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Article by DailyStocks_admin    (08-05-08 08:47 AM)

The Daily Magic Formula Stock for 08/05/2008 is Energen Corp. According to the Magic Formula Investing Web Site, the ebit yield is 10% and the EBIT ROIC is 75-100 %.

Dailystocks.com only deals with facts, not biased journalism. What is a better way than to go to the SEC Filings? It's not exciting reading, but it makes you money. We cut and paste the important information from SEC filings for you to get started on your research on a specific company.


Dailystocks.com makes NO RECOMMENDATIONS whatsoever, and provides this for informational purpose only.

BUSINESS OVERVIEW

General

Energen Corporation, based in Birmingham, Alabama, is a diversified energy holding company engaged primarily in the development, acquisition, exploration and production of oil, natural gas and natural gas liquids in the continental United States and in the purchase, distribution and sale of natural gas in central and north Alabama. Its two principal subsidiaries are Energen Resources Corporation and Alabama Gas Corporation (Alagasco).

Alagasco was formed in 1948 by the merger of Alabama Gas Company into Birmingham Gas Company, the predecessors of which had been in existence since the mid-1800s. Alagasco became publicly traded in 1953. Energen Resources was formed in 1971 as a subsidiary of Alagasco. Energen was incorporated in 1978 in preparation for the 1979 corporate reorganization in which Alagasco and Energen Resources became subsidiaries of Energen.

The Company maintains a Web site with the address www.energen.com . The Company does not include the information contained on its Web site as part of this report nor is the information incorporated by reference into this report. The Company makes available free of charge through its Web site the annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports. Also, these reports are available in print upon shareholder request. These reports are available as soon as reasonably practicable after being electronically filed with or furnished to the Securities and Exchange Commission. The Company’s Web site also includes its Code of Ethics, Corporate Governance Guidelines, Audit Committee Charter, Officers’ Review Committee Charter, Governance and Nominations Committee Charter and Finance Committee Charter, each of which is available in print upon shareholder request.

Financial Information About Industry Segments

The information required by this item is provided in Note 19, Industry Segment Information, in the Notes to Financial Statements.

Narrative Description of Business


•

Oil and Gas Operations

General: Energen’s oil and gas operations focus on increasing production and adding proved reserves through the development and acquisition of oil and gas properties. In addition, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. All gas, oil and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Black Warrior, San Juan and Permian basins for its joint interest and third parties. These services include overall project management and day-to-day decision-making relative to project operations.

At the end of 2007, Energen Resources’ proved oil and gas reserves totaled 1,754 billion cubic feet equivalent (Bcfe). Substantially all of these reserves are located in the San Juan Basin in New Mexico and Colorado, the Permian Basin in west Texas and the Black Warrior Basin in Alabama. Approximately 82 percent of Energen Resources’ year-end reserves are proved developed reserves. Energen Resources’ reserves are long-lived, with a year-end reserves-to-production ratio of 18 years. Natural gas represents approximately 64 percent of Energen Resources’ proved reserves, with oil representing approximately 26 percent and natural gas liquids comprising the balance.

Growth Strategy: Energen has operated for more than ten years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $1.2 billion in property acquisitions, $1.3 billion in related development, and $209 million in exploration and related development. Energen Resources’ capital investment in 2008 and 2009 is currently expected to approximate $579 million primarily for existing properties. The Company also may allocate additional capital during this two-year period for other oil and gas activities such as property acquisitions and the exploration and development of potential shale plays primarily in Alabama. The estimates above do not include amounts for capital related to potential acquisitions or development of these shale plays discussed below.

Energen Resources seeks to acquire onshore North American properties which offer proved undeveloped and/or behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers properties with long-lived reserves and multiple pay-zone opportunities; however, Energen Resources will consider acquisitions of other types of properties which meet its investment requirements, including acquisitions with unproved properties. In addition, Energen Resources conducts exploration activities primarily in areas in which it has operations and remains open to exploration activities which complement its core expertise and meet its investment requirements. Following an acquisition, Energen Resources focuses on increasing production and reserves through development of the properties’ undeveloped reserves and behind-pipe reserve potential as well as engaging in other activities. These activities include development well drilling, exploration, behind-pipe recompletions, pay-adds, workovers, secondary recovery and operational enhancements. Energen Resources prefers to operate its properties in order to better control the nature and pace of development activities. Energen Resources operated approximately 91 percent of its proved reserves at December 31, 2007.

In October 2006, Energen Resources sold to Chesapeake Energy Corporation (Chesapeake) a 50 percent interest in its unproved lease position of approximately 200,000 acres in various shale plays in Alabama for $75 million and a $15 million carried drilling interest. In addition, the two companies signed an agreement to form an area of mutual interest (AMI) through which they will pursue new leases, exploration, development and operations on a 50-50 basis, for at least the next 10 years. Energen Resources and Chesapeake continue to lease shared acreage in the AMI, which encompasses Alabama and some of Georgia, in advance of drilling. As of February 25, 2008, Energen Resources’ net acreage position in Alabama shale totaled approximately 287,500 acres and represents multiple shale opportunities.

Energen Resources’ development activities can result in the addition of new proved reserves and can serve to reclassify proved undeveloped reserves to proved developed reserves. Proved reserve disclosures are provided annually, although changes to reserve classifications occur throughout the year. Accordingly, additions of new reserves from development activities can occur throughout the year and may result from numerous factors including, but not limited to, regulatory approvals for drilling unit downspacing that increase the number of available drilling locations; changes in the economic or operating environments that allow previously uneconomic locations to be added; technological advances that make reserve locations available for development; successful development of existing proved undeveloped reserve locations that reclassify adjacent probable locations to proved undeveloped reserve locations; increased knowledge of field geology and engineering parameters relative to oil and gas reservoirs; and changes in management’s intent to develop certain opportunities.

During the three years ended December 31, 2007, the Company’s development efforts have added 364 Bcfe of proved reserves from the drilling of 975 gross development wells (including 27 sidetrack wells) and 150 well recompletions and pay-adds. In 2007, Energen Resources’ successful development wells and other activities added approximately 127 Bcfe of proved reserves; the company drilled 367 gross development wells (including 22 sidetrack wells), performed some 34 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources’ production from continuing operations totaled 98.6 Bcfe in 2007 and is estimated to total 102 Bcfe in 2008, including 100 Bcfe of estimated production from proved reserves owned at December 31, 2007. In 2009, production is estimated to be 108 Bcfe, including approximately 100 Bcfe produced from proved reserves currently owned.

As of December 31, 2007, the Company was participating in the drilling of 9 gross development wells, with the Company’s interest equivalent to 5 wells. In addition to the development wells drilled, the Company drilled 99.8, 35.9 and 33 net service wells during 2007, 2006 and 2005, respectively. As of December 31, 2007, the Company was participating in the drilling of 1 gross service well, with the Company’s interest equivalent to 0.9 well.

