oge10q103009.htm
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q

(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
        THE SECURITIES EXCHANGE ACT OF 1934
           For the quarterly period ended September 30, 2009

 
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  x  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 (Sec.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  x  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  x  

At September 30, 2009, there were 96,791,187 shares of common stock, par value $0.01 per share, outstanding.
 


 
 
 
 
 

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2009

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
  
7
Notes to Condensed Consolidated Financial Statements
  
8
     
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
  
38
     
Item 3. Quantitative and Qualitative Disclosures About Market Risk
  
68
     
Item 4. Controls and Procedures
  
69
     
     
   
     
Item 1. Legal Proceedings
  
70
     
Item 1A. Risk Factors
  
72
     
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
  
73
     
Item 6. Exhibits
  
73
     
 
74
     


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, 2008 (“2008 Form 10-K”) and “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
 
●
general economic conditions, including the availability of credit, access to existing lines of credit, actions of rating agencies and their impact on capital expenditures;
 
●
OGE Energy Corp.’s (collectively, with its subsidiaries, the “Company”) ability and the ability of its subsidiaries to access the capital markets and obtain financing on favorable terms;
 
●
prices and availability of electricity, coal, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other;
 
●
business conditions in the energy and natural gas midstream industries;
 
●
competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;
 
●
unusual weather;
 
●
availability and prices of raw materials for current and future construction projects;
 
●
Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company’s markets;
 
●
environmental laws and regulations that may impact the Company’s operations;
 
●
changes in accounting standards, rules or guidelines;
 
●
the discontinuance of accounting principles for certain types of rate-regulated activities;
 
●
creditworthiness of suppliers, customers and other contractual parties;
 
●
the higher degree of risk associated with the Company’s nonregulated business compared with the Company’s regulated utility business; and
 
●
other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in “Item 1A. Risk Factors” and in Exhibit 99.01 to the Company’s 2008 Form 10-K.
 
 
 
1
 
 
 
PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
 
   
Three Months Ended
    
Nine Months Ended
  
   
September 30,
    
September 30,
  
(In millions, except per share data)
  
2009
    
2008
    
2009
    
2008
  
OPERATING REVENUES
                        
Electric Utility operating revenues
   $ 577.9     $ 682.5     $ 1,339.9     $ 1,589.6  
Natural Gas Pipeline operating revenues
     267.4       571.8       756.1       1,795.1  
Total operating revenues
     845.3       1,254.3       2,096.0       3,384.7  
COST OF GOODS SOLD (exclusive of depreciation and amortization
                                
shown below)
                                
Electric Utility cost of goods sold
     223.8       368.9       559.3       892.4  
Natural Gas Pipeline cost of goods sold
     190.3       467.9       532.2       1,515.3  
Total cost of goods sold
     414.1       836.8       1,091.5       2,407.7  
Gross margin on revenues
     431.2       417.5       1,004.5       977.0  
Other operation and maintenance
     113.0       113.6       335.1       357.8  
Depreciation and amortization
     66.6       53.4       193.8       156.5  
Impairment of assets
     0.6       ---       2.0       ---  
Taxes other than income
     21.3       19.3       65.5       60.7  
OPERATING INCOME
     229.7       231.2       408.1       402.0  
OTHER INCOME (EXPENSE)
                                
Interest income
     0.3       2.3       1.4       4.4  
Allowance for equity funds used during construction
     5.5       ---       10.7       ---  
Other income
     7.0       0.2       20.0       8.6  
Other expense
     (3.9 )     (3.6 )     (8.9 )     (18.6 )
Net other income (expense)
     8.9       (1.1 )     23.2       (5.6 )
INTEREST EXPENSE
                                
Interest on long-term debt
     37.3       25.7       100.6       73.4  
Allowance for borrowed funds used during construction
     (2.9 )     (0.8 )     (5.9 )     (2.4 )
Interest on short-term debt and other interest charges
     2.3       3.5       6.4       14.0  
Interest expense
     36.7       28.4       101.1       85.0  
INCOME BEFORE TAXES
     201.9       201.7       330.2       311.4  
INCOME TAX EXPENSE
     64.4       60.3       104.2       96.6  
NET INCOME
     137.5       141.4       226.0       214.8  
Less: Net income attributable to noncontrolling interest
     0.7       1.9       1.9       5.2  
NET INCOME ATTRIBUTABLE TO OGE ENERGY
   $ 136.8     $ 139.5     $ 224.1     $ 209.6  
                                 
BASIC AVERAGE COMMON SHARES OUTSTANDING
     96.7       92.6       96.0       92.2  
DILUTED AVERAGE COMMON SHARES OUTSTANDING
     97.7       93.0       96.9       92.7  
BASIC EARNINGS PER AVERAGE COMMON SHARE
                                
