Energen (EGN) 8-K Results of Operations and Financial Condition

Exhibit 99.1

For Release: 4:30 p.m. EDT	Contacts: Julie S. Ryland
Wednesday, July 30, 2014	205.326.8421

WOLFCAMP WELLSIN WARD, HOWARD,AND MARTIN COUNTIES HEADLINE

ENERGEN’S LATEST ROUNDOF PERMIAN BASIN EXPLORATORY RESULTS

San Juan Basin Mancos Oil Wells Generate Strong, Encouraging Rates

FIRST WOLFCAMP DEVELOPMENT WELLSIN MIDLAND BASIN POST SOLID RESULTS

Highlights

• Latest Ward County Wolfcamp B tests at 24-hour peak IP (3-phase) of 1,896 boepd (78% oil).

• Company’s first Wolfcamp A well in Howard Co. generates peak 24-hour IP (3-phase) of 955 boepd (84% oil).

• Wolfcamp A test in east central Martin County scores peak 24-hour IP (3-phase) of 970 boepd (79% oil).

• Potential oil play in San Juan Basin bolstered by top-tier results from two non-operated Mancos wells.

• First 4 Wolfcamp development wells performing above internal expectations.

• 2014 Wolfcamp drilling in Delaware Basin to include 2 wells with 7,500’ laterals and 2 “C” bench tests.

• Company plans to test 10,000’ lateral length in three Glasscock County exploratory Wolfcamp wells in 2014.

• Lower Spraberry tests in Midland and Martin counties planned for late 2014.

BIRMINGHAM, Alabama – Energen Corporation (NYSE: EGN) has tested five new Wolfcamp exploratory wells in the Permian Basin, including a Ward County Wolfcamp B well in the Delaware Basin that generated an

outstanding peak 24-hour IP rate of just under 1,900 barrels of oil equivalent per day (boepd) and had a 3-stream product mix that was 78 percent oil. The company’s first Wolfcamp A test in Howard County in the Midland Basin also posted strong rates, as did a second Wolfcamp A test in Martin County.[See locator maps atwww.energen.com].

In addition to the exploratory wells, Energen has drilled 19 gross (18 net) wells through June 30 as part of its Wolfcamp development program in southern Glasscock County. The two A-bench and two B-bench wells on production in the second quarter are performing above internal expectations. The four wells generated average peak 24-hour IP rates and peak 30-day average rates (3-stream) of 1,237 boepd and 794 boepd, respectively.

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. The first two wells are producing, and the results suggest that this horizontal oil play in northern New Mexico could generate returns that compete with Energen’s extensive opportunity set in the Permian Basin.

The peak 24-hour IP rates (3-phase) of the wells were 914 boepd and 1,155 boepd; oil comprised 78 percent and 62 percent, respectively. The average peak 20-day rates were 766 boepd and 752 boepd. Neither well was on gas lift during testing.

“We still want to see how the next two wells perform but are very encouraged by our on-going analysis of these first two wells and increasingly optimistic that Energen could well have a viable, horizontal oil play in the San Juan Basin,” said James McManus, Energen’s chairman and chief executive officer. “We likely will deploy a drilling rig in the San Juan Basin in 2015 to begin testing our approximately 75,000 net acres with potential in the oil window of the Mancos formation.”

Utility Sale Receives Approval from Alabama Regulators

In a unanimous decision, the three-member Alabama Public Service Commission last week approved the sale of Energen’s natural gas utility, Alagasco, to The Laclede Group. The transaction, valued at $1.6 billion, including $1.28 billion of cash and approximately $320 million of utility debt, is on track to close by September 30, 2014.

Energen estimates that its after-tax proceeds will be $1.1 billion, after consideration of accelerated intangible drilling costs, and it plans to use those proceeds to reduce short-term indebtedness. The company’s enhanced financial capacity will be used to help fund its future oil- and NGL-focused drilling plans.

Earnings Overview

For the 3 months ended June 30, 2014, Energen reported a consolidated net loss from all operations (GAAP) of $8.0 million, or $0.11 per diluted share. After adjusting for non-cash items and discontinued operations, Energen’s adjusted income from continuing operations in the second quarter of 2014 totaled $35.0 million, or $0.48 per diluted share. This compares with adjusted income from continuing operations in the second quarter of 2013 of $46.9 million, or $0.65 per diluted share.

