RESULTS OF OPERATIONS

Energen's net income totaled $95.6 million ($1.33 per diluted share) for the three months ended March 31, 2009 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, 2009, of $47.1 million as compared with $72.5 million in the same quarter in the previous year. Significantly lower commodity prices (approximately $28 million after-tax), increased depreciation, depletion and amortization (DD&A) expense (approximately $7 million after-tax), a 2008 after-tax gain of $6.4 million on the sale of certain Permian Basin oil properties and increased lease operating expense (approximately $2 million after-tax) were partially offset by increased natural gas, oil and natural gas liquids production volumes (approximately $13 million after-tax) and lower production taxes (approximately $5 million after-tax). Energen's natural gas utility, Alagasco, reported net income of $47.5 million in the first quarter of 2009 compared to net income of $43.7 million in the same period last year largely reflecting the utility's ability to earn on a higher level of equity (approximately $3 million after-tax).

Oil and Gas Operations

Revenues from oil and gas operations declined 15.9 percent to $189.1 million for the three months ended March 31, 2009 largely as a result of decreased commodity prices partially offset by the impact of higher production volumes. During the current quarter, revenue per unit of production for natural gas fell 17.8 percent to $6.55 per thousand cubic feet (Mcf), while oil revenue per unit of production decreased 22 percent to $52.97 per barrel. Natural gas liquids revenue per unit of production decreased 20.2 percent to an average price of $0.83 per gallon.

Production for the current quarter increased primarily due to additional development activities in the San Juan and Permian basins partially offset by normal production declines. Natural gas production in the first quarter rose 7.4 percent to 17.7 billion cubic feet (Bcf), oil volumes increased 15.5 percent to 1,090 thousand barrels (MBbl) and natural gas liquids production increased 4.8 percent to 17.5 million gallons (MMgal). Natural gas comprised approximately 65 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 $0.3 million in the three months ended March 31, 2009 on the sale of various properties. In the first quarter of 2008, Energen Resources recorded a pre-tax gain of $10.3 million largely from the sale of certain Permian Basin oil properties.

O&M expense increased $1.6 million for the quarter. Lease operating expense (excluding production taxes) increased by $2.7 million for the quarter largely due to higher non-operated expense (approximately $1.8 million), increased ad valorem taxes (approximately $1.6 million) and additional marketing and transportation costs (approximately $0.7 million) partially offset by lower compression costs (approximately $1 million). Administrative expense decreased $1 million for the three months ended March 31, 2009 largely due to insurance recoveries associated with certain legal expenses. Exploration expense declined $0.2 million in the first quarter of 2009.

Energen Resources' DD&A expense for the quarter rose $11.6 million. The average depletion rate for the current quarter was $1.54 per thousand cubic feet equivalent (Mcfe) as compared to $1.21 per Mcfe in the same period a year ago. The increase in the current quarter per unit DD&A rate, which contributed approximately $8 million, was largely due to higher rates resulting from an increase in development costs and the negative effect on reserves of lower year-end oil and gas prices. Increased production volumes also contributed approximately $3.5 million to the increase in DD&A expense.

Energen Resources' expense for taxes other than income taxes was $8.7 million lower in the three months ended March 31, 2009 largely due to production-related taxes. In the current quarter, lower oil, natural gas and natural gas liquid commodity market prices contributed approximately $10.2 million to the decrease in production-related taxes. Negatively affecting production-related taxes were increased production volumes which contributed approximately $1.5 million. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

As discussed more fully in Note 2, Regulatory Matters, in the Notes to Unaudited Condensed Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) and is allowed to earn a range of return on equity of 13.15 percent to 13.65 percent. At September 30, 2009, RSE will limit the utility's equity upon which a return is permitted to 55 percent of total capitalization.

Natural gas distribution revenues declined $1.8 million for the quarter largely due to a decline in customer usage partially offset by a slight rise in gas costs. Weather that was 3.4 percent warmer than in the same quarter in the prior year contributed to a 2.9 percent decrease in residential sales volumes while commercial and industrial customer sales volumes declined 8.2 percent. Transportation volumes declined 23.3 percent in period comparisons due primarily to decreased large customer and industrial usage. A decrease in gas purchase volumes partially offset by a rise in gas costs resulted in a 5.8 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 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 rose 1.3 percent in the current quarter primarily due to increased insurance costs (approximately $1.4 million) and increased bad debt expense (approximately $0.6 million) partially offset by lower distribution operation expenses (approximately $0.5 million) and decreased consulting and technology fees (approximately $0.4 million).

A 5 percent increase in depreciation expense in the current quarter was primarily due to extension and replacement of the utility's distribution system and replacement of its support systems. 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 $1.3 million in the first quarter of 2009 largely due to lower borrowings at Energen Resources combined with lower interest rates on short-term borrowings. Income tax expense for the Company decreased $12.5 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 $236.9 million as compared to $159.4 million in the prior period. Net income decreased during period comparisons primarily due to lower realized commodity prices partially offset by higher production volumes at Energen Resources. These decreases were more than offset by lower working capital requirements which were influenced primarily by income tax receivables along with commodity prices and the timing of payments. Working capital needs at Alagasco were additionally affected by decreased storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $120.5 million for the three months ended March 31, 2009 primarily due to additions of property, plant and equipment. Energen Resources invested $105.9 million (includes approximately $33.1 million of payments associated with accrued development cost) in capital expenditures primarily related to the development of oil and gas properties. Utility capital expenditures totaled $14.5 million (excludes approximately $1.4 million of accrued capital cost) in the year-to-date and primarily represented expansion and replacement of its distribution system and support facilities.

The Company used $70.8 million for net financing activities in the year-to-date primarily for the repayment of short-term debt borrowings and the payment of dividends to common shareholders.

FUTURE CAPITAL RESOURCES AND LIQUIDITY

Recent Market Events

Capital and credit markets have experienced significant volatility and disruption in recent periods. If such volatility and disruptions continue or worsen during 2009, the Company may experience material adverse effects upon its financial position, results of operations and cash flows. While such events did not have a material impact on 2008, these events have the potential for a negative impact including, but not limited to, the following areas:

Risk Management: The Company utilizes derivative instruments to hedge its exposure to commodity price fluctuations. These derivative instruments are entered into with investment grade counterparties and are assessed each reporting period as to hedge effectiveness. Specifically, the Company considers the likelihood that the counterparty will be able to perform under the terms of the derivative instrument. If the Company is unable to conclude that it is probable that such counterparty will be able to perform under the terms of the derivative instrument, then the Company would be required to cease hedge accounting and recognize all gains and losses from that point forward in its results of operations. Further, the Company is at risk of nonperformance for any derivative contracts which are in a gain position. The Company's current counterparties with active positions are Morgan Stanley Capital Group, Inc, J Aron & Company, Citibank, N.A., Bank of Montreal, Merrill Lynch Commodities, Inc., BP, Barclays Bank PLC and Shell Energy North America (US), L.P.

Access to Capital: Energen and Alagasco rely upon excess cash flows supplemented by short-term credit facilities to fund working capital needs. The Company currently has available short-term credit facilities with eight financial institutions aggregating $515 million of which Energen has available $230 million, Alagasco has available $100 million and $185 million is available to either Company. These short-term credit facilities are 364-day committed bilateral agreements. Energen and Alagasco are subject to the risk that these facilities will not be renewed or will be renewed at less favorable terms. However, the Company believes that its expected cash flows, the diversity of credit facilities and its ability to adjust future capital spending provides adequate support for its liquidity needs.

Oil and Gas Operations

During 2009, Energen Resources anticipates some decline in various market driven costs due to the recently lower commodity price environment including, but not limited to, workover and maintenance expenses, capital costs and other field-service-related expenses. The Company anticipates influences such as weather, natural disasters, changes in global economics and political unrest will continue to contribute to increased price volatility in the near term. Commodity price volatility will affect the Company's revenue and associated cash flow available for investment.

