Crude Oil ( ) Brent Crude ( ) Natural Gas ( ) S&P 500 ( ) PHLX Oil ( )

For the 3 months ended September 30, 2014, Energen Corporation (EGN) reported GAAP net income from all operations of $457.3 million, or $6.22 per diluted share. After adjusting for a mark-to-market gain, impairment losses in advance of potential asset sales, dry hole expense, and discontinued operations, Energen’s adjusted income from continuing operations in the 3rd quarter of 2014 totaled $45.2 million, or $0.62 per diluted share. This compares with adjusted income from continuing operations in the 3rd quarter of 2013 of $46.6 million, or $0.64 per diluted share. The difference between the periods primarily is attributable to a 13 percent increase in oil and natural gas liquids (NGL) production being more than offset by lower realized oil and NGL prices and increased DD&A expense. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Energen’s adjusted EBITDAX from continuing operations totaled $229.3 million in the 3rd quarter of 2014, up approximately 5 percent from $217.9 million in the same period last year. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

“Energen had a terrific 3rd quarter,” said James McManus, Energen’s chairman and chief executive officer. “Production exceeded our internal expectations by half-a-million barrels. We now estimate that our Permian Basin production in 2014 could grow approximately 23 percent from 2013 levels and that our December 2014 exit rate could exceed 77,000 barrels of oil equivalent per day (boepd).

“Our excellent exploratory and development drilling results in the Midland Basin served to further reinforce our current plans to add two development rigs in the Midland Basin in 2015. And the results of our exploratory wells in the Delaware Basin served to increase our excitement about the Wolfcamp potential across much of our acreage there while underscoring the need for continued delineation.

“The results coming from the Mancos formation oil play in the San Juan Basin continue to impress. We have a 50 percent non-operated working interest in four Mancos oil wells drilled this year in the south-central portion of the basin, and the results of wells three and four were even better than the first two. We continue to secure drilling permits and plan to run a rig in 2015 to test our acreage position in the play. We recently purchased approximately 15,000 net acres in the Mancos formation oil window, bringing our total position in the emerging play to 90,000 net acres. If we find what we expect from our 2015 drilling program, this play will compete on a return basis with our best Permian opportunities.

“As we look ahead to 2015 in our budget planning process, we are very conscious of the recent pull-back in oil prices and are scenario-planning for different price levels. Given our quality of assets, under-levered balance sheet, financial capacity, and hedge position, we believe we are extremely well-positioned to continue moving forward with most of our preliminary plans for 2015, even if oil prices were to average in the low $80s. Midland Basin Wolfcamp economics remain attractive at those levels; however, we may choose to limit our lower-return, exploratory drilling activity in the Delaware Basin Wolfcamp. Even at sub-$80 price levels, Midland Basin Wolfcamp economics remain solid.

“Energen’s balance sheet may be further de-levered in 2015 through asset sales. We anticipate marketing for sale the majority of our gas assets in the San Juan Basin as well as 5,300 net acres and assets in the northeast quadrant of Glasscock County located in the Eastern Shelf of the Permian Basin.

“Despite the current uncertainty surrounding near-term oil prices, Energen is in an excellent position — both in terms of our assets and our financial strength — and we have a great deal of flexibility with which to manage our capital investments and operating plans to best serve the interests of our shareholders.”

Permian Basin Exploration and Development Well Update

Midland and Delaware Basin Exploration Program Results

Energen tested six new exploratory wells in the Permian Basin during the 3rd quarter of 2014, including its first two Cline wells in the Midland Basin and its first Wolfcamp C well in the Delaware Basin. [See locator maps at www.energen.com]

Permian Basin Exploratory Well Results (3-Stream)

Well Name

Zone/
County

Lateral length (ft)

Frac
Stages

Peak 24-Hour IP Peak 30-day Avg.
Drilled* Completed Boepd %Oil %NGL %Gas Boepd %Oil %NGL %Gas
Jones Holton #201H WC B/Martin 7,500 6,825 28 1,172 93 4 3 602 85 8 6
Daniel SN 10-3 #202H WC B/Glasscock 7,500 6,930 28 1,148 93 3 4 719 83 7 9
Jones Holton #401H Cline/Martin 8,150 7,580 31 2,425 74 16 10 788 73 17 10
Horwood SN 36-37 #401H Cline/Glasscock 7,500 6,930 28 1,233 74 16 10 548 65 22 14
Intrepid 55-12 #1H† WC C/Reeves 4,800 4,100 18 2,128 46 26 28 1,502 41 29 30
Atlantis 59-10 #1H WC B/Reeves 4,800 4,200 18 1,665 11 37 52 1,382 12 37 51
† Pro forma to 4,100’ completed length
* Represents distance from vertical departure to toe

“Energen’s Jones Holton #401H generated the best known publicly disclosed rates for a Cline well in Martin County,” said McManus. “We are very pleased with this well and our two Wolfcamp B wells in Martin and Glasscock counties. All three have outperformed our internal expectations as we continue to successfully delineate the Wolfcamp and Cline potential across our Midland Basin footprint. [See discussion of Horwood SN 36-37 #401H on page 5, Asset Sales Under Consideration].

Energen’s 2014 Midland Basin exploratory drilling plans include a total of 19 gross (18 net) wells. In addition to the 8 gross wells drilled, completed, and producing, 7 gross wells currently are in various stages of drilling, completion, and flow back. These include the first of two planned Martin County Lower Spraberry test wells, a Glasscock County Lower Spraberry test, the company’s third Martin County Wolfcamp A well as well as its second Martin County Wolfcamp B well, and the company’s first three Wolfcamp C wells in Glasscock County. Energen expects to complete 18 gross wells in 2014.

“In the Delaware Basin, we are pleased with the results of our first Wolfcamp C test, the Intrepid 55-12 #1H. The Intrepid and the Atlantis 59-10 #1H are among our top six Delaware Wolfcamp performers on the basis of 30-day rates,” McManus added.

Energen’s 2014 Delaware Basin Wolfcamp drilling plans include a total of 13 gross (12 net) wells. In addition to the 4 gross wells drilled, completed, and producing, 7 gross wells currently are in various stages of drilling, completion, and flow back, including a 6,700’ lateral length well targeting the Wolfcamp B in Reeves County and a second Wolfcamp C well in Reeves County. Energen expects to complete 12 gross wells in 2014.

Southern Glasscock Development Well Results (3-Stream)

In addition to its exploratory programs in the Midland and Delaware basins, Energen drilled 16 gross (15 net) wells in the 3rd quarter as part of its Wolfcamp development program in southern Glasscock County. This brings the total number of development wells drilled in the first nine months of the year to 34 gross (32 net). Energen’s development program consists of pad drilling stacked A & B laterals with lengths of 6,700’ and 7,500’.

Energen completed and tested 11 gross (10 net) wells in the development program during the 3rd quarter; another 3 gross (3 net) wells were completed but do not have sufficient production history to report. The new 3rd quarter wells generated average peak 24-hour IP rates (3-stream) of 1,066 boepd (79% oil) and peak 30-day average rates (3-stream) of 766 boepd (72% oil), both of which exceeded our internal expectations. For the year to date through September 30, Energen has completed and tested 15 gross (14 net) wells.

In the 4th quarter, the company expects to drill 19 gross (19 net) development wells and complete an additional 18 gross (17 net) wells. For the full year, the company plans to drill 53 gross (51 net) and complete 36 gross (34 net) wells.

“We have continued to realize improved drilling efficiency during the 3rd quarter and currently are averaging 18-21 days from spud to rig release,” McManus said. “This improvement in cycle time is helping us execute completions in a timely manner and helping offset cost increases associated with a variety of items from increasing our pipe inspection level and frequency to using more sand as we refine our completions. Our target drill-and-complete cost for Wolfcamp development wells for the remainder of the year is $7.5-$8.0 million.

“We will have six rigs drilling development wells within the next couple of weeks and plan to add two more before year end to get a jump-start on next year’s program,” McManus added. “We anticipate running 6-8 development rigs throughout 2015.”

San Juan Basin Mancos Oil Well Results (3-Stream)

In the San Juan Basin, Energen is a 50 percent non-operated participant in four oil wells that have been drilled this year by WPX Energy in the Mancos formation in south-central San Juan Basin. Results of all four wells, the first two of which were disclosed last quarter, are strong indicators that this horizontal oil play in northern New Mexico could generate returns that compete with Energen’s extensive opportunity set in the Permian Basin.

Well Name

Completed
Lateral Length

Frac
Stages

Peak 24-Hour IP Peak 30-day Avg.
Boepd %Oil %NGL %Gas Boepd %Oil %NGL %Gas

Chaco 2308 14E #151H 

4,400’ 14 1,147 79 10 11 656 79 10 11

Chaco 2308 14E #152H 

4,500’ 14 929 79 10 11 642 79 10 11

Utility Sale Completed

Energen completed the sale of its natural gas utility company, Alabama Gas Corporation, to The Laclede Group on September 2, 2014. The transaction’s effective date was August 31, 2014. The $1.6 billion purchase price included the assumption of approximately $267 million of utility debt. Energen’s net pre-tax proceeds from the sale totaled approximately $1.3 billion (subject to additional working capital adjustments post-close). Energen estimates its after-tax proceeds will be $1.1 billion.