NOTE: The earnings of Energen’s utility subsidiary, Alabama Gas Corporation, are reflected as discontinued operations due to the pending sale of the utility.

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

[See “Non-GAAP Financial Measures” beginning on pp. 16 for more information]

	2Q14						2Q13
	$M			$/dil. sh.			$M			$/dil. sh.
Net Income All Operations (GAAP)	$	(7,953	)	$	(0.11	)	$	83,067		$	1.15
Less: Non-cash Mark-to-Market gain/(loss)		(38,131	)		(0.52	)		35,486			0.49
Adjusted Net Income All Operations (Non-GAAP)	$	30,178		$	0.41		$	47,581		$	0.66
Less: Discontinued Operations
Gain (Loss) on Disposal of E&P Assets		—			—			—			—
Income (Loss) from E&P Discontinued Operations		97			(0.00	)		2,453			0.03
Income (Loss) from Utility Discontinued Operations		(4,896	)		(0.07	)		(1,808	)		(0.02	)
Adj. Income Continuing Operations (Non-GAAP)	$	34,977		$	0.48		$	46,936		$	0.65

Note: Per share amounts may not sum due to rounding

In comparing the second quarter of 2014 with the prior-year period, the benefits of a 14 percent increase in oil and NGL production were more than offset by higher depreciation, depletion, and amortization (DD&A) expense, a 4 percent decline in realized oil prices largely due to a wider WTI Midland to WTI Cushing differential, increased production expenses, marketing, and transportation (collectively, lease operating expense, or LOE), higher production and ad valorem taxes, and increased net general and administrative (G&A) expenses.

The company met its internal expectations for the second quarter, as the benefit of approximately 300,000 BOE of increased production was essentially offset by higher DD&A expense, increased production and ad valorem taxes, and lower realized commodity prices.

Energen’s adjusted EBITDAX from continuing operations totaled $204.1 million in the second quarter of 2014, up approximately 2 percent from $200.3 million in the same period last year.[See “Non-GAAP Financial Measures” beginning on pp 16 for more information and reconciliation.]

Wolfcamp Shale Exploration Results

MIDLAND BASIN WOLFCAMP EXPLORATORY WELLS

Well	Zone/ County	Lateral length				Frac Stages		Peak 24-Hour IP								Peak 30-day Average
		Drilled*		Completed				Boepd		Oil (Bopd)		NGL (Bpd)		Gas (Mcfd)		Boepd		Oil (Bopd)		NGL (Bpd)		Gas (Mcfd)
Smith SN 48-37 #101H	A/ Howard		7,500’		6,930’		28		955		804		88		377		868		726		83		355
Wilbanks SN 16-15 #101H	A/ Martin		7,500’		6,930’		28		970		769		117		505		745		608		80		343
Daniel SN 10-3 #101H	A/ Glasscock		8,150’		7,699		31		775		630		88		338		594		468		77		294

* Represents distance from vertical departure to toe

Energen’s first Wolfcamp exploratory well in Howard County had a completed lateral length of 6,930 feet and generated one of the highest IP rates publicly reported to-date for an A-bench well in Howard County. The Smith SN 48-37 #101H generated a peak24-hour IP (3-stream) of 955 boepd and a peak 30-day average rate of 868 boepd. The product stream was very “oily,” with a mix of 84% oil, 9% NGL, and 7% gas for both test periods.

The company also tested its second Wolfcamp A well in Martin County, approximately 15 miles east of its Jones-Holton well. The Wilbanks SN 16-15 #101H had a completed lateral length of 6,930 feet and generated a solid peak 24-hour IP (3-stream) of 970 boepd (79% oil, 12% NGL, and 9% gas). The Wilbanks tested at a peak 30-day average of 745 boepd (82% oil, 11% NGL, and 7% gas).

In southern Glasscock County, the Daniel SN 10-3 #101H tested the Wolfcamp A at a 24-hour peak IP of 775 boepd (81% oil, 11% NGL, and 8% gas). The peak 30-day average rate was 594 boepd (79% oil, 13% NGL, and 8% gas).

