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Energen Targets Capital Investment in CY15 of $1.0 Billion

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For the 3 months ended December 31, 2014, Energen Corporation (NYSE: EGN) reported GAAP net income from all operations of $65.4 million, or $0.89 per diluted share. After adjusting for a mark-to-market gain, impairment losses resulting largely from low commodity prices, and discontinued operations, Energen’s adjusted income from continuing operations in the 4th quarter of 2014 totaled $41.1 million, or $0.56 per diluted share. This compares with adjusted income from continuing operations in the 4th quarter of 2013 of $50.1 million, or $0.69 per diluted share. The variance between the periods primarily is attributable to an 8 percent decline in realized oil and natural gas liquids (NGL) prices, increased lease operating expenses (LOE), and increased depreciation, depletion, and amortization (DD&A) expense, partially offset by an 18 percent increase in oil and NGL production. [See “Non-GAAP Financial Measures” beginning on pp 19 for more information and reconciliation.]

Energen’s adjusted EBITDAX from continuing operations totaled $226.0 million in the 4th quarter of 2014, up approximately 7 percent from $211.9 million in the same period last year. [See “Non-GAAP Financial Measures” beginning on pp 19 for more information and reconciliation.]

The company’s 4th quarter earnings per diluted share met internal expectations as less-than-expected production, increased LOE, and lower realized commodity prices were essentially offset by certain tax benefits.

Production in the 4th quarter was near the low end of the company’s guidance range due to the timing of completions and a longer-than-estimated flow-back period for certain wells in the Midland Basin; and in the Delaware Basin, a third-party handling issue associated with liquids in the gas stream negatively affected 4th quarter production by approximately 80,000 barrels of oil equivalents (BOE). In addition, severe weather in late December impacted 4th quarter production by approximately 30,000 BOE.

“Making responsible capital allocation decisions in a declining commodity price environment is never easy and requires some tough decisions,” said James McManus, chairman and chief executive officer of Energen Corporation. “Fortunately for Energen, we have a high-quality asset base, particularly in the Midland Basin, where we can generate acceptable returns from our Wolfcamp development program and drive double-digit production growth…even in the current market. A solid hedge position, a clean balance sheet, and lower drilling and completion costs also are working to our advantage in 2015.

“We estimate that our capital budget for drilling and development in 2015 of some $1.0 billion will approximate internally generated cash flows plus proceeds from the sale of our San Juan Basin divestiture package such that Energen’s debt-to-ebitdax multiple at year-end 2015 remains well under 2.0x. This level of spending also is expected to generate production growth of approximately 15 percent.

“The toughest issue we faced in allocating capital in 2015 was how to deal with our substantial Delaware Basin Wolfcamp potential. The high drilling costs across the basin in this young play, coupled with areas of high gas content and lack of infrastructure in more remote areas of Reeves County, does not support an active drilling program at current strip prices. Our approach has been to allocate enough capital to preserve most of our Wolfcamp potential through lease extensions and a two-rig drilling program in 2015.

“At the same time, we have ranked our Wolfcamp acreage in the Delaware Basin. Tiers 1 and 2 encompass more than 95,000 net acres and offer the greatest potential for success in four identified zones (Wolfcamp A, B, B/C, and C). The greatest potential for realizing reduced drill-and-complete costs in development is in Tier 1, where we also enjoy reasonable to good infrastructure. If oil prices rebound significantly, we believe Tier 2 could offer potential in the eastern Delaware Basin where infrastructure is in place but where more work is needed to drive down costs given a higher pressure regime and challenging rock mechanics. Our Tier 3 properties in southwest Reeves County, which we believe to be largely natural gas assets, are challenged not only by persistently low natural gas prices but also by a lack of infrastructure, and we have removed the well potential there from our unrisked drilling inventory. In our financials for the quarter, you will note that we took impairments on Tiers 2 and 3.

“Despite the current uncertainty surrounding the depth and duration of low oil prices, Energen is in a strong position — both in terms of our assets and our financial strength — and we are committed to managing our capital investments and operating plans to best serve the long-term interests of our shareholders.”

4th Quarter Financial Review

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

[See “Non-GAAP Financial Measures” beginning on pp 19 for more information]

4Q14 4Q13
$M $/dil. sh. $M $/dil. sh.
Net Income All Operations (GAAP) $ 65,418 $ 0.89 $ 84,093 $ 1.15
Less: Non-cash Mark-to-Market gain/(loss) 167,315 2.28 159 0.00
Less: Asset Impairment, other (141,945 ) (1.94 ) (4,619 ) (0.06 )
Less: Discontinued Operations (1,101 ) (0.02 ) 38,460 0.53
Adj. Income Continuing Operations (Non-GAAP) $ 41,149 $ 0.56 $ 50,093 $ 0.69

Note: Per share amounts may not sum due to rounding

After-tax asset impairments included $59 million for wells in Delaware Basin Tiers 2 and 3 as a result of low commodity prices; an additional $48 million for the San Juan Basin held-for-sale assets due to lower natural gas prices; and $34 million for unproved leasehold primarily in Delaware Basin Tiers 2 and 3.

