025                                                                                
$
47.0
 
0.35% - 0.52%
Muskogee Industrial Authority, January 1, 2025                                                                                
 
32.4
 
0.33% - 0.49%
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-
 

 
19

 

term debt in the Company’s Condensed Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.
 
10.       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 approximately $341.6 million and $175.0 million at March 31, 2010 and December 31, 2009, respectively.  The following table provides information regarding the Company’s revolving credit agreements and available cash at March 31, 2010.
 
Revolving Credit Agreements and Available Cash (In millions)
 
Aggregate
Amount
Weighted-Average
 
Entity
Commitment 
Outstanding (A)
Interest Rate
Maturity
OGE Energy (B)
$
596.0
 
$
341.6
 
0.29% (D)
December 6, 2012
OG&E (C)
 
389.0
   
9.5
 
  --- % (D)
December 6, 2012
Enogex (E)
 
250.0
   
115.0
 
0.54% (D)
March 31, 2013
   
1,235.0
   
466.1
 
0.35%     
 
Cash
 
5.7
   
N/A
 
N/A      
N/A
Total
$
1,240.7
 
$
466.1
 
0.35%     
 
(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2010.
(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 March 31, 2010, there were no outstanding borrowings under this revolving credit agreement and approximately $341.6 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 March 31, 2010, there was approximately $9.5 million supporting letters of credit.  There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at March 31, 2010.
(D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements and commercial paper borrowings.
(E) This bank facility is available to provide revolving credit borrowings for Enogex.  As Enogex’s credit agreement matures on March 31, 2013, borrowings thereunder are classified as long-term debt in the Company’s Condensed Consolidated Balance Sheets.
 
OGE Energy’s and OG&E’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 back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrades of the ratings of OGE Energy or OG&E would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade of the Company would 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.
 
Unlike OGE Energy and Enogex, 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, 2009 and ending December 31, 2010.
 

 
20

 

11.       Retirement Plans and Postretirement Benefit Plans
 
The details of net periodic benefit cost of the 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
Three Months Ended
 
March 31,
March 31,
 (In millions)
2010
  2009
2010
2009
Service cost
$
4.4 
 
$
4.5 
 
$
0.2
 
$
0.2 
 
Interest cost
 
7.8 
   
7.8 
   
0.1
   
0.1 
 
Return on plan assets
 
(10.7)
   
(8.2)
   
---
   
 --- 
 
Amortization of net loss
 
5.1 
   
5.9 
   
0.1
   
  0.1 
 
Amortization of unrecognized prior service cost
 
0.6 
   
0.2 
   
0.1
   
  0.1 
 
Net periodic benefit cost (A)
$
7.2 
 
$
10.2 
 
$
0.5
 
$
0.5 
 
 (A) In addition to the approximately $7.7 million and $10.7 million of net periodic benefit cost recognized during the three months ended March 31, 2010 and 2009, respectively, the Company recognized an increase in pension expense during the three months ended March 31, 2010 of approximately $1.9 million and a reduction in pension expense of approximately $1.1 million during the three months ended March 31, 2009 to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are identified as Deferred Pension Plan Expenses (see Note 1).

 
Postretirement Benefit Plans
 
Three Months Ended
 
March 31,
 (In millions)
2010
2009
Service cost
$
1.2 
$
0.8 
 
Interest cost
 
4.2 
 
3.5 
  
Return on plan assets
 
(1.7)
 
(1.6)
 
Amortization of transition obligation
 
0.7 
 
0.7 
 
Amortization of net loss
 
2.7 
 
1.2 
 
Amortization of unrecognized prior service cost
 
--- 
 
0.3 
 
Net periodic benefit cost
$
7.1 
$
4.9 
 
 
Pension Plan Funding
 
The Company previously disclosed in its 2009 Form 10-K that it may contribute up to $50 million to its pension plan during 2010.  In April 2010, the Company contributed approximately $20 million to its pension plan and currently expects to contribute an additional $30 million to its pension plan during the remainder of 2010.  Any remaining expected contributions to its pension plan during 2010 would be discretionary contributions, anticipated to be in the form of cash, and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended.
 