Energen currently is testing multiple sections of a Cline well drilled on the Eastern Shelf in Glasscock County. Another Cline test, this one in Martin County, is completing. Other exploratory wells under way in the Midland Basin include A- and B-bench wells in Martin County and B- and C-bench tests in southern Glasscock County.

Energen also plans to test the Lower Spraberry formation in the Midland Basin in late 2014. One Lower Spraberry well is slated to be drilled in Martin County late in the 3^rd quarter and the other in Midland County late in the fourth quarter. The company expects to test the Lower Spraberry in Glasscock County in early 2015.

Energen’s 2014 Midland Basin exploratory drilling plans include a total of 22 gross (21 net) wells: eight Wolfcamp A wells, five Wolfcamp B wells, four Wolfcamp C wells, three Cline wells, and two Lower Spraberry wells. Three of these wells are scheduled to be drilled to lateral lengths of 10,000 feet and test the A, B, and C benches of the Wolfcamp in southern Glasscock County.

DELAWARE BASIN

Well

Zone/ County

Lateral length

Frac Stages

Peak 24-Hour IP

Peak30-day Average

Drilled*

Completed

Boepd

Oil (Bopd)

NGL (Bpd)

Gas (Mcfd)

Boepd

Oil (Bopd)

NGL (Bpd)

Gas (Mcfd)

University 16-17 #1H

B/ Ward

5,500

4,808

20

1,896

1,483

214

1,191

1,081

797

147

819

* Represents distance from vertical departure to toe

Well

Zone/ County

Lateral length

Frac Stages

Peak 24-Hour IP

Peak 20-day Average

Drilled*

Completed

Boepd

Oil (Bopd)

NGL (Bpd)

Gas (Mcfd)

Boepd

Oil (Bopd)

NGL (Bpd)

Gas (Mcfd)

Enterprise C19-5 #1H

B/ Reeves

4,750’

4,237’

18

634

191

164

1,669

553

131

157

1,595

* Represents distance from vertical departure to toe

Energen’s latest “east side” well in the Delaware Basin tested the B bench of the Wolfcamp in Ward County and generated top-tier rates. The University 16-17 #1H generated a peak 24-hour IP (3-stream) of 1,896 boepd (78% oil, 11% NGL, and 11% gas) and a peak 30-day average rate of 1,081 boepd (74% oil, 14% NGL, and 12% gas).

In Reeves County, Energen’s latest Wolfcamp B test produced at lower rates than the company’s other Reeves County Wolfcamp wells, including the near-by E.J. Brady well. Company engineers and geologists continue to monitor and analyze the performance of the Enterprise C19-5 #1H but think the lateral may not have been optimally landed. The Enterprise well generated a peak 24-hour IP (3-stream) of 634 boepd (30% oil, 26% NGL, and 44% gas) and a peak 20-day average rate of 553 boepd (24% oil, 28% NGL, and 48% gas).

Energen currently is completing its first Wolfcamp C well in Reeves County; three other Reeves County wells targeting the Wolfcamp A and B benches are drilling or flowing back.

The company plans to test a second C-bench well in Reeves County later in the year; Energen also plans to test longer lateral lengths of 7,500 feet in the Delaware Basin with two wells to be drilled this year in Ward County.

Energen’s 2014 Delaware Basin Wolfcamp drilling plans now include a total of 15 gross (14 net) wells: five Wolfcamp A wells, six Wolfcamp B wells, two Wolfcamp C wells, and two to be determined.

Mancos Formation Results

Well	Target Zone		Completed Lat. Length		Frac Stages		Peak 24-Hour IP (3-phase)								Peak 20-day Average (3-phase)
							Boepd		Oil (Bopd)		NGL (Bpd)		Gas (Mcfd)		Boepd		Oil (Bopd)		NGL (Bpd)		Gas (Mcfd)
Chaco 2308-09A #145H		Mancos		4,518		14		1,155		717		225		1,275		752		466		147		829
Chaco 2308-09A #146H		Mancos		4,485’		14		914		709		101		626		766		594		85		525

Note: Wells not on gas lift during testing period

Energen is very pleased with the results of two Mancos formation wells drilled and operated by WPX Energy in the San Juan Basin in New Mexico; Energen has a 50 percent non-operated interest in these wells. The Chaco 2308-09A #145H and #146H wells targeted the Mancos formation at vertical depths of approximately 5,500-5,800 feet.