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
   $ 1.42     $ 1.51     $ 2.34     $ 2.27  
DILUTED EARNINGS PER AVERAGE COMMON SHARE
                                
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
   $ 1.40     $ 1.50     $ 2.31     $ 2.26  
                                 
DIVIDENDS DECLARED PER SHARE
   $ 0.3550     $ 0.3475     $ 1.0650     $ 1.0425  

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

 
2
 
 


OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS

   
September 30,
    
December 31,
  
   
2009
    
2008
  
(In millions)
  
(Unaudited)
        
             
ASSETS
            
CURRENT ASSETS
            
Cash and cash equivalents                                                                              
   $ 2.3     $ 174.4  
Accounts receivable, less reserve of $2.8 and $3.2, respectively
     285.3       288.1  
Accrued unbilled revenues                                                                              
     59.5       47.0  
Income taxes receivable                                                                              
     40.5       ---  
Fuel inventories                                                                              
     108.1       88.7  
Materials and supplies, at average cost                                                                              
     78.8       72.1  
Price risk management                                                                              
     9.3       11.9  
Gas imbalances                                                                              
     8.0       6.2  
Accumulated deferred tax assets                                                                              
     13.0       14.9  
Fuel clause under recoveries                                                                              
     0.3       24.0  
Prepayments                                                                              
     3.5       9.0  
Other                                                                              
     7.0       8.3  
Total current assets                                                                        
     615.6       744.6  
                 
OTHER PROPERTY AND INVESTMENTS, at cost
     42.1       42.2  
                 
PROPERTY, PLANT AND EQUIPMENT
                
In service                                                                              
     8,221.9       7,722.4  
Construction work in progress                                                                              
     553.2       399.0  
Total property, plant and equipment                                                                        
     8,775.1       8,121.4  
Less accumulated depreciation                                                                   
     3,001.7       2,871.6  
Net property, plant and equipment                                                                        
     5,773.4       5,249.8  
                 
DEFERRED CHARGES AND OTHER ASSETS
                
Income taxes recoverable from customers, net                                                                              
     20.7       14.6  
Benefit obligations regulatory asset                                                                              
     324.4       344.7  
Price risk management                                                                              
     18.0       22.0  
McClain Plant deferred expenses                                                                              
     1.6       6.2  
Unamortized loss on reacquired debt                                                                              
     16.8       17.7  
Unamortized debt issuance costs                                                                              
     13.9       13.5  
Other                                                                              
     71.3       63.2  
Total deferred charges and other assets                                                                        
     466.7       481.9  
                 
TOTAL ASSETS                                                                                   
   $ 6,897.8     $ 6,518.5  

 

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


 
3
 
 


OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)


   
September 30,
    
December 31,
  
   
2009
    
2008
  
(In millions)
  
(Unaudited)
        
             
LIABILITIES AND STOCKHOLDERS’ EQUITY
            
CURRENT LIABILITIES
            
Short-term debt                                                                       
   $ 308.0     $ 298.0  
Accounts payable                                                                       
     174.7       279.7  
Dividends payable                                                                       
     34.4       33.2  
Customer deposits                                                                       
     62.1       58.8  
Accrued taxes                                                                       
     60.6       26.8  
Accrued interest                                                                       
     30.8       48.7  
Accrued compensation                                                                       
     44.2       45.2  
Long-term debt due within one year                                                                       
     289.4       ---  
Price risk management                                                                       
     12.7       2.3  
Gas imbalances                                                                       
     9.7       24.9  
Fuel clause over recoveries                                                                       
     176.4       8.6  
Other                                                                       
     43.4       62.2  
Total current liabilities                                                                  
     1,246.4       888.4  
                 
LONG-TERM DEBT                                                                            
     1,930.8       2,161.8  
                 
DEFERRED CREDITS AND OTHER LIABILITIES
                
Accrued benefit obligations                                                                       
     318.1       350.5  
Accumulated deferred income taxes                                                                       
     1,096.1       996.9  
Accumulated deferred investment tax credits
     14.2       17.3  
Accrued removal obligations, net                                                                       
     164.4       150.9  
Price risk management                                                                       
     1.6       3.8  
Other                                                                       
     54.9       34.9  
Total deferred credits and other liabilities
     1,649.3       1,554.3  
                 
Total liabilities                                                                  
     4,826.5       4,604.5  
                 
COMMITMENTS AND CONTINGENCIES (NOTE 12)
                
                 
STOCKHOLDERS’ EQUITY
                
Common stockholders’ equity                                                                       
     880.7       802.9  
Retained earnings                                                                       
     1,228.7       1,107.6  
Accumulated other comprehensive loss, net of tax
    (57.2 )     (13.7 )
Total OGE Energy stockholders’ equity                                                                  
     2,052.2       1,896.8  
Noncontrolling interest
        19.1       17.2  
Total stockholders’ equity                                                                  
     2,071.3       1,914.0  
                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
   $ 6,897.8     $ 6,518.5  
 