There were 17 wells with multiple completions in 2007. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Alabama.

Risk Management: Energen Resources attempts to lower the commodity price risk associated with its oil and natural gas business through the use of futures, swaps and options. Energen Resources does not hedge more than 80 percent of its estimated annual production and generally does not hedge more than two fiscal years forward. Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended requires all derivatives to be recognized on the balance sheet and measured 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 as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change.

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, put options and swaps 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.

In the case of an acquisition, Energen Resources may hedge more than two years forward to protect targeted returns. Energen Resources prefers long-lived reserves and primarily uses the then-current oil and gas futures prices in its evaluation models, the prevailing swap curve and, for the longer-term, its own pricing assumptions.

See the Forward-Looking Statements in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 1A, Risk Factors, for further discussion with respect to price and other risks.


•

Natural Gas Distribution

General: Alagasco is the largest natural gas distribution utility in the state of Alabama. Alagasco purchases natural gas through interstate and intrastate marketers and suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from producers, marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a fee to transport such customer-owned gas through its distribution system to the customers’ facilities.

Alagasco’s service territory is located in central and parts of north Alabama and includes 177 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.4 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2007, Alagasco served an average of 416,967 residential customers and 34,200 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 10,200 miles of main and more than 11,900 miles of service lines, odorization and regulation facilities, and customer meters.

APSC Regulation: As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended in 2007, 2002, 1996, 1990, 1987 and 1985. On December 21, 2007, the APSC extended RSE for a seven-year period through December 31, 2014. Under the terms of the extension, 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 equity remains 13.15 percent to 13.65 percent throughout the term of the order. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year).

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 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. Prior to the December 21, 2007 extension, RSE limited the utility’s equity upon which a return is permitted to 60 percent of total capitalization and provided for certain cost control measures designed to monitor Alagasco’s operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer fell within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment was required. If the change in O&M expense per customer exceeded the index range, three-quarters of the difference was returned to customers. To the extent the change was less than the index range, the utility benefited by one-half of the difference through future rate adjustments.

Subsequent to the extension, the equity on which a return will be permitted will be phased down to 57 percent by December 31, 2008 and 55 percent by December 31, 2009. The changes to the O&M expense cost control measurement subsequent to the extension are as follows: annual changes in O&M expense will be measured on an aggregate basis rather than per customer; the percentage change in O&M expense must fall within a range of 0.75 points above or below the percentage change in the index range; non-recurring and/or recurring items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the cost control measurement calculation; the O&M expense base for measurement purposes will continue to 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.

The temperature adjustment rider to Alagasco’s rate tariff, approved by the APSC in 1990, was designed to mitigate the earnings impact of variances from normal temperatures. Alagasco calculates a temperature adjustment to customers’ monthly bills to moderate the impact of departures from normal temperatures on Alagasco’s earnings. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers’ bills. Other non-temperature weather conditions that may affect customer usage are not included such as the impact of wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. Adjustments to customers’ bills are made in the same billing cycle in which the weather variation occurs. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider that permits the pass-through to customers of changes in the cost of gas supply.

The APSC approved an Enhanced Stability Reserve (ESR) beginning October 1997, with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events such as storms, severe weather, and outages, 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) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco’s return on equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR in an amount of no more than $40,000 monthly until the maximum funding level is achieved. Subsequent to the 2007 extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR.

Gas Supply: Alagasco’s distribution system is connected to two major interstate natural gas pipeline systems, Southern Natural Gas Company (Southern) and Transcontinental Gas Pipe Line Company (Transco). It is also connected to several intrastate natural gas pipeline systems and to Alagasco’s two liquified natural gas (LNG) facilities.

Alagasco purchases natural gas from various natural gas producers and marketers. Certain volumes are purchased under firm contractual commitments with other volumes purchased on a spot market basis. The purchased volumes are delivered to Alagasco’s system using a variety of firm transportation, interruptible transportation and storage capacity arrangements designed to meet the system’s varying levels of demand. Alagasco’s LNG facilities can provide the system with up to an additional 200,000 thousand cubic feet per day (Mcfd) of natural gas to meet peak day demand. Competition and Rate Flexibility: The price of natural gas is a significant competitive factor in Alagasco’s service territory, particularly among large commercial and industrial transportation customers. Propane, coal and fuel oil are readily available, and many industrial customers have the capability to switch to alternate fuels and/or alternate sources of gas. In the residential and small commercial and industrial markets, electricity is the principal competitor. With the support of the APSC, Alagasco has implemented a variety of flexible rate strategies to help it compete for the large customer gas load in the marketplace. Rate flexibility remains critical as the utility faces competition for this load. To date, the utility has been effective in utilizing its flexible rate strategies to minimize bypass and price-based switching to alternate fuels and alternate sources of gas.

In 1994 Alagasco implemented the P Rate in response to the competitive challenge of interstate pipeline capacity release. Under this tariff provision, Alagasco releases much of its excess pipeline capacity and repurchases it as agent for its transportation customers under 12 month contracts. The transportation customers benefit from lower pipeline costs; Alagasco’s core market customers benefit, as well, since the utility uses the revenues received from the P Rate to decrease gas costs for its residential and its small commercial and industrial customers. In 2007, approximately 300 of Alagasco’s transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled more than $7.8 million.

The Competitive Fuel Clause (CFC) and Transportation Tariff also have been important to Alagasco’s ability to compete effectively for customer load in its service territory. The CFC allows Alagasco to adjust large customer rates on a case-by-case basis to compete with alternate fuels and alternate sources of gas. The GSA rider to Alagasco’s tariff allows the Company to recover a reduction in charges allowed under the CFC because the retention of any customer, particularly large commercial and industrial transportation customers, benefits all customers by recovering a portion of the system’s fixed costs. The Transportation Tariff allows Alagasco to transport gas for customers, rather than buy and resell it to them, and is based on Alagasco’s sales profit margin so that operating margins are unaffected. During 2007 substantially all of Alagasco’s large commercial and industrial customer deliveries involved the transportation of customer-owned gas. In addition, Alagasco served as gas purchasing agent for more than 99 percent of its transportation customers. Alagasco also uses long-term special contracts as a vehicle for retaining large customer load. At the end of 2007, 65 of the utility’s largest commercial and industrial transportation customers were under special contracts of varying lengths.