 
21

 

12.       Report of Business Segments
 
The Company’s business is divided into four segments for financial reporting purposes. These segments are 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 for the three months ended March 31, 2010 and 2009.
 
   
Transportation
Gathering
       
Three Months Ended
Electric
and
and
 
Other
   
March 31, 2010
Utility
Storage
Processing
Marketing
Operations
Eliminations
Total
(In millions)
                           
                             
Operating revenues
$
444.0
$
111.1
$
247.9
$
245.7 
$
--- 
$
(172.9)
$
875.8
Cost of goods sold
 
250.8
 
66.2
 
180.0
 
244.3 
 
--- 
 
(171.2)
 
570.1
Gross margin on revenues
 
193.2
 
44.9
 
67.9
 
1.4 
 
--- 
 
(1.7)
 
305.7
Other operation and maintenance
 
93.9
 
11.0
 
21.3
 
2.7 
 
(4.1)
 
(1.2)
 
123.6
Depreciation and amortization
 
49.7
 
5.4
 
12.4
 
--- 
 
2.8 
 
--- 
 
70.3
Taxes other than income
 
17.7
 
3.9
 
1.9
 
0.2 
 
1.3 
 
--- 
 
25.0
Operating income (loss)
$
31.9
$
24.6
$
32.3
$
(1.5)
$
--- 
$
(0.5)
$
86.8
                             
Total assets
$
5,421.6
$
1,503.0
$
876.5
$
122.9 
$
2,654.8 
$
(3,409.5)
$
7,169.3

   
Transportation
Gathering
       
Three Months Ended
Electric
and
and
 
Other
   
March 31, 2009
Utility
Storage
Processing
Marketing
Operations
Eliminations
Total
(In millions)
                           
                             
Operating revenues
$
336.7
$
108.3
$
138.5
$
192.3
$
--- 
$
(169.2)
$
606.6
Cost of goods sold
 
171.0
 
66.2
 
96.1
 
187.8
 
--- 
 
(167.9)
 
353.2
Gross margin on revenues
 
165.7
 
42.1
 
42.4
 
4.5
 
--- 
 
(1.3)
 
253.4
Other operation and maintenance
 
85.3
 
9.9
 
23.1
 
2.6
 
(3.3)
 
(1.1)
 
116.5
Depreciation and amortization
 
45.5
 
4.7
 
10.1
 
---
 
2.3 
 
--- 
 
62.6
Taxes other than income
 
16.1
 
3.6
 
1.3
 
0.2
 
1.1 
 
--- 
 
22.3
Operating income (loss)
$
18.8
$
23.9
$
7.9
$
1.7
$
(0.1)
$
(0.2)
$
52.0
                             
Total assets
$
4,963.2
$
1,348.0
$
846.0
$
176.8
$
2,461.6 
$
(3,188.1)
$
6,607.5
 
13.       Commitments and Contingencies
 
Except as set forth below and in Note 14, the circumstances set forth in Notes 13 and 14 to the Company’s Consolidated Financial Statements included in the Company’s 2009 Form 10-K appropriately represent, in all material respects, the current status of the Company’s material commitments and contingent liabilities.
 
OG&E Railcar Lease Agreement
 
At March 31, 2010, OG&E had a noncancellable operating lease with purchase options, covering 1,462 coal hopper railcars to transport coal from Wyoming to OG&E’s coal-fired generation units.  Rental payments are charged to Fuel Expense and are recovered through OG&E’s tariffs and fuel adjustment clauses.  At the end of the lease term, which is January 31, 2011, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease.  If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of approximately $31.5 million.
 
On February 10, 2009, OG&E executed a short-term lease agreement for 270 railcars in accordance with new coal transportation contracts with BNSF Railway and Union Pacific.  These railcars were needed to replace railcars that have been taken out of service or destroyed.  The lease agreement expired with respect to 135 railcars on November 2, 2009 and was not
 

 
22

 

replaced.  The lease agreement with respect to the remaining 135 railcars expired on March 5, 2010 and is now continuing on a month-to-month basis with a 30-day notice required by either party to terminate the agreement.
 