Production from Continuing Operations by Product

Commodity 4Q14 4Q13 Change 3Q14
MBOE boepd MBOE boepd MBOE boepd
Oil 3,213 34,924 2,694 29,283 19 % 3,017 32,793
NGL 1,027 11,163 888 9,652 16 % 1,108 12,043
Natural Gas 2,441 26,533 2,446 26,587 0 % 2,526 27,457
Total 6,681 72,620 6,028 65,522 11 % 6,651 72,293

Production from Continuing Operations by Area

Area 4Q14 4Q13 Change 3Q14
MBOE boepd MBOE boepd MBOE boepd
Midland Basin 2,238 24,326 1,477 16,054 52 % 1,876 20,391
Wolfberry 1,189 12,924 1,453 15,793

1,292 14,043
Wolfcamp/Cline 1,049 11,402 24 261 584 6,348
Delaware Basin 1,421 15,446 1,234 13,413 15 % 1,525 16,576
3rd Bone Spring/Other 1,129 12,272 1,043 11,337 1,219 13,250
Wolfcamp 292 3,174 190 2,065 306 3,326
Central Basin Platform 979 10,641 1,091 11,859 (10 ) % 998 10,848
Total Permian Basin 4,638 50,413 3,802 41,326 22 % 4,399 47,815
San Juan Basin/Other 2,043 22,207 2,226 24,196 (8 ) % 2,252 24,478
Total 6,681 72,620 6,028 65,522 11 % 6,651 72,293

Note: Totals may not sum due to rounding

Average Realized Sales Prices from Continuing Operations

Commodity 4Q14 4Q13 Change
Oil (per barrel) $ 81.81 $ 87.80 (7 ) %
NGL (per gallon) $ 0.59 $ 0.79 (25 ) %
Natural Gas (per Mcf) $ 4.28 $ 4.35 (2 ) %

Expenses from Continuing Operations (per BOE, except interest expense)

Expenses 4Q14 4Q13 Change
LOE* $ 11.16 $ 11.04 1

%

Production & ad valorem taxes $ 3.14 $ 4.15 (24

)%

DD&A $ 22.08 $ 19.96 11

%

Net G&A $ 4.27 $ 4.50 (5

)%

Interest ($MM) $ 10.4 $ 9.5 9

%

*Production costs + workovers and repairs + marketing and transportation

4th Quarter Comparisons, 2014 vs 2013 (Continuing Operations)

  • Permian Basin production increased 22 percent as new drilling in the horizontal Wolfcamp more than offset declines resulting from a reduced vertical Wolfberry program and from natural declines in the company’s legacy assets in the Central Basin Platform.
  • Energen did not feel the full brunt of rapidly declining oil prices in the 4th quarter of 2014 due to its substantial hedge position. The company’s average realized oil price fell 7 percent largely due to higher Midland to Cushing basis differentials for sweet and sour oil production. Excluding the impact of all hedges, the average price of oil would have declined $26.88 per barrel to $65.96.
  • LOE per unit was little changed at $11.16 per barrel. Per-unit production taxes and ad valorem taxes declined 24 percent.
  • Per-unit DD&A expense increased 11 percent to $22.08 per BOE largely due to year-over-year increases in development costs.
  • Per-unit net G&A expense of $4.27 per BOE decreased 5 percent from the same period a year ago.
  • Interest expense increased 9 percent to total $10.4 million largely due to prior-year reclassification of certain interest expense to discontinued operations.

CY14 Financial Summary

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

[See “Non-GAAP Financial Measures” beginning on pp 19 for more information]

CY14 CY13
$M $/dil. sh. $M $/dil. sh.
Net Income All Operations (GAAP) $ 568,032 $ 7.75 $ 204,554 $ 2.82
Less: Non-cash Mark-to-Market gain/(loss) 201,790 2.75 (30,574 ) (0.42 )
Less: Asset Impairment (257,298 ) (3.51 ) (8,866 ) (0.12 )
Less: Dry hole expense (5,891 ) (0.08 ) (1,286 ) (0.02 )
Less: Discontinued Operations 468,389 6.39 62,673 0.86
Adj. Income Continuing Operations (Non-GAAP) $ 161,042 $ 2.20 $ 182,607 $ 2.52

Note: Per share amounts may not sum due to rounding

After-tax asset impairments in 2014 included $142 million for San Juan Basin held-for-sale assets; $59 million for wells in Delaware Basin Tiers 2 and 3 as a result of low commodity prices; and $34 million of unproved leasehold primarily in Delaware Basin Tiers 2 and 3.

Production from Continuing Operations by Product

Commodity CY14 CY13 Change
MMBOE MMBOE
Oil 11.8 10.4 13 %
NGL 4.1 3.2 28 %
Natural Gas 9.8 9.7 1 %
Total 25.7 23.3 10 %

Note: Totals may not sum due to rounding

Production from Continuing Operations by Area

Area CY14 CY13 Change
MMBOE MMBOE
Midland Basin 7.4 5.1 45

%

Wolfberry 5.3 5.0

Wolfcamp/Cline 2.1 0.1
Delaware Basin 5.8 4.7 23

%

3rd Bone Spring/Other 4.6 4.3
Wolfcamp 1.2 0.4
Central Basin Platform 4.1 4.4 (7

)%

Total Permian Basin 17.3 14.2 22

%

San Juan Basin/Other 8.4 9.1 (8

)%

Total 25.7 23.3 10

%

Note: Totals may not sum due to rounding

Average Realized Sales Prices from Continuing Operations

Commodity CY14 CY13 Change
Oil (per barrel) $ 84.07 $ 87.65

(4

)%

NGL (per gallon) $ 0.68 $ 0.75

(9

)%

Natural Gas (per Mcf) $ 4.32 $ 4.19 3

%

Expenses from Continuing Operations (per BOE, except interest expense)

Expenses CY14 CY13 Change
LOE* $ 10.68 $ 11.06 (3

)%

Production & ad valorem taxes $ 3.97 $ 4.04 (2

)%

DD&A $ 21.17 $ 19.32 10

%

Net G&A $ 4.75 $ 4.89 (3

)%

Interest ($MM) $ 37.8 $ 39.7 (5

)%

*Production costs + workovers and repairs + marketing and transportation

Energen Signs Purchase & Sale Agreement for San Juan Basin Gas Assets

Energen has agreed to sell the majority of its natural gas assets in the San Juan Basin to a private company for $395 million. The assets to be sold include approximately 985 net operated wells on some 205,000 net acres. These assets had proved, probable, and possible reserves at year-end 2014 of 244 MMBOE, of which 84 percent was natural gas and 16 percent was NGL; associated production in 2014 totaled 6.6 MMBOE. The sale is expected to close by March 31, 2015, and have an effective date of January 1, 2015.