Immediately following the close, Energen repaid $570 million in outstanding principal under its December 2013 Senior Term Loans along with $750 million outstanding under its October 2012 Credit Facility Agreement. Energen also executed a new syndicated, senior secured, revolving credit facility with initial aggregate lender commitments of $1.5 billion and a reserve-backed borrowing base of $2.1 billion. In the fourth quarter of 2014, the company intends to draw approximately $230 million in borrowings under the September 2014 Credit Facility to pay income taxes generated from the sale; the full tax obligation is being partially offset by the expensing of intangible drilling costs incurred during 2013 and 2014.

Asset Sales Under Consideration

Energen expects to market for sale the majority of its natural gas assets in the San Juan Basin as well as properties in the northeast quadrant of Glasscock County located in the Eastern Shelf of the Permian Basin. Both assets were marked down in the 3rd quarter to their estimated fair market value in anticipation of being designated as “held for sale” by year-end 2014.

Energen has not invested drilling capital in its San Juan Basin gas assets for several years, and management does not expect to see in the foreseeable future a recovery in prices sufficient to allow these natural gas plays to compete for capital with the company’s extensive oil opportunities.

The assets under consideration to be sold include approximately 985 net operated wells on some 208,000 net acres. These assets had proved reserves at year-end 2013 of 73.1 MMBOE, of which 84 percent was natural gas and 16 percent was NGL; associated production in 2014 is estimated to be 6.7 MMBOE.

In 2014 Energen has been testing the Cline potential on an isolated 5,300 net acres in far eastern Glasscock County. Through the prior testing of vertical targets, the company determined that, on this acreage, the Cline shale offered the greatest potential to be economically competitive with its drilling opportunities in the core of the Midland Basin. While the results of the Horwood SN 36-37 #401H Cline well were good for this northeastern Glasscock area (see page 3), the company has decided its deep inventory in the core of the Midland Basin offers better economics and repeatable returns.

3rd Quarter Financial Review

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations

[See “Non-GAAP Financial Measures” beginning on pp. 13 for more information]

3Q14 3Q13
$M $/dil. sh. $M $/dil. sh.
Net Income All Operations (GAAP) $ 457,251 $ 6.22 $ (19,298 ) $ (0.27 )
Less: Non-cash Mark-to-Market gain/(loss) 94,142 1.28 (40,277 ) (0.56 )
Less: Asset Impairments (in anticipation of sale) (113,945 ) (1.55 )
Less: Dry hole expense (4,792 ) (0.07 ) (883 ) (0.01 )
Less: Discontinued Operations
Gain (Loss) on Disposal of E&P Assets (1 ) (0.00 ) (15,678 ) (0.22 )
Income (Loss) from E&P Discontinued Operations (25 ) (0.00 ) 1,785 0.02
Gain (Loss) on Disposal of Utility 440,106 5.99
Income (Loss) from Utility Discontinued Operations (3,460 ) (0.05 ) (10,812 ) (0.15 )
Adj. Income Continuing Operations (Non-GAAP) $ 45,226 $ 0.62 $ 46,567 $ 0.64

Note: Per share amounts may not sum due to rounding

Production from Continuing Operations by Product

Commodity 3Q14 3Q13 Change 2Q14
MBOE boepd MBOE boepd MBOE boepd
Oil 3,017 32,793 2,764 30,043

9%

2,833 31,132
NGL 1,108 12,043 874 9,500

27%

1,065 11,703
Natural Gas 2,526 27,457 2,478 26,935

2%

2,446 26,879
Total 6,651 72,293 6,116 66,478

9%

6,344 69,714

Production from Continuing Operations by Area

Area 3Q14 3Q13 Change 2Q14
MBOE boepd MBOE boepd MBOE boepd
Midland Basin 1,876 20,391 1,407 15,293

33%

1,755 19,286
Wolfberry 1,292 14,043 1,385 15,054 1,371 15,066
Wolfcamp/Cline 584 6,348 22 239 384 4,220
Delaware Basin 1,525 16,576 1,301 14,141

17%

1,488 16,352
3rd Bone Spring/Other 1,219 13,250 1,170 12,717 1,201 13,198
Wolfcamp 306 3,326 131 1,424 287 3,154
Central Basin Platform 998 10,848 1,106 12,022

(10)%

1,060 11,648
Total Permian Basin 4,399 47,815 3,814 41,456

15%

4,303 47,286
San Juan Basin/Other 2,252 24,478 2,302 25,022

(2)%

2,041 22,429
Total 6,651 72,293 6,116 66,478

9%

6,344 69,714

Note: Totals may not sum due to rounding

Average Realized Sales Prices from Continuing Operations

Commodity 3Q14 3Q13 Change
Oil (per barrel) $ 84.33 $ 89.67 (6

)%

NGL (per gallon) $ 0.69 $ 0.75 (8

)%

Natural Gas (per Mcf) $ 4.27 $ 4.06 5 %

Expenses from Continuing Operations (per barrel)