OG&E is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.
 
Oxley Litigation
 
OG&E has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma.  This case has been pending for more than 11 years.  The plaintiffs alleged that OG&E breached the terms of contracts covering several wells by failing to purchase gas from the plaintiffs in amounts set forth in the contracts.  The plaintiffs’ most recent Statement of Claim describes approximately $2.7 million in take-or-pay damages  (including interest) and approximately $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, OG&E agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, OG&E will only be liable for the amount, if any, of an arbitration award in excess of $5.8 million. The arbitration hearing was completed recently and the final briefs were provided to the arbitration panel on March 17, 2010.  A ruling by the panel is expected in the second quarter of 2010.  While the Company cannot predict the precise outcome of the arbitration, based on the information known at this time, OG&E believes that this lawsuit will not have a material adverse effect on the Company’s consolidated financial position or results of operations.
 
Natural Gas Measurement Cases
 
Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I).  On September 24, 1999, various subsidiaries of the Company were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands.  On April 10, 2003, the court entered an order denying class certification.  On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003.  In its amended petition (the “Fourth Amended Petition”), OG&E and Enogex Inc. were omitted from the case but two of the Company’s other subsidiary entities remained as defendants.  The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of the Company’s subsidiary entities, have improperly measured the volume of natural gas.  The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment.  In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion.  The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest.  The plaintiffs also reserved the right to seek punitive damages.
 
Discovery was conducted on the class certification issues, and the parties fully briefed these same issues.  A hearing on class certification issues was held April 1, 2005.  In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action.  The court has not yet ruled on the motion to intervene.
 
The class certification issues were briefed and argued by the parties in 2005 and proposed findings of facts and conclusions of law on class certification were filed in 2007.  On September 18, 2009, the court entered its order denying class certification.  On October 2, 2009, the plaintiffs filed for a rehearing of the court’s denial of class certification. On February 10, 2010 the court heard arguments on the rehearing request and by an order dated March 31, 2010, the court denied the plaintiffs’ request for rehearing.
 
The Company intends to vigorously defend this action.  At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.
 
Will Price, et al. v. El Paso Natural Gas Co., et al. (Price II).  On May 12, 2003, the plaintiffs (same as those in the Fourth Amended Petition in Price I above) filed a new class action petition in the District Court of Stevens County, Kansas naming the same defendants and asserting substantially identical legal and/or equitable theories as in the Fourth Amended Petition of the Price I case.  OG&E and Enogex Inc. were not named in this case, but two subsidiary entities of the Company were named in this case.  The plaintiffs allege that the defendants mismeasured the Btu content of natural gas obtained from or measured for the plaintiffs.  In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion.  The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest.  The plaintiffs also reserved the right to seek punitive damages.
 

 
23

 

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues.  A hearing on class certification issues was held April 1, 2005.  In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action.  The court has not yet ruled on the motion to intervene.
 
The class certification issues were briefed and argued by the parties in 2005 and proposed findings of facts and conclusions of law on class certification were filed in 2007.  On September 18, 2009, the court entered its order denying class certification.  On October 2, 2009, the plaintiffs filed for a rehearing of the court’s denial of class certification. On February 10, 2010 the court heard arguments on the rehearing request and by an order dated March 31, 2010, the court denied the plaintiffs’ request for rehearing.
 
The Company intends to vigorously defend this action.  At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.
 
Pipeline Rupture
 
On November 14, 2008, a natural gas gathering pipeline owned by Enogex ruptured in Grady County, near Alex, Oklahoma, resulting in a fire that caused injuries to one resident and destroyed three residential structures.  After the incident, Enogex coordinated and assisted the affected residents.  Enogex resolved matters with two of the residents and Enogex continued to seek resolution with a remaining resident.  This resident filed a legal action in May 2009 in the District Court of Cleveland County, Oklahoma, against OGE Energy and Enogex.  This matter was resolved by the parties on April 8, 2010.  The ultimate resolution of this incident was not material to the Company in light of previously established reserves and insurance coverage.
 