Natural gas service available to Alagasco customers falls into two broad categories: interruptible and firm. Interruptible service contractually is subject to interruption by Alagasco for various reasons; the most common occurrence is curtailment of industrial customers during periods of peak core market heating demand. Interruptible service typically is provided to large commercial and industrial transportation customers who can reduce their gas consumption by adjusting production schedules or by switching to alternate fuels for the duration of the service interruption. More expensive firm service, on the other hand, generally is not subject to interruption and is provided to residential and to small commercial and industrial customers; these core market customers depend on natural gas primarily for space heating.

Growth: Customer growth presents a major challenge for Alagasco, given its mature, slow-growth service area. In 2007 Alagasco’s average number of customers decreased 1 percent. Alagasco will continue to concentrate on maintaining its current penetration levels in the residential new construction market and generating additional revenue in the small and large commercial and industrial market segments.

CEO BACKGROUND

Mr. McManus has been employed by the Company in various capacities since 1986. He was elected Executive Vice President and Chief Operating Officer of Energen Resources in October 1995 and President of Energen Resources in April 1997. He was elected President and Chief Operating Officer of Energen effective January 1, 2006 and Chief Executive Officer of Energen and each of its subsidiaries effective July 1, 2007. He was elected Chairman of the Board of Energen and each of its subsidiaries effective January 1, 2008. Mr. McManus serves as a Director of Energen and each of its subsidiaries.

Mr. Warren retired from the Company at the end of 2007. He had been employed by the Company in various capacities since 1983 and served as Chairman of the Board and Chief Executive Officer of Energen and each of its subsidiaries since 1998. Mr. Warren was succeeded by Mr. McManus as Chief Executive officer effective July 1, 2007 and as Chairman of the Board of Energen and each of its subsidiaries effective January 1, 2008. Mr. Warren continues to serve as a Director of Energen and each of its subsidiaries.
Mr. Porter has been employed by the Company in various financial capacities since 1989. He was elected Controller of Energen Resources in 1998. In 2001, he was elected Vice President – Finance of Energen Resources. He was elected Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries effective January 1, 2007.

Mr. Richardson has been employed by the Company in various capacities since 1985. He was elected Vice President – Acquisitions and Engineering of Energen Resources in 1997. He was elected Executive Vice President and Chief Operating Officer of Energen Resources effective January 1, 2006. He was elected President and Chief Operating Officer of Energen Resources effective January 23, 2008.

Mr. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003.

Mr. Woodruff has been employed by the Company in various capacities since 1986. He was elected Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries in April 1991 and Vice President-Corporate Development of Energen in October 1995. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003.


Ms. Carr was employed by the Company in various capacities from January 1985 to April 1989. She was not employed from May 1989 through December 1997. She was elected Controller of Energen in January 1998 and elected Vice President and Controller of Energen in October 2001.

MANAGEMENT DISCUSSION FROM LATEST 10K

RESULTS OF OPERATIONS

Consolidated Net Income

Energen Corporation’s net income for the year ended December 31, 2007 totaled $309.2 million, or $4.28 per diluted share and compared favorably to the year ended December 31, 2006 net income of $273.6 million, or $3.73 per diluted share. This 14.7 percent increase in earnings per diluted share (EPS) largely reflected the result of significantly higher prices for natural gas, oil and natural gas liquids and the impact of a 3 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen Resources Corporation, Energen’s oil and gas subsidiary, partially offset by the prior year after-tax gain of approximately $34.5 million, or $0.47 per diluted share, on the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shale to Chesapeake Energy Corporation (Chesapeake). For the year ended December 31, 2007, Energen Resources earned $273.2 million, as compared with $237.6 million in the previous year. Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, generated net income of $36.8 million in the current year as compared with net income in the prior period of $37.3 million. For the year ended December 31, 2005, Energen reported earnings of $173 million, or $2.35 per diluted share.

2007 vs 2006: For the year ended December 31, 2007, Energen Resources’ net income and income from continuing operations totaled $273.2 million and compared favorably to $237.6 million in the prior year. The primary factors positively influencing income from continuing operations included higher commodity prices of approximately $80 million after-tax, the impact of increased production volumes of approximately $14 million after-tax and the Section 199 Domestic Production Activities Deduction tax benefit on qualified oil and gas production income of approximately $7 million. Negatively affecting comparable income from continuing operations was the $34.5 million after-tax gain on the acreage position sale to Chesapeake recorded in the prior year, higher depreciation, depletion and amortization (DD&A) expense of approximately $10 million after-tax, higher lease operating expense of approximately $8 million after-tax, increased administrative expenses of approximately $3 million after-tax and a prior year $6.7 million after-tax gain on the sale of Energen Resources’ bankruptcy claim against Enron.

Alagasco earned net income of $36.8 million in 2007 as compared with net income of $37.3 million in 2006. This decrease in earnings largely reflected revenue reductions under the utility’s rate-setting mechanism of $2.3 million after-tax partially offset by a $1.2 million after-tax increase arising from the utility’s ability to earn on a higher level of equity and a $0.9 million after-tax reduction in expenses associated with the prior year’s Cost Control Measurement (CCM) giveback. Alagasco’s return on average equity (ROE) was 12.3 percent in 2007 compared with 13.1 percent in 2006.

2006 vs 2005: Energen Resources’ net income rose 75.6 percent to $237.6 million in 2006. Energen Resources’ income from continuing operations totaled $237.6 million in 2006 as compared with $135.2 million in 2005 primarily due to increased commodity prices of approximately $77 million after-tax along with the impact of increased production volumes of approximately $16 million after-tax, the $34.5 million after-tax gain on the sale to Chesapeake and the $6.7 million after-tax gain on the Enron bankruptcy settlement. These increases were partially offset by higher lease operating expense of approximately $19 million after-tax, increased DD&A expense of approximately $5 million after-tax and increased administrative expenses of approximately $5 million after-tax. Alagasco earnings increased to $37.3 million in 2006 from $37 million in 2005 largely as a result of $2 million after-tax increase arising from the utility’s ability to earn on a higher level of equity and reductions in the prior year under the utility’s rate setting mechanism of $1.9 million after-tax largely offset by a decrease in customer usage and a $0.9 million after-tax reduction associated with the CCM giveback. Alagasco achieved a ROE of 13.1 percent in 2006 compared with 13.5 percent in 2005.

Operating Income

Consolidated operating income in 2007, 2006 and 2005 totaled $522 million, $477.3 million and $315.7 million, respectively. This growth in operating income has been influenced by strong financial performance from Energen Resources under Energen’s diversified growth strategy. Alagasco’s operating income has been relatively flat for the three previous years as the utility’s ability to earn a return on a higher level of equity was offset by decreased customer usage and revenue reductions under its rate-setting mechanisms.

Oil and Gas Operations: Revenues from oil and gas operations rose in the current year largely as a result of increased commodity prices as well as the impact of increased production volumes. Production increased primarily due to additional development activities in the San Juan and Permian basins partially offset by normal production declines. Revenue per unit of production for natural gas production increased 11.6 percent to $7.77 per thousand cubic feet (Mcf), oil revenue per unit of production rose 30.2 percent to $64.83 per barrel and natural gas liquids revenue per unit of production increased 34.8 percent to an average price of $0.89 per gallon during 2007. Production from continuing operations rose 3.1 percent to 98.6 Bcfe during 2007. Natural gas production increased 2.3 percent to 64.3 billion cubic feet (Bcf) and oil volumes increased 6.4 percent to 3,879 thousand barrels (MBbl). Production of natural gas liquids increased 1.2 percent to 77.2 million gallons (MMgal).

In 2006, revenues from oil and gas operations increased primarily as a result of increased commodity prices and increased production volumes. Production increased primarily due to additional development activities in the San Juan Basin, accelerated workovers due to milder winter weather and increased volumes related to the purchase of Permian Basin oil properties in the fourth quarter of 2005. Negatively affecting production were normal production declines. Revenue per unit of production related to natural gas increased 16.2 percent to $6.96 per Mcf, oil revenue per unit of production rose 41.5 percent to $49.79 per barrel and natural gas liquids revenue per unit of production increased 20 percent to an average price of $0.66 per gallon during the year ended December 31, 2006. Production from continuing operations increased 5 percent to 95.6 Bcfe in 2006. Natural gas production rose 2.9 percent to 62.8 Bcf, oil volumes increased 9.9 percent to 3,645 MBbl and natural gas liquids production increased 8.2 percent to 76.3 MMgal.

Coalbed methane operating fees are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes and operating expenses. Revenues from operating fees were $6.1 million, $6.6 million and $8.7 million in 2007, 2006 and 2005, respectively. During 2006, Energen Resources recorded a $55.5 million pre-tax gain in other operating revenues for the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shale to Chesapeake.

Operations and maintenance (O&M) expense increased $28.7 million and $31.5 million in 2007 and 2006, respectively. Lease operating expense (excluding production taxes) in 2007 increased $13.4 million largely due to additional compression costs (approximately $2 million), increased repair and maintenance expense in the San Juan and Permian basins (approximately $7 million), higher transportation related to increased San Juan Basin production (approximately $3 million) and a general rise in field service costs. In 2006, lease operating expense (excluding production taxes) increased by $30.6 million due to a variety of factors including the December 2005 acquisition of Permian Basin oil properties (approximately $9 million), additional maintenance expense primarily in the San Juan Basin designed to increase production (approximately $2 million), increased workover expense (approximately $6 million), higher transportation costs (approximately $4 million), an increased number of wells in period comparisons and other overall cost increases. In 2007, administrative expense increased $16.6 million primarily due to a prior year pre-tax gain of $10.7 million on the sale of Energen Resources’ bankruptcy claims against Enron and increased labor-related costs, including settlement charges for the nonqualified supplemental retirement plans and the defined benefit pension plans of $2.3 million. Administrative expense decreased $2.6 million in 2006 largely due to the $10.7 million pre-tax gain against Enron; this gain was partially offset by higher labor-related costs. Exploration expense declined $1.3 million in 2007 largely due to decreased exploratory efforts. In 2006, exploration expense rose $3.5 million.

DD&A expense increased $16.4 million in 2007 and $8.5 million in 2006. The average DD&A rates were $1.13 per Mcfe in 2007, $1.00 per Mcfe in 2006 and $0.96 per Mcfe in 2005. The increase in the average 2007 DD&A rate, which contributed approximately $13 million, was primarily due to higher development costs along with a decline in prior year-end reserve prices. Increased production volumes also contributed approximately $3 million to the increase in DD&A expense in the current year. The increase in the average 2006 rate contributed approximately $3.8 million and was largely due to higher depletion rates on oil properties purchased in the Permian Basin in December 2005 and higher rates due to a downward revision to estimated reserves resulting from a reduction in year-end reserve prices. Partially offsetting the higher rate was increased production in lower rate areas. Increased production volumes contributed approximately $4.4 million due to the 2006 increase in DD&A expense.

Energen Resources’ expense for taxes other than income taxes primarily reflected production-related taxes. Energen Resources recorded severance taxes of $53.8 million, $49.5 million and $52.3 million for 2007, 2006 and 2005, respectively. Severance taxes increased $4.3 million in 2007 over the prior year. Higher commodity market prices and the impact of increased production volumes contributed approximately $3 million and $1.6 million, respectively. Decreased severance taxes in 2006 resulted from lower natural gas commodity market prices largely offset by higher production volumes and increased oil and natural gas liquids commodity market prices. 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 Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On December 21, 2007, the APSC issued an order to extend the utility’s rate-setting mechanism. Under the terms of the extension, 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 equity remains 13.15 percent to 13.65 percent throughout the term of the order. Prior to the December 21, 2007 extension, RSE limited the utility’s equity upon which a return is permitted to 60 percent of total capitalization and provided for certain cost control measures designed to monitor Alagasco’s O&M expense. Subsequent to the extension, the equity on which a return will be permitted will be phased down to 57 percent by December 31, 2008 and 55 percent by December 31, 2009.

Prior to the extension, under the inflation-based CCM established by the APSC, if the percentage change in O&M expense per customer fell within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment was required. If the change in O&M expense per customer exceeded the index range, three-quarters of the difference was returned to customers. To the extent the change was less than the index range, the utility benefited by one-half of the difference through future rate adjustments. The changes to the O&M expense cost control measurement subsequent to the extension are as follows: annual changes in O&M expense will be measured on an aggregate basis rather than per customer; the percentage change in O&M expense must fall within a range of 0.75 points above or below the percentage change in the index range; certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the cost control measurement calculation; the O&M expense base for measurement purposes will continue to 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.

Alagasco generates revenues through the sale and transportation of natural gas. The transportation rate does not contain an amount representing the cost of gas, and Alagasco’s rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues, but the financial impact is moderated by a temperature adjustment mechanism that requires Alagasco to adjust certain customer bills monthly to reflect changes in usage due to departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

Alagasco’s natural gas and transportation sales revenues totaled $609.5 million, $663.4 million and $600.7 million in 2007, 2006 and 2005, respectively. Sales revenue in 2007 declined largely due to a decrease in gas costs of approximately $28 million and a decline in customer usage of approximately $27 million. In 2006, sales revenue increased primarily due to an increase in gas costs approximately $82 million partially offset by a decrease in customer usage of approximately $28 million. In 2007, weather was 7.9 percent warmer than in the prior year. Residential sales volumes declined 7.4 percent while commercial and industrial volumes decreased 5.6 percent. Transportation volumes rose 1.4 percent. In 2006, weather that was 2.5 percent warmer than in the prior year along with customer conservation related to higher gas costs contributed to a 9.3 percent decline in residential sales volumes while commercial and industrial volumes decreased 10.2 percent. Transportation volumes increased 1.8 percent. In 2007, lower gas costs along with decreased gas purchase volumes contributed to a 14.7 percent decrease in cost of gas. Higher gas costs partially offset by a decline in gas purchase volumes resulted in a 17.2 percent increase in cost of gas in 2006.

O&M expense at the utility increased 1.9 percent in 2007 primarily due to increased labor-related costs (approximately $2 million), including settlement charges for the nonqualified supplemental retirement plans and the defined benefit pension plans of $3.4 million, largely offset by decreased bad debt expense (approximately $1 million). In 2006, O&M expense increased slightly primarily due to higher bad debt expense (approximately $1 million) and increased distribution maintenance expenses (approximately $1.7 million). These increases were offset by decreased labor-related expenses (approximately $4.5 million). The increase in O&M expense per customer for the rate year ended September 30, 2006 was above the inflation-based CCM established by the APSC as part of the utility’s rate-setting mechanism; as a result, three quarters of the differences, or $1.5 million pre-tax, was returned to the customers through RSE (see Note 2, Regulatory Matters, in the Notes to Financial Statements). Alagasco’s O&M expense fell within the index range for the rate years ended September 30, 2007 and 2005.

Depreciation expense rose 6.5 percent and 4.5 percent in 2007 and 2006, respectively, due to extension and replacement of the utility’s distribution and replacement of its support systems. Alagasco’s expense for taxes other than income primarily reflects 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

Consolidated: Interest expense in 2007 declined $1.6 million primarily due to lower borrowings at Energen Resources along with decreased interest expense associated with the May 2007 voluntary call of the $100 million Floating Rate Senior Notes due November 15, 2007. Also contributing to the decrease in interest expense at Alagasco was the January 2007 redemption of $34.4 million of 6.75% Notes maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026 partially offset by the issuance of $45 million in long-term debt with an interest rate of 5.9%. Interest expense in 2006 increased $1.9 million largely due to financing costs associated with higher storage gas inventories at Alagasco and an increase in interest rates associated with Energen’s $100 million Floating Rate Senior Notes. The average daily outstanding balance under short-term credit facilities was $67.7 million in 2007. The average daily outstanding balance under short-term credit facilities was $63.7 million in 2006 as compared to $17.7 million in 2005. Income tax expense increased in the periods presented primarily due to higher pre-tax income. Partially offsetting the increase in income tax expense in 2007 was the after-tax impact of the Section 199 deduction (approximately $7 million after-tax).

FINANCIAL POSITION AND LIQUIDITY

The Company’s net cash from operating activities totaled $484.2 million, $482.9 million and $335.1 million in 2007, 2006 and 2005, respectively. Operating cash flow in 2007, 2006 and 2005 benefited from higher realized commodity prices and production volumes at Energen Resources. Negatively affecting operating cash flows during 2007 was an increase in income taxes payable related to depreciation and basis differences in the current period and the prior period utilization of minimum tax credit. In 2006, income from operations before income taxes included a pre-tax gain of $55.5 million related to the Chesapeake acreage sale; the cash proceeds from the sale are included in the investing activities on the Consolidated Statements of Cash Flows, as described more fully below. Working capital needs at Alagasco were reduced by declining gas costs for 2007. During 2006 and 2005, working capital needs at Alagasco were largely affected by increased gas costs compared to the prior period and storage gas inventory. Other working capital items, which primarily are the result of changes in throughput and the timing of payments, combined to create the remaining increases for all years.

During 2007, the Company made net investments of $431.9 million. Energen Resources invested $54.6 million in property acquisitions, including an $18 million acquisition in the Permian Basin and approximately $32 million of unproved leaseholds (including approximately $28 million related to Alabama shale), $313.2 million for development costs including approximately $202 million to drill 345 gross development wells and $7.5 million for exploration. Utility expenditures in 2007 totaled $58.2 million and primarily represented extension and replacement of its distribution system and support facilities. During 2006, the Company made net investments of $256.9 million. Energen Resources invested $46.4 million in property acquisitions, $186.3 million for development costs including approximately $130.6 million to drill 309 gross development wells and $25.9 million for exploration. In December 2006, Energen Resources completed its purchase of gas properties located in the San Juan Basin from Dominion Resources, Inc. for approximately $30 million. Energen Resources sold certain properties during 2006, resulting in cash proceeds of $79.4 million including $75 million received from Chesapeake for a 50 percent interest in its lease position in certain unproved shale acreage in Alabama. Utility expenditures in 2006 totaled $75.1 million. During 2005, cash used in investing activities totaled $400.7 million. Energen Resources invested $188.4 million in property acquisitions, $157.5 million for development costs including approximately $123 million to drill 294 gross development wells and $5.1 million for exploration. In December 2005, Energen Resources completed its purchase of oil properties located in the Permian Basin for approximately $168 million. During 2005, Energen Resources sold certain properties resulting in cash proceeds of $10.8 million. Utility expenditures in 2005 totaled $72.4 million.

During 2007, the Company added approximately 15 Bcfe of reserves primarily from the Permian Basin acquisition. Also during 2007, Energen Resources added 127 Bcfe of reserves from discoveries and other additions, primarily the result of improved drilling technology that increased the number of proved undeveloped locations in the San Juan Basin as well as continued downspacing in the Permian Basin . Energen Resources added approximately 167 Bcfe and 224 Bcfe of reserves in 2006 and 2005, respectively.

The Company used $53.9 million for net financing activities in 2007 primarily for the early redemption of $100 million Floating Rate Senior Notes due November 15, 2007, $34.4 million of 6.75% Notes maturing September 1, 2031, $10 million of Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026. Partially offsetting these uses of cash was the January 2007 issuance by Alagasco of $45 million in long-term debt with an interest rate of 5.9% due January 15, 2037. In 2006, net cash used for financing activities totaled $224.4 million largely due to $84.3 million incurred from the buy-back of Energen common stock under its stock repurchase plan along with the repayment of short-term borrowings. In addition, long-term debt was reduced by $15.9 million for current maturities in 2006. The Company provided $69.8 million from net financing activities in 2005. In January 2005, Alagasco issued $40 million of long-term debt with an interest rate of 5.2 percent due January 15, 2020 and $40 million of long-term debt with an interest rate of 5.7 percent due January 15, 2035. In November 2005, Alagasco issued $80 million of long-term debt with an interest rate of 5.368 percent due December 1, 2015. Long-term debt was reduced by $84.8 million including Alagasco’s redemption of $18 million in Medium-Term Notes maturing June 27, 2007 to July 5, 2022 in August 2005 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 in December 2005. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

RESULTS OF OPERATIONS

Energen’s net income totaled $116.7 million ($1.62 per diluted share) for the three months ended March 31, 2008 and compared favorably with net income of $103.9 million ($1.44 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen’s oil and gas subsidiary, had net income and income from continuing operations for the three months ended March 31, 2008, of $72.5 million as compared with $63.2 million in the same quarter in the previous year. Significantly higher commodity prices (approximately $9 million after-tax), increased oil and gas production volumes (approximately $4 million after-tax) and a $6.4 million after-tax gain on the sale of certain Permian Basin oil properties were partially offset by increased lease operating expenses (approximately $5 million after-tax), higher production taxes (approximately $3 million after-tax) and increased depreciation, depletion and amortization (DD&A) expense (approximately $2 million after-tax). Energen’s natural gas utility, Alagasco, reported net income of $43.7 million in the first quarter of 2008 compared to net income of $40.3 million in the same period last year largely reflecting the utility’s ability to earn on a higher level of equity (approximately $2 million after-tax) and reduced operations and maintenance (O&M) expense (approximately $2 million after-tax) partially offset by a slight decrease in customer usage (approximately $1 million after-tax).

Oil and Gas Operations

Revenues from oil and gas operations rose 15.9 percent to $224.9 million for the three months ended March 31, 2008 largely as a result of increased commodity prices as well as the impact of higher production volumes. During the current quarter, revenue per unit of production for natural gas rose 0.5 percent to $7.97 per thousand cubic feet (Mcf), while oil revenue per unit of production increased 16.3 percent to $67.90 per barrel. Natural gas liquids revenue per unit of production increased 30 percent to an average price of $1.04 per gallon. The Company recorded an after-tax loss of approximately $0.6 million year-to-date on contracts which did not meet the definition of cash flow hedges under Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” For the three months ended March 31, 2008, the Company recorded a $1 million after-tax loss for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges.

Production increased primarily due to additional development activities in the San Juan and North Louisiana/East Texas basins partially offset by normal production declines. Natural gas production from continuing operations in the first quarter rose 5.7 percent to 16.4 billion cubic feet (Bcf), while oil volumes increased 1.8 percent to 944 thousand barrels (MBbl). Natural gas liquids production decreased 11.6 percent to 16.7 million gallons (MMgal) due to normal production declines and severe winter weather in the San Juan Basin. 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. 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. Energen Resources recorded a pre-tax gain of $0.3 million in the prior quarter on the sale of various properties.

O&M expense increased $6.1 million for the quarter. Lease operating expense (excluding production taxes) increased by $7.7 million for the quarter largely due to additional compression costs (approximately $2.7 million), higher transportation costs related to increased San Juan Basin production (approximately $1.2 million), higher workover expense (approximately $1.3 million), increased repairs and maintenance expense in the San Juan and East Texas basins (approximately $0.7 million), increased electricity costs (approximately $0.5 million) and increased environmental compliance expense (approximately $0.3 million). Administrative expense decreased $1.9 million for the three months ended March 31, 2008 largely due to lower labor-related expenses. The first quarter of 2007 included a settlement charge for the nonqualified supplemental retirement plan of approximately $1.1 million. Exploration expense rose $0.3 million in the first quarter of 2008.

Energen Resources’ DD&A expense for the quarter rose $3.9 million. The average DD&A rate for the current quarter was $1.21 per Mcfe as compared to $1.09 per Mcfe in the same period a year ago. The increase in the current quarter per unit DD&A rate, which contributed approximately $3.3 million, was largely due to higher rates resulting from an increase in development costs. Increased production volumes also contributed approximately $0.5 million to the increase in DD&A expense in the quarter comparisons.

Energen Resources’ expense for taxes other than income taxes was $4.5 million higher in the first quarter largely due to production-related taxes. Severance taxes increased $4.7 million during the three months ended March 31, 2008 over the same quarter in the prior year. Higher oil, natural gas and natural gas liquid commodity market prices and the impact of increased production volumes contributed approximately $4.4 million and $0.3 million, respectively. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues declined $1.9 million for the quarter largely due to a decline in customer usage. Although in the first quarter weather was 4.2 percent colder than the same period last year, residential sales volumes decreased due to customer conservation. Commercial and industrial customer sales volumes increased 2.1 percent while transportation volumes rose 6.5 percent in period comparisons. A decline in gas costs partially offset by an increase in gas purchase volumes resulted in a 4 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. As discussed further in Future Capital Resources and Liquidity, a continued higher price commodity environment may result in significant increases in the GSA and further customer and usage declines. Alagasco’s tariff provides a temperature adjustment to certain customers’ bills 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.

As discussed more fully in Note 2, Regulatory Matters, in the Unaudited Condensed Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On December 21, 2007, the APSC issued an order to extend Alagasco’s rate-setting mechanism. Under the terms of that extension, RSE will continue after December 31, 2014, unless, after notice to Alagasco and a hearing, the APSC votes to either modify or discontinue the RSE methodology.

O&M expense decreased 5.3 percent in the current quarter primarily due to lower labor-related costs (approximately $1 million) and decreased insurance costs (approximately $1 million). The three months ended March 31, 2007 included a settlement charge for the nonqualified supplemental retirement plan of approximately $1 million. For the year ended December 31, 2008, O&M expense is expected to increase over the prior year by approximately 3 percent. A 4.1 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 $1.1 million in the first quarter of 2008 largely due to the May 2007 voluntary call of the $100 million Floating Rate Senior Notes due November 15, 2007 partially offset by higher borrowings at Energen Resources. Income tax expense for the Company increased $9.7 million in the current quarter largely due to higher pre-tax income.

FINANCIAL POSITION AND LIQUIDITY



Cash flows from operations for the year-to-date were $159.4 million as compared to $187.9 million in the prior period. Operating cash flow benefited from higher realized commodity prices and production volumes at Energen Resources and a decrease in income taxes payable related to depreciation and basis differences from the prior period. In the current quarter, these benefits were more than offset by increased working capital needs which are highly influenced by commodity prices and the timing of payments. Working capital needs at Alagasco were primarily affected by decreased gas costs compared to the prior period and decreased storage gas inventory.

The Company had a net outflow of cash from investing activities of $69 million for the three months ended March 31, 2008 primarily due to additions of property, plant and equipment. Energen Resources invested $74.4 million in capital expenditures primarily related to the development of oil and gas properties including approximately $6.8 million of unproved leaseholds, primarily shale related. During the current quarter, Energen Resources received cash proceeds of $15.5 million primarily from the sale of certain Permian Basin oil properties. Utility capital expenditures totaled $12.9 million in the year-to-date and primarily represented expansion and replacement of its distribution system and support facilities.

The Company used $85.1 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 partially offset by the tax benefit on stock compensation.

FUTURE CAPITAL RESOURCES AND LIQUIDITY



The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2008, the Company expects its oil and gas capital spending to total approximately $330 million, including $305 million for existing properties. The Company expects capital spending at Energen Resources to total approximately $271 million during 2009, including approximately $260 million for existing properties.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional accelerated development of existing properties and the exploration and further development of potential shale plays 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. In October 2006, Energen Resources and Chesapeake Energy Corporation (Chesapeake) signed an agreement to form an area of mutual interest (AMI) through which they will pursue new leases, exploration, development and operations on a 50-50 basis in an area which encompasses Alabama and some of Georgia, for at least the next 10 years. Energen Resources and Chesapeake continue to lease shared acreage in the AMI; as of March 31, 2008, Energen Resources had approximately $34 million of unproved leasehold costs related to its lease position in Alabama shale. As of May 8, 2008, Energen Resources’ net acreage position totaled approximately 320,000 acres and represents multiple shale opportunities. During the first quarter of 2008, the Company initiated drilling activities for three wells as part of a 5 to 10 well test program. The Company has not included in its capital spending estimates discussed above any amounts associated with exploratory drilling and/or future potential development for the Alabama shale position.

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.

Energen also plans to consider stock repurchases as a capital investment. Energen may buy shares from time to time 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, 2008 and 2007. The Company currently plans to continue utilizing internally generated cash flow to fund any future stock repurchases. During the three months ended March 31, 2008, the Company had noncash purchases of approximately $27 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.

Energen Resources has experienced various market driven conditions generally caused by the increased commodity price environment including, but not limited to, higher workover and maintenance expenses, increased taxes 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.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. Energen Resources applies SFAS No. 133 which requires all derivatives to be recognized on the balance sheet and measured 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 equity and subsequently reclassified into earnings 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. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change.

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 with a corresponding regulatory asset or liability in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff.

Energen Resources and Alagasco utilize derivative instruments which 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. In some contracts, the amount of credit allowed before collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. At March 31, 2008, 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 all of its counterparties as of March 31, 2008. The Company believes the creditworthiness of these counterparties is satisfactory. These hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

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

Effective January 1, 2008, the Company partially 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”. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. As defined under SFAS No. 157, 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). SFAS No.157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value defined 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 in Level 1, which are either directly or indirectly observable as of the reporting date;
Level 3 –

Pricing that requires inputs that are both significant to the fair value measure and unobservable.

Over-the-counter derivatives are 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, and the determination of fair value is inherently more difficult than for actively traded, unadjusted quoted prices. 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 NYMEX swaps. 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 Company believes that these prices represent the best estimate of the exit price for these instruments as of the balance sheet date and are representative of the prices for which the contract will ultimately settle or realize.

Level 3 liabilities as of March 31, 2008 represent approximately 4 percent of total liabilities. Changes in fair value 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 commodities prices would result in a $64.9 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. 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.

The Company’s use of commodity price hedges for a portion of its gas supply needs is reflected in the utility’s current rates. Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider which permits the pass-through to customers for changes in the cost of gas supply. The GSA rider is designed to capture the Company’s cost of natural gas and provides for a pass-through of gas cost fluctuations to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management gains and losses.

A continued higher price commodity environment has the potential to produce adverse effects for the utility. Alagasco could have significant GSA increases in future periods. Sustained higher natural gas prices may decrease Alagasco’s customer base and could result in a further decline in per customer use. 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. Further, during the first quarter, Alagasco experienced a decline in usage by its construction industry related customers. Alagasco expects this usage decline to continue in the near term and currently anticipates utilizing its Enhanced Stability Reserve (ESR) of approximately $4 million during 2008. Absent the ESR reserve, projected earnings for 2008 would be lower by approximately $2.5 million. Under the provisions of the Rate Stabilization and Equalization rate-setting process, Alagasco’s rates in future periods will be adjusted to allow the utility to earn within its allowed range of return on average equity of 13.15 percent to 13.65 percent.

Alagasco maintains an investment in storage gas that is expected to average approximately $72 million in 2008 but will vary depending upon the price of natural gas. During 2008 and 2009, Alagasco plans to invest an estimated $69 million and $75 million, respectively, 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 issued $45 million in long-term debt with an interest rate of 5.9% in January 2007 and redeemed $34.4 million of 6.75% Notes maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026 in the same period in order to capitalize on lower interest rates.

Access to capital is an integral part of the Company’s business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. On September 25, 2007, Moody’s Investors Service (Moody’s) downgraded the debt rating of Energen to Baa3 senior unsecured from Baa2. Energen’s debt rating of Baa3 remains investment grade and reflects Moody’s assignment of increased risk exposure related to the growth of its oil and gas operations in contrast to its legacy natural gas distribution assets. Moody’s also confirmed the debt rating of Alagasco during this review as A1 senior unsecured. On October 31, 2007, Standard & Poor’s affirmed its BBB+ corporate credit rating on Energen and Alagasco; the outlook remained stable. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets, continued access could be adversely affected by 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 aggregating $435 million of which Energen has available $285 million, Alagasco has available $100 million and $50 million is available to either Company.

Dividends

Energen expects to pay annual cash dividends of $0.48 per share on the Company’s common stock in 2008. 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, 2007.

Recent Pronouncements of the Financial Accounting Standards Board

The Company partially adopted the provisions of SFAS No. 157, “Fair Value Measurements,” as of January 1, 2008. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The additional disclosures required under the standard are included in Note 3, Derivative Commodity Instruments.

CONF CALL

Julie S. Ryland - Vice President, Investor Relations

Thank you Jas, and good morning. Welcome to all of you joining us by phone and by internet. Today's conference call is being held in conjunction with Energen Corporation announcement yesterday of results of operations for the three months and year-to-date, ended June 30th, 2008.

Our prepared remarks will include statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements, made pursuant to the Safe Harbor Provision of the Private Security Litigation Reform Act of 1995. Except as otherwise disclosed, the company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructuring.

All statements based on future expectations, rather than on historical facts, are forward-looking statements, that are dependant on certain events, risks and uncertainties that maybe outside the company's control and could cause actual results to differ materially from those anticipated. A discussion of risks and uncertainties that could affect future results of Energen and its subsidiaries is included in the company's periodic reports filed with the Securities and Exchange Commission.

At this time, I would like to turn the call over to Energen Chairman and Chief Executive Officer, James McManus. James?

James T. McManus, II - Chairman and Chief Executive Officer

Thanks, Julie and good morning to everyone joining us today. Let's begin by talking about 2008. Energen Resources continues to drive our growth in 2008. Our aggregate realized sales price increased approximately 9% in the first six months year-over- year. And our production is up 1.6 Bcf equivalents, primarily in the San Juan basin, where we are benefiting from new drilling, and continued development of our proven coal properties.