Wolfcamp, Cline, and Mancos Potential Drilling Inventory Totals 5,590 Wells

Energen updated its unrisked potential drilling inventory as of year-end 2014. Plays included in this inventory are three benches of the Wolfcamp shale in the Midland Basin, the Cline shale in the Midland Basin, four benches of the Wolfcamp shale in the Delaware Basin, and one bench in the Mancos oil formation in the San Juan Basin. The company’s total unrisked potential drilling inventory is 5,590 net locations on approximately 66,000 net acres in the Midland Basin, 113,300 net acres in the Delaware Basin, and 91,000 net acres in the San Juan Basin.

Changes to the inventory include the addition of the San Juan Basin Mancos oil potential as well as a fourth Wolfcamp bench in the Delaware Basin along with an increase in spacing in the Delaware Basin to 880 feet and the exclusion of Tier 3 locations; in the Midland Basin, previously identified Cline potential in Mitchell County was excluded. Later in the year, subject to supporting well results, Energen plans to quantify its Spraberry potential in the Midland Basin; this could result in a significant increase in the company’s already-deep inventory.

Midland Basin Wolfcamp/Cline Potential by County
(unrisked, 660-foot spacing, 4,400’/6,700’/7,500′ lateral lengths)

Wolfcamp A Wolfcamp B Wolfcamp C Cline

Net
Locations

Net
Acres

Net
Locations

Net
Acres

Net
Locations

Net
Acres

Net
Locations

Net
Acres

Glasscock 224 24,248 221 25,654 236 25,255 238 25,582
Howard 74 6,183 75 6,183 32 2,893
Martin 209 18,616 210 18,606 207 17,697
Midland 87 9,029 80 8,383 35 4,253
Reagan 61 7,368 60 6,047 40 6,047 21 2,291
Upton 9 889 7 649 1 76
Total 664 66,333 653 65,523 276 31,302 534 52,792

Delaware Basin Wolfcamp Potential by County
(unrisked, 880-foot spacing, 4,400′ lateral lengths)

Wolfcamp A Wolfcamp B Wolfcamp B/C Wolfcamp C

Net
Locations

Net
Acres

Net
Locations

Net
Acres

Net
Locations

Net
Acres

Net
Locations

Net
Acres

Tier 1 575 64,395 562 62,085 475 54,666 481 54,666
Tier 2 294 31,071 141 30,350 137 27,700 233 27,700
Tier 3 17,831 17,831 17,831 17,831
Total 869 113,297 703 110,266 612 100,197 714 100,197

San Juan Basin Mancos Oil Potential by Area
(unrisked, 1,320-foot spacing, 4,400′ lateral lengths)

Net Locations Net Acres
Southwest 125 20,154
South Central 53 8,609
Southeast/Jicarilla 387 62,290
Total 565 91,053

Southern Glasscock Development Wells Performing (3-Stream)

4Q14 CY14
Wells drilled (gross/net) 26/26 60/58
Wells completed 21/21 36/34
Wells awaiting completion 24/24 24/24

During 2014, Energen implemented a development program in the Wolfcamp shale in Glasscock County in the Midland Basin. This program focused on pad drilling stacked A & B laterals with lengths of 6,700′ and 7,500′. Late in 2014, the company added some 4,400′ lateral length wells to the program to test a tighter spacing configuration. Nine wells with short laterals were drilled in the 4th quarter but have not been completed. In total, Energen drilled 60 gross (58 net) wells in the development program in 2014 and completed 36 gross (34 net) wells.

During the 4th quarter, the company tested 12 gross (12 net) wells; these wells generated average peak 24-hour IP rates of 977 boepd (77% oil) and peak 30-day average rates of 914 boepd (77% oil). In aggregate, the 27 gross (26 net) wells tested in 2014 generated average peak 24-hour IPs (3-stream) of 975 boepd (75% oil) and peak 30-day average rates (3-stream) of 821 boepd (75% oil).

The early performance of these wells has met or exceeded the company’s unrisked type curves that support EURs of 770 MBOE for 6,700′ lateral lengths and 850 MBOE for 7,500′ lateral lengths. The company today is issuing a type curve for its southern Glasscock Wolfcamp A- and B-bench development program wells, with the lateral length normalized to 7,000′; normalized production for 4th quarter and calendar year 2014 wells have been plotted on the curve. (See type curve on Energen’s Web site at www.energen.com).

Midland and Delaware Basin Exploration Program Results

Energen tested six new exploratory wells in the Permian Basin during the 4th quarter of 2014, including its first two Wolfcamp C wells in the Midland 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
Dickenson SN 20-17 #101H WC A/Martin 6,250 5,800 24 614 83 10 7 463 72 16 12
Dickenson SN 20-17 #201H WC B/Martin 6,800 6,300 26 1,376 85 8 6 806 78 13 10
Brazos SN 17-8 #304H WC C/Glasscock 6,500 5,925 26 848 48 28 24 664 67 18 15
Daniel SN 10-3 #303H WC C/Glasscock 8,100 7,580 31 1,087 65 21 14 623 65 21 14
Ron 56-8 #1H

WC BC/Reeves

4,800 4,050 17 1,734 11 40 49 1,293 12 39 49
Matador 6-33 #2H WC B/Reeves 4,825 4,200 22 1,292 68 17 15 864 69 17 14

* Represents distance from vertical departure to toe

Energen’s first two Wolfcamp C wells in Glasscock County tested at attractive initial rates. The company also tested its first two wells in southern Martin County, close to the Midland County line. In 2014, Energen drilled 16 gross (16 net) wells in its Midland Basin exploratory program; three of the wells originally planned for 2014 were moved to 2015. Energen completed and tested 12 gross (12 net) wells during the year; the remaining 4 gross (4 net) wells drilled are currently flowing back, including a third Wolfcamp C well in Glasscock County, two lower Spraberry test wells, and a Wolfcamp B in Howard County.

In the Delaware Basin, the Matador 6-33 #2H was a very nice Wolfcamp B well tested during the 4th quarter. The Ron 56-8 #1H, a BC-bench well in Reeves County, also had good rates. Energen’s 2014 Delaware Basin Wolfcamp program resulted in the drilling of 11 gross (10 net) wells. Two wells planned for 2014 were moved to 2015. Six gross (five net) wells were completed and tested during the year, and another 5 gross (5 net) wells are in various stages of completion and flow back.

3P and Contingent Resources top 3.3 Billion BOE

Energen’s proved reserves at year-end 2014 totaled a record 372.7 MMBOE and represented a 7 percent increase from the prior year. Energen delivered 401% drillbit reserve replacement by adding net proved reserves of 103.7 MMBOE (excludes the removal of 53.4 MMBOE of proved undeveloped reserves and positive pricing revisions of 3.9 MMBOE) at a drillbit finding and development cost of approximately $14.00 per BOE. Total reserve revisions of 75.6 MMBOE primarily reflect Midland Basin Wolfberry PUDs moved to “probable” as a result of updated drilling plans that slow the pace of vertical Wolfberry development in deference to higher-return horizontal wells.

Oil and NGL reserves at year end represented approximately 68 percent of total proved reserves and are expected to increase as Energen continues to focus on drilling its liquids-rich assets. Pro forma for the sale of the majority of the company’s San Juan Basin gas assets, oil and NGL reserves represent 80 percent of the company’s proved reserves.

Commodity prices used for calculating reserves at year-end 2014 were $94.98 per barrel of oil (down from $96.94 in 2013), $4.35 per thousand cubic feet (Mcf) for natural gas (up from $3.67 in 2013); and an average of $0.75 per gallon of NGL before transportation and fractionation (essentially unchanged from $0.76 per gallon in 2013).

Proved Reserves by Basin (MMBOE)

Basin YE13

2014
Production

2014
Acquisitions/
(Divestitures)

Additions

Price/Other
Revisions

YE14
Permian 246.6 (17.3 ) 0.1 128.6 (77.2 ) 280.8
San Juan Basin/Other 97.4 (8.4 ) 0.0 1.3 1.6 91.9
NL/ETX 3.9 (0.2 ) (3.7 ) 0.0 0.0 0.0
TOTAL 347.8 (25.8 ) (3.6 ) 129.9 (75.6 ) 372.7

NOTE: Totals may not sum due to rounding

Proved Reserves by Commodity (MMBOE)

Commodity 2014 2013 % Change
Oil 181 165 10
Natural gas liquids 73 63 16
Natural gas 119 120 (1 )
TOTAL 373 348 7

YE2014 3P Reserves & Contingent Resources (MMBOE)

Basin Proved Probable Possible Contingent Total
Permian Basin 281 226 279 1,950 2,736
Delaware Basin 37 21 8 1,407 1,473
  • Wolfcamp/Wolfbone
12 17 8 1,407 1,443
  • 3rd Bone Spring/Other
25 4 NM NM 30
Midland Basin 184 194 232 543 1,154
  • Wolfcamp
114 133 167 362 776
  • Cline/Other
2 2 65 181 250
  • Wolfberry
68 60 NM NM 128
Central Basin Platform 60 10 39 0.0 109
San Juan/Other 92 63 147 302 604
  • Divestiture
69 60 115 125 369
  • Remaining
23 3 32 177 235
TOTAL 373 289 427 2,252 3,340

NOTE: Totals may not sum due to rounding

The definitions of probable and possible reserves imply different probabilities of potential recovery in each classification; the quantities reported here are unrisked and based on the Company’s best estimate of current costs to drill wells in each basin/area and bring associated production to market.

Capital, Production and Financial Guidance

Energen plans to invest approximately $1.0 billion of capital in its 2015 drilling and development program. Capital reflects a decrease in service costs of approximately 10 percent; continued low commodity prices could drive service costs in the Permian Basin lower as the year progresses. More than 50 percent of 2015 drilling and development capital will be focused in the company’s Midland Basin Wolfcamp and Spraberry appraisal and development programs. Capital investment for drilling and development in 2015 reflects a 26 percent decrease from the $1.36 billion invested in 2014. In 2014, Energen also invested another $71 million for acquisitions of proved properties and unproved leasehold (UPLH), bringing total drilling, development, and acquisition/UPLH capital in 2014 to $1.4 billion.

2015 Capital, Drilling and Production Summary

2015e
Capital
($MM)

Operated
Rigs

Operated Wells
to Be Drilled
Gross (Net)

Midland Basin $ 665 530 5-8*
Wolfcamp 515
Development 437

97

(89

)
Exploration 78
Spraberry 68

68

(64

)
Wolfberry 27

8

(8

)
SWD/Facilities 45

7

(7

)
Non-operated/Other 10

14

(10

)
Delaware Basin $ 187 2+
Bone Spring 10
Wolfcamp 85
Wolfbone 13

14

(13

)
Lease extensions 37

3

(2

)
SWD/Facilities 39

8

(8

)
Non-operated/Other 3

3

(3

)
Other Permian $ 12
Waterflood injectors 3
Facilities/C02 6

6

(6

)
Non-operated/Other 3

6

(6

)
San Juan Basin/Other $ 73

1

Mancos 52
Facilities 1
Non-operated/Other 20

8

(8

)
Net Carry-in/Carry Out $ 63

8

(8

)
TOTAL $

1,000

8-11

125

(116

)

Note: “Facilities” capital includes artificial lift and central gathering facilities; “Other” capital includes payadds and refracs

* Includes 2 horizontal rigs and 1 vertical rig each running for 1/2 year

+ Both rigs run for 1/2 year

DRILLING PLANS

Midland Basin (operated): Horizontal drilling in the Midland Basin is the focus of Energen’s 2015 capital and drilling programs. Five full-year and two partial-year rigs will be employed to drill an estimated 68 gross wells in the company’s Wolfcamp A & B development program; 57 of these wells have lateral lengths of 6,700′ and 7,500′. Plans for 2015 call for the development program to expand from southern Glasscock County to Martin County; 44 gross wells are slated to be drilled in Glasscock County and 13 gross wells to be drilled in Martin County. The cost to drill and complete these wells is estimated to be $6.5-$7.5 million per well.