Franchise Fee Lawsuit 
 
On June 19, 2006, two OG&E customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on OG&E’s electric bills.  The plaintiffs claim that OG&E improperly charged sales tax based on franchise fee charges paid by its customers.  The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law. OG&E’s motion for summary judgment was denied by the trial judge.  OG&E filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit.  In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC.  In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorizes OG&E to collect the challenged franchise fee charges.  On March 10, 2009, the Oklahoma Attorney General, OG&E, OG&E Shareholders Association and the Staff of the Public Utility Division of the OCC all filed briefs arguing that the application should be dismissed.  On December 9, 2009 the OCC issued an order dismissing the plaintiffs’ request for a modification of the 1994 OCC order which authorized OG&E to collect and remit sales tax on franchise fee charges. In its December 9, 2009 order, the OCC advised the plaintiffs that the ruling does not address the question of whether OG&E’s collection and remittance of such sales tax should be discontinued prospectively. On December 21, 2009, the plaintiffs filed a motion at the Oklahoma Supreme Court asking the court to deny OG&E’s writ of prohibition and to remand the cause to the District Court. On December 29, 2009, the Oklahoma Supreme Court declared the plaintiffs’ motion moot. On January 27, 2010, the OCC Staff filed a motion asking the OCC to dismiss the cause and close the cause at the OCC.  On April 19, 2010, the OCC issued a final order dismissing with prejudice the applicants’ claims for recovery of previously paid taxes on franchise fees and approving the closing of this matter.
 
Environmental Matters
 
Water
 
OG&E filed Oklahoma Pollutant Discharge Elimination permit renewal applications for its Muskogee, Mustang and Horseshoe Lake generating stations on March 4, 2009, April 3, 2009 and October 29, 2009, respectively, and have received draft permits for review. Preliminary comments have been submitted to the Oklahoma Department of Environmental Quality for OG&E’s Mustang and Horseshoe Lake generating stations. The Muskogee generating station draft permit is currently being reviewed.
 

 
24

 

Other
 
In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability.  These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies.  When appropriate, management consults with legal counsel and other appropriate experts to assess the claim.  If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Condensed Consolidated Financial Statements.  Except as otherwise stated above, in Note 14 below, in Item 1 of Part II of this Form 10-Q, in Notes 13 and 14 of Notes to the Company’s Consolidated Financial Statements included in the Company’s 2009 Form 10-K and in Item 3 of that report, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.
 
14.       Rate Matters and Regulation
 
Except as set forth below, the circumstances set forth in Note 14 to the Company’s Consolidated Financial Statements included in the Company’s 2009 Form 10-K appropriately represent, in all material respects, the current status of any regulatory matters.
 
Completed Regulatory Matters
 
OG&E Windspeed Transmission Line Project
 
OG&E filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma (“Windspeed”). The OCC subsequently authorized recovery at a construction cost of up to approximately $218 million, including allowance for funds used during construction (“AFUDC”).  At March 31, 2010, the construction costs and AFUDC incurred for the Windspeed transmission line were approximately $200.3 million and the final costs are expected to be less than $218 million.  The Windspeed transmission line was placed into service on March 31, 2010, with the recovery rider being implemented with the first billing cycle in April 2010.
 
Pending Regulatory Matters
 
OG&E Smart Grid Application
 
In February 2009, the ARRA was enacted into law. Several provisions of this law relate to issues of direct interest to the Company including, in particular, financial incentives to develop smart grid technology, transmission infrastructure and renewable energy.  After review of the ARRA, OG&E filed a grant request on August 4, 2009 for $130 million with the U.S. Department of Energy (“DOE”) to be used for the Smart Grid application in OG&E’s service territory.  On October 27, 2009, OG&E received notification from the DOE that its grant had been accepted by the DOE for the full requested amount of $130 million, which will not be subject to income tax.  Receipt of the grant monies was contingent upon successful negotiations with the DOE on final details of the award.  On April 21, 2010, OG&E and the DOE entered into a definitive agreement with regards to the award.  On March 15, 2010, OG&E filed an application with the OCC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant.  A procedural schedule has not been established in this matter.
 
