RESULTS OF OPERATIONS

Energen's net income totaled $55 million ($0.76 per diluted share) for the three months ended June 30, 2009 compared with net income of $66.9 million ($0.93 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 June 30, 2009, of $54.9 million as compared with $70.6 million in the same quarter in the previous year. Significantly lower commodity prices (approximately $35 million after-tax) and increased depreciation, depletion and amortization (DD&A) expense (approximately $7 million after-tax) were partially offset by increased natural gas, oil and natural gas liquids production volumes (approximately $13 million after-tax), lower production taxes (approximately $9 million after-tax) and decreased exploration expense (approximately $2 million after-tax). Current-quarter results also include a $1.7 million after-tax insurance settlement associated with its business interruption claim following a natural gas processing plant fire in November 2007. Energen's natural gas utility, Alagasco, reported net income of $0.9 million in the second quarter of 2009 compared to a net loss of $3.1 million in the same period last year largely reflecting the utility's ability to earn on a higher level of equity, lower operations and maintenance (O&M) expense, increased revenue from cycle sales partially offset by decreased revenue from large commercial and industrial customers.

For the 2009 year-to-date, Energen's net income totaled $150.6 million ($2.09 per diluted share) and compared to net income of $183.6 million ($2.55 per diluted share) for the same period in the prior year. Energen Resources generated net income for the six months ended June 30, 2009, of $102 million as compared with $143.1 million in the previous period primarily as a result of lower commodity prices (approximately $63 million after-tax), higher DD&A expense (approximately $15 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 expenses (approximately $3 million after-tax). Positively affecting net income was the impact of increased production volumes (approximately $26 million after-tax), decreased production taxes (approximately $14 million after-tax), lower exploration expense (approximately $2 million after-tax) and the $1.7 million after-tax insurance settlement discussed above. Alagasco's net income of $48.4 million in the current year-to-date compared to net income of $40.6 million in the same period in the previous year primarily due to the same reasons discussed above.

Oil and Gas Operations

Revenues from oil and gas operations declined 14.3 percent to $198.5 million for the three months ended June 30, 2009 and 15.1 percent to $387.7 million in the year-to-date 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 24 percent to $6.27 per thousand cubic feet (Mcf), while oil revenue per unit of production decreased 19.7 percent to $59.85 per barrel. Natural gas liquids revenue per unit of production decreased 20.7 percent to an average price of $0.88 per gallon. In the year-to-date, revenue per unit of production for natural gas declined 21 percent to $6.41 per Mcf, oil revenue per unit of production decreased 20.9 percent to $56.44 per barrel and natural gas liquids revenue per unit of production fell 21.3 percent to an average price of $0.85 per gallon.

Production for both the current quarter and year-to-date 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 second quarter rose 9.8 percent to 18 billion cubic feet (Bcf), oil volumes increased 10.6 percent to 1,113 thousand barrels (MBbl) and natural gas liquids production increased 1.7 percent to 18.4 million gallons (MMgal). For the year-to-date, natural gas production from continuing operations increased 8.6 percent to 35.7 Bcf, while oil volumes rose 13 percent to 2,203 MBbl. Natural gas liquids production increased 2.9 percent to 35.9 MMgal. Natural gas comprised approximately 66 percent of Energen Resources' production for the current quarter and the year-to-date.

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 first quarter of 2009 on the sale of various properties. In the second quarter of 2008, Energen Resources recorded a pre-tax loss of $0.2 million and a pre-tax gain of $10.1 million in the year-to-date largely from the sale of certain Permian Basin oil properties.

O&M expense decreased $3.2 million for the quarter and $1.7 million in the year-to-date. Lease operating expense (excluding production taxes) increased by $1.8 million for the quarter largely due to increased ad valorem taxes
(approximately $1.7 million) and higher labor costs (approximately $1 million)
partially offset by lower electrical costs (approximately $1.3 million). In the year-to-date, lease operating expense (excluding production taxes) rose $4.5 million primarily due to increased ad valorem taxes (approximately $3.4 million), higher non-operated costs (approximately $2 million), and increased labor costs (approximately $1 million) partially offset by decreased electrical costs (approximately $1 million) and lower repairs and maintenance expense (approximately $0.8 million). Administrative expense decreased $2.2 million for the three months ended June 30, 2009 primarily due to lower benefit costs primarily related to the Company's performance-based compensation plans. For the six months ended June 30, 2009, administrative expense declined $3.1 million largely due to insurance recoveries associated with certain legal expenses along with lower benefit costs as described above. Exploration expense declined $2.9 million and $3.1 million in the second quarter of 2009 and in the year-to-date, respectively, primarily due to mechanical difficulties encountered in the prior year while drilling an exploratory well in the San Juan Basin.