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)
 
 
OGE Energy Corp. Stockholders’
    
   
Premium
  
Accumulated
    
   
on
  
Other
    
 
Common
Capital
Retained
Comprehensive
Noncontrolling
  
(In millions)
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:
            
Net loss, net of tax ($1.3 pre-tax)
---
---
--- 
0.8 
---
           0.8 
Defined benefit postretirement plans:
            
Net loss, net of tax ($0.2 pre-tax)
---
---
--- 
0.1 
---
0.1 
Deferred hedging losses (($46.2) pre-tax)
---
---
--- 
(28.3)
---
(28.3)
Amortization of cash flow hedge ($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 
             
 Comprehensive income
            
Net income for second quarter of 2009
---
---
70.5 
---
0.4
70.9 
Other comprehensive income (loss), net of tax
            
Defined benefit pension plan and restoration of
            
retirement income plan:
            
Net loss, net of tax ($1.3 pre-tax)
---
---
--- 
0.7 
---
0.7 
Prior service cost, net of tax ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Defined benefit postretirement plans:
            
Prior service cost, net of tax ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Deferred hedging losses (($32.4) pre-tax)
---
---
--- 
(19.8)
---
(19.8)
Amortization of cash flow hedge ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Other comprehensive loss
---
---
--- 
(18.8)
---
(18.8)
 Comprehensive income (loss)
---
---
70.5 
(18.8)
0.4
52.1 
 Dividends declared on common stock
---
---
(34.4)
--- 
---
(34.4)
 Issuance of common stock
---
14.1
--- 
--- 
---
14.1 
 Balance at June 30, 2009
$        1.0
$   871.8
$   1,126.3 
$         (59.8)
$          18.4
$  1,957.7 
             
 Comprehensive income
            
Net income for third quarter of 2009
---
---
136.8 
--- 
0.7
137.5 
Other comprehensive income (loss), net of tax
            
Defined benefit pension plan and restoration of
            
retirement income plan:
            
Net loss, net of tax ($1.3 pre-tax)
---
---
--- 
0.8 
---
0.8 
Defined benefit postretirement plans:
            
Net loss, net of tax ($0.3 pre-tax)
---
---
--- 
0.2 
---
0.2 
Net transition obligation, net of tax ($0.1 pre-tax)
   ---    ---   --- 
0.1 
    ---
0.1 
Deferred hedging gains ($2.5 pre-tax)
---
---
--- 
1.5 
---
1.5 
Other comprehensive income
---
---
--- 
2.6 
---
2.6 
 Comprehensive income
---
---
136.8 
2.6 
0.7
140.1 
 Dividends declared on common stock
---
---
(34.4)
--- 
---
(34.4)
 Issuance of common stock
---
7.9
--- 
--- 
---
7.9 
 Balance at September 30, 2009
$        1.0
$   879.7
$   1,228.7 
$         (57.2)
$          19.1
$  2,071.3 
 
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
 
 
5
 
 

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Continued)
(Unaudited)
 
 
OGE Energy Corp. Stockholders’
    
   
Premium
  
Accumulated
    
   
on
  
Other
    
 
Common
Capital
Retained
Comprehensive
Noncontrolling
  
  (In millions)
Stock
Stock
Earnings
Income (Loss)
Interest
Total
 
 Balance at December 31, 2007
$       0.9
$   755.3
$  1,005.7
$        (81.0)
$         10.7
$  1,691.6 
 Comprehensive income
            
Net income for first quarter of 2008
---
---
13.0 
--- 
1.6
14.6 
Other comprehensive income, net of tax
            
Defined benefit pension plan and restoration of
            
retirement income plan:
            
Net loss, net of tax ($0.5 pre-tax)
---
---
--- 
0.3 
---
 0.3 
Prior service cost, net of tax ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Defined benefit postretirement plans:
            
Net loss, net of tax ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Prior service cost, net of tax ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Deferred hedging gains ($26.0 pre-tax)
---
---
--- 
16.0 
---
16.0 
Amortization of cash flow hedge ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Other comprehensive income
---
---
--- 
16.7 
---
16.7 
 Comprehensive income
---
---
13.0 
16.7 
1.6
31.3 
 Dividends declared on common stock
---
---
(32.0)
--- 
---
(32.0)
 Contributions from partner
---
---
--- 
--- 
0.5
0.5 
 Issuance of common stock
---
2.2
--- 
--- 
---
2.2 
 Balance at March 31, 2008
$       0.9
$   757.5
$  986.7 
$        (64.3)
$        12.8
$  1,693.6 
             
 Comprehensive income
            
Net income for second quarter of 2008
---
---
57.1 
--- 
1.7
58.8 
Other comprehensive income (loss), net of tax
            