Separately, on November 30, 2009, OG&E requested a grant with a 50 percent match of up to $5 million for a variety of types of smart grid training for OG&E’s workforce.  In April 2010, OG&E was notified that it was not a recipient of the training grant.
 
OG&E Long-Term Gas Supply Agreements
 
On February 26, 2010, OG&E filed an application with the OCC requesting a waiver of the competitive bid rules to negotiate desired long-term gas purchase agreements.  A hearing is scheduled for May 13, 2010 in this matter.
 
OG&E Arkansas OU Spirit Application and Renewable Energy Filing
 
OG&E expects to file an application with the APSC in May 2010, requesting approval to recover from Arkansas customers the cost of OU Spirit through a surcharge and approval to recover, through the fuel adjustment clause, the costs of purchasing power under two wind purchase power agreements totaling 280 MWs, which were signed in September 2009, as a result of a request for proposal issued by OG&E in December 2008.  The agreements are both 20-year power purchase
 

 
25

 

agreements, under which the developers are to build, own and operate the wind generating facilities and OG&E will purchase their electric output.  The two wind farms are expected to be in service by the end of 2010.
 
OG&E Crossroads Wind Project Application
 
OG&E signed memoranda of understanding in February 2010 for approximately 197.8 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind project (“Crossroads”) located in Dewey County, Oklahoma.  OG&E will build, own and operate the wind farm, if approved by the OCC.  On April 8, 2010, OG&E filed an application with the OCC requesting pre-approval of this project and a rider to recover from Oklahoma customers the costs to construct Crossroads.  A procedural schedule has not been established in this matter. Crossroads is expected to cost approximately $397.6 million with a related annual revenue requirement of approximately $40.0 million, of which approximately $34.5 million is the Oklahoma jurisdictional portion.
 
Enogex 2010 Fuel Filing
 
Pursuant to its Statement of Operating Conditions (“SOC”), Enogex makes an annual fuel filing at the FERC to establish the zonal fuel percentages for each calendar year.  The tracker mechanism set out in the SOC establishes prospectively the zonal fixed fuel factors (expressed as a percentage of natural gas shipped in the zone) for the upcoming calendar year.  The collected fuel is later trued-up to actual usage and based on the value of the fuel at the time of usage.
 
On November 23, 2009, Enogex made its annual filing to establish the fixed fuel percentages for its East Zone and West Zone for calendar year 2010 (“2010 Fuel Year”).  The FERC accepted the proposed zonal fuel percentages for the 2010 Fuel Year by an order dated April 23, 2010.
 
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
Introduction
 
OGE Energy Corp. (“OGE Energy” and collectively, with its subsidiaries, 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.
 
The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“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 LLC and its subsidiaries (“Enogex”) are providers of integrated natural gas midstream services.  Enogex is engaged in the business of gathering, processing, transporting and storing 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 two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.  Also, Enogex holds a 50 percent ownership interest in the Atoka Midstream, LLC joint venture (“Atoka”) through Enogex Atoka LLC, a wholly-owned subsidiary of Enogex Gathering & Processing LLC.
 
Executive Overview
 
Financial Strategy
 
The Company’s mission is to fulfill its critical role in the nation’s electric utility and natural gas midstream pipeline infrastructure and meet individual customers’ needs for energy and related services in a safe, reliable and efficient manner. The Company intends to execute its vision by focusing on its regulated electric utility business and unregulated midstream natural gas business.  The Company intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business.  The Company’s financial objectives from 2010 through 2012 include a long-term annual earnings growth rate of five to seven percent on a weather-normalized basis as well as an annual dividend growth rate of two percent subject to approval by the Company’s Board of Directors.  The target payout ratio for the Company is to pay out as dividends no more than 60 percent of its normalized earnings on an annual basis.  The target payout
 

 
26

 

ratio has been determined after consideration of numerous factors, including the largely retail composition of the Company’s shareholder base, the Company’s financial position, the Company’s growth targets, the composition of the Company’s assets and investment opportunities.  The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.
 