While both timing and usage issues negatively affected Alagasco's earnings in the quarter and year-to-date, the timing issue shifts settle out by the end of the rate year. Accordingly, we still expect utility to earn a very respectable 12.6% return on equity for the calendar year.

For Energen, with half the year under our belt, we believe we are progressing toward another record earnings year in 2008. With that in mind, yesterday, we reaffirmed our earnings guidance for 2008, of $4.30 to $4.70 per diluted share.

Key assumptions in 2008 earnings guidance are, a hedge position that covers 75% of our estimated production for the remainder of the year, the same prices for unhedged natural gas, oil and NGL production of $10 per Mcf, $100 per barrel, and $1.30 per gallon respectively, production of 101 Bcf, capital spending of approximately 430 million, including approximately 360 million by Energen Resources and 70 million by Alagasco.

The additional capital at Energen Resources largely reflects additional drilling in the San Juan basin and North Louisiana and East Texas area, leasehold acquisitions and generally rising costs. An average DD&A rate at Energen resources of $1.27 per Mcf, LOE including production taxes of 2.45 per Mcf, G&A expense of $0.55 per Mcf, and Alagasco earning an estimated, as I mentioned earlier 12.6% on average equity of approximately 311 million. Average share outstanding of 72.1 million.

Yesterday we also affirmed our earnings guidance for 2009. That's a range of $5.15 to $5.55 per diluted share. Please bear in mind that we will begin working soon on a formal budget for 2009. Given that quickly and dramatically market conditions are changing right now, our capital budget could increase due to rising cost. Energen's earnings guidance does not include potential benefits from property acquisitions, Alabama shale's exploration or stock purchases.

Nor does the guidance make any assumptions related to potential impairment of capitalized unproved leasehold related to Alabama shale, currently that amount is approximately 40 million. For additional details on our guidance, I'll refer to our news release of yesterday.

At this time to I am going ask to Chuck to step in and review our quarter and year-to-date results and then I will return with a stash report on our Shell program and then open up the call for questions, Chuck

Charles W. Porter - Jr.Vice President, Chief Financial Officer and Treasurer

Thank you, James, In the second quarter 2008 we earned $66.9 million or $0.93 per diluted share, that was down slightly from $66.9 million of $0.94 per diluted share in the same period a year ago. Energen Resources net income in the current year, second quarter total $70.6 million and that compared with $66.9 million in the same period last year. That's a 5.5% increase and largely reflects a higher average realized sales prices for the company's natural gas, oil and natural gas liquids production as well as production growth of about 4%.

Now negatively influencing Energen Resources net income or increased LOE, DD&A exploration expense and G&A expense. Also our effective tax rate is higher due to reduced tax benefit under section 199. There is break out of our average realized sales prices by commodity and production by commodity and region that is available of course in yesterday's news release. I would point out that production was up, some 0.9 Bcf equivalent in the San Juan basin in the second quarter, year-over-year largely due to new drilling as we continue to develop our proven coal properties.

Energen Resources second quarter per unit LOE increased 15% from the same period, a year ago to $2.53 per Mcf equivalent. That increase is really driven by 54% rise in per unit production taxes resulting from increased commodity prices. DD&A stats per unit in the second quarter 2008 increased 15% over the same period last year to a $1.25 per Mcf equivalent, largely due to higher development costs.

Exploration expense in the current year second quarter increased $2.8 million over the same period a year ago, primarily due to mechanical difficulties encountered while dealing an exploratory hole on the San Juan basin. We had no dry hole calls in the prior period.

In second quarter net G&A expense in '08 rose $2.5 million over the same period in '07 and that's largely due to increased net salaries and benefits expense. And this primarily is the result of accruing [ph] adequately for our anticipated obligations under our performance based plans, along with general inflationary increases.

Energen's natural gas utility Alagasco had a net loss of $3.1 million in the second quarter of '08, as compared with net income of $1.4 million in the same period a year ago. This $4.5 million deficit year-over-year, largely reflects timing differences of approximately $2.4 million associated with rate recovery under the utilities rate setting mechanism, and we also had a decline in customer usage and other items, which would approximate $2 million.

For the six months ended June 30th, 2008. Energen's net income total of $183.6 million or $2.85 per diluted share. This is up from $171.8 million or $2.38 per diluted share, in the first half of 2007. Energen Resources net income for the year-to-date 2008, totaled $143.1 million and compared with $130.1 million in the same period last year. This 10% increase, largely reflects higher average realized sales prices, a 3% rise in production, and a one time gain from the sale of some Permian basin properties in the first quarter.

Partial offsets included higher LOE and DD&A, as well as higher effective tax rate due to our reduced tax benefits under section 199. Again, price and production breakdowns are included in our news release. Per unit LOE in the current year-to-date period increased 19% over the same period a year ago, to $2.48 for Mcf equivalent. This increase largely was due to a 45% increase in per unit production taxes, resulting from higher commodity prices, but in addition, we also had experienced some increases in compression, work overs, some weather related road maintenance, along with some environmental compliance.

DDNA expense per unit in the year-to-date 2008 increased 13% over the same period last year, to $1.23 per Mcf, also driven by higher development costs. Alagasco's year-to-date net income in 2008 was $40.6 million or a $1.1 million decline year-over-year. While the utility is earning on a higher level of equity, and is benefiting from lower O&M expenses of approximately $1.4 million after tax, these factors were more than offset by reduced customer usage and other items of approximately $2.9 million after tax.

Now that's basically a round up of Energen's financial status for the second quarter and year-to-date and with that I will kick you back to James.

James T. McManus, II - Chairman and Chief Executive Officer

Thank you, Chuck. Before we take your questions, I want to update you on status of our activity in pursuit of natural gas from Alabama shales. Energen Resources in Chesapeake now have a lease position in Alabama of approximately 654,000 acres. Our share is one half of that, or 327,000 acres. We drilled our first two test wells in Bibb County, Alabama to a total depth of between 10,005 and 12,500 feet. Bibb County is located generally southwest of Birmingham. Our third test well is nearing projected total depth of some 9,500 feet is located in Greene County, which is west and south of Bibb.

Our target shale formations are the Conasauga and Chattanooga. We are learning a lot about formations and concepts that we are looking in Alabama right now. As we mentioned in the press release, we encountered gas in each well drilled and we are working on designing what type of completion techniques that we will put on these wells to see whether this play can be turned into a commercial venture. The fact that we encountered gas is positive; you can't have a play unless you have gas in the well. So, we think that is a good thing, it doesn't mean we're home free but we do have something to work with, in each one of these wells that we've drilled.

At this point, I would like to turn the call back over to the moderator to see what type of questions that you may have.

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