Defined benefit pension plan and restoration of
            
retirement income plan:
            
Net loss, net of tax ($0.6 pre-tax)
---
---
--- 
0.4 
---
0.4 
Prior service cost, net of tax ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Defined benefit postretirement plans:
            
Net loss, net of tax ($0.2 pre-tax)
---
---
--- 
0.1 
---
0.1 
Net transition obligation, net of tax ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Deferred hedging losses (($22.1) pre-tax)
---
---
--- 
(13.8)
---
(13.8)
Other comprehensive loss
---
---
--- 
(13.1)
---
(13.1)
 Comprehensive income (loss)
---
---
57.1 
(13.1)
1.7
45.7 
 Dividends declared on common stock
---
---
(32.1)
--- 
---
(32.1)
 Issuance of common stock
---
10.4
--- 
--- 
---
10.4 
 Balance at June 30, 2008
$       0.9
$ 767.9
$ 1,011.7 
$        (77.4)
$       14.5
$  1,717.6 
             
 Comprehensive income
            
Net income for third quarter of 2008
---
---
139.5 
--- 
1.9
141.4 
Other comprehensive income, net of tax
            
Defined benefit pension plan and restoration of
            
retirement income plan:
            
Net loss, net of tax ($0.5 pre-tax)
---
---
--- 
0.3 
---
0.3 
Defined benefit postretirement plans:
            
Net loss, net of tax ($0.2 pre-tax)
---
---
--- 
0.1 
---
0.1 
Deferred hedging gains ($23.8 pre-tax)
---
---
--- 
14.6 
---
14.6 
Amortization of cash flow hedge ($0.1 pre-tax)
---
---
--- 
0.1 
---
0.1 
Other comprehensive income
---
---
--- 
15.1 
---
15.1 
 Comprehensive income
---
---
139.5 
15.1 
1.9
156.5 
 Dividends declared on common stock
---
---
(32.2)
--- 
---
(32.2)
 Issuance of common stock
---
13.5
--- 
--- 
---
13.5 
 Balance at September 30, 2008
$       0.9
$ 781.4
$ 1,119.0 
$        (62.3)
$         16.4
$  1,855.4 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
 
6
 
OGE ENERGY CORP.
  
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
  
(Unaudited)
  
     
 
Nine Months Ended
  
 
September 30,
  
(In millions)
2009
2008
  
           
CASH FLOWS FROM OPERATING ACTIVITIES
          
Net income
$ 
226.0 
$ 
214.8 
  
Adjustments to reconcile net income to net cash provided from
          
operating activities
          
Depreciation and amortization
  
193.8 
  
156.5 
  
Impairment of assets
  
2.0 
  
--- 
  
Deferred income taxes and investment tax credits, net
  
132.3 
  
134.1 
  
Allowance for equity funds used during construction
  
(10.7)
  
--- 
  
Loss on disposition of assets
  
1.2 
  
0.3 
  
Write-down of regulatory assets
  
--- 
  
9.2 
  
Stock-based compensation expense
  
4.2 
  
3.4 
  
Excess tax benefit on stock-based compensation
  
(3.3)
  
(1.9)
  
Stock-based compensation converted to cash for tax withholding
  
(1.7)
  
--- 
  
Price risk management assets
  
6.6 
  
--- 
  
Price risk management liabilities
  
(67.7)
  
23.2 
  
Other assets
  
11.4 
  
(14.9)
  
Other liabilities
  
(34.4)
  
(21.1)
  
Change in certain current assets and liabilities
          
Accounts receivable, net
  
2.8 
  
(40.6)
  
Accrued unbilled revenues
  
(12.5)
  
(3.4)
  
Income taxes receivable
  
(40.5)
  
--- 
  
Fuel, materials and supplies inventories
  
(26.1)
  
(24.0)
  
Gas imbalance assets
  
(1.8)
  
4.2 
  
Fuel clause under recoveries
  
23.7 
  
(82.6)
  
Other current assets
  
6.8 
  
1.5 
  
Accounts payable
  
(105.0)
  
(167.2)
  
Customer deposits
  
3.3 
  
1.5 
  
Accrued taxes
  
34.2 
  
(6.8)
  
Accrued interest
  
(17.9)
  
(11.3)
  
Accrued compensation
  
(1.0)
  
(15.8)
  
Gas imbalance liabilities
  
(15.2)
  
4.7 
  
Fuel clause over recoveries
  
167.8 
  
(3.8)
  
Other current liabilities
  
(18.8)
  
18.2 
  
Net Cash Provided from Operating Activities
  
459.5 
  
178.2 
  
           
CASH FLOWS FROM INVESTING ACTIVITIES
          
Capital expenditures (less allowance for equity funds used during
          
construction)
  
(676.4)
  