Summary of Operating Results
 
Three Months Ended March 31, 2010 as Compared to Three Months Ended March 31, 2009
 
Net income attributable to OGE Energy was approximately $24.2 million, or $0.25 per diluted share, during the three months ended March 31, 2010, as compared to approximately $16.8 million, or $0.18 per diluted share, during the same period in 2009.  Included in net income attributable to OGE Energy during the three months ended March 31, 2010 was a one-time, non-cash charge of approximately $11.4 million, or $0.11 per diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements).  The increase in net income attributable to OGE Energy of approximately $7.4 million, or 44.0 percent, or $0.07 per diluted share, during the three months ended March 31, 2010 as compared to the same period in 2009 was primarily due to an increase in net income at Enogex of approximately $12.0 million, or $0.12 per diluted share of the Company’s common stock, mainly attributable to higher commodity prices and volumes, which offset decreases in net income at OG&E, OGE Energy Resources, Inc. (“OERI”) and the holding company.  In particular,
 
Ÿ  
net income at OG&E was approximately $1.2 million during the three months ended March 31, 2010 as compared to approximately $1.3 million during the same period in 2009, which was a decrease in net income of approximately $0.1 million or 7.7 percent, or less than $0.01 per diluted share of the Company’s common stock, during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to higher other operation and maintenance expense, higher depreciation and amortization expense and higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements) partially offset by a higher gross margin on revenues (“gross margin”) primarily due to cooler weather, rate increases and riders;
Ÿ  
net income at Enogex was approximately $27.4 million during the three months ended March 31, 2010 as compared to approximately $15.4 million during the same period in 2009, which was an increase in net income of approximately $12.0 million or 77.9 percent, or $0.12 per diluted share of the Company’s common stock, during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to a higher gross margin, as a result of higher processing spreads, higher natural gas liquids (“NGL”) prices and volumes and higher natural gas prices and volumes partially offset by higher depreciation and amortization expense, higher interest expense and higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements);
Ÿ  
net loss at OGE Energy was approximately $3.3 million during the three months ended March 31, 2010 as compared to approximately $0.8 million during the same period in 2009, which was an increase in the net loss of approximately $2.5 million, or $0.03 per diluted share of the Company’s common stock, during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements); and
Ÿ  
net loss at OERI was approximately $1.1 million during the three months ended March 31, 2010 as compared to net income of approximately $0.9 million during the same period in 2009, which was a decrease in net income of approximately $2.0 million, or $0.02 per diluted share of the Company’s common stock, during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to a lower gross margin partially offset by lower income tax expense.
 
Timing Items.  Enogex’s net income for the three months ended March 31, 2010 was approximately $27.4 million, which included a realized gain of approximately $1.5 million related to the March 2010 component of Enogex’s operational storage hedges. This amount will be offset by a realized loss of approximately $1.0 million upon recognition of the May 2010 component of Enogex’s operational storage hedges, which are currently deferred in Accumulated Other Comprehensive Income.
 
Enogex’s net income for the three months ended March 31, 2009 was approximately $15.4 million, which included a realized gain of approximately $3.3 million related to the March 2009 component of Enogex’s operational storage hedges.
 

 
27

 

This amount was offset by a realized loss of approximately $1.5 million upon recognition of the May 2009 component of Enogex’s operational storage hedges.
 
Recent Developments and Regulatory Matters
 
Volatility in the Commodity Markets
 
Enogex’s gathering and processing margins generally improve when NGLs prices, both on an actual basis and also relative to the price of natural gas (sometimes referred to as high commodity spreads), are high.  For much of the first nine months of 2008, commodity spreads and NGLs prices were relatively high.  However, later in 2008, both commodity spreads and NGLs prices were significantly lower.  During 2009 and through the first quarter of 2010, commodity spreads and NGLs prices increased over year-end 2008 levels but remained below the higher levels experienced in mid-2008.  Enogex expects the volatility in these markets to continue.
 