Energen Resources' DD&A expense for the quarter rose $11.8 million and increased $23.3 million year-to-date. The average depletion rate for the current quarter was $1.57 per thousand cubic feet equivalent (Mcfe) as compared to $1.25 per Mcfe in the same period a year ago. For the six months ended June 30, 2009, the average depletion rate was $1.56 per Mcfe as compared to $1.23 per Mcfe in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $7.7 million and $15.7 million, respectively, 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 $4.1 million and $7.6 million to the increase in DD&A expense in the three months and six months ended June 30, 2009, respectively.

Energen Resources' expense for taxes other than income taxes was $14.2 million and $22.9 million lower in the three months and six months ended June 30, 2009, respectively, largely due to production-related taxes. In the current quarter and year-to-date, lower oil, natural gas and natural gas liquid commodity market prices contributed approximately $16.3 million and $26.5 million, respectively, to the decrease in production-related taxes. Increasing production-related taxes were higher production volumes which contributed approximately $2 million and $3.5 million, respectively, for the quarter and year-to-date. 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 gas costs and a decrease in customer usage. Weather that was 13.6 percent warmer than in the same quarter in the prior year contributed to a 3.6 percent decrease in residential sales volumes while commercial and industrial customer sales volumes declined 8.7 percent. Transportation volumes declined 26.3 percent in period comparisons due primarily to decreased large customer and industrial usage. Revenues for the year-to-date declined $3.6 million primarily due to decreased customer usage along with lower gas costs. For the year-to-date, weather was 5 percent warmer compared to the same period last year. Residential sales volumes declined 3.1 percent, commercial and industrial customer sales volumes decreased 8.3 percent and transportation volumes fell 24.6 percent in period comparisons. A decrease in gas costs partially offset by a rise in gas purchase volumes resulted in a 9 percent decrease in cost of gas for the quarter. For the year-to-date, lower gas costs combined with decreased gas purchase volumes contributed to a 6.6 percent decrease in cost of gas. 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 declined 4.4 percent in the current quarter primarily due to decreased consulting and technology fees (approximately $0.9 million), lower distribution operation expenses (approximately $0.8 million) and decreased bad debt expense (approximately $0.7 million) partially offset by increased marketing expenses (approximately $0.7 million). In the six months ended June 30, 2009, O&M expense decreased 1.7 percent. Decreased consulting fees (approximately $1.4 million) and lower distribution operation expenses (approximately $1.3 million) were partially offset by increased insurance costs (approximately $1.8 million).

A 4.4 percent increase in depreciation expense in the current quarter and a 4.7 percent increase in the year-to-date 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 $0.5 million in the first quarter of 2009 and $1.8 million in the year-to-date largely due to lower borrowings at Energen Resources combined with lower interest rates on short-term borrowings. Income tax expense for the Company decreased $7.8 million in the current quarter and $20.4 million year-to-date largely due to lower pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $396.8 million as compared to $315.4 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.

The Company had a net outflow of cash from investing activities of $386.7 million for the six months ended June 30, 2009 primarily due to additions of property, plant and equipment. Energen Resources invested $354.1 million (includes approximately $48.4 million of payments associated with accrued development cost) in capital expenditures primarily related to the acquisition and development of oil and gas properties. In June 2009, Energen Resources completed its purchase of oil properties located in the Permian Basin for a cash price of approximately $182 million. The acquisition added approximately 15.2 million barrels of oil equivalents in proved reserves. Utility capital expenditures totaled $33 million (excludes approximately $2.4 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 provided $15.1 million from net financing activities in the year-to-date primarily due to the increase in short-term debt borrowings partially offset by the payment of dividends to common shareholders.