(914.7)
  
Proceeds from sale of assets
  
0.8 
  
0.2 
  
Other investing activities
  
--- 
  
(0.1)
  
Net Cash Used in Investing Activities
  
(675.6)
  
(914.6)
  
           
CASH FLOWS FROM FINANCING ACTIVITIES
          
Proceeds from long-term debt
  
198.4 
  
444.7 
  
Proceeds from line of credit
  
80.0 
  
145.0 
  
Issuance of common stock
  
74.9 
  
18.5 
  
Increase in short-term debt, net
  
10.0 
  
444.0 
  
Excess tax benefit on stock-based compensation
  
3.3 
  
1.9 
  
Contributions from noncontrolling interest partner
  
--- 
  
0.5 
  
Dividends paid on common stock
  
(101.8)
  
(96.0)
  
Repayment of line of credit
  
(110.0)
  
(25.0)
  
Retirement of long-term debt
  
(110.8)
  
(1.1)
  
Net Cash Provided from Financing Activities
  
44.0 
  
932.5 
  
           
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS   (172.1)    196.1   
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
  
174.4  
  
8.8 
  
CASH AND CASH EQUIVALENTS AT END OF PERIOD
   $
2.3  
   $   204.9  
           
            
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
  
       
 
7
 
 

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

1.           Summary of Significant Accounting Policies

Organization
 
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.  The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located primarily 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.

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 (“Tallgrass”) to construct high-capacity transmission line projects in western Oklahoma.  The Company owns 50 percent of Tallgrass.  Tallgrass is intended to allow the companies to lead development of renewable wind by sharing capital costs associated with the planned 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.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at September 30, 2009 and December 31, 2008, the results of its operations for the three and nine months ended September 30, 2009 and 2008, and the results of its cash flows for the nine months ended September 30, 2009 and 2008, have been included and are of a normal recurring nature except as otherwise disclosed.  Management also has evaluated the impact of subsequent events for inclusion in the Company’s Condensed Consolidated Financial Statements occurring after September 30, 2009 through October 29, 2009, the date the Company’s financial statements were issued, and, in the opinion of management, the Company’s Condensed Consolidated Financial Statements and Notes contain all necessary adjustments and disclosures resulting from that evaluation.

 
8
 
 
Due to seasonal fluctuations and other factors, the operating results for the three and nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009 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, 2008 (“2008 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:

   
September 30,
    
December 31,
  
(In millions)
  
2009
    
2008
  
Regulatory Assets
            
Benefit obligations regulatory asset                                                                         
   $ 324.4     $ 344.7  
Deferred storm expenses                                                                         
     28.8       32.2  
Income taxes recoverable from customers, net                                                                         
     20.7       14.6  
Deferred pension plan expenses                                                                         
     19.2       14.6  
Unamortized loss on reacquired debt                                                                         
     16.8       17.7  
Red Rock deferred expenses                                                                         
     7.8       7.4  
McClain Plant deferred expenses                                                                         
     1.6       6.2  
Fuel clause under recoveries                                                                         
     0.3       24.0  
Miscellaneous                                                                         
     3.1       2.9  
Total Regulatory Assets                                                                    
   $ 422.7     $ 464.3  
                 
Regulatory Liabilities
                
Fuel clause over recoveries                                                                         
   $ 176.4     $ 8.6  
Accrued removal obligations, net                                                                         
     164.4       150.9  
Miscellaneous                                                                         
     11.7       4.9  
Total Regulatory Liabilities                                                                    
   $ 352.5     $ 164.4  

In accordance with the APSC order received by OG&E in May 2009 in its Arkansas rate case, OG&E was allowed recovery of its 2006 and 2007 pension settlement costs.  During the second quarter of 2009, OG&E reduced its pension expense and recorded a regulatory asset for approximately $3.2 million, which is reflected in Deferred Pension Plan Expenses in the table above.

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 reduced or written off, 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.

Price Risk Management Assets and Liabilities

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

 
9
 
 
 
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 contracts under master netting agreements using a net fair value presentation.  If these transactions with the same counterparty were presented on a gross basis in the Condensed Consolidated Balance Sheets, current Price Risk Management (“PRM”) assets and liabilities would be approximately $29.7 million and $33.1 million, respectively, at September 30, 2009, and non-current PRM assets and liabilities would be approximately $39.5 million and $23.1 million, respectively, at September 30, 2009.  If these transactions with the same counterparty were presented on a gross basis in the Condensed Consolidated Balance Sheets, current PRM assets and liabilities would be approximately $51.8 million and $35.4 million, respectively, at December 31, 2008, and non-current PRM assets and liabilities would be approximately $105.6 million and $36.2 million, respectively, at December 31, 2008.

Reclassifications

Certain prior year amounts have been reclassified on the Condensed Consolidated Financial Statements to conform to the 2009 presentation related to the separate presentation of the noncontrolling interest in a subsidiary.

2.           Fair Value Measurements

The following table is a summary of the Company’s assets and liabilities that are measured at fair value on a recurring basis at September 30, 2009.
 
                         
(In millions)
  
Total
    
Level 1
    
Level 2
    
Level 3
  
Assets
                        
Gross derivative assets                                                                      
   $ 91.8     $ 19.1     $ 9.3     $ 63.4  
Gas imbalance assets                                                                      
     8.0       ---       8.0       ---  
Total                                                             
   $ 99.8     $ 19.1     $ 17.3     $ 63.4  
                                 
Liabilities
                                
Gross derivative liabilities
   $ 75.0     $ 14.1     $ 59.5     $ 1.4  
Gas imbalance liabilities (A)                                                                      
     2.8       ---       2.8       ---  
Total                                                             
   $ 77.8     $ 14.1     $ 62.3     $ 1.4  
(A) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of approximately $6.9 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 includes 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

 
10
 
 
 
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 either NYMEX published market prices, independent broker pricing data or broker/dealer valuations in determining the fair value of its derivative positions.  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 September 30, 2009 and December 31, 2008.
 
   
September 30,
    
December 31,
  
(In millions)
  
2009
    
2008
  
Assets
            
Gross derivative assets
   $ 91.8     $ 243.7  
Less:  Amounts held in clearing broker accounts reflected in Other Current Assets
     22.6       86.3  
Less:  Amounts offset under master netting agreements
     41.9       65.4  
Less:  Net collateral payments from counterparties
     ---       58.1  
   Net Price Risk Management Assets 
   $ 27.3     $ 33.9  
                 
Liabilities
                
Gross derivative liabilities
   $ 75.0     $ 141.8  
Less:  Amounts held in clearing broker accounts reflected in Other Current Assets
     18.8       70.3  
Less:  Amounts offset under master netting agreements
     41.9       65.4  
   Net Price Risk Management Liabilities 
   $ 14.3     $ 6.1  


 

 
11
 
 

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).

   
Derivative Assets
  
(In millions)
  
2009
    
2008
  
Balance at January 1                                                                                                            
   $ 121.2     $ 1.4  
Total gains or losses (realized/unrealized)
                
Included in other comprehensive income                                                                                                         
     (11.1 )     0.1  
Purchases, sales, issuances and settlements, net                                                                                                         
     (4.5 )     ---  
Balance at March 31                                                                                                            
   $ 105.6     $ 1.5  
Total gains or losses (realized/unrealized)
                
Included in earnings                                                                                                         
     ---       0.2  
Included in other comprehensive income                                                                                                         
     (34.4 )     (0.8 )
Purchases, sales, issuances and settlements, net
     (3.9 )     14.5  
Balance at June 30                                                                                                            
   $ 67.3     $ 15.4  
Total gains or losses (realized/unrealized)
                
Included in earnings
     ---       0.9  
Included in other comprehensive income
     (2.5 )     17.1  
Purchases, sales, issuances and settlements, net
     (1.4 )     ---  
Balance at September 30
   $ 63.4     $ 33.4  
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 September 30
   $ ---     $ 0.9  

   
Derivative Liabilities
  
(In millions)
  
2009
    
2008
  
Balance at January 1                                                                                                            
   $ ---     $ ---  
Total gains or losses (realized/unrealized)
                
Included in earnings                                                                                                         
     ---       ---  
Included in other comprehensive income                                                                                                         
     ---       ---  
Purchases, sales, issuances and settlements, net                                                                                                         
     ---       ---  
Transfers in and/or out of Level 3                                                                                                         
     ---       ---  
Balance at March 31                                                                                                            
   $ ---     $ ---  
Total gains or losses (realized/unrealized)
                
Included in earnings                                                                                                         
     ---       ---  
Included in other comprehensive income                                                                                                         
     ---       ---  
Purchases, sales, issuances and settlements, net
     1.8       ---  
Transfers in and/or out of Level 3
     ---       ---  
Balance at June 30
   $ 1.8     $ ---  
Total gains or losses (realized/unrealized)
                
Included in earnings
     ---       ---  
Included in other comprehensive income
     (0.4 )      ---  
Purchases, sales, issuances and settlements, net
     ---       ---  
Transfers in and/or out of Level 3
     ---       ---  
Balance at September 30
   $ 1.4     $ ---  
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 September 30
   $ ---     $ ---  

Gains and losses (realized and unrealized) included in earnings for the three and nine months ended September 30, 2009 and 2008 attributable to the change in unrealized gains or losses relating to assets and liabilities held at September 30, 2009 and 2008, if any, are reported in Operating Revenues.

 

 
12
 
 

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 PRM activities at September 30, 2009 and December 31, 2008.
         