The other 11 gross development program wells will be drilled with 4,400′ laterals in a continuation of a 20-well program begun in December 2014 to test tighter spacing concepts. All 20 wells are being drilled in southern Glasscock County at an estimated average drill-and-complete cost of $6.0-$6.3 million per well.

During 2015 Energen expects to complete 68 gross (66 net) wells in the development program, including 24 gross (24 net) wells from the 2014 program.

In addition to the development program, Energen plans to drill 15 gross appraisal wells in the Midland Basin. These include seven Spraberry tests and five Wolfcamp wells with lateral lengths of 6,700′ and 7,500′; the budgeted costs to drill and complete these wells are estimated to range from $9.0-$10.0 million per well. The other three Wolfcamp appraisal wells will test 10,000′ laterals at an estimated drill-and-complete cost of $11.5-$12.0 million per well. At current low commodity prices, the company has no plans to drill Cline shale wells.

One vertical rig is scheduled to run for part of 2015 to drill 14 gross Wolfberry wells at an average drill-and-complete cost of $2.6 million per well. With the drilling of these wells, Energen’s Midland Basin acreage position is held by production.

Delaware Basin (operated): The focus of Delaware Basin drilling in 2015 is on retaining leasehold. To this end, the company has paid $36.8 million to extend certain leases and also will drill six Tier 1 wells and two Tier 2 wells at an estimated cost to drill and complete of $10.0-$11.0 million per well; three vertical Wolfbone wells also are scheduled to be drilled at an average cost of $4.0-$4.5 million per well. In addition, Energen plans to drill three 3rd Bone Spring wells in the Delaware Basin at an average cost of $7.0-$7.5 million per well. Plans call for two horizontal rigs to run for parts of the year.

All planned Delaware Basin wells drilled in 2015 are expected to be completed by year end.

San Juan Basin (operated): Energen’s delineation work in the Mancos oil formation in the San Juan Basin begins in 2015 with a one-rig program. Current plans are to drill six wells in the South Central area, one well in the Southwest area, and one in the Southeast/Jicarilla area. The average cost to drill and complete is estimated to be $6.5 million per well. All eight wells are expected to be completed by year end.

Non-operated Activities: Energen plans to participate as a 50 percent working interest partner in six Mancos oil wells that WPX Energy plans to drill and operate in 2015. Elsewhere, Energen’s non-operated activity is minimal.

1Q15 AND CY15 PRODUCTION

Energen’s 2015 production (excluding volumes from the company’s San Juan Basin divestiture package) is estimated to range from 21.4-22.4 MMBOE (58,545-61,285 boepd), with a midpoint of 21.9 MMBOE. This reflects an increase of 15 percent from comparable, adjusted 2014 production volumes of 19.1 MMBOE. First quarter 2015 production is estimated to range from 4.4-4.8 MMBOE (4,889-5,333 boepd), with a midpoint of 4.6 MMBOE.

Severe winter weather across the Permian Basin in late December/early January is estimated to negatively affect first quarter and calendar year 2015 production by 225 MBOE, with 61 percent of the impact being felt in the Midland Basin.

The company also estimates that a third party liquids handling issue that emerged in late 2014 in the Delaware Basin will negatively affect first quarter production by approximately 210 MBOE and calendar year production by approximately 285 MBOE. Due to an increase in liquids in the gas stream in the Delaware Basin, Energen’s gas gatherer/processor is modifying its plant facilities to handle the liquids load and is adding compression; the issue is expected to be resolved in May 2015.

First quarter and calendar year 2015 production estimates also reflect longer flow-back periods for certain wells in the company’s Midland Basin Wolfcamp development program.

Production from Continuing Operations by Play, Pro Forma to Exclude San Juan Basin Divestiture

Area 2015e Midpoint 2014 Change
MMBOE MMBOE
Midland Basin 11.6 7.4 57

%

Wolfcamp/Spraberry/Cline 7.5 2.1

Wolfberry 4.1 5.3
Delaware Basin 4.8 5.8 (17

)%

3rd Bone Spring/Other 3.4 4.6
Wolfcamp 1.4 1.2
Central Basin Platform 3.5 4.1 (15

)%

Total Permian Basin 19.9 17.3 15

%

San Juan Basin/Other 2.0 1.8 11

%

Total 21.9 19.1 15

%

NOTE: Totals may not sum due to rounding

Production from Continuing Operations by Product, Pro Forma to Exclude San Juan Basin Divestiture

Midpoint 2015e

2014

Commodity

MMBOE

boepd

MMBOE

boepd

% change

Oil 14.0 38,375 11.8 32,323 19 %
NGL 3.7 10,126 3.4 9,337 9 %
Natural Gas 4.2 11,383 3.9 10,660 7 %
Total Continuing Operations 21.9 59,884 19.1 52,320 15 %

Production from Continuing Operations by Basin/Quarter, Pro Forma to Exclude San Juan Divestiture

Basin 1Q15e Midpoint 2Q15e Midpoint 3Q15e Midpoint 4Q15e Midpoint
MMBOE boepd MMBOE boepd MMBOE boepd MMBOE boepd
Midland Basin 2.3 1 25,078 2.8 30,923 3.2 34,782 3.4 36,413
Delaware Basin 1.0 1 11,244 1.2 13,560 1.3 14,000 1.2 13,337
Central Basin Platform/Other 0.9 1 10,000 0.9 9,835 0.9 9,544 0.9 9,283
San Juan Basin/Other 0.4 4,644 0.4 4,692 0.5 5,924 0.6 6,217
Total Production 4.6 50,956 5.4 59,000 5.9 64,239 6.0 65,250

NOTE: Totals may not sum due to rounding

Production from Continuing Operations by Commodity/Quarter, Pro Forma to Exclude San Juan Basin Divestiture

Commodity 1Q15e Midpoint 2Q15e Midpoint 3Q15e Midpoint 4Q15e Midpoint
MBOE boepd MBOE boepd MBOE boepd MBOE boepd
Oil 3.0 1 33,300 3.5 38,187 3.8 40,880 3.8 41,087
NGL 0.7 1 8,144 0.9 9,780 1.0 11,076 1.1 11,489
Gas 0.9 1 9,522 1.0 11,033 1.1 12,283 1.2 12,685
Total Production 4.6 50,956 5.4 59,000 5.9 64,239 6.0 65,250

NOTE: Totals may not sum due to rounding

1Q15 AND CY15 FINANCIAL GUIDANCE

Energen’s estimated expenses from continuing operations, pro forma to exclude San Juan Basin divestiture, are as follows:

Per BOE, except where noted 1Q15 CY15
LOE (production costs, marketing & transportation)

$11.70-$12.50

$10.15-$11.25
Production & ad valorem taxes (% of revenues, excluding hedges) 10.3% 8.9%
DD&A expense (per BOE) $24.65-$26.15 $23.50-$25.75
General & administrative expense, net* $6.85 $5.67
Exploration expense (seismic, delay rentals, etc.) $0.70-$0.80 $0.45-$0.50
Interest expense ($MM) $11.5-$12.3 $44.0-$49.0

*Excludes $0.87 per BOE in 1Q15 and $1.69 per BOE in CY15 for pension and pension settlement expenses.

For comparison purposes, calendar year 2014 expenses pro forma to exclude the San Juan Basin divestiture were: LOE of $11.24 per BOE, production and ad valorem taxes of $4.55 per BOE, DD&A of $25.55 per BOE, net G&A $6.46 per BOE, exploration expense of $0.99 per BOE, and Interest Expense of $37.8 million.

2015 Hedge Position

Approximately 57 percent of the company’s 2015 production guidance midpoint of 21.9 MMBOE is hedged. Hedges also are in place 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 (sweet oil) differential for 7.4 million barrels at an average price of $4.62 per barrel. Energen estimates that approximately 79 percent of its oil production in 2015 will be sweet. Gas basis assumptions for all open contracts (March-December) are $0.17 per Mcf (basis actuals in January and February are $0.16 and $0.23, respectively).

The company’s current hedge position for 2015 is:

Commodity

Hedge Volumes

CY15e Production
Midpoint

Hedge %

NYMEXe Price

Oil

8.3 MMBO

14.0 MMBO

59 %

$ 89.30 per barrel

Natural Gas

24.9 Bcf

24.9 Bcf

100 %

$ 4.34 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 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 $2.41 per barrel in 2015; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin.

Energen’s assumptions for the commodity prices of unhedged production in 2015 are $57 per barrel of oil, $2.85 per Mcf of gas, and $0.45 per gallon of NGL. Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil are $2.80 and $2.25, respectively.

For unhedged production, every $1.00 change in the average NYMEX price of oil from $57 per barrel is estimated to have a $4.7 million impact on cash flows, and every 1-cent change in the average price of NGL from $0.45 per gallon is estimated to have a cash flows impact of $1.0 million.

Conference Call

Energen will hold its quarterly conference call Friday, February 13, at 11:00 a.m. EST. 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 1.1 billion barrels of oil-equivalent proved, probable, and possible reserves and another 2.2 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 12/31/2014
Energen Net Income ($ in millions except per share data) Net Income

Per Diluted
Share

Net Income (GAAP) 65.4 0.89
Non-cash mark-to-market gains (net of $94.1 tax) (167.3 ) (2.28 )
Asset impairment (net of $93.7 tax) 141.6 1.93
Dry hole expense (net of $0.2 tax) 0.3 0.00
Adjusted Net Income from All Operations (Non-GAAP) 40.0 0.55
Loss from discontinued operations (net of $0.2 tax) 1.1 0.02
Gain on disposal of discontinued operations (net of $0.2 tax) (0.0 ) (0.00 )
Adjusted Income from Continuing Operations (Non-GAAP) 41.1 0.56
Quarter Ended 12/31/2013
Energen Net Income ($ in millions except per share data) Net Income

Per Diluted
Share

Net Income (GAAP) 84.1 1.15
Non-cash mark-to-market gains (net of $0.5 tax) (0.2 ) (0.00 )
Asset impairment (net of $2.6 tax) 4.5 0.06
Dry hole expense (net of $0.1 tax) 0.1 0.00
Adjusted Net Income from All Operations (Non-GAAP) 88.6 1.21
Income from discontinued operations (net of $9.0 tax) (19.2 ) (0.26 )
Gain on disposal of discontinued operations (net of $10.9 tax) (19.3 ) (0.26 )
Adjusted Income from Continuing Operations (Non-GAAP) 50.1 0.69
Year-to-Date Ended 12/31/2014
Energen Net Income ($ in millions except per share data) Net Income

Per Diluted
Share

Net Income (GAAP) 568.0 7.75
Non-cash mark-to-market gains (net of $113.7 tax) (201.8 ) (2.75 )
Asset impairment (net of $159.5 tax) 257.3 3.51
Dry hole expense (net of $3.4 tax) 5.9 0.08
Adjusted Net Income from All Operations (Non-GAAP) 629.4 8.59
Income from discontinued operations (net of $17.9 tax) (29.3 ) (0.40 )
Gain on disposal of discontinued operations (net of $285.5 tax) (439.1 ) (5.99 )
Adjusted Income from Continuing Operations (Non-GAAP) 161.0 2.20
Year-to-Date Ended 12/31/2013
Energen Net Income ($ in millions except per share data) Net Income

Per Diluted
Share

Net Income (GAAP) 204.554 2.82
Non-cash mark-to-market losses (net of $17.3 tax) 30.574 0.42
Asset impairment (net of $5.0 tax) 8.866 0.12
Dry hole expense (net of $0.7 tax) 1.286 0.02
Adjusted Net Income from All Operations (Non-GAAP) 245.280 3.38
Income from discontinued operations (net of $33.2 tax) (59.079 ) (0.82 )
Loss on disposal of discontinued operations (net of $2.0 tax) (3.594 ) (0.05 )
Adjusted Income from Continuing Operations (Non-GAAP) 182.607 2.52
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 12/31
($ in millions) 2014 2013
Energen Net Income (GAAP) 65.4 84.1
Interest expense 10.4 9.5
Income tax expense 17.4 20.9
Depreciation, depletion and amortization 149.0 120.6
Accretion expense 2.0 1.8
Exploration expense 6.3 6.8
Dry hole expense 0.5 0.2
Adjustment for asset impairment 235.3 7.1
Adjustment for mark-to-market gains (261.5 ) (0.6 )
Adjustment for (income) loss from discontinued operations, net of tax 1.1 (19.2 )
Adjustment for gain on disposal of discontinued operations, net of tax (0.0 ) (19.3 )
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP) 226.0 211.9
Note: Amounts may not sum due to rounding

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 3 months ending December 31, 2014 and 2013

4th Quarter

(in thousands, except per share data)

2014 2013 Change
Revenues
Oil, natural gas liquids and natural gas sales $ 286,747 $ 328,571 $ (41,824 )
Gain on derivative instruments, net 325,521 1,880 323,641
Loss on sale of assets and other (833 ) (489 ) (344 )

Total revenues 611,435 329,962 281,473
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 74,571 66,494 8,077
Production and ad valorem taxes 20,961 24,994 (4,033 )
Depreciation, depletion and amortization 148,996 120,629 28,367
Asset impairment 235,301 7,082 228,219
Exploration 6,872 6,958 (86 )
General and administrative 28,553 27,122 1,431
Accretion of discount on asset retirement obligations 1,958 1,808 150
Total costs and expenses 517,212 255,087 262,125
Operating Income 94,223 74,875 19,348
Other Income (Expense)
Interest expense (10,397 ) (9,504 ) (893 )
Other income 134 1,184 (1,050 )
Total other expense (10,263 ) (8,320 ) (1,943 )

Income From Continuing Operations Before Income Taxes

83,960

66,555

17,405

Income tax expense 17,441 20,922 (3,481 )
Income From Continuing Operations 66,519 45,633 20,886
Discontinued Operations, net of tax
Income (loss) from discontinued operations (1,143 ) 19,188 (20,331 )
Gain on disposal of discontinued operations 42 19,272 (19,230 )
Income (Loss) From Discontinued Operations (1,101 ) 38,460 (39,561 )
Net Income $ 65,418 $ 84,093 $ (18,675 )
Diluted Earnings Per Average Common Share
Continuing operations $ 0.91 $ 0.62 $ 0.29
Discontinued operations (0.02 ) 0.53 (0.55 )
Net Income $ 0.89 $ 1.15 $ (0.26 )
Basic Earnings Per Average Common Share
Continuing operations $ 0.91 $ 0.63 $ 0.28
Discontinued operations (0.01 ) 0.53 (0.54 )
Net Income $ 0.90 $ 1.16 $ (0.26 )
Diluted Avg. Common Shares Outstanding 73,343 73,086 257
Basic Avg. Common Shares Outstanding 72,988 72,628 360
Dividends Per Common Share $ 0.02 $ 0.145 $ (0.125 )

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 12 months ending December 31, 2014 and 2013

Year-to-date

(in thousands, except per share data)

2014 2013 Change
Revenues
Oil, natural gas liquids and natural gas sales $ 1,344,194 $ 1,256,317 $ 87,877
Gain (loss) on derivative instruments, net 335,019 (50,024 ) 385,043
Loss on sale of assets and other (2,642 ) (981 ) (1,661 )

Total revenues 1,676,571 1,205,312 471,259
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 274,432 257,438 16,994
Production and ad valorem taxes 102,063 94,103 7,960
Depreciation, depletion and amortization 548,564 452,876 95,688
Asset impairment 416,801 13,906 402,895
Exploration 28,090 14,036 14,054
General and administrative 122,052 113,821 8,231
Accretion of discount on asset retirement obligations 7,608 6,995 613
Total costs and expenses 1,499,610 953,175 546,435
Operating Income 176,961 252,137 (75,176 )
Other Income (Expense)
Interest expense (37,771 ) (39,736 ) 1,965
Other income 1,181 3,803 (2,622 )
Total other expense (36,590 ) (35,933 ) (657 )

Income From Continuing Operations Before Income Taxes

140,371

216,204

(75,833

)

Income tax expense 40,728 74,323 (33,595 )
Income From Continuing Operations 99,643 141,881 (42,238 )
Discontinued Operations, net of tax
Income from discontinued operations 29,292 59,079 (29,787 )
Gain on disposal of discontinued operations 439,097 3,594 435,503
Income From Discontinued Operations 468,389 62,673 405,716
Net Income $ 568,032 $ 204,554 $ 363,478
Diluted Earnings Per Average Common Share
Continuing operations $ 1.36 $ 1.96 $ (0.60 )
Discontinued operations 6.39 0.86 5.53
Net Income $ 7.75 $ 2.82 $ 4.93
Basic Earnings Per Average Common Share
Continuing operations $ 1.37 $ 1.96 $ (0.59 )
Discontinued operations 6.42 0.87 5.55
Net Income $ 7.79 $ 2.83 $ 4.96
Diluted Average Common Shares Outstanding 73,275 72,471 804
Basic Average Common Shares Outstanding 72,897 72,318 579
Dividends Per Common Share $ 0.47 $ 0.58 $ (0.11 )

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

(in thousands)