Expenses 3Q14 3Q13 Change
LOE* $ 10.18 $ 10.76 (5

)%

Production & ad valorem taxes $ 3.87 $ 3.63 7 %
DD&A $ 20.71 $ 20.27 2 %
Net G&A $ 4.18 $ 5.06 (17

)%

Interest $ 1.73 $ 1.66 4 %

*Production costs + workovers and repairs + marketing and transportation

3rd Quarter Comparisons, 2014 vs 2013 (Continuing Operations)

  • Permian Basin production increased 15 percent as new drilling in the horizontal Wolfcamp in the Midland and Delaware basins more than offset declines in the company’s legacy assets in the Central Basin Platform and from a reduced vertical Wolfberry program.
  • NGL production increased 27 percent largely due to less ethane rejection and new horizontal Wolfcamp drilling.
  • Average realized oil prices were lower by 6 percent, primarily due to the impact of wider WTI Midland to WTI Cushing and WTS Midland to WTI Cushing differentials.
  • LOE per unit decreased 5 percent to $10.18 per BOE largely due to lower water disposal costs and to decreased marketing and transportation expenses. Per-unit production taxes and ad valorem taxes increased approximately 7 percent as lower price-driven production taxes were more than offset by higher ad valorem taxes.
  • Per-unit DD&A expense totaled $20.71 per BOE, increasing approximately 2 percent largely due to year-over-year increases in development costs.
  • Per-unit net G&A expense of $4.18 per BOE fell approximately 17 percent from the same period a year ago largely due to stock-based compensation.
  • Interest expense increased $1.4 million to total $11.5 million.

4th Quarter and Full-year 2014 Capital, Production and Financial Guidance

Energen’s 2014 drilling and development capital is estimated to remain under $1.4 billion, in keeping with prior guidance. The company production guidance midpoint, however, is estimated to increase 0.5 MMBOE to 25.9 MMBOE (70,950 boepd). Energen is both raising and narrowing its 2014 production guidance range to 25.6 to 26.2 MMBOE (70,135-71,780 boepd). The company is maintaining its 4th quarter production guidance midpoint of 6.9 MMBOE (75,000 boepd) within a range of 6.6 to 7.2 MMBOE (71,740-78,260 boepd).

Energen’s estimated expenses from continuing operations in the 4th quarter of 2014 and CY2014 are:

4Q14 CY2014
LOE (production costs, marketing & transportation) (per BOE) $9.20-$9.60 $10.15-$10.30
Production and ad valorem taxes (% of revenues, excluding hedges) 7.8%
DD&A expense (per BOE) $22.20-$22.70 $21.20-$21.35
General & administrative expense, net (per BOE) $4.00-$4.40 $4.70-$4.80
Exploration expense (delay rentals, seismic, G&G, etc.) (per BOE) $1.00-$1.20 $0.85-$0.95
Interest expense ($MM) $11.3-$12.3 $38.6-$39.6

Approximately 72 percent of the company’s 4th quarter production guidance midpoint of 6.9 MMBOE is hedged. Hedges also are in place that limit the company’s exposure in the 4th quarter to the Midland to Cushing differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 0.3 million barrels of oil production at an average price of $3.30 per barrel and the WTI Midland to WTI Cushing differential for 0.6 million barrels at an average price of $3.08 per barrel. Energen estimates that approximately 76 percent of its oil production for the remainder of 2014 will be sweet. Gas basis assumptions are $0.05 per Mcf in the Permian and San Juan basins.

The company’s current hedge position for the 4th quarter of 2014:

Commodity

Hedge Volumes

4Q14e Production
Midpoint

Hedge %

NYMEXe Price

Oil

2.5 MMBO

3.3 MMBO

76 %

$ 92.66 per barrel

NGL

18.5 MMgal

46.2 MMgal

40 %

$ 0.93 per gallon

Natural Gas

12.7 Bcf

14.9 Bcf

85 %

$ 4.53 per Mcf

Note: Known actuals included

In the table above, basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen’s assumed San Juan and Permian basis differentials.

Average realized oil and gas prices for Energen’s production associated with NYMEX contracts as well as for unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect estimated oil transportation charges of $2.65 per barrel in the 4th quarter; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.09 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin. The company also has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price.

Energen’s assumptions for the commodity prices of unhedged production in the 4th quarter are $85 per barrel of oil, $4.00 per Mcf of gas, and $0.92 per gallon of NGL. As a result of Energen’s 2014 hedge position for the remainder of the year, changes in commodity prices are expected to have a minimal impact on Energen’s 2014 revenues.

Energen estimates that for the 4th quarter, every $1 change in the Midland to Cushing differentials for sweet and sour oil from our assumed $6 per barrel will impact net income by approximately $0.7 million and $0.2 million, respectively.