   
September 30, 2009
    
December 31, 2008
  
   
Carrying
    
Fair
    
Carrying
    
Fair
  
(In millions)
  
Amount
    
Value
    
Amount
    
Value
  
                         
Price Risk Management Assets
                        
Energy Derivative Contracts
   $ 27.3     $ 27.3     $ 33.9     $ 33.9  
                                 
Price Risk Management Liabilities
                                
Energy Derivative Contracts
   $ 14.3     $ 14.3     $ 6.1     $ 6.1  
                                 
Long-Term Debt
                                
Senior Notes
   $ 1,505.8     $ 1,650.2     $ 1,505.6     $ 1,420.8  
Industrial Authority Bonds
     135.4       135.4       135.3       135.3  
Enogex Notes
     489.0       533.2       400.9       436.1  
Enogex Revolving Credit Facility
     90.0       90.0       120.0       120.0  

           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.

3.           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 commodity price futures, commodity price swap contracts and commodity price option features to manage the Company’s commodity price risk exposures. The commodity price futures and 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:

 
●
natural gas liquids (“NGL”) put options and NGLs swaps are used to manage Enogex’s NGLs exposure associated with its processing agreements;
 
●
natural gas swaps are used to manage Enogex’s keep-whole natural gas exposure associated with its processing agreements and Enogex’s natural gas exposure associated with operating its gathering, transportation and storage assets;
 
●
natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OGE Energy’s natural gas marketing subsidiary, OGE Energy Resources, Inc.’s (“OERI”), natural gas exposure associated with its storage and transportation contracts; and
 
●
natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage 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.  Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of

 
13
 
 

natural gas used in or produced by its operations; (ii) commodity contracts for the sale of NGLs produced by its 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 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.

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 September 30, 2009, the Company had no outstanding treasury lock agreements that were designated as cash flow hedges.

The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex’s contractual length and operational storage natural gas, keep-whole natural gas and NGLs hedges.  Enogex’s cash flow hedging activity at September 30, 2009 covers the period from October 1, 2009 through 2011.  The Company also designates certain derivatives used to manage commodity exposure for certain transportation and natural gas inventory positions at OERI. OERI’s cash flow hedging activity at September 30, 2009 does not extend beyond the first quarter of 2010. At September 30, 2009, the Company had the following outstanding commodity derivative instruments that were designated as cash flow hedges.
 
 
 
14
 
 
   
Notional
    
 
Commodity
Volume (A)
Maturity
  
 
(volumes in millions)
         
Short Financial Swaps/Futures (fixed)
NGLs
0.5
Current
  
Short Financial Swaps/Futures (fixed)
NGLs
0.1
Non-Current
  
Total Short Financial Swaps/Futures (fixed)
  
0.6
    
         
Purchased Financial Options
NGLs
1.3
Current
  
Purchased Financial Options
NGLs
1.7
Non-Current
  
Total Purchased Financial Options
  
3.0
    
         
Long Financial Swaps/Futures (fixed)
Natural Gas
 6.7
Current
  
Long Financial Swaps/Futures (fixed)
Natural Gas
 6.7
Non-Current
  
Total Long Financial Swaps/Futures (fixed)
  
13.4  
    
         
Short Financial Swaps/Futures (fixed)
Natural Gas
4.8
Current
  
Short Financial Swaps/Futures (fixed)
Natural Gas
0.5
Non-Current
  
Total Short Financial Swaps/Futures (fixed)
 
5.3
    
         
Long Financial Basis Swaps
Natural Gas
0.5
Current
  
         
Short Financial Basis Swaps
Natural Gas
4.8
Current
  
Short Financial Basis Swaps
Natural Gas
0.5
Non-Current
  
Total Short Financial Basis Swaps
  
5.3
    
(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 September 30, 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 that are 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 keep-whole natural gas and NGLs 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.
 
 
 
15
 
 

At September 30, 2009, the Company had the following outstanding commodity derivative instruments that were not designated as either a cash flow or fair value hedge. 
   
Notional
  
 
Commodity
Volume (A)
Maturity
 
(volumes in millions)
       
Short Financial Swaps/Futures (fixed)
NGLs
0.8
Current
Short Financial Swaps/Futures (fixed)
NGLs
0.2
Non-Current
Total Short Financial Swaps/Futures (fixed)
  
1.0
  
       
Long Financial Swaps/Futures (fixed)
NGLs
0.8
Current
Long Financial Swaps/Futures (fixed)
NGLs
0.2
Non-Current
Total Long Financial Swaps/Futures (fixed)
  