The Company plans to continue investing significant capital in Energen Resources' oil and gas production operations. For 2009, the Company expects its oil and gas capital spending to total approximately $235 million, including $212 million for existing properties. Capital spending has been reduced from 2008 levels reflecting a lower price environment and the current economic outlook.

In May 2009, Energen signed a purchase and sale agreement to buy interests in certain oil properties in the Permian Basin for a cash purchase price of $182 million (subject to closing adjustments). This sale is expected to close during the second quarter and will have an effective date of May 1, 2009. Energen Resources will use its short-term credit facilities and internally generated cash flows to finance the acquisition. The Company does not anticipate significant development costs during 2009 for this acquisition.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional development of existing properties and the exploration and further development of potential shales acreage primarily in Alabama. 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 short-term 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.

Alabama Shales

In October 2006, Energen Resources sold to Chesapeake Energy Corporation (Chesapeake) a 50 percent interest in its unproved lease position of approximately 200,000 gross acres in various shale plays in Alabama for $75 million plus certain net drilling cost (approximately $10.85 million). Currently, Energen Resources' net acreage position in Alabama shales totals approximately 343,000 acres representing multiple shale opportunities. As of March 31, 2009, Energen Resources had approximately $42 million of unproved leasehold costs related to its lease position in Alabama shales.

Effective April 1, 2009, Chesapeake agreed to farm out its half-interest in Alabama shales to Energen Resources. Under this agreement, Energen Resources has 18 months to drill two wells; after each well is drilled, Chesapeake will farm out its 50 percent interest to Energen Resources. Chesapeake will retain a net overriding royalty interest of approximately 1 to 2.5 percent convertible to a proportionately reduced working interest of 25 percent (net 12.5 percent) at 125 percent payout on a well-by-well basis. Included in the capital spending estimates above, the Company plans to invest approximately $10 million during 2009 to drill additional shale wells, test alternative completion techniques and complete other zones in the existing test wells.

Natural Gas Distribution

In recent years, the higher price commodity environment has resulted in a decline in the utility's customer base of approximately 1% annually. The recent lower commodity price environment has not yet reversed this adverse trend at the utility. A return of natural gas prices to higher levels could result in a further decline in Alagasco's customer base and usage and in significant increases in the utility's GSA. During 2008, Alagasco charged approximately $4 million against the ESR due to a decline in usage by its construction industry related customers. Alagasco expects this usage decline to continue in the near term. Alagasco will continue to monitor its bad debt reserve and will make adjustments as required based on the evaluation of its receivables which are impacted by natural gas prices and the economy.

Alagasco maintains an investment in storage gas that is expected to average approximately $56 million in 2009 but will vary depending upon the price of natural gas. During 2009, Alagasco plans to invest an estimated $70 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 short-term credit facilities. Alagasco received a cash benefit in February 2009 from an approximate $26.2 million income tax refund claim from 2007 which resulted from an approved change by the Internal Revenue Service in a tax accounting method relating to the Company's recovery of its gas distribution property.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. At March 31, 2009, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with all of its counterparties at March 31, 2009. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. These 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. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco's APSC approved tariff and are recognized as a regulatory asset or liability in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation".

Energen Resources entered into the following transactions for the remainder of 2009 and subsequent years:

                                                                Average
Production                     Total Hedged                     Contract
  Period                          Volumes                        Price              Description
Natural Gas
2009                                 11.4 Bcf                    $8.33
                                                                  Mcf               NYMEX Swaps
                                     24.2 Bcf                    $7.53
                                                                  Mcf           Basin Specific Swaps
   2010                              14.3 Bcf                    $8.79
                                                                  Mcf               NYMEX Swaps
                                     28.3 Bcf                    $7.98
                                                                  Mcf           Basin Specific Swaps
   2010                              *0.2 Bcf                    $6.17
                                                                  Mcf               NYMEX Swaps
                                     *0.5 Bcf                    $5.35
                                                                  Mcf           Basin Specific Swaps
Oil
   2009                            2,025 MBbl                    $72.93
                                                                  Bbl               NYMEX Swaps
   2009                             *405 MBbl                    $56.20
                                                                  Bbl               NYMEX Swaps
   2010                            2,160 MBbl                    $97.60
                                                                  Bbl               NYMEX Swaps
   2010                             *641 MBbl                    $63.75
                                                                  Bbl               NYMEX Swaps
   2011                             *864 MBbl                    $68.68
                                                                  Bbl               NYMEX Swaps
   2012                             *852 MBbl                    $71.30
                                                                  Bbl               NYMEX Swaps
   2013                             *336 MBbl                    $73.30
                                                                  Bbl               NYMEX Swaps
Oil Basis Differential
   2009                            1,602 MBbl                      **               Basis Swaps
   2009                             *344 MBbl                      **               Basis Swaps
   2010                            1,440 MBbl                      **               Basis Swaps
   2010                             *833 MBbl                      **               Basis Swaps
   2011                             *600 MBbl                      **               Basis Swaps
Natural Gas Liquids
   2009                            32.5 MMGal                    $1.15
                                                                  Gal              Liquids Swaps

Alagasco entered into the following transactions for the remainder of 2009 and subsequent years:

            Production       Total Hedged       Average Contract
              Period           Volumes               Price         Description
            Natural Gas
            2009                 12.0 Bcf          $6.95 Mcf       NYMEX Swaps
            2010                 19.1 Bcf          $7.33 Mcf       NYMEX Swaps
            2010                 *0.5 Bcf          $6.75 Mcf       NYMEX Swaps
            2011                  9.9 Bcf          $7.34 Mcf       NYMEX Swaps
            2011                 *0.8 Bcf          $6.75 Mcf       NYMEX Swaps
            2012                 13.4 Bcf          $7.33 Mcf       NYMEX Swaps

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

The Company has adopted SFAS No. 157, "Fair Value Measurements," under the provisions of the Financial Accounting Standards Board (FASB) Staff Position 157-2, "Effective Date of FASB Statement No. 157." See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for information regarding SFAS No. 157.

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

                                                      March 31, 2009
         (in thousands)                     Level 2*      Level 3*      Total
         Current assets                     $ 115,713     $ 137,364   $ 253,077
         Noncurrent assets                     78,022        53,695     131,717
         Current liabilities                  (35,298 )          -      (35,298 )
         Noncurrent liabilities               (24,289 )          -      (24,289 )
         Net derivative asset (liability)   $ 134,148     $ 191,059   $ 325,207

* Amounts classified in accordance with FASB Interpretation No. 39 (as amended), "Offsetting of Amounts Related to Certain Contracts" which permits offsetting of fair value of amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Alagasco has $35.3 million and $24.3 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.

Level 3 assets as of March 31, 2009 represent approximately 5 percent of total assets. 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 a $22.1 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 under SFAS No. 133. 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, 2009. The Company expects any future stock repurchases to be funded through internally generated cash flow or through the utilization of its short-term credit facilities. During the three months ended March 31, 2009, the Company had noncash purchases of approximately $0.5 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.

Short-Term Credit Facilities

Access to capital is an integral part of the Company's business plan. While the
Company expects to have ongoing access to its short-term credit facilities and
the longer-term markets, continued access could be adversely affected by current
and future economic and business conditions and credit rating downgrades. To
help finance its growth plans and operating needs, the Company currently has
available short-term credit facilities as follows:


  (in thousands)                        Current Term    Energen    Alagasco      Total
  Regions Bank                           4/23/2010     $ 165,000   $  35,000   $ 200,000
  Wachovia Bank, National Association    10/31/2009      100,000     100,000     100,000
  Compass Bank                            8/6/2009        70,000      70,000      70,000
  RBC Bank (USA)                         10/21/2009       20,000      15,000      35,000
  Citicorp USA, Inc.                     4/16/2010        20,000      15,000      35,000
  The Bank of New York Mellon            1/22/2010        25,000          -       25,000
  The Northern Trust Company             10/14/2009       15,000      25,000      25,000
  First Commercial Bank                  7/13/2009            -       25,000      25,000
                                                       $ 415,000   $ 285,000   $ 515,000

The Company regularly provides information to corporate rating agencies related . . .