FUTURE CAPITAL RESOURCES AND LIQUIDITY

Recent Market Events

Capital and credit markets experienced significant volatility and disruption during 2008. If such economic disruptions were to worsen during 2009, the Company could experience material adverse effects upon its financial position, results of operations and cash flows. These events have the potential for 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, Wachovia Bank National Association 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 $500 million of which Energen has available $230 million, Alagasco has available $85 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 $430 million, including $216 million for existing properties and $187 for property acquisitions. In June 2009 the Company purchased certain oil properties for a cash price of $182 million (subject to closing adjustments) in the Permian Basin from Range Resources Corporation (Range Resources). The effective date of this acquisition was May 1, 2009. Energen Resources used 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 further 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 further property acquisitions is subject to market conditions and industry trends. Property acquisitions, other than Range Resources discussed above, 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 June 30, 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.

Energen Resources plans to drill a new well targeting the Chattanooga shale formation in Alabama prior to the end of 2009. Of the above mentioned $42 million of unproved leasehold costs for Alabama shales, approximately $15 million of unproved leasehold costs are associated with the Chattanooga shale formation. The Company continues to pursue a partner as it seeks to unlock the potential of the Conasauga and Chattanooga shales on its extensive acreage position.

Natural Gas Distribution

In recent years, the higher price commodity environment has been a major factor in the decline in the utility's customer base of approximately 1% annually and in continuing declines in usage volume per customer. 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 $54 million in 2009 but will vary depending upon the price of natural gas. During 2009, Alagasco plans to invest an estimated $75 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 June 30, 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 June 30, 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:

       Production       Total Hedged       Average Contract
         Period           Volumes               Price             Description
       Natural Gas
          2009               8.1 Bcf          $8.03 Mcf           NYMEX Swaps
                            17.9 Bcf          $7.12 Mcf       Basin Specific Swaps
          2010              14.9 Bcf          $8.68 Mcf           NYMEX Swaps
                            29.4 Bcf          $7.88 Mcf       Basin Specific Swaps
          2011              11.4 Bcf          $6.82 Mcf           NYMEX Swaps
                            25.7 Bcf          $6.36 Mcf       Basin Specific Swaps

Oil
   2009                           2,087 MBbl                 $70.91 Bbl            NYMEX Swaps
   2010                           2,973 MBbl                 $88.48 Bbl            NYMEX Swaps
   2010                            *492 MBbl                 $76.30 Bbl            NYMEX Swaps
   2011                           2,556 MBbl                 $74.98 Bbl            NYMEX Swaps
   2011                            *456 MBbl                 $79.50 Bbl            NYMEX Swaps
   2012                             852 MBbl                 $71.30 Bbl            NYMEX Swaps
   2013                             336 MBbl                 $73.30 Bbl            NYMEX Swaps
Oil Basis Differential
   2009                           1,535 MBbl                     **                Basis Swaps
   2010                           2,383 MBbl                     **                Basis Swaps
   2011                           2,076 MBbl                     **                Basis Swaps
Natural Gas Liquids
   2009                           21.7 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                  9.0 Bcf          $6.90 Mcf       NYMEX Swaps
            2010                 19.6 Bcf          $7.31 Mcf       NYMEX Swaps
            2011                 10.7 Bcf          $7.30 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 sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

                                                  June 30, 2009
            (in thousands)           Level 2*       Level 3*         Total
            Current assets           $  68,655      $ 110,299      $ 178,954
            Noncurrent assets           16,974         35,057         52,031
            Current liabilities        (32,413 )         (169 )      (32,582 )
            Noncurrent liabilities     (13,332 )         (304 )      (13,636 )
            Net derivative asset     $  39,884      $ 144,883      $ 184,767




                                               December 31, 2008
             (in thousands)           Level 2*       Level 3*      Total
             Current assets           $  91,687      $ 104,812   $ 196,499
             Noncurrent assets           91,321         49,282     140,603
             Current liabilities        (27,653 )           -      (27,653 )
             Noncurrent liabilities      (8,821 )           -       (8,821 )
             Net derivative asset     $ 146,534      $ 154,094   $ 300,628

* Amounts classified in accordance with FASB Interpretation No. 39 (as amended), "Offsetting of Amounts Related to Certain Contracts" which permits offsetting . . .