1.0
  
       
Physical Purchases (B)
Natural Gas
12.6  
Current
Physical Sales (B)
Natural Gas
 
48.1 
 
Current
Physical Sales (B)
Natural Gas
11.0 
Non-Current
Total Physical Sales
  
59.1 
  
       
Long Financial Swaps/Futures (fixed)
Natural Gas
29.9 
Current
Long Financial Swaps/Futures (fixed)
Natural Gas
  1.0 
Non-Current
Total Long Financial Swaps/Futures (fixed)
  
30.9 
  
       
Short Financial Swaps/Futures (fixed)
Natural Gas
31.7 
Current
Short Financial Swaps/Futures (fixed)
Natural Gas
  1.0 
Non-Current
Total Short Financial Swaps/Futures (fixed)
  
32.7 
  
Purchased Financial Option
Natural Gas
 3.3
 
Current
Sold Financial Option
Natural Gas
 3.3
Current
 
Long Financial Basis Swaps
Natural Gas
12.0 
 
Current
Long Financial Basis Swaps
Natural Gas
0.3
Non-Current
Total Long Financial Basis Swaps
  
12.3 
  
       
Short Financial Basis Swaps
Natural Gas
13.3 
Current
Short Financial Basis Swaps
Natural Gas
 0.4 
Non-Current
Total Short Financial Basis Swaps
  
13.7 
  
(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.
 
 
16
 
 
The fair value of the derivative instruments that are presented in the Company’s Condensed Consolidated Balance Sheet at September 30, 2009 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
$
21.0
$
---
     
Non-Current PRM
  
38.4
  
---
Financial Futures/Swaps
NGLs
  
Current PRM
  
1.0
  
0.2
     
Non-Current PRM
  
0.2
  
---
Financial Futures/Swaps
Natural Gas
  
Current PRM
  
2.7
  
18.0
     
Non-Current PRM
  
---
  
20.4
     
Other Current Assets
  
7.4
  
2.0
Total Gross Derivatives Designated as Hedging Instruments
$
70.7
$
40.6
             
Derivatives Not Designated as Hedging Instruments
               
Financial Futures/Swaps (A)
NGLs
  
Current PRM
$
2.3
$
0.9
     
Non-Current PRM
  
0.4
  
0.3
Financial Futures/Swaps (B)
Natural Gas
  
Current PRM
  
0.9
  
12.7
     
Non-Current PRM
  
---
  
2.4
     
Other Current Assets
  
15.0
  
16.6
Physical Purchases/Sales
Natural Gas
  
Current PRM
  
1.8
  
1.3
     
Non-Current PRM
  
0.5
  
---
Financial Options                                       
Natural Gas
  
Other Current Assets
  
0.2
  
0.2
Total Gross Derivatives Not Designated as Hedging Instruments
$
21.1
$
34.4
               
Total Gross Derivatives (C)
$
91.8
$
75.0
(A)
The fair value of Financial Futures/Swaps – NGLs not designated as hedging instruments includes derivatives that were designated as hedging instruments prior to June 30, 2009.  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.  The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $2.3 million, Non-Current Assets of approximately $0.4 million, Current Liabilities of approximately $0.9 million and Non-Current Liabilities of approximately $0.3 million.
(B)
The fair value of Financial Futures/Swaps – Natural Gas not designated as hedging instruments includes derivatives that were designated as hedging instruments prior to June 30, 2009.  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.  The referenced derivatives had a fair value as presented in the table above in Current Liabilities of approximately $11.5 million and Non-Current Liabilities of approximately $2.4 million.
(C)
See reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at September 30, 2009 (see Note 2).

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 September 30, 2009, the Company would have been required to post approximately $12.7 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 September 30, 2009.



 
17
 
 

The following table presents the effect of derivative instruments on the Company’s Condensed Consolidated Statement of Income for the three months ended September 30, 2009.
 
         
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
$
(2.7)
Operating Revenues
$
0.3 
  Operating Revenues
$
---
NGLs Financial
                
Futures/Swaps
  
(0.8)
Operating Revenues
  
2.2 
  Operating Revenues
  
---
Natural Gas Financial
                
Futures/Swaps
  
--- 
Operating Revenues
  
(8.3)
Operating Revenues
  
0.1
Total
$
(3.5)
Total
$
(5.8)
Total
$
0.1
(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at September 30, 2009 that
is expected to be reclassified into earnings within the next 12 months is a loss of approximately $9.0 million.
 
     
Amount of Gain or
    
   
Location of Gain or
Loss Recognized in
    
   
Loss Recognized in
Income of
    
   
Income on Derivative
Derivative
    
(dollars in millions)
Derivatives in Cash Flow Hedging Relationships
             
Natural Gas Physical Purchases/Sales  Operating Revenues   $  (8.3)      
Natural Gas Financial Future/Swaps  Operating Revenues    4.3      
                           Total     $   (4.0)       
                                      
 
 
18
 
 

The following table presents the effect of derivative instruments on the Company’s Condensed Consolidated Statement of Income for the nine months ended September 30, 2009.