Global Climate Change and Environmental Concerns
 
There is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the Federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions.   In June 2009, the U.S. House of Representatives passed legislation that would regulate greenhouse gas emissions by instituting a cap-and-trade-system, in which a cap on U.S. greenhouse gas emissions would be established starting in 2012 at a level three percent below the baseline 2005 level. The cap would decline over time until in 2050 it reaches 83 percent below the baseline level. Emission allowances, which are rights to emit greenhouse gases, would be both allocated for free and auctioned. In addition, the legislation contains a renewable energy standard of 25 percent by the year 2025 and an energy efficiency mandate for electric and natural gas utilities, as well as other requirements. Legislation pending in the U.S. Senate proposes to regulate greenhouse gas emissions by instituting a cap-and-trade-system, with primarily the same target levels proposed by the House bill; however, the proposed Senate bill is more aggressive in its 2020 target – a reduction to 20 percent below 2005 levels by 2020 (versus 17 percent in the House bill). It is uncertain at this time whether, and in what form, such legislation will ultimately be adopted.  If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional capital expenditures and compliance costs.

Uncertainty surrounding global climate change and environmental concerns related to new coal-fired generation development is changing the mix of the potential sources of new generation in the region.  Adoption of renewable portfolio standards would be expected to increase the region’s reliance on wind generation.  The Company believes it can leverage its unique geographic position to develop renewable energy resources for wind and transmission to deliver the renewable energy.
 
OG&E Windspeed Transmission Line Project
 
OG&E filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma (“Windspeed”). The OCC subsequently authorized recovery at a construction cost of up to approximately $218 million, including allowance for funds used during construction (“AFUDC”).  At March 31, 2010, the construction costs and AFUDC incurred for the Windspeed transmission line were approximately $200.3 million and the final costs are expected to be less than $218 million.  The Windspeed transmission line was placed into service on March 31, 2010, with the recovery rider being implemented with the first billing cycle in April 2010.
 
OG&E Smart Grid Application
 
In February 2009, the American Recovery and Reinvestment Act of 2009 (“ARRA”) was enacted into law.  Several provisions of this law relate to issues of direct interest to the Company including, in particular, financial incentives to develop smart grid technology, transmission infrastructure and renewable energy.  After review of the ARRA, OG&E filed a grant request on August 4, 2009 for $130 million with the U.S. Department of Energy (“DOE”) to be used for the Smart Grid application in OG&E’s service territory.  On October 27, 2009, OG&E received notification from the DOE that its grant had been accepted by the DOE for the full requested amount of $130 million, which will not be subject to income tax.  Receipt of the grant monies was contingent upon successful negotiations with the DOE on final details of the award.  On April 21, 2010, OG&E and the DOE entered into a definitive agreement with regards to the award.   On March 15, 2010, OG&E filed an application with the OCC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant.  A procedural schedule has not been established in this matter.
 

 
28

 

Separately, on November 30, 2009, OG&E requested a grant with a 50 percent match of up to $5 million for a variety of types of smart grid training for OG&E’s workforce.  In April 2010, OG&E was notified that it was not a recipient of the training grant.
 
OG&E Crossroads Wind Project Application
 
OG&E signed memoranda of understanding in February 2010 for approximately 197.8 megawatts (“MW”) of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind project (“Crossroads”) located in Dewey County, Oklahoma.  OG&E will build, own and operate the wind farm, if approved by the OCC.  On April 8, 2010, OG&E filed an application with the OCC requesting pre-approval of this project and a rider to recover from Oklahoma customers the costs to construct Crossroads.  A procedural schedule has not been established in this matter. Crossroads is expected to cost approximately $397.6 million with a related annual revenue requirement of approximately $40.0 million, of which approximately $34.5 million is the Oklahoma jurisdictional portion.
 