2014e Capital, Drilling and Production Summary

2014e Capital Operated Wells Production Midpoint
($ MM) Gross (Net) MMBOE boepd
Midland Basin $ 835 126 (119) 7.7 21,000

Wolfcamp/Lower Sprby/Cline

600 72 (69) 2.3

Wolfberry/Other

125 54 (50) 5.4

Facilities/Non-operated/Other

110
Delaware Basin $ 415 40 (36) 5.8 16,000

3rd Bone Spring/Other

185 27 (24) 4.6

Wolfcamp

175 13 (12) 1.2

Facilities/Non-operated/Other

55
Other Permian $ 45 26 (22)* 4.0 10,950

Waterfloods/CO2 floods

17 26 (22)*

Facilities/Non-operated/Other

28
San Juan Basin/Other $ 25 0 (0) 8.4 23,000

Facilities/Non-operated/Other

25
Net Carry In/Carry Out/Other $ 32
Acquisition/Unproved Leasehold YTD $ 48

TOTAL

$

1,400

192 (177)

25.9

70,950

Note: “Facilities” capital includes salt water disposal wells, artificial lift, and central gathering facilities; “Other” capital includes payadds and refracs

* Includes 10 gross (9 net) injectors

Production from Continuing Operations by Product

Commodity

2014e Midpoint

2013

% change
MMBOE boepd MMBOE boepd
Oil 11.9 32,610 10.4 28,395 15 %
NGL 4.2 11,490 3.2 8,858 30 %
Natural Gas 9.8 26,850 9.7 26,532 1 %
Total Continuing Operations 25.9 70,950 23.3 63,785 11 %

Production from Continuing Operations by Basin per Quarter

Basin 1Q14 2Q14 3Q14 4Qe Midpoint
MBOE boepd MBOE boepd MBOE boepd MMBOE boepd
Midland Basin 1,537

17,078

1,756 19,297 1,876 20,391 2.5 27,011
Delaware Basin 1,404

15,600

1,488 16,352 1,525 16,576 1.4 15,598
Central Basin Platform/Other 1,016

11,289

1,060 11,648 998 10,848 0.9 9,837
San Juan Basin/Other 2,051

22,789

2,040 22,418 2,252 24,478 2.1 22,554
Total Production 6,008 66,756 6,344 69,714 6,651 72,293 6.9 75,000

NOTE: Totals may not sum due to rounding

2015 Hedges Include 8.3 Million Barrels of Oil and Oil Differential Hedges

The company’s current hedge position for 2015 is as follows:

Commodity

Hedge Volumes

NYMEXe Price

Oil

 8.3 MMBO

$ 89.30 per barrel

Natural Gas

29.0 Bcf

$  4.30 per Mcf

Basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price in the table above by adding to them Energen Resources’ assumed San Juan and Permian basis differentials for 2015 of $0.14 per Mcf and $0.20 per Mcf, respectively.

Hedges also are in place throughout 2015 that limit the company’s exposure to the Midland to Cushing differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 2.2 million barrels of oil production at an average price of $4.30 per barrel and the WTI Midland to WTI Cushing differential for 6.1 million barrels at an average price of $5.11 per barrel.

Conference Call

Energen will hold its quarterly conference call Friday, October 31, at 11:00 a.m. EDT. Members of the investment community may participate by calling 1-877-407-8289 (reference Energen earnings call). A live audio Webcast of the program as well as a replay may be accessed through Web site, www.energen.com.

Energen Corporation is an oil and gas exploration and production company with headquarters in Birmingham, Alabama. The company has approximately 775 million barrels of oil-equivalent proved, probable, and possible reserves and another 2.5 billion barrels of oil-equivalent contingent resources. These all-domestic reserves and resources are located primarily in the Permian Basin in west Texas. For more information, go to http://www.energen.com.

FORWARD LOOKING STATEMENT: This release contains statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities 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 restructurings. We undertake no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. A more complete 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.

Financial, operating, and support data pertaining to all reporting periods included in this release are unaudited and subject to revision.

Non-GAAP Financial Measures

Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles) which excludes certain non-cash mark-to-market derivative financial instruments. Adjusted  income from continuing operations further excludes gains and losses on disposal of discontinued operations, income and losses from discontinued operations, impairment losses and dry hole expense. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.

Quarter Ended 9/30/2014
Energen Net Income ($ in millions except per share data) Net Income

Per Diluted
Share

Net Income (GAAP) 457.3 6.22
Non-cash mark-to-market gains (net of $53.1 tax) (94.1 ) (1.28 )
Asset impairment (net of $65.1 tax) 113.9 1.55
Dry hole expense (net of $2.8 tax) 4.8 0.07
Adjusted Net Income from All Operations (Non-GAAP) 481.8 6.56
Loss from discontinued operations (net of $2.5 tax) 3.5 0.05
Gain on disposal of discontinued operations (net of $286.3 tax) (440.1 ) (5.99 )
Adjusted Income from Continuing Operations (Non-GAAP) 45.2 0.62
Quarter Ended 9/30/2013
Energen Net Income ($ in millions except per share data) Net Income

Per Diluted
Share

Net Income (GAAP) (19.3 ) (0.27 )
Non-cash mark-to-market losses (net of $23.3 tax) 40.3 0.56
Dry hole expense (net of $0.5 tax) 0.9 0.01
Adjusted Net Income from All Operations (Non-GAAP) 21.9 0.30
Loss from discontinued operations (net of $5.7 tax) 9.0 0.12
Loss on disposal of discontinued operations (net of $8.9 tax) 15.7 0.22
Adjusted Income from Continuing Operations (Non-GAAP) 46.6 0.64
Year-to-Date Ended 9/30/2014

Energen Net Income ($ in millions except per share data)

Net Income

Per Diluted
Share

Net Income (GAAP) 502.6 6.86
Non-cash mark-to-market gains (net of $19.5 tax) (34.5 ) (0.47 )
Asset impairment (net of $65.1 tax) 113.9 1.56
Dry hole expense (net of $2.8 tax) 4.8 0.07
Adjusted Net Income from All Operations (Non-GAAP) 586.9 8.01
Income from discontinued operations (net of $18.1 tax) (30.4 ) (0.42 )
Gain on disposal of discontinued operations (net of $285.7 tax) (439.1 ) (5.99 )
Adjusted Income from Continuing Operations (Non-GAAP) 117.4 1.60
Year-to-Date Ended 9/30/2013
Energen Net Income ($ in millions except per share data) Net Income

Per Diluted
Share

Net Income (GAAP) 120.5 1.67
Non-cash mark-to-market losses (net of $17.7 tax) 30.7 0.43
Dry hole expense (net of $0.5 tax) 0.9 0.01
Adjusted Net Income from All Operations (Non-GAAP) 152.1 2.10
Income from discontinued operations (net of $24.2 tax) (39.9 ) (0.55 )
Loss on disposal of discontinued operations (net of $8.9 tax) 15.7 0.22
Adjusted Income from Continuing Operations (Non-GAAP) 127.9 1.77
Note: Amounts may not sum due to rounding

Non-GAAP Financial Measures

Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles).  Adjusted EBITDAX from continuing operations further excludes income and losses from discontinued operations, gains and  losses on disposal of discontinued operations, certain non-cash mark-to-market derivative financial  instruments, impairment losses  and dry hole expense. Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies.

Reconciliation To GAAP Information

Quarter Ended 9/30

($ in millions)

2014

2013

Energen Net Income (GAAP) 457.3 (19.3 )
Interest expense 11.5 10.1
Income tax expense 16.1 3.1
Depreciation, depletion and amortization 139.1 124.9
Asset impairment 179.1
Accretion expense 1.9 1.8
Exploration expense 8.3 8.9
Adjustment for mark-to-market (gains) losses (147.3 ) 63.6
Adjustment for (income) loss from discontinued operations, net of tax 3.5 9.0
Adjustment for (gain) loss on disposal of discontinued operations, net of tax (440.1 ) 15.7
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP) 229.3 217.9

Note: Amounts may not sum due to rounding

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 3 months ending September 30, 2014 and 2013

3rd Quarter
(in thousands, except per share data) 2014 2013 Change
Revenues
Oil, natural gas liquids and natural gas sales $ 350,773 $ 360,507 $ (9,734 )
Gain (loss) on derivative instruments, net 147,735 (88,192 ) 235,927
Loss on sale of assets and other (747 ) (277 ) (470 )

Total revenues 497,761 272,038 225,723
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 67,720 65,795 1,925
Production and ad valorem taxes 25,729 22,230 3,499
Depreciation, depletion and amortization 139,104 124,911 14,193
Asset impairment 179,074 179,074
Exploration 8,255 8,949 (694 )
General and administrative 27,784 30,947 (3,163 )
Accretion of discount on asset retirement obligations 1,924 1,771 153
Total costs and expenses 449,590 254,603 194,987
Operating Income 48,171 17,435 30,736
Other Income (Expense)
Interest expense (11,522 ) (10,149 ) (1,373 )
Other income 37 1,249 (1,212 )
Total other expense (11,485 ) (8,900 ) (2,585 )

Income From Continuing Operations Before Income Taxes

36,686

8,535

28,151

Income tax expense 16,055 3,128 12,927
Income From Continuing Operations 20,631 5,407 15,224
Discontinued Operations, net of tax
Loss from discontinued operations (3,485 ) (9,027 ) 5,542
Gain (loss) on disposal of discontinued operations 440,105 (15,678 ) 455,783
Income (Loss) From Discontinued Operations 436,620 (24,705 ) 461,325
Net Income (Loss) $ 457,251 $ (19,298 ) $ 476,549
Diluted Earnings Per Average Common Share
Continuing operations $ 0.28 $ 0.07 $ 0.21
Discontinued operations 5.94 (0.34 ) 6.28
Net Income (Loss) $ 6.22 $ (0.27 ) $ 6.49
Basic Earnings Per Average Common Share
Continuing operations $ 0.28 $ 0.07 $ 0.21
Discontinued operations 5.98 (0.34 ) 6.32
Net Income (Loss) $ 6.26 $ (0.27 ) $ 6.53
Diluted Avg. Common Shares Outstanding 73,507 72,346 1,161
Basic Avg. Common Shares Outstanding 73,093 72,346 747
Dividends Per Common Share $ 0.150 $ 0.145 $ 0.005

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 9 months ending September 30, 2014 and 2013

Year-to-date
(in thousands, except per share data) 2014 2013 Change
Revenues
Oil, natural gas liquids and natural gas sales $ 1,057,447 $ 927,746 $ 129,701
Gain (loss) on derivative instruments, net 9,498 (51,904 ) 61,402
Loss on sale of assets and other (1,809 ) (492 ) (1,317 )

Total revenues 1,065,136 875,350 189,786
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 199,861 190,944 8,917
Production and ad valorem taxes 81,102 69,109 11,993
Depreciation, depletion and amortization 399,568 332,247 67,321
Asset impairment 179,074 179,074
Exploration 23,644 13,902 9,742
General and administrative 93,499 86,699 6,800
Accretion of discount on asset retirement obligations 5,650 5,187 463
Total costs and expenses 982,398 698,088 284,310
Operating Income 82,738 177,262 (94,524 )
Other Income (Expense)
Interest expense (27,374 ) (30,232 ) 2,858
Other income 1,047 2,619 (1,572 )
Total other expense (26,327 ) (27,613 ) 1,286

Income From Continuing Operations Before Income Taxes

56,411

149,649

(93,238

)

Income tax expense 23,287 53,401 (30,114 )
Income From Continuing Operations 33,124 96,248 (63,124 )
Discontinued Operations, net of tax
Income from discontinued operations 30,435 39,891 (9,456 )
Gain (loss) on disposal of discontinued operations 439,055 (15,678 ) 454,733
Income From Discontinued Operations 469,490 24,213 445,277
Net Income $ 502,614 $ 120,461 $ 382,153
Diluted Earnings Per Average Common Share
Continuing operations $ 0.45 $ 1.33 $ (0.88 )
Discontinued operations 6.41 0.34 6.07
Net Income $ 6.86 $ 1.67 $ 5.19
Basic Earnings Per Average Common Share
Continuing operations $ 0.45 $ 1.33 $ (0.88 )
Discontinued operations 6.45 0.34 6.11
Net Income $ 6.90 $ 1.67 $ 5.23
Diluted Avg. Common Shares Outstanding 73,238 72,272 966
Basic Avg. Common Shares Outstanding 72,861 72,220 641
Dividends Per Common Share $ 0.45 $ 0.435 $ 0.015

CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of September 30, 2014 and December 31, 2013

(in thousands) September 30, 2014 December 31, 2013
ASSETS
Current Assets
Cash and cash equivalents $ 1,321 $ 2,523
Short-term investments 18,000
Accounts receivable, net of allowance 185,342 136,334
Inventories 14,373 11,130
Assets held for sale with prior period comparable 1,242,872
Derivative instruments 30,195 17,463
Prepayments and other 39,289 31,239
Total current assets 288,520 1,441,561
Property, Plant and Equipment
Oil and natural gas properties, net 5,457,875 5,087,573
Other property and equipment, net 43,355 30,515
Total property, plant and equipment, net 5,501,230 5,118,088
Noncurrent derivative instruments 5,758 5,439
Other assets 37,462 57,124
TOTAL ASSETS $ 5,832,970 $ 6,622,212
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year $ $ 60,000
Notes payable to banks 489,000
Accounts payable 110,955 78,178
Accrued taxes 227,180 8,201
Liabilities related to assets held for sale with prior period comparable 831,570
Derivative instruments 808 30,302
Other current liabilities 254,495 193,974
Total current liabilities 593,438 1,691,225
Long-term debt 632,458 1,093,541
Asset retirement obligations 115,431 108,533
Deferred income taxes 1,074,690 807,614
Noncurrent derivative instruments 640 398
Other long-term liabilities 55,065 62,882
Total liabilities 2,471,722 3,764,193
Total Shareholders’ Equity 3,361,248 2,858,019
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 5,832,970 $ 6,622,212

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending September 30, 2014 and 2013

3rd Quarter
(in thousands, except sales price and per unit data) 2014 2013 Change
Oil and Gas Operations

Oil, natural gas liquids and natural gas sales from continuing operations

Oil $ 260,447 $ 285,308 $ (24,861 )
Natural gas liquids 31,259 24,785 6,474
Natural gas 59,067 50,414 8,653
Total 350,773 360,507 (9,734 )
Loss on sale of assets and other $ (747 ) $ (277 ) $ (470 )

Open non-cash mark-to-market gains (losses) on derivative instruments

Oil $ 128,346 $ (63,889 ) $ 192,235
Natural gas liquids 1,276 (1,355 ) 2,631
Natural gas 17,665 1,684 15,981
Total $ 147,287 $ (63,560 ) $ 210,847
Closed gains (losses) on derivative instruments
Oil $ (6,012 ) $ (37,469 ) $ 31,457
Natural gas liquids 873 2,862 (1,989 )
Natural gas 5,587 9,975 (4,388 )
Total $ 448 $ (24,632 ) $ 25,080
Total Revenues $ 497,761 $ 272,038 $ 225,723
Production volumes from continuing operations
Oil (MBbl) 3,017 2,764 253
Natural gas liquids (MMgal) 46.5 36.7 9.8
Natural gas (MMcf) 15,156 14,868 288

Production volumes from continuing operations(MBOE)

6,651

6,116 535
Total production volumes (MBOE) 6,652 6,758 (106 )
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 84.33 $ 89.67 $ (5.34 )
Natural gas liquids (per gallon) $ 0.69 $ 0.75 $ (0.06 )
Natural gas (per Mcf) $ 4.27 $ 4.06 $ 0.21
Average realized prices excluding derivative instruments
Oil (per barrel) $ 86.33 $ 103.22 $ (16.89 )
Natural gas liquids (per gallon) $ 0.67 $ 0.68 $ (0.01 )
Natural gas (per Mcf) $ 3.90 $ 3.39 $ 0.51
Other costs per BOE from continuing operations
Oil, natural gas liquids and natural gas production expenses

$

10.18

$

10.76

$

(0.58

)

Production and ad valorem taxes $ 3.87 $ 3.63 $ 0.24
Depreciation, depletion and amortization $ 20.71 $ 20.27 $ 0.44
Exploration expense $ 1.24 $ 1.46 $ (0.22 )
General and administrative $ 4.18 $ 5.06 $ (0.88 )
Capital expenditures $ 356,725 $ 257,759 $ 98,966

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
For the 9 months ending September 30, 2014 and 2013

Year-to-date
(in thousands, except sales price and per unit data) 2014 2013 Change
Oil and Gas Operations

Oil, natural gas liquids and natural gas sales from continuing operations

Oil $ 776,952 $ 710,937 $ 66,015
Natural gas liquids 90,625 64,311 26,314
Natural gas 189,870 152,498 37,372
Total 1,057,447 927,746 129,701
Loss on sale of assets and other $ (1,809 ) $ (492 ) $ (1,317 )

Open non-cash mark-to-market gains (losses) on derivative instruments

Oil $ 40,710 $ (63,861 ) $ 104,571
Natural gas liquids 1,603 (1,208 ) 2,811
Natural gas 11,672 16,610 (4,938 )
Total $ 53,985 $ (48,459 ) $ 102,444
Closed gains (losses) on derivative instruments
Oil $ (46,568 ) $ (39,101 ) $ (7,467 )
Natural gas liquids 1,228 8,453 (7,225 )
Natural gas 853 27,203 (26,350 )
Total $ (44,487 ) $ (3,445 ) $ (41,042 )
Total Revenues $ 1,065,136 $ 875,350 $ 189,786
Production volumes from continuing operations
Oil (MBbl) 8,601 7,670 931
Natural gas liquids (MMgal) 129.2 98.5 30.7
Natural gas (MMcf) 43,956 43,428 528
Production volumes from continuing operations(MBOE) 19,003 17,253 1,750
Total production volumes (MBOE) 19,168 19,159 9
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 84.92 $ 87.59 $ (2.67 )
Natural gas liquids (per gallon) $ 0.71 $ 0.74 $ (0.03 )
Natural gas (per Mcf) $ 4.34 $ 4.14 $ 0.20
Average realized prices excluding derivative instruments
Oil (per barrel) $ 90.33 $ 92.69 $ (2.36 )
Natural gas liquids (per gallon) $ 0.70 $ 0.65 $ 0.05
Natural gas (per Mcf) $ 4.32 $ 3.51 $ 0.81
Other costs per BOE from continuing operations
Oil, natural gas liquids and natural gas production expenses

$

10.52

$

11.07

$

(0.55

)

Production and ad valorem taxes $ 4.27 $ 4.00 $ 0.27
Depreciation, depletion and amortization $ 20.85 $ 19.10 $ 1.75
Exploration expense $ 1.24 $ 0.81 $ 0.43
General and administrative $ 4.92 $ 5.03 $ (0.11 )
Capital expenditures $ 950,993 $ 862,691 $ 88,302