EX-99.1

EX-99.1 2 d873651dex991.htm EX-99.1 EX-99.1

Exhibit 99.1


For Release: 4:30 p.m. EDT		Contacts: Julie S. Ryland

Thursday, February 12, 2015		205.326.8421

ENERGEN TARGETS CAPITAL INVESTMENT IN CY15 OF $1.0 BILLION

Permian Production Estimated to Increase Approximately 15% in 2015

ENERGEN AGREES TO SELL MAJORITY OF SAN JUAN GAS ASSETS FOR $395 MM

Drillbit Reserve Replacement Exceeds 400% in 2014 at F&D of $14/BOE

Highlights

•

4Q14 production from continuing operations increases 11% from prior-year 4^th quarter

•

Wolfcamp drilling drives 22% growth in CY14 Permian Basin production

•

2015 capital investment plans focus on Midland Basin Wolfcamp development in Glasscock, Martin counties

•

Wolfcamp development program wells performing at/above newly released type curve

•

Wolfcamp development in CY14 drives increase in year-end proved reserves to record 373 MMBOE

•

Potential unrisked drilling inventory in San Juan Basin Mancos oil formation totals 565 net wells

BIRMINGHAM, Alabama – 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 4^th 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 4^th 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 4^th quarter production by approximately 80,000 barrels of oil equivalents (BOE). In addition, severe weather in late December impacted 4^th 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

1,876

20,391

Wolfberry

1,189

12,924

1,453

15,793

1,292

14,043

Wolfcamp/Cline

1,049

11,402

261

584

6,348

Delaware Basin

1,421

15,446

1,234

13,413

1,525

16,576

3^rd 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

4,399

47,815

San Juan Basin/Other

2,043

22,207

2,226

24,196

2,252

24,478

Total

6,681

72,620

6,028

65,522

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

Midland Basin

7.4

5.1

Wolfberry

5.3

5.0

Wolfcamp/Cline

2.1

0.1

Delaware Basin

5.8

4.7

3^rd Bone Spring/Other

4.6

4.3

Wolfcamp

1.2

0.4

Central Basin Platform

4.1

4.4

Total Permian Basin

17.3

14.2

San Juan Basin/Other

8.4

9.1

Total

25.7

23.3

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 4^th 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 4^th 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.
Well Name	Zone/ County	Drilled*		Completed		Frac Stages		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 4^th 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

1,407

1,473

• Wolfcamp/Wolfbone

1,407

1,443

• 3^rd Bone Spring/Other

Midland Basin

184

194

232

543

1,154

• Wolfcamp

114

133

167

362

776

• Cline/Other

181

250

• Wolfberry

128

Central Basin Platform

0.0

109

San Juan/Other

147

302

604

• Divestiture

115

125

369

• Remaining

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		5-8	*		97 (89	)
Wolfcamp		515
Development		437					68 (64	)
Exploration		78					8 (8	)
Spraberry		68					7 (7	)
Wolfberry		27					14 (10	)
SWD/Facilities		45
Non-operated/Other		10

Delaware Basin	$	187		2	†		14 (13	)
Bone Spring		10					3 (2	)
Wolfcamp		85					8 (8	)
Wolfbone		13					3 (3	)
Lease extensions		37
SWD/Facilities		39
Non-operated/Other		3

Other Permian	$	12					6 (6	)
Waterflood injectors		3					6 (6	)
Facilities/C02		6
Non-operated/Other		3

San Juan Basin/Other	$	73		1			8 (8	)
Mancos		52					8 (8	)
Facilities		1
Non-operated/Other		20

Net Carry-in/Carry Out	$	63

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

Midland Basin

11.6

7.4

Wolfcamp/Spraberry/Cline

7.5

2.1

Wolfberry

4.1

5.3

Delaware Basin

4.8

5.8

(17

3^rd 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

San Juan Basin/Other

2.0

1.8

Total

21.9

19.1

NOTE: Totals may not sum due to rounding

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


Commodity	2015e Midpoint				2014				% change
	MMBOE		boepd		MMBOE		boepd
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		25,078		2.8		30,923		3.2		34,782		3.4		36,413
Delaware Basin		1.0		11,244		1.2		13,560		1.3		14,000		1.2		13,337
Central Basin Platform/Other		0.9		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		33,300		3.5		38,187		3.8		40,880		3.8		41,087
NGL		0.7		8,144		0.9		9,780		1.0		11,076		1.1		11,489
Gas		0.9		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

89.30 per barrel

Natural Gas

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. 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 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.