December 31, 2014 December 31, 2013
ASSETS
Current Assets
Cash and cash equivalents $ 1,852 $ 2,523
Accounts receivable, net of allowance 147,675 136,334
Inventories 14,251 11,130
Assets held for sale 411,654 1,242,872
Deferred income taxes - 21,250
Derivative instruments 322,337 17,463
Prepayments and other 24,574 9,989
Total current assets 922,343 1,441,561
Property, Plant and Equipment
Oil and natural gas properties, net 5,152,748 5,087,573
Other property and equipment, net 43,812 30,515
Total property, plant and equipment, net 5,196,560 5,118,088
Noncurrent derivative instruments - 5,439
Other assets 19,512 57,124
TOTAL ASSETS $ 6,138,415 $ 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 101,562 78,178
Accrued taxes 4,003 8,201
Accrued wages and benefits 46,162 27,036
Accrued capital costs 207,461 93,623
Revenue and royalty payable 64,446 51,519
Liabilities related to assets held for sale 33,406 831,570
Deferred income taxes 79,164
Derivative instruments 988 30,302
Other current liabilities 23,288 21,796
Total current liabilities 560,480 1,691,225
Long-term debt 1,038,563 1,093,541
Asset retirement obligations 94,060 108,533
Deferred income taxes 1,000,486 807,614
Noncurrent derivative instruments - 398
Other long-term liabilities 30,222 62,882
Total liabilities 2,723,811 3,764,193
Total Shareholders’ Equity 3,414,604 2,858,019
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 6,138,415 $ 6,622,212

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
For the 3 months ending December 31, 2014 and 2013

4th 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 $ 211,916 $ 250,118 $ (38,202 )
Natural gas liquids 20,293 27,096 (6,803 )
Natural gas 54,538 51,357 3,181
Total $ 286,747 $ 328,571 $ (41,824 )
Loss on sale of assets and other $ (833 ) $ (489 ) $ (344 )

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

Oil $ 230,490 $ 20,600 $ 209,890
Natural gas liquids (1,316 ) 556 (1,872 )
Natural gas 32,286 (20,529 ) 52,815
Total $ 261,460 $ 627 $ 260,833
Closed gains (losses) on derivative instruments
Oil $ 50,945 $ (13,593 ) $ 64,538
Natural gas liquids 4,990 2,342 2,648
Natural gas 8,126 12,504 (4,378 )
Total $ 64,061 $ 1,253 $ 62,808
Total Revenues $ 611,435 $ 329,962 $ 281,473
Production volumes from continuing operations
Oil (MBbl) 3,213 2,694 519
Natural gas liquids (MMgal) 43.1 37.3 5.8
Natural gas (MMcf) 14,646 14,676 (30 )
Production volumes from continuing operations(MBOE) 6,681 6,028 653
Total production volumes (MBOE) 6,681 6,203 478

Average realized prices excluding effects of open non-cash mark-to-market derivative instruments

Oil (per barrel) $ 81.81 $ 87.80 $ (5.99 )
Natural gas liquids (per gallon) $ 0.59 $ 0.79 $ (0.20 )
Natural gas (per Mcf) $ 4.28 $ 4.35 $ (0.07 )
Average realized prices excluding derivative instruments
Oil (per barrel) $ 65.96 $ 92.84 $ (26.88 )
Natural gas liquids (per gallon) $ 0.47 $ 0.73 $ (0.26 )
Natural gas (per Mcf) $ 3.72 $ 3.50 $ 0.22
Other costs per BOE from continuing operations
Oil, natural gas liquids and natural gas production expenses

$

11.16

$

11.04

$

0.12

Production and ad valorem taxes $ 3.14 $ 4.15 $ (1.01 )
Depreciation, depletion and amortization $ 22.08 $ 19.96 $ 2.12
Exploration expense $ 1.03 $ 1.15 $ (0.12 )
General and administrative $ 4.27 $ 4.50 $ (0.23 )
Capital expenditures $ 425,045 $ 212,054 $ 212,991

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
For the 12 months ending December 31, 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 $ 988,868 $ 961,055 $ 27,813
Natural gas liquids 110,918 91,407 19,511
Natural gas 244,408 203,855 40,553
Total $ 1,344,194 $ 1,256,317 $ 87,877
Loss on sale of assets and other $ (2,642 ) $ (981 ) $ (1,661 )

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

Oil $ 271,200 $ (43,261 ) $ 314,461
Natural gas liquids 287 (652 ) 939
Natural gas 43,958 (3,919 ) 47,877
Total $ 315,445 $ (47,832 ) $ 363,277
Closed gains (losses) on derivative instruments
Oil $ 4,377 $ (52,694 ) $ 57,071
Natural gas liquids 6,218 10,795 (4,577 )
Natural gas 8,979 39,707 (30,728 )
Total $ 19,574 $ (2,192 ) $ 21,766
Total Revenues $ 1,676,571 $ 1,205,312 $ 471,259
Production volumes from continuing operations
Oil (MBbl) 11,814 10,364 1,450
Natural gas liquids (MMgal) 172.3 135.8 36.5
Natural gas (MMcf) 58,602 58,104 498
Production volumes from continuing operations(MBOE) 25,684 23,281 2,403
Total production volumes (MBOE) 25,849 25,362 487
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 84.07 $ 87.65 $ (3.58 )
Natural gas liquids (per gallon) $ 0.68 $ 0.75 $ (0.07 )
Natural gas (per Mcf) $ 4.32 $ 4.19 $ 0.13
Average realized prices excluding derivative instruments
Oil (per barrel) $ 83.70 $ 92.73 $ (9.03 )
Natural gas liquids (per gallon) $ 0.64 $ 0.67 $ (0.03 )
Natural gas (per Mcf) $ 4.17 $ 3.51 $ 0.66
Other costs per BOE from continuing operations
Oil, natural gas liquids and natural gas production expenses

$

10.68

$

11.06

$

(0.38

)

Production and ad valorem taxes $ 3.97 $ 4.04 $ (0.07 )
Depreciation, depletion and amortization $ 21.17 $ 19.32 $ 1.85
Exploration expense $ 1.09 $ 0.60 $ 0.49
General and administrative $ 4.75 $ 4.89 $ (0.14 )
Capital expenditures $ 1,376,038 $ 1,104,745 $ 271,293

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