The #145H generated a peak 24-hour IP (3-stream) of 1,155 boepd (62% oil, 20% NGL, and 18% gas) and a peak 20-day average rate (3-stream) of 752 boepd (62% oil, 20% NGL, and 18% gas). The #146H tested at a peak 24-hour IP (3-stream) of 914 boepd (78% oil, 11% NGL, and 11% gas) and at a peak 20-day average rate (3-stream) of 766 boepd (78% oil, 11% NGL, and 11% gas).

Wolfcamp Shale Development Program Results

Through the first half of 2014, Energen has drilled 19 gross (18 net) wells in its Wolfcamp development program in southern Glasscock County. Four wells with sufficient production history – 2 of which are A-bench laterals and 2 are B-bench laterals – have generated average peak 24-hour IP rates (3-stream) of 1,237 boepd (87% oil, 7% NGL, and 6% gas) and average peak 30-day average rates of 794 boepd (78% oil, 12% NGL, and 10% gas). Energen plans to drill 57 gross (55 net) wells – Wolfcamp A and Wolfcamp B stacked laterals – in 2014.

During the second quarter, Energen realized spud-to-total depth drill times of as few as 14 days; however, a drill pipe-related issue in one well led to a significant delay in the timing of completions for a group of adjacent wells. As a result, production from the development program in 2014 is estimated to be negatively affected by approximately 500,000 BOE, primarily in the third quarter. Total annual production is not expected to be affected largely due to better-than-expected year-to-date production and anticipated increases in vertical Wolfberry production.

Second Quarter Earnings Detail

As noted previously, Energen’s adjusted income from continuing operations in the second quarter of 2014 totaled $35.0 million, or $0.48 per diluted share, down from $46.9 million, or $0.65 per diluted share, in the same period last year. The benefits of a 14 percent increase in oil and NGL production were more than offset by higher DD&A expense, a 4 percent decline in realized oil prices largely due to a wider WTI Midland to WTI Cushing differential, increased LOE, greater production and ad valorem taxes, and higher G&A expenses.

Production by Commodity (MBOE)

Commodity	2Q14		2Q13		Change
Continuing Operations
Oil		2,833		2,592		9	%
NGL		1,065		815		31	%
Natural Gas		2,446		2,457		(0	)%
Total Continuing Operations		6,344		5,864		8	%

Production from Continuing Operations by Area (MBOE)

Area	2Q14		2Q13		Change
Midland Basin		1,755		1,223		43	%
Wolfberry		1,371		1,221
Wolfcamp/Cline		384		2
Delaware Basin		1,488		1,190		25	%
3rd Bone Spring/Other		1,201		1,098
Wolfcamp		287		92
Central Basin Platform		1,060		1,136		(7	)%
Total Permian Basin		4,303		3,549		21	%
San Juan Basin/Other		2,041		2,315		(12	)%
Total Continuing Operations		6,344		5,864		8	%

Average Realized Sales Prices from Continuing Operations

Commodity	2Q14		2Q13		Change
Oil (per barrel)	$	83.65	$	87.11		(4	)%
NGL (per gallon)	$	0.70	$	0.70		0	%
Natural Gas (per Mcf)	$	4.25	$	4.19		1	%

Oil production in the second quarter increased 9 percent year-over-year as new drilling in the horizontal Wolfcamp in the Midland and Delaware basins more than offset declines in the mature Central Basin Platform. NGL production increased 31 percent year-over-year largely due to less ethane rejection and new horizontal Wolfcamp drilling. Natural gas production was essentially unchanged, as associated gas production in the Permian Basin was offset by declining San Juan Basin gas production.

The biggest increases in production by play in the second quarter, year-over-year, resulted from horizontal Wolfcamp drilling in the Midland and Delaware basins. The vertical Wolfberry and 3^rd Bone Spring also demonstrated improved production; and, as expected, production declined in the mature Central Basin Platform and the San Juan Basