Attached files

file filename
EX-32.(A) - SECTION 906 ENERGEN CORPORATION CERTIFICATION - SPIRE ALABAMA INCdex32a.htm
EX-31.(C) - SECTION 302 ALABAMA GAS CORPORATION CERTIFICATION - SPIRE ALABAMA INCdex31c.htm
EX-31.(B) - SECTION 302 ENERGEN CORPORATION - SPIRE ALABAMA INCdex31b.htm
EX-31.(A) - SECTION 302 ENERGEN CORPORATION - SPIRE ALABAMA INCdex31a.htm
EX-31.(D) - SECTION 302 ALABAMA GAS CORPORATION CERTIFICATION - SPIRE ALABAMA INCdex31d.htm
EXCEL - IDEA: XBRL DOCUMENT - SPIRE ALABAMA INCFinancial_Report.xls
EX-32.(B) - SECTION 906 ALABAMA GAS CORPORATION CERTIFICATION - SPIRE ALABAMA INCdex32b.htm
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

 

FORM 10-Q

 

x

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2011

OR

 

¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM                TO               

 

Commission
File Number

    

Registrant

    

State of
Incorporation

    

IRS
Employer
Identification
Number

1-7810        Energen Corporation      Alabama      63-0757759
2-38960      Alabama Gas Corporation      Alabama      63-0022000

605 Richard Arrington Jr. Boulevard North

Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

Alabama Gas Corporation, a wholly owned subsidiary of Energen Corporation, meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form with reduced disclosure format pursuant to General Instruction H(2).

Indicate by a check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YES (X) NO ( )

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 

Energen Corporation   

YES  x

    

NO  ¨

Alabama Gas Corporation   

YES  ¨

    

NO  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Energen Corporation - Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

Alabama Gas Corporation - Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

Energen Corporation

  

YES  ¨

    

NO  x

Alabama Gas Corporation

  

YES  ¨

    

NO  x

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of May 3, 2011.

 

Energen Corporation

  

$0.01 par value

  

72,074,957 shares

Alabama Gas Corporation

  

$0.01 par value

  

1,972,052 shares

 

 

 


Table of Contents

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2011

TABLE OF CONTENTS

 

         Page  

PART I: FINANCIAL INFORMATION

  

Item 1.

 

Financial Statements (Unaudited)

  
 

(a) Consolidated Condensed Statements of Income of Energen Corporation

     3   
 

(b) Consolidated Condensed Balance Sheets of Energen Corporation

     4   
 

(c) Consolidated Condensed Statements of Cash Flows of Energen Corporation

     6   
 

(d) Condensed Statements of Income of Alabama Gas Corporation

     7   
 

(e) Condensed Balance Sheets of Alabama Gas Corporation

     8   
 

(f) Condensed Statements of Cash Flows of Alabama Gas Corporation

     10   
 

(g) Notes to Unaudited Condensed Financial Statements

     11   

Item 2.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     25   
 

Selected Business Segment Data of Energen Corporation

     34   

Item 3.

 

Quantitative and Qualitative Disclosures about Market Risk

     35   

Item 4.

 

Controls and Procedures

     36   
  PART II: OTHER INFORMATION   

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

     37   

Item 6.

 

Exhibits

     37   

SIGNATURES

     38   

 

2


Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

ENERGEN CORPORATION

(Unaudited)

 

     Three months ended
March 31,
 
(in thousands, except per share data)    2011     2010  

Operating Revenues

    

Oil and gas operations

   $ 216,792      $ 237,614   

Natural gas distribution

     269,572        337,300   

Total operating revenues

     486,364        574,914   

Operating Expenses

    

Cost of gas

     131,749        197,156   

Operations and maintenance

     103,782        91,702   

Depreciation, depletion and amortization

     61,128        61,735   

Taxes, other than income taxes

     28,175        30,637   

Accretion expense

     1,649        1,486   

Total operating expenses

     326,483        382,716   

Operating Income

     159,881        192,198   

Other Income (Expense)

    

Interest expense

     (9,404     (9,960

Other income

     1,230        977   

Other expense

     (163     (163

Total other expense

     (8,337     (9,146

Income Before Income Taxes

     151,544        183,052   

Income tax expense

     57,276        66,342   

Net Income

   $ 94,268      $ 116,710   

Diluted Earnings Per Average Common Share

   $ 1.30      $ 1.62   

Basic Earnings Per Average Common Share

   $ 1.31      $ 1.63   

Dividends Per Common Share

   $ 0.135      $ 0.130   

Diluted Average Common Shares Outstanding

     72,240        72,039   

Basic Average Common Shares Outstanding

     72,001        71,810   

The accompanying notes are an integral part of these consolidated condensed financial statements.

 

3


Table of Contents

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

 

 

(in thousands)    March 31, 2011      December 31, 2010  

ASSETS

     

Current Assets

     

Cash and cash equivalents

   $ 51,571       $ 22,659   

Accounts receivable, net of allowance for doubtful accounts of $12,561 at March 31, 2011, and $15,048 at December 31, 2010

     217,151         286,849   

Inventories

     

Storage gas inventory

     30,365         36,706   

Materials and supplies

     20,984         19,045   

Liquified natural gas in storage

     3,113         3,551   

Regulatory asset

     27,410         28,286   

Income tax receivable

     4,664         44,489   

Deferred income taxes

     63,498         32,732   

Prepayments and other

     11,172         11,966   

Total current assets

     429,928         486,283   

Property, Plant and Equipment

     

Oil and gas properties, successful efforts method

     4,209,389         4,080,779   

Less accumulated depreciation, depletion and amortization

     1,202,465         1,161,635   

Oil and gas properties, net

     3,006,924         2,919,144   

Utility plant

     1,305,443         1,292,611   

Less accumulated depreciation

     518,807         509,989   

Utility plant, net

     786,636         782,622   

Other property, net

     18,410         17,461   

Total property, plant and equipment, net

     3,811,970         3,719,227   

Other Assets

     

Regulatory asset

     95,947         105,365   

Pension and other postretirement assets

     13,140         13,907   

Deferred charges and other

     38,480         38,778   

Total other assets

     147,567         158,050   

TOTAL ASSETS

   $ 4,389,465       $ 4,363,560   

The accompanying notes are an integral part of these consolidated condensed financial statements.

 

4


Table of Contents

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

 

 

(in thousands, except share and per share data)

   March 31, 2011     December 31, 2010  

LIABILITIES AND SHAREHOLDERS’ EQUITY

    

Current Liabilities

    

Long-term debt due within one year

   $ 5,000      $ 5,000   

Notes payable to banks

     225,000        305,000   

Accounts payable

     321,946        268,214   

Accrued taxes

     58,062        52,845   

Customers’ deposits

     21,647        20,459   

Amounts due customers

     4,188        20,161   

Accrued wages and benefits

     22,446        25,203   

Regulatory liability

     79,120        75,703   

Royalty payable

     21,188        19,221   

Other

     26,897        26,805   

Total current liabilities

     785,494        818,611   

Long-term debt

     405,232        405,254   

Deferred Credits and Other Liabilities

    

Asset retirement obligation

     99,719        97,415   

Pension and other postretirement liabilities

     34,285        36,551   

Regulatory liability

     94,837        110,447   

Long-term derivative instruments

     186,029        112,936   

Deferred income taxes

     625,441        615,084   

Other

     9,911        13,219   

Total deferred credits and other liabilities

     1,050,222        985,652   

Commitments and Contingencies

                

Shareholders’ Equity

    

Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized

     -        -   

Common shareholders’ equity

    

Common stock, $0.01 par value; 150,000,000 shares authorized, 74,983,359 shares issued at March 31, 2011, and 74,786,376 shares issued at December 31, 2010

     750        748   

Premium on capital stock

     479,363        468,934   

Capital surplus

     2,802        2,802   

Retained earnings

     1,964,724        1,880,183   

Accumulated other comprehensive loss, net of tax

    

Unrealized loss on hedges, net

     (144,223     (43,667

Pension and postretirement plans

     (30,048     (30,730

Deferred compensation plan

     3,459        3,288   

Treasury stock, at cost; 3,035,686 shares at March 31, 2011, and 3,024,847 shares at December 31, 2010

     (128,310     (127,515

Total shareholders’ equity

     2,148,517        2,154,043   

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

   $ 4,389,465      $ 4,363,560   

The accompanying notes are an integral part of these consolidated condensed financial statements.

 

5


Table of Contents

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

ENERGEN CORPORATION

(Unaudited)

 

 

Three months ended March 31, (in thousands)    2011     2010  

Operating Activities

    

Net income

   $ 94,268      $ 116,710   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation, depletion and amortization

     61,128        61,735   

Accretion expense

     1,649        1,486   

Deferred income taxes

     40,772        14,552   

Bad debt expense

     718        (2,450

Exploratory expense

     291        978   

Change in derivative fair value

     (241     (1,598

Gain on sale of assets

     (25     (626

Other, net

     3,036        8,939   

Net change in:

    

Accounts receivable

     (30,173     (2,852

Inventories

     4,840        21,568   

Accounts payable

     34,050        (9,074

Amounts due customers including gas supply pass-through

     9,032        32,989   

Income tax receivable

     39,825        2,767   

Pension and other postretirement benefit contributions

     (3,097     (5,626

Other current assets and liabilities

     6,465        29,739   

Net cash provided by operating activities

     262,538        269,237   

Investing Activities

    

Additions to property, plant and equipment

     (146,971     (62,003

Acquisitions, net of cash acquired

     (4,303     (3,850

Proceeds from sale of assets

     552        626   

Other, net

     (25     (175

Net cash used in investing activities

     (150,747     (65,402

Financing Activities

    

Payment of dividends on common stock

     (9,727     (9,342

Issuance of common stock

     6,112        408   

Payment of long-term debt

     (31     (215

Net change in short-term debt

     (80,000     -   

Tax benefit on stock compensation

     767        576   

Net cash used in financing activities

     (82,879     (8,573

Net change in cash and cash equivalents

     28,912        195,262   

Cash and cash equivalents at beginning of period

     22,659        75,844   

Cash and Cash Equivalents at End of Period

   $ 51,571      $ 271,106   

The accompanying notes are an integral part of these consolidated condensed financial statements.

 

6


Table of Contents

CONDENSED STATEMENTS OF INCOME

ALABAMA GAS CORPORATION

(Unaudited)

 

     Three months ended
March 31,
 
(in thousands)    2011     2010  

Operating Revenues

   $ 269,572      $ 337,300   

Operating Expenses

    

Cost of gas

     131,749        197,156   

Operations and maintenance

     37,322        31,403   

Depreciation and amortization

     9,780        13,039   

Income taxes

    

Current

     21,571        24,655   

Deferred

     6,400        3,293   

Taxes, other than income taxes

     15,662        20,447   

Total operating expenses

     222,484        289,993   

Operating Income

     47,088        47,307   

Other Income (Expense)

    

Allowance for funds used during construction

     158        122   

Other income

     619        474   

Other expense

     (73     (163

Total other income

     704        433   

Interest Charges

    

Interest on long-term debt

     3,042        2,968   

Other interest expense

     575        526   

Total interest charges

     3,617        3,494   

Net Income

   $ 44,175      $ 44,246   

The accompanying notes are an integral part of these condensed financial statements.

 

7


Table of Contents

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

 

 

(in thousands)    March 31, 2011     December 31, 2010  

ASSETS

    

Property, Plant and Equipment

    

Utility plant

   $ 1,305,443      $ 1,292,611   

Less accumulated depreciation

     518,807        509,989   

Utility plant, net

     786,636        782,622   

Other property, net

     43        43   

Current Assets

    

Cash and cash equivalents

     41,190        16,910   

Accounts receivable

    

Gas

     87,661        136,800   

Other

     10,317        10,229   

Affiliated companies

     -        698   

Allowance for doubtful accounts

     (11,700     (14,200

Inventories

    

Storage gas inventory

     30,365        36,706   

Materials and supplies

     4,098        4,147   

Liquified natural gas in storage

     3,113        3,551   

Regulatory asset

     27,410        28,286   

Income tax receivable

     1,347        10,315   

Deferred income taxes

     26,808        27,302   

Prepayments and other

     3,638        4,223   

Total current assets

     224,247        264,967   

Other Assets

    

Regulatory asset

     95,947        105,365   

Pension and other postretirement assets

     8,713        9,201   

Deferred charges and other

     4,988        5,399   

Total other assets

     109,648        119,965   

TOTAL ASSETS

   $ 1,120,574      $ 1,167,597   

The accompanying notes are an integral part of these condensed financial statements.

 

8


Table of Contents

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

 

 

(in thousands, except share data)

   March 31, 2011      December 31, 2010  

LIABILITIES AND CAPITALIZATION

     

Capitalization

     

Preferred stock, cumulative $0.01 par value, 120,000 shares authorized

   $ -       $ -   

Common shareholder’s equity

     

Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at
March 31, 2011 and December 31, 2010

     20         20   

Premium on capital stock

     31,682         31,682   

Capital surplus

     2,802         2,802   

Retained earnings

     331,996         292,815   

Total common shareholder’s equity

     366,500         327,319   

Long-term debt

     200,762         200,793   

Total capitalization

     567,262         528,112   

Current Liabilities

     

Long-term debt due within one year

     5,000         5,000   

Notes payable to banks

     15,000         70,000   

Accounts payable

     73,868         83,515   

Affiliated companies

     1,687         -   

Accrued taxes

     60,089         48,476   

Customers’ deposits

     21,647         20,459   

Amounts due customers

     4,188         20,161   

Accrued wages and benefits

     7,419         11,851   

Regulatory liability

     79,120         75,703   

Other

     12,281         11,822   

Total current liabilities

     280,299         346,987   

Deferred Credits and Other Liabilities

     

Deferred income taxes

     147,686         141,780   

Pension and other postretirement liabilities

     4,453         4,733   

Regulatory liability

     94,837         110,447   

Long-term derivative instruments

     23,282         32,461   

Other

     2,755         3,077   

Total deferred credits and other liabilities

     273,013         292,498   

Commitments and Contingencies

                 

TOTAL LIABILITIES AND CAPITALIZATION

   $ 1,120,574       $ 1,167,597   

The accompanying notes are an integral part of these condensed financial statements.

 

9


Table of Contents

CONDENSED STATEMENTS OF CASH FLOWS

ALABAMA GAS CORPORATION

(Unaudited)

 

 

Three months ended March 31, (in thousands)    2011     2010  

Operating Activities

    

Net income

   $ 44,175      $ 44,246   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization

     9,780        13,039   

Deferred income taxes

     6,400        3,293   

Bad debt expense

     705        (2,454

Other, net

     1,226        2,578   

Net change in:

    

Accounts receivable

     8,085        (18,165

Inventories

     6,828        23,979   

Accounts payable

     (8,452     13,580   

Amounts due customers including gas supply pass-through

     9,032        32,989   

Income tax receivable

     8,968        2,130   

Pension and other postretirement benefit contributions

     (703     (2,403

Other current assets and liabilities

     9,415        13,170   

Net cash provided by operating activities

     95,459        125,982   

Investing Activities

    

Additions to property, plant and equipment

     (13,655     (14,311

Other, net

     814        (33

Net cash used in investing activities

     (12,841     (14,344

Financing Activities

    

Dividends

     (4,994     (9,340

Payment of long-term debt

     (31     (215

Net increases (decreases) in advances from affiliates

     1,687        (21,624

Net change in short-term debt

     (55,000     -   

Net cash used in financing activities

     (58,338     (31,179

Net change in cash and cash equivalents

     24,280        80,459   

Cash and cash equivalents at beginning of period

     16,910        9,460   

Cash and Cash Equivalents at End of Period

   $ 41,190      $ 89,919   

The accompanying notes are an integral part of these condensed financial statements.

 

10


Table of Contents

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

 

1. BASIS OF PRESENTATION

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2010, 2009 and 2008 included in the 2010 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year.

All adjustments to the unaudited financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consisted of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

During the first quarter of 2010, Alagasco identified an error in calculating the estimate of the allowance for doubtful accounts as of December 31, 2009. This error resulted in a $3 million overstatement to the allowance for doubtful accounts and a corresponding overstatement of net income by approximately $0.6 million (approximately $0.01 per diluted share) after reflecting the regulatory limits on Alagasco’s allowed rate of return for rate year ending September 30, 2010 in the application of Rate Stabilization and Equalization. The Company considered the net impact of this adjustment on the prior quarterly and year-end results, and the results of Alagasco and Energen for the year ended December 31, 2010 and determined that the amount was not material to these periods. The Company corrected this error in the first quarter of 2010.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period ended December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology.

Alagasco’s allowed range of return on average common equity remains 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months ended March 31, 2011, Alagasco had a net $3.3 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the three months ended March 31, 2010, Alagasco had an $8.8 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $1.3 million annual decrease and a $10.2 million annual increase in revenues became effective December 1, 2010 and 2009, respectively.

RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The

 

11


Table of Contents

O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. In the rate year ended September 30, 2010, $2.5 million of extraordinary bad debt expense was excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2010 and 2009.

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

In 1998, the APSC approved an Enhanced Stability Reserve, with a maximum funding level of $4 million, to which Alagasco could charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) negative individual large commercial and industrial customer budget revenue variances that exceed $250,000 during the rate year, if such losses caused Alagasco’s year-end return on average common equity (RCE) to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent. Prior to June 28, 2010, the APSC provided for accretions to the ESR of no more than $40,000 monthly until the maximum funding level was achieved, following a year in which a charge against the ESR was made. The APSC’s June 28, 2010 order approved Alagasco’s lower depreciation rates and approved standing authority for Alagasco to charge items to the ESR in excess of its funded balance and to allocate each year from the refundable negative salvage costs that are being refunded to customers over the nine year period the amount necessary to clear the debit balance in the ESR each September 30, subject to APSC-approved guidelines. The APSC also approved the amortization of the ESR into rates over a five year period in cases where the ESR is unfunded or underfunded, subject to APSC-approved guidelines. As a result of these changes in the funding mechanism for the ESR, the APSC suspended the $40,000 per month accruals to the ESR during the nine year period when the refundable negative salvage costs are being refunded to customers.

Following a vote on September 7, 2010, the APSC, by order dated November 1, 2010, approved expansion of the ESR to include extraordinary O&M charges related to environmental response costs and to self insurance costs that exceed $1 million per occurrence. In addition, the APSC raised the thresholds on items that may be charged to the ESR as follows: (1) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single event that results in more than $275,000 of increased O&M; (2) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a combination of extraordinary O&M events that result in more than $412,500 of increased O&M; and (3) negative individual large commercial and industrial customer budget variances that exceed $350,000. Charges to the ESR relating to extraordinary O&M expenses can only be made when the Company’s year-end return on average common equity for RSE, not including the ESR charge, is below the midpoint of the APSC-approved return on equity range and only to the extent necessary to bring the RCE to the midpoint of the range. Charges to the ESR relating to negative individual large commercial and industrial customer revenue variances can only be made if such losses cause the RCE to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent, and then only to the extent necessary to bring the RCE up to the midpoint of the range. In the event that Alagasco’s RCE at September 30 of the related year is above the midpoint, any debit balance in the ESR shall remain in the ESR for recovery in subsequent years subject to the established guidelines. Additionally, the APSC, while confirming the five year amortization period established in the June 28, 2010 order for charges to the ESR in cases where the ESR is unfunded or underfunded, limited the amortization expense to $660,000 annually, with any excess amortization expense over $660,000 in any rate year being carried over and amortized in future rate years until full amortization of the ESR debit balance is complete. The APSC also raised the $40,000 per month accruals to $55,000 per month, but suspended the accruals pending further order of the APSC. Finally, the APSC established guidelines for the documentation, reporting and approval of rate recovery of items charged to the ESR.

 

12


Table of Contents

In connection with the above, Alagasco expects to recover certain manufactured gas plant site remediation costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory account of $4.1 million and $3.8 million as of March 31, 2011 and December 31, 2010, respectively, as more fully described in Note 9, Commitments and Contingencies.

3. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include over-the-counter (OTC) swaps and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net loss position with ten of its active counterparties and in a net gain position with the remaining one at March 31, 2011. The four largest counterparty positions at March 31, 2011, Morgan Stanley Capital Group, Inc., Citibank, N.A., Shell Energy North America (US), L.P. and J Aron & Company, constituted approximately $64.6 million, $60.5 million, $45.3 million and a $34.3 million, respectively, of Energen Resources’ net loss on fair value of derivatives. Barclays Bank PLC was the only counterparty in a gain position of $8.1 million.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of March 31, 2011, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company may also enter into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding New York Mercantile Exchange hedge and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

The following tables detail the fair values of commodity contracts by business segment on the balance sheets:

 

(in thousands)    March 31, 2011  
     Oil and
Gas
Operations
    Natural Gas
Distribution
     Total  
        

Derivative assets or (liabilities) designated as hedging instruments

       

Accounts receivable

   $ 62,236      $ -       $ 62,236   

Long-term asset derivative instruments

     1,901     -         1,901   

Total derivative assets

     64,137        -         64,137   

Accounts receivable

     (46,954 )*      -         (46,954

Accounts payable

     (94,219     -         (94,219

 

13


Table of Contents
(in thousands)    March 31, 2011  
     Oil and Gas
Operations
    Natural Gas
Distribution
    Total  
        

Long-term liability derivative instruments

     (164,648     -        (164,648

Total derivative liabilities

     (305,821     -        (305,821

Total derivatives designated

     (241,684     -        (241,684

Derivative assets or (liabilities) not designated as hedging instruments

      

Accounts payable

     (94     (27,003     (27,097

Long-term liability derivative instruments

     -        (23,282     (23,282

Total derivative liabilities

     (94     (50,285     (50,379

Total derivatives not designated

     (94    
(50,285

    (50,379

Total derivatives

   $ (241,778   $ (50,285   $ (292,063

 

(in thousands)    December 31, 2010  
     Oil and Gas
Operations
    Natural Gas
Distribution
    Total  
        

Derivative assets or (liabilities) designated as hedging instruments

      

Accounts receivable

   $ 85,867      $ -      $ 85,867   

Long-term asset derivative instruments

     3,156     -        3,156   

Total derivative assets

     89,023        -        89,023   

Accounts receivable

     (25,315 )*      -        (25,315

Accounts payable

     (50,508     -        (50,508

Long-term liability derivative instruments

     (83,631     -        (83,631

Total derivative liabilities

     (159,454     -        (159,454

Total derivatives designated

     (70,431     -        (70,431

Derivative assets or (liabilities) not designated as hedging instruments

      

Accounts payable

     (110     (27,906     (28,016

Long-term liability derivative instruments

     -        (32,461     (32,461

Total derivative liabilities

     (110     (60,367     (60,477

Total derivatives not designated

     (110     (60,367     (60,477

Total derivatives

   $ (70,541   $ (60,367   $ (130,908
*

Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $88.4 million and a net $26.8 million deferred tax asset included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in OCI as of March 31, 2011 and December 31, 2010, respectively.

Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet with a corresponding regulatory asset or liability. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff.

The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:

 

(in thousands)    Location on
Income Statement
    

Three months ended

March 31, 2011

   

Three months ended

March 31, 2010

 

Gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($59.4) million and $34 million

     -       $ (96,873   $ 55,469   

Gain reclassified from accumulated OCI into income (effective portion)

     Operating revenues       $ 7,591      $ 36,724   

Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)

     Operating revenues       $ (1,651   $ 1,704   

 

14


Table of Contents

The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:

 

(in thousands)    Location on
Income Statement
    

Three months ended

March 31, 2011

   

Three months ended

March 31, 2010

 

Loss recognized in income on derivative

     Operating revenues       $ (1   $ (2

As of March 31, 2011, $43.4 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of March 31, 2011, the Company had 9 thousand barrels (MBbl) of oil hedges which expire during 2011 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges.

Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:

 

Production

    Period

  

Total Hedged

Volumes

  

Average Contract

Price

     Description

Natural Gas

2011

   10.7 Bcf                    $6.47 Mcf         NYMEX Swaps
   29.2 Bcf                  $5.65 Mcf       Basin Specific Swaps

2012

   11.0 Bcf                  $5.07 Mcf       NYMEX Swaps
   29.5 Bcf                  $4.60 Mcf       Basin Specific Swaps

2013

   8.8 Bcf                  $5.30 Mcf       NYMEX Swaps
   25.1 Bcf                  $4.88 Mcf       Basin Specific Swaps

Oil

2011

   3,249 MBbl                  $78.69 Bbl       NYMEX Swaps

2012

   3,744 MBbl                  $82.52 Bbl       NYMEX Swaps

2013

   3,199 MBbl                  $85.32 Bbl       NYMEX Swaps

2014

   2,742 MBbl                  $87.44 Bbl       NYMEX Swaps

Oil Basis Differential

2011

   1,557 MBbl                    *         Basis Swaps

2012

   672 MBbl                  *       Basis Swaps

Natural Gas Liquids

2011

   31.9 MMGal                  $0.90 Gal       Liquids Swaps

2012

   39.9 MMGal                  $0.86 Gal       Liquids Swaps

*    Average contract prices are not meaningful due to the varying nature of each contract.

Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:

 

Production

    Period

  

Total Hedged

Volumes

           Description

2011

   8.1 Bcf                   NYMEX Swaps

2012

   17.2 Bcf                   NYMEX Swaps

2013

   1.5 Bcf                         NYMEX Swaps

As of March 31, 2011, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014 and December 31, 2013, respectively.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The fair value hierarchy that prioritizes the inputs used to measure fair value is as follows:

 

Level 1 –

Unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2 –

Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;

Level 3 –

Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumptions that market value participants would use in pricing the asset or liability.

 

15


Table of Contents

Derivative commodity instruments are over-the-counter (OTC) derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to New York Mercantile Exchange (NYMEX) natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and liquids swaps.

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

 

      March 31, 2011  
(in thousands)    Level 2*     Level 3*     Total  

Current assets

   $ (17,467   $ 32,749      $ 15,282   

Current liabilities

     (116,455     (4,861     (121,316

Noncurrent liabilities

     (175,068     (10,961     (186,029

Net derivative asset (liability)

   $ (308,990   $ 16,927      $ (292,063

 

      December 31, 2010  
(in thousands)    Level 2*     Level 3*     Total  

Current assets

   $ 10,316      $ 50,236      $ 60,552   

Current liabilities

     (76,527     (1,997     (78,524

Noncurrent liabilities

     (107,452     (5,484     (112,936

Net derivative asset (liability)

   $ (173,663   $ 42,755      $ (130,908
*

Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of March 31, 2011, Alagasco had $27 million and $23.3 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities and noncurrent liabilities, respectively. As of December 31, 2010, Alagasco had $27.9 million and $32.5 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of March 31, 2011 and December 31, 2010.

The tables below set forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:

 

(in thousands)    Three months ended
March 31, 2011
    Three months ended
March 31, 2010
 

Balance at beginning of period

   $ 42,755      $ 64,517   

Realized losses

     702        4   

Unrealized gains (losses) relating to instruments held at the reporting date

     (11,274     66,671   

Settlements during period

     (15,256     (16,752

Balance at end of period

   $ 16,927      $ 114,440   

 

16


Table of Contents

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

 

(in thousands, except per share amounts)   

Three months ended

March 31, 2011

    

Three months ended

March 31, 2010

 
      Net
Income
     Shares      Per Share
Amount
     Net Income      Shares      Per Share
Amount
 

Basic EPS

   $ 94,268         72,001       $ 1.31       $ 116,710         71,810       $ 1.63   

Effect of dilutive securities

                 

Stock options

        233               214      

Non-vested restricted stock

              6                           15            

Diluted EPS

   $ 94,268         72,240       $ 1.30       $ 116,710         72,039       $ 1.62   

For the three months ended March 31, 2011 and 2010, the Company had 293,978 and 479,820, respectively, options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months ended March 31, 2011 and 2010, the Company had no shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

5. SEGMENT INFORMATION

The Company principally is engaged in two business segments: the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution).

 

     

Three months ended

March 31,

 
(in thousands)    2011     2010  

Operating revenues

    

Oil and gas operations

   $ 216,792      $ 237,614   

Natural gas distribution

     269,572        337,300   

Total

   $ 486,364      $ 574,914   

Operating income (loss)

    

Oil and gas operations

   $ 85,059      $ 117,285   

Natural gas distribution

     75,059        75,255   

Eliminations and corporate expenses

     (237     (342

Total

   $ 159,881      $ 192,198   

Other income (expense)

    

Oil and gas operations

   $ (5,447   $ (5,871

Natural gas distribution

     (2,913     (3,061

Eliminations and other

     23        (214

Total

   $ (8,337   $ (9,146

Income before income taxes

   $ 151,544      $ 183,052   

 

(in thousands)    March 31, 2011      December 31, 2010  

Identifiable assets

     

Oil and gas operations

   $ 3,231,375       $ 3,160,601   

Natural gas distribution

     1,120,574         1,166,899   

Eliminations and other

     37,516         36,060   

Total

   $ 4,389,465       $ 4,363,560   

 

17


Table of Contents

6. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

 

     

Three months ended

March 31,

 
(in thousands)    2011     2010  

Net income

   $ 94,268      $ 116,710   

Other comprehensive income (loss):

    

Current period change in fair value of derivative instruments, net of tax of ($59.4) million and $34 million

     (96,873     55,469   

Reclassification adjustment for derivative instruments, net of tax of ($2.3) million and ($14.6) million

     (3,683     (23,825

Pension and postretirement plans, net of tax of $0.4 million and $0.3 million

     682        628   

Comprehensive income (loss)

   $ (5,606   $ 148,982   

 

(in thousands)    March 31, 2011     December 31, 2010  

Unrealized loss on hedges, net of tax of ($88.4) million and ($26.8) million

   $ (144,223   $ (43,667

Pension and postretirement plans, net of tax of ($16.2) million and ($16.5) million

     (30,048     (30,730

Accumulated other comprehensive loss

   $ (174,271   $ (74,397

7. STOCK COMPENSATION

1997 Stock Incentive Plan

The 1997 Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. On April 27, 2011, the Company amended the 1997 Stock Incentive Plan to increase the number of shares authorized for issuance by 3,000,000 shares. This increase resulted in 3,794,326 shares being available for future issuances. Options granted under the Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 293,978 non-qualified option shares during the first quarter of 2011 with a grant-date fair value of $19.65.

2004 Stock Appreciation Rights Plan

The Energen 2004 Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 189,984 awards during the first quarter of 2011. These awards had a fair value of $26.74 as of March 31, 2011.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During 2011, Energen Resources awarded 5,076 Petrotech units with a three year vesting period. These awards had a fair value of $61.66 as of March 31, 2011.

1997 Deferred Compensation Plan

During the three months ended March 31, 2011, the Company had noncash purchases of approximately $0.4 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

 

18


Table of Contents

8. EMPLOYEE BENEFIT PLANS

The components of net pension expense for the Company’s two defined benefit non-contributory pension plans and certain nonqualified supplemental pension plans were:

 

     

Three months ended

March 31,

 
(in thousands)    2011     2010  

Service cost

   $ 2,293      $ 2,144   

Interest cost

     2,740        2,841   

Expected long-term return on assets

     (3,868     (3,229

Actuarial loss

     1,609        1,443   

Prior service cost amortization

     124        124   

Net periodic expense

   $ 2,898      $ 3,323   

The Company anticipates required contributions of approximately $7.2 million during 2011 to the pension plans. The Company expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. It is not anticipated that the funded status of the pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2011. For the three months ending March 31, 2011, the Company made benefit payments aggregating $2.2 million to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $105,000 through the remainder of 2011.

The components of net periodic postretirement benefit expense for the Company’s postretirement benefit plans were:

 

     

Three months ended

March 31,

 
(in thousands)    2011     2010  

Service cost

   $ 442      $ 516   

Interest cost

     1,111        1,208   

Expected long-term return on assets

     (1,104     (996

Transition amortization

     479        479   

Net periodic expense

   $ 928      $ 1,207   

For the three months ended March 31, 2011, the Company made contributions aggregating $0.9 million to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $2.8 million to postretirement benefit plan assets through the remainder of 2011. During the first quarter of 2010, the Company recognized $128,000 in income tax expense resulting from a reduction in deferred tax asset related to changes in the tax treatment for the Medicare Part D subsidy under the recently enacted health care reform legislation.

9. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $138 million through September 2024. During the three months ending March 31, 2011 and 2010, Alagasco recognized approximately $14.3 million and $14.8 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 229 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the

 

19


Table of Contents

substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At March 31, 2011, the fixed price purchases under these guarantees had a maximum term outstanding through March 2012 and an aggregate purchase price of $3.3 million with a market value of $3.3 million.

Income Taxes: Energen and its subsidiaries’ 2007 and 2008 federal consolidated income tax returns have been under Internal Revenue Service (IRS) examination. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company has filed a petition in United States Tax Court challenging the IRS assessment. Although the timing of the resolution is highly uncertain, an unfavorable outcome in this matter would result in income tax cash payments of approximately $31 million with no material impact to the Company and Alagasco’s effective income tax rate.

The Company and Alagasco have on-going income tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of the completion of various audits and the expiration of statute of limitations. Although the timing and outcome of these tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Other: Various other pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability.

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company’s financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs. Remediation of the Huntsville, Alabama manufactured gas plant site, as discussed below, may also result in unanticipated costs.

Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns), and five manufactured gas distribution sites (one of which it still owns). Subject to the following paragraph discussing the Huntsville, Alabama manufactured gas plant site, an investigation of the sites does not indicate the present need for remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco’s share, if any, of such costs will not materially affect the financial position of Alagasco.

In June 2009, Alagasco received a General Notice Letter from the United States Environmental Protection Agency (EPA) identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949 with such sale being approved by the APSC. While Alagasco no longer owns the Huntsville site, the Company and the current site owner have entered into a Consent Order, developed an action plan for the site and are in the process of executing the plan. Based on information available at this time, Alagasco estimates that it may incur costs associated with the site of approximately $4.4 million, including costs previously incurred. During the three months ended March 31, 2011, the Company incurred costs of $1 million associated with the site. As of March 31, 2011, the Company has accrued a contingent liability of $2.5 million in addition to the costs previously incurred. The estimate assumes an action plan for excavation of affected soil and sediment only. If it is determined that a greater scope of work is appropriate, then actual costs

 

20


Table of Contents

will likely exceed the estimate. Alagasco expects to recover such costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

New Mexico Audits: During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The Department proposes a change in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the Office of Natural Resources Revenue (ONRR) to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004 forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to those allowed under previous audits and are inconsistent with the Company’s understanding of industry practice. The Company intends to vigorously contest the Order and has requested additional information from the Department to determine the basis of its conclusion. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order and no amount has been accrued as of March 31, 2011.

10. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, approximates $429.4 million and has a carrying value of $410.8 million at March 31, 2011. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, approximates $205.9 million and has a carrying value of $205.8 million at March 31, 2011. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At March 31, 2011 and December 31, 2010, Alagasco’s finance receivable totaled $9 million and $8.8 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. At March 31, 2011 and December 31, 2010, Alagasco had an allowance for credit losses related to its finance receivables of $482,000 and $447,000, respectively. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $317,000 as of March 31, 2011.

The following table sets forth a summary of changes in the allowance for credit losses as follows:

 

(in thousands)        

Allowance for credit losses as of December 31, 2010

   $ 447   

Provision

     35   

Allowance for credit losses as of March 31, 2011

   $ 482   

11. REGULATORY ASSETS AND LIABILITIES

The following table details regulatory assets and liabilities on the balance sheets:

 

      March 31, 2011      December 31, 2010  
        
(in thousands)    Current      Noncurrent      Current      Noncurrent  

Regulatory assets:

           

Pension and postretirement assets

   $ 166       $ 59,657       $ 132       $ 60,284   

Accretion and depreciation for asset retirement obligation

     -         8,789         -         8,681   

 

21


Table of Contents
      March 31, 2011      December 31, 2010  
        
(in thousands)    Current      Noncurrent      Current      Noncurrent  

Risk management activities

     27,003         23,282         27,906         32,461   

RSE adjustment

     25         -         25         -   

Enhanced stability reserve

     -         4,124         -         3,794   

Other

     216         95         223         145   

Total regulatory assets

   $ 27,410       $ 95,947       $ 28,286       $ 105,365   

Regulatory liabilities:

           

RSE adjustment

   $ 7,398       $ -       $ 4,147       $ -   

Unbilled service margin

     15,294         -         34,197         -   

Postretirement liabilities

     -         856         -         754   

Gas supply adjustment

     36,737         -         14,990         -   

Asset removal costs, net

     -         7,306         -         6,913   

Refundable negative salvage

     19,658         74,322         22,336         90,504   

Asset retirement obligation

     -         11,525         -         11,439   

Other

     33         828         33         837   

Total regulatory liabilities

   $ 79,120       $ 94,837       $ 75,703       $ 110,447   

12. ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the periods incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company.

During the three months ended March 31, 2011, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

 

(in thousands)        

Balance of ARO as of December 31, 2010

   $ 97,415   

Liabilities incurred

     1,164   

Liabilities settled

     (509

Accretion expense

     1,649   

Balance of ARO as of March 31, 2011

   $ 99,719   

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exist. Alagasco recorded a conditional asset retirement obligation, on a discounted basis of $11.5 million and $11.4 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of March 31, 2011 and December 31, 2010, respectively. The conditional asset retirement obligations as of December 31, 2010 reflect the re-estimation of removal costs associated with Alagasco’s revised depreciation rate. The costs associated with asset retirement obligations are currently either being recovered in rates or are probable of recovery in future rates.

Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Regulatory liabilities for accumulated asset removal costs of $7.3 million and $6.9 million for March 31, 2011 and December 31, 2010, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets. As of March 31, 2011, the Company recognized $19.7 million and $74.3 million of refundable negative salvage as regulatory liabilities in current liabilities and deferred credit and other liabilities, respectively, on the balance sheet in response to the June 28, 2010 APSC order.

13. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

In April 2011, Energen completed the purchase of unproved leasehold oil properties for a cash purchase price of approximately $37 million covering an estimated 11,000 net acres in the Permian Basin.

 

22


Table of Contents

On December 15, 2010, Energen completed the purchase of certain oil properties in the Permian Basin for a cash purchase price of $74 million. This purchase had an effective date of December 1, 2010. Energen acquired proved reserves of approximately 7.6 million barrels of oil equivalents (MMBOE). Of the proved reserves acquired, an estimated 92 percent are undeveloped. Approximately 62 percent of the acquisition’s estimated proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 15, 2010 (including the effects of closing adjustments).

 

(in thousands)        

Consideration given

  

Cash (net)

   $ 73,630   

Recognized amounts of identifiable assets acquired and liabilities assumed

  

Proved properties

   $ 41,066   

Unproved leasehold properties

     32,500   

Accounts receivable

     143   

Asset retirement obligation

     (79

Total identifiable net assets

   $ 73,630   

The impact to operating revenues and operating income from this acquisition was not material for the three months ended March 31, 2011.

On December 9, 2010, Energen completed the asset purchase of certain oil properties in the Permian Basin from SandRidge Energy, Inc. for a cash purchase price of $103 million (subject to closing adjustments). This purchase had an effective date of December 9, 2010. Energen acquired no proved reserves related to this acquisition. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

On September 30, 2010, Energen completed the purchase of certain oil properties in the Permian Basin for a cash price of $189 million (subject to closing adjustments). This purchase had an effective date of September 1, 2010. Energen acquired proved reserves of approximately 18 MMBOE. Of the proved reserves acquired, an estimated 89 percent are undeveloped. Approximately 65 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 13 percent. Energen Resources used its internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of September 30, 2010. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

 

(in thousands)        

Consideration given

  

Cash (net)

   $ 188,531   

Recognized amounts of identifiable assets acquired and liabilities assumed

  

Proved properties

   $ 152,050   

Unproved leasehold properties

     35,360   

Accounts receivable

     1,375   

Asset retirement obligation

     (142

Accounts payable

     (112

Total identifiable net assets

   $ 188,531   

Included in the Company’s consolidated results of operations for the three months ended March 31, 2011, is $7.6 million of operating revenues and $3.7 million in operating income resulting from the operation of the properties acquired above.

 

23


Table of Contents

14. RECENTLY ISSUED ACCOUNTING STANDARDS

In July 2010, the FASB issued ASU No. 2010-20, Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses. These disclosures as of the end of a reporting period are effective for the interim and annual reporting periods ending on or after December 15, 2010. The disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The disclosures required under this standard have been included in Note 10, Financial Instruments.

On January 1, 2010, the Company adopted Accounting Standard Update (ASU) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures About Fair Value Measurements. These disclosures are effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. The disclosures required under this standard have been included in Note 3, Derivative Commodity Instruments.

 

24


Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

RESULTS OF OPERATIONS

Energen’s net income totaled $94.3 million ($1.30 per diluted share) for the three months ended March 31, 2011 compared with net income of $116.7 million ($1.62 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen’s oil and gas subsidiary, had net income for the three months ended March 31, 2011, of $49.7 million as compared with $71.7 million in the same quarter in the previous year. Lower commodity prices (approximately $21 million after-tax), increased administrative expense (approximately $2 million after-tax), higher depreciation, depletion and amortization (DD&A) expense (approximately $2 million after-tax) and increased lease operating expense excluding production taxes (approximately $2 million after-tax) were partially offset by increased production volumes (approximately $9 million after-tax). Energen’s natural gas utility, Alagasco, reported net income of $44.2 million in both the first quarter of 2011 and 2010.

Oil and Gas Operations

Revenues from oil and gas operations fell 8.8 percent to $216.8 million for the three months ended March 31, 2011 largely as a result of decreased realized natural gas and oil commodity prices partially offset by higher oil and natural gas liquid production volumes. During the current quarter, revenue per unit of production for natural gas decreased 23.3 percent to $5.52 per thousand cubic feet (Mcf), while oil revenue per unit of production fell 4.5 percent to $75.70 per barrel. Natural gas liquids revenue per unit of production rose 1.1 percent to an average price of $0.89 per gallon.

Production in the current quarter increased largely due to higher volumes related to the September 2010 and December 2010 purchases of certain Permian Basin oil properties and field development. Negatively impacting production was the effect of severe winter weather and wildfires in the Permian Basin along with normal production declines. Natural gas production in the first quarter declined slightly to 17.3 billion cubic feet (Bcf), oil volumes increased 15 percent to 1,364 thousand barrels (MBbl) and natural gas liquids production rose 4.8 percent to 19.7 million gallons (MMgal). Natural gas comprised approximately 61 percent of Energen Resources’ production for the current quarter.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. Energen Resources recorded a pre-tax gain of $42,000 on the sale of various properties in the first quarter of 2011. In the first quarter of 2010, Energen Resources recorded a pre-tax gain of $0.6 million largely from the sale of certain property in the Black Warrior Basin.

Operations and maintenance (O&M) expense increased $6.3 million for the quarter. Lease operating expense (excluding production taxes) increased $3.1 million for the quarter largely due to the September and December 2010 acquisitions of Permian Basin oil properties (approximately $0.9 million), higher ad valorem taxes (approximately $0.8 million), additional nonoperated costs ($0.8 million) and higher gathering system expense ($0.5 million). Administrative expense increased $3.7 million for the three months ended March 31, 2011 largely due to Company’s performance-based compensation plans (approximately $2.4 million), increased labor costs (approximately $0.8 million) partially offset by decreased legal expenses (approximately $0.5 million). Exploration expense fell $0.6 million in the first quarter of 2011.

Energen Resources’ DD&A expense for the quarter rose $2.7 million. The average depletion rate for the current quarter was $10.67 per barrel of oil equivalent (BOE) as compared to $10.54 per BOE in the same period a year ago. The increase in the current quarter per unit DD&A rate, which contributed approximately $0.6 million to the increase in DD&A expense, was largely due to higher rates resulting from the acquisition of oil properties and an increase in development costs. Increased production volumes contributed approximately $2 million to the increase in DD&A expense for the three months ended March 31, 2011.

Energen Resources’ expense for taxes other than income taxes was $2.3 million higher in the three months ended March 31, 2011 largely due to production-related taxes. In the current quarter, higher oil and natural gas liquid commodity market prices contributed approximately $1.9 million to the increase in production-related taxes. Also increasing production-related taxes were higher oil and natural gas liquid production volumes

 

25


Table of Contents

which contributed approximately $0.4 million for the quarter. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues decreased $67.7 million for the quarter largely due to a decline in gas costs and lower customer usage partially offset by adjustments from the utility’s rate setting mechanisms. During the first quarter of 2011, Alagasco had a $3.3 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the first quarter of 2010, Alagasco had an $8.8 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Weather that was 16.3 percent warmer than in the same quarter last year contributed to a 15.8 percent decrease in residential sales volumes and a 12.7 percent fall in commercial and industrial customer sales volumes. Transportation volumes increased 2.3 percent in period comparisons. A decrease in gas costs and a decrease in gas purchase volumes resulted in a 33.2 percent decrease in cost of gas for the quarter. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense increased 18.8 percent in the current quarter primarily due to increased labor-related costs (approximately $1 million), higher marketing expenses (approximately $0.7 million) and increased distribution expense (approximately $0.9 million). Also significantly impacting the increase in O&M expense was the increase to bad debt expense (approximately $3.2 million) which is attributable to the prior year correction of a $3 million error identified by Alagasco during the first quarter of 2010 in the calculation of the estimate of the allowance for doubtful accounts as of December 31, 2009. See Note 1, Basis of Presentation, in the Notes to Unaudited Condensed Financial Statements for further discussion.

A 25 percent decrease in depreciation expense in the current quarter was primarily due to revised depreciation rates effective June 1, 2010, partially offset by the extension and replacement of the utility’s distribution system and replacement of its support systems. The revised depreciation rates decreased depreciation expense by approximately $4.1 million for the three months ended March 31, 2011 from expense amounts calculated using the prior depreciation rate. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the past five years. Approved depreciation rates averaged approximately 3.1 percent and 4.4 percent in the three months ended March 30, 2011 and 2010, respectively.

Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company decreased $0.6 million in the first quarter of 2011. Income tax expense for the Company decreased $9.1 million in the current quarter largely due to lower pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

 

Cash flows from operations for the year-to-date were $262.5 million as compared to $269.2 million in the prior period. Net income decreased during period comparisons primarily due to lower realized commodity prices partially offset by increased production volumes at Energen Resources. Deferred income taxes increased in the current year due to the tax effect of higher 2011 capital expenditures and the 2011 impact of bonus depreciation. The Company’s working capital needs were also influenced by accrued taxes, commodity prices and the timing of payments. During the first quarter of 2011, the income tax receivable decreased approximately $39.8 million primarily from an income tax refund associated with the 2010 impact of bonus depreciation and the write-off of Alabama shale leasehold. Working capital needs at Alagasco were additionally affected by lower gas costs and increased storage gas inventory compared to the prior period.

 

26


Table of Contents

The Company had a net outflow of cash from investing activities of $150.7 million for the three months ended March 31, 2011 primarily due to additions of property, plant and equipment of $151.3 million. Energen Resources incurred on a cash basis $137.5 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. Utility capital expenditures on a cash basis totaled $13.7 million year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities.

The Company had a net cash use of $82.9 million for financing activities in the year-to-date primarily due to a decrease in short-term borrowings and the payment of dividends to common shareholders.

Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2011, the Company expects its oil and gas capital spending to total approximately $786 million, including $681 million for existing properties, $61 million for exploration and $48 for unproved leasehold acquisitions.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company primarily expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity.

Natural Gas Distribution

Alagasco is subject to regulation by the APSC and is allowed to earn a range of return on average equity of 13.15 percent to 13.65 percent. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Given existing economic conditions, Alagasco expects only modest growth in equity as annual dividends are typically paid by the utility.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July, 2010. Refunds of negative salvage costs to customers through lower tariff rates were $18.9 million and $2.7 million for the period January through March 2011 and in December, 2010, respectively. Alagasco anticipates refunding approximately $19.7 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $74.3 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over an eight year period beginning December 1, 2011. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the ESR and other commission-approved charges. On November 1, 2010, the APSC specifically approved adjustments to the total amount refundable to include items originally approved in the APSC’s 1998 order establishing the ESR, environmental response costs and self insurance costs above $1 million per occurrence. The refunds as of December, 2010 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the past five years.

Alagasco is a mature utility operating in a slow-growth service area. Over the last five years, Alagasco’s customer count has declined at a rate of approximately 1 percent annually despite above-average levels of penetration along existing distribution lines. To increase its customer base, the utility is capitalizing on opportunities to expand its distribution lines to areas with economic growth potential and pursuing the

 

27


Table of Contents

acquisition of mutually beneficial municipally owned gas systems in Alabama. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices and the underlying current and future economic conditions facing the utility’s customer base.

Another aspect of growth is usage per customer. Throughout the country, customer use of natural gas has declined over the years in large part due to energy-efficiencies in home construction and appliances and conservation. Alagasco’s marketing emphasis in this area is directed toward retention and increasing end-use applications by existing customers.

Alagasco maintains an investment in storage gas that is expected to average approximately $39 million in 2011 but will vary depending upon the price of natural gas. During 2011, Alagasco plans to invest an estimated $76 million in utility capital expenditures for normal distribution and support systems. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities.

Weather Event

On April 27, 2011, severe weather including a number of deadly tornados caused significant damage to several communities in Alabama served by Alagasco. These communities include Tuscaloosa, Pleasant Grove, Hueytown and parts of Birmingham. Alagasco is currently reviewing the impact of these storms to its distribution system and customers. Related costs are expected to be recovered through the Enhanced Stability Reserve to the extent that such costs result in Alagasco’s return on average common equity falling below the midpoint of the APSC-approved return. Energen Resources is not expected to be materially impacted by the storms.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment and commercial banks and energy-trading firms. At March 31, 2011, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net loss position with ten of its active counterparties and in a net gain position with the remaining one at March 31, 2011. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

Alagasco also enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:

 

Production

    Period

  

Total Hedged

Volumes

  

Average Contract

Price

     Description  

Natural Gas

                      

2011

   10.7 Bcf                  $6.47 Mcf         NYMEX Swaps   
   29.2 Bcf                  $5.65 Mcf         Basin Specific Swaps   

2012

   11.0 Bcf                  $5.07 Mcf         NYMEX Swaps   
   29.5 Bcf                  $4.60 Mcf         Basin Specific Swaps   

2013

   8.8 Bcf                  $5.30 Mcf         NYMEX Swaps   
   25.1 Bcf                  $4.88 Mcf         Basin Specific Swaps   

2014

   *3.0 Bcf                  $5.72 Mcf         NYMEX Swaps   
     *6.0 Bcf                  $5.34 Mcf         Basin Specific Swaps   

Oil

                      

2011

   3,249 MBbl                  $78.69 Bbl         NYMEX Swaps   

2011

   *191 MBbl                  $112.76 Bbl           NYMEX Swaps   

2012

   3,744 MBbl                  $82.52 Bbl         NYMEX Swaps   

2012

   *137 MBbl                  $111.05 Bbl           NYMEX Swaps   

2013

   3,199 MBbl                  $85.32 Bbl         NYMEX Swaps   

2013

   *97 MBbl                  $107.65 Bbl           NYMEX Swaps   

2014

   2,742 MBbl                  $87.44 Bbl         NYMEX Swaps   

2014

   *76 MBbl                  $105.42 Bbl           NYMEX Swaps   

Oil Basis Differential

                      

2011

   1,557 MBbl                    **           Basis Swaps   

2011

   *99MBbl                  **         Basis Swaps   

2012

   672 MBbl                  **         Basis Swaps   

2012

   *81MBbl                  **         Basis Swaps   

Natural Gas Liquids

                      

2011

   31.9 MMGal                  $0.90 Gal         Liquids Swaps   

2012

   39.9 MMGal                  $0.86 Gal         Liquids Swaps   

2013

   *35.2 MMGal                  $1.02 Gal         Liquids Swaps   

 

28


Table of Contents

*           Contract entered into subsequent to March 31, 2011

**         Average contract prices are not meaningful due to the varying nature of each contract.

Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:

 

Production

    Period

  

Total Hedged

Volumes

         Description

2011

   8.1 Bcf                   NYMEX Swaps

2012

   17.2 Bcf                   NYMEX Swaps

2013

   1.5 Bcf                     NYMEX Swaps

Realized prices are anticipated to be lower than New York Mercantile Exchange (NYMEX) prices primarily due to basis differences and other factors.

See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for information regarding the Company’s policies on fair value measurement.

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

 

      March 31, 2011  
(in thousands)    Level 2*     Level 3*     Total  

Current assets

   $ (17,467   $ 32,749      $ 15,282   

Current liabilities

     (116,455     (4,861     (121,316

Noncurrent liabilities

     (175,068     (10,961     (186,029

Net derivative asset (liability)

   $ (308,990   $ 16,927      $ (292,063

 

      December 31, 2010  
(in thousands)    Level 2*     Level 3*     Total  

Current assets

   $ 10,316      $ 50,236      $ 60,552   

Current liabilities

     (76,527     (1,997     (78,524

Noncurrent liabilities

     (107,452     (5,484     (112,936

Net derivative asset (liability)

   $ (173,663   $ 42,755      $ (130,908

 

*

Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of March 31, 2011, Alagasco had $27 million and $23.3 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities and noncurrent liabilities, respectively. As of December 31, 2010, Alagasco has $27.9 million and $32.5 million of derivative instruments which are classified as Level 2 fair values and are included in the table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of March 31, 2011 and December 31, 2010.

Level 3 assets and liabilities as of March 31, 2011 represent an immaterial amount of total assets and liabilities. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $44 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations for Level 3 derivatives would be immaterial due to derivative instruments qualifying as cash flow hedges. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

Stock Repurchases

Energen periodically considers stock repurchases as a capital investment. Energen may buy shares on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. The Company did not repurchase shares of common stock for this program during the three months ended March 31, 2011. The Company expects any future stock repurchases to be funded through internally generated cash flow or through the utilization of its credit facilities. During the three months ended

 

29


Table of Contents

March 31, 2011, the Company had noncash purchases of approximately $0.6 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation plans. The Company utilized internally generated cash flows in payment of the related tax withholdings.

Credit Facilities

On October 29, 2010, Energen and Alagasco entered into an $850 million and a $150 million, respectively, three-year syndicated unsecured credit facility (syndicated credit facilities) with domestic and foreign lenders. Energen obligations under the $850 million syndicated credit facility are unconditionally guaranteed by Energen Resources. These syndicated credit facilities replace the majority of the Company’s short term credit facilities which were available to Energen and Alagasco. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of 65 percent for each of the Company and Alagasco. The Company currently has available credit facilities as follows:

 

(in thousands)    Current Term      Energen      Alagasco      Total  

Syndicated Credit Facility

     10/29/2013       $ 850,000       $ 150,000       $ 1,000,000   

Bryant Bank

     11/1/2011         -         9,000         9,000   

BancorpSouth Bank

     5/23/2011         -         10,000         10,000   

Total

            $ 850,000       $ 169,000       $ 1,019,000   

Energen and Alagasco rely upon excess cash flow supplemented by the syndicated credit facilities and the short-term credit facilities to fund working capital needs. The Company may also issue long-term debt and equity periodically to replace obligations under the credit facilities, enhance liquidity and provide for permanent financing.

Dividends

Energen expects to pay annual cash dividends of $0.54 per share on the Company’s common stock in 2011. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. There have been no material changes to the contractual cash obligations of the Company since December 31, 2010.

Energen and its subsidiaries 2007 and 2008 federal consolidated income tax returns have been under Internal Revenue Service (IRS) examination. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company has filed a petition in United States Tax Court challenging the IRS assessment. Although the timing of the resolution is highly uncertain, a maximum exposure of an unfavorable outcome would result in income tax cash payments of approximately $31 million with no material impact to the Company and Alagasco’s effective income tax rate.

During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The Department proposes a change in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the Office of Natural Resources Revenue (ONRR) to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004 forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to those allowed under previous audits and are inconsistent with the Company’s understanding of industry practice. The Company intends to vigorously contest the Order and has requested additional information from the Department to determine the basis of its conclusion. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order and no amount has been accrued as of March 31, 2011.

Other Acreage

Energen has identified across its holdings acreage positions that may have potential for future development in various shale gas and oil plays. In the San Juan Basin, the company has 55,000, 54,000, and 55,500 net undeveloped acres in the Mancos/Niobrara Shale - gas phase, Mancos/Niobrara Shale - oil phase, and Lewis Shale, respectively; all acreage is held by other production. The company also owns the mineral rights on 200,000 net undeveloped acres in West Virginia, south of the Marcellus shale play. And in North Louisiana/East Texas, the company has 12,000 net undeveloped acres near the Haynesville shale play; this acreage is held by other production.

Given Energen’s planned level of activity in the Permian Basin for, at least, the next several years and given continued weakness in natural gas prices, the company has no near-term plans to pursue any of these plays but is monitoring the activity of other operators in the areas.

 

30


Table of Contents

Recent Accounting Standards Updates

See Note 14, Recently Issued Accounting Standards, in the Notes to Unaudited Condensed Financial Statements for information regarding recently issued accounting standards.

FORWARD LOOKING STATEMENTS AND RISK FACTORS

 

The disclosure and analysis in this report contains forward-looking statements that express management’s expectations of future plans, objectives and performance of the Company and its subsidiaries. Such statements constitute forward-looking statements within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended, and are noted in the Company’s disclosure as permitted by the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address the Company’s future business and financial performance and financial condition, and often contain words such as “expect”, “anticipate”, “intend”, “plan”, “believe”, “seek”, “see”, “project”, “will”, “estimate”, “may”, and other words of similar meaning.

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, gas and natural gas liquids, fluctuations in the weather, drilling risks, costs associated with compliance with environmental obligations, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other factors and uncertainties discussed elsewhere in this report and in the Company’s other public filings and press releases, all of which are difficult to predict. While it is not possible to predict or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors that may affect the Company’s future business and financial performance.

Commodity Prices: The Company and Alagasco are significantly influenced by commodity prices. Historical markets for natural gas, oil and natural gas liquids have been volatile. Energen Resources’ revenues, operating results, profitability and cash flows depend primarily upon the prices realized for its oil, gas and natural gas liquid production. Additionally, downward commodity price trends may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.

Access to Credit Markets: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for both lenders and the Company. Recent market volatility and credit market disruption have demonstrated that credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs or limit availability of funds to the Company.

Energen Resources’ Hedging: Although Energen Resources makes use of futures, swaps, options, collars and fixed-price contracts to mitigate price risk, fluctuations in future oil, gas and natural gas liquids prices could materially affect the Company’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options, collars and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position. In addition, the recent adoption of financial reform legislation could have an adverse effect on the ability of Energen Resources to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

 

31


Table of Contents

Alagasco’s Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position. In addition, the recent adoption of financial reform legislation could have an adverse effect on the ability of Alagasco to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

Energen Resources Customer Concentration: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids to a small number of energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to a limited number of customers in the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

Third Party Facilities: Energen Resources delivers to and Alagasco is served by third party facilities. These facilities include third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Energen Resources, Alagasco and the Company.

Energen Resources’ Production and Drilling: There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. Further, the Company’s insurance retention levels are such that significant events could adversely affect Energen Resources’, Alagasco’s and the Company’s financial position, results of operations and cash flows. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and the Company’s financial position, results of operations and cash flows.

Alagasco Service Territory: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this

 

32


Table of Contents

region could adversely affect Alagasco and the Company.

Federal, State and Local Laws and Regulations: Energen and Alagasco are subject to extensive federal, state and local regulation which significantly influences operations. Although the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations. Such changes can subject the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company’s operations.

 

33


Table of Contents

SELECTED BUSINESS SEGMENT DATA

ENERGEN CORPORATION

(Unaudited)

      Three months ended
March 31,
 
(in thousands, except sales price data)    2011     2010  

Oil and Gas Operations

    

Operating revenues

    

Natural gas

   $ 95,599      $ 125,427   

Oil

     103,256        93,975   

Natural gas liquids

     17,533        16,536   

Other

     404        1,676   

Total

   $ 216,792      $ 237,614   

Production volumes

    

Natural gas (MMcf)

     17,334        17,412   

Oil (MBbl)

     1,364        1,186   

Natural gas liquids (MMgal)

     19.7        18.8   

Total production volumes (MMcfe)

     28,338        27,209   

Total production volumes (MBOE)

     4,723        4,535   

Revenue per unit of production including effects of all derivative instruments

    

Natural gas (Mcf)

   $ 5.52      $ 7.20   

Oil (barrel)

   $ 75.70      $ 79.23   

Natural gas liquids (gallon)

   $ 0.89      $ 0.88   

Revenue per unit of production including effects of qualifying cash flow hedges

    

Natural gas (Mcf)

   $ 5.52      $ 7.20   

Oil (barrel)

   $ 75.70      $ 79.23   

Natural gas liquids (gallon)

   $ 0.89      $ 0.88   

Revenue per unit of production excluding effects of all derivative instruments

    

Natural gas (Mcf)

   $ 4.01      $ 5.24   

Oil (barrel)

   $ 88.67      $ 74.49   

Natural gas liquids (gallon)

   $ 1.01      $ 0.95   

Other data

    

Lease operating expense (LOE)

    

LOE and other

   $ 46,945      $ 43,839   

Production taxes

     12,283        9,941   

Total

   $ 59,228      $ 53,780   

Depreciation, depletion and amortization

   $ 51,348      $ 48,696   

Capital expenditures

   $ 140,323      $ 38,563   

Exploration expenditures

   $ 614      $ 1,184   

Operating income

   $ 85,059      $ 117,285   

Natural Gas Distribution

    

Operating revenues

    

Residential

   $ 187,674      $ 241,406   

Commercial and industrial

     66,906        84,290   

Transportation

     16,493        17,833   

Other

     (1,501     (6,229

Total

   $ 269,572      $ 337,300   

Gas delivery volumes (MMcf)

    

Residential

     12,591        14,962   

Commercial and industrial

     5,000        5,727   

Transportation

     12,970        12,682   

Total

     30,561        33,371   

Other data

    

Depreciation and amortization

   $ 9,780      $ 13,039   

Capital expenditures

   $ 13,540      $ 16,360   

Operating income

   $ 75,059      $ 75,255   

 

34


Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Energen Resources’ major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, world and national supply-and-demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, by worldwide political developments and by actions of the Organization of Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply-and-demand factors, including seasonal factors and the availability and price of transportation to consuming areas.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its gas supply exposure. Such instruments may include over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by the Company. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. All hedge transactions are subject to the Company’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. As of March 31, 2011, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2014.

A failure to meet sales volume targets at Energen Resources or gas supply targets at Alagasco due to miscalculations, weather events, natural disasters, accidents, mechanical failure, criminal act or otherwise could leave the Company or Alagasco exposed to its counterparties in commodity hedging contracts and result in material adverse financial losses.

See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for details related to the Company’s hedging activities.

The Company’s interest rate exposure as of March 31, 2011, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at March 31, 2011 was 2.07 percent. All long-term debt obligations were at fixed rates.

 

35


Table of Contents

ITEM 4. CONTROLS AND PROCEDURES

 

 

Energen Corporation

(a)    

  

Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b)    

  

Our chief executive officer and chief financial officer of Energen Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Alabama Gas Corporation

(a)    

  

Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b)    

  

Our chief executive officer and chief financial officer of Alabama Gas Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

 

36


Table of Contents

PART II. OTHER INFORMATION

 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

Period    Total Number of
Shares Purchased
    Average
Price Paid
per Share
    

Total Number of
Shares Purchased
as Part of Publicly
Announced Plans

or Programs

     Maximum
Number of Shares
that May Yet Be
Purchased Under
the Plans or
Programs**
 

January 1, 2011 through January 31, 2011

     9,649   $ 54.90         -         8,992,700   

February 1, 2011 through February 28, 2011

     -        -         -         8,992,700   

March 1, 2011 through March 31, 2011

     1,556   $ 60.69         -         8,992,700   

Total

     11,205      $ 55.70         -         8,992,700   

 

*

Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.

**

By resolution adopted May 24, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board of Directors authorized the Company to repurchase up to 12,564,400 shares of the Company’s common stock. The resolutions do not have an expiration date.

ITEM 6. EXHIBITS

 

31(a)         

Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)

31(b)         

Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)

31(c)         

Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)

31(d)         

Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)

32(a)         

Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350

32(b)         

Section 906 Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350

101         

The following financial statements from Energen Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, formatted in XBRL: (i) Consolidated Condensed Statements of Income, (ii) Consolidated Condensed Balance Sheets, (iii) Consolidated Condensed Statements of Cash Flows, (iv) the Notes to Unaudited Condensed Financial Statements, tagged as blocks of text.

 

37


Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

    ENERGEN CORPORATION
ALABAMA GAS CORPORATION

    May 9, 2011    

 

By

 

/s/ J. T. McManus, II

   

J. T. McManus, II

   

Chairman, Chief Executive Officer and

   

President of Energen Corporation;

Chairman and Chief Executive Officer of

Alabama Gas Corporation

    May 9, 2011    

 

By

 

/s/ Charles W. Porter, Jr.

   

Charles W. Porter, Jr.

   

Vice President, Chief Financial Officer

   

and Treasurer of Energen Corporation

   

and Alabama Gas Corporation

    May 9, 2011    

 

By

 

/s/ Russell E. Lynch, Jr.

   

Russell E. Lynch, Jr.

   

Vice President and Controller of Energen

Corporation

    May 9, 2011    

 

By

 

/s/ William D. Marshall

   

William D. Marshall

   

Vice President and Controller of Alabama

Gas Corporation

 

38