Gathering and Processing System Expansions
 
Southeastern Oklahoma / East Side Expansions
 
Enogex plans to construct a new compressor station in Coal County, Oklahoma, as well as approximately 10 miles of gathering pipe and related treating facilities.  The station would be designed to accommodate up to 6,700 horsepower of low pressure compression and would be supported by approximately five miles of 20-inch steel pipe and five miles of 12-inch steel pipe.  The new compressor station will also include the purchase of associated gas treating facilities for the incremental gas in this area.  The initial 2,700 horsepower at the compressor station, and the gathering pipe, are currently in service, with an incremental 2,700 horsepower that went into service in March 2010.  The treating facilities are expected to be completed in the third quarter of 2010; however, Enogex will use its blending capabilities to accept gas for throughput until such time as the treating facilities have been constructed.  The capital expenditures for this project are expected to be approximately $22 million.
 
In order to gather additional volume in southeast Oklahoma, Enogex plans to construct an additional low pressure compressor station in Pittsburg County, Oklahoma.  This station is expected to include approximately 5,400 horsepower of compression, together with leased treating facilities.  The station is expected to be fully operational by November 2010, with capital expenditures of approximately $13 million.
 
Texas Panhandle / West Side Expansions
 
Enogex is planning to further expand its gathering infrastructure in 2010 in the Wheeler County, Texas area with the construction of approximately 15 miles of 10-inch steel pipe, as well as the addition of approximately 2,700 horsepower of compression.  The gathering pipelines are expected to be in service by the end of the third quarter of 2010, while the compression is expected to be operational by July 2010.  The capital expenditures associated with this project are expected to be approximately $12 million.
 
2010 Outlook
 
The Company’s 2010 ongoing earnings guidance remains unchanged and is between approximately $265 million and $290 million of net income, or $2.70 to $2.95 per average diluted share.  The Company now projects ongoing earnings to be at the upper end of the earnings range primarily due to Enogex’s ongoing earnings which are anticipated to be at the top end of the earnings range.

2010 Ongoing Earnings Guidance:
 
 Ÿ  
Excludes a one-time, non-cash charge recorded in March 2010 of approximately $11.4 million, or $0.11 per average diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy.  Approximately $7.0 million is related to OG&E, approximately $2.0 million is related to Enogex and approximately $2.4 million is related to the holding company.
 Ÿ  
Includes a projected increase for the remainder of 2010 in income tax expense of approximately $2.3 million, or $0.02 per average diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy.  Approximately $1.9 million is related to OG&E, approximately $0.2 million is related to Enogex and approximately $0.2 million is related to the holding company.
 
All other assumptions are unchanged from those included in the earnings guidance in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 Form 10-K”).

 
29

 


Ongoing earnings, which as indicated above excludes the one-time, non-cash charge of approximately $11.4 million associated with the elimination of the tax deduction for the Medicare Part D subsidy as a result of the recent health care legislation, is a non-GAAP financial measure.  As the Medicare Part D tax subsidy represents a charge which management believes will not be recurring on a regular basis, management believes that the presentation of Ongoing Earnings and Ongoing Earnings per Average Diluted Share (“EPS”) provides useful information to investors, as it provides them an additional relevant comparison of the Company’s performance across periods.  Reconciliations of Ongoing Earnings and Ongoing EPS to generally accepted accounting principles (“GAAP”) net income and GAAP EPS are provided below.
 
Reconciliation of projected ongoing earnings to projected GAAP net income
 

(In millions)
Twelve Months Ended December 31, 2010
 
     
   
OG&E
 
       Enogex
 
Holding Company   
 
Consolidated
   
Low
 
High
 
   Low
 
    High
 
    Low
 
   High
 
   Low
 
High
Ongoing earnings
$
207.0 
$
217.0 
$
63.0 
$
85.0  
$
(9.0)
$
(7.0)
$
265.0 
$
290.0 
Medicare Part D tax subsidy
 
(7.0)
 
(7.0)
 
(2.0)
 
(2.0) 
 
(2.4)
 
(2.4)
 
(11.4)
 
(11.4)
Projected GAAP net income
$
200.0 
$
210.0 
$
61.0 
$
83.0  
$
(11.4)
$
(9.4)
$
253.6 
$
278.6 

Reconciliation of projected ongoing EPS to projected GAAP EPS

 
Twelve Months Ended December 31, 2010
 
     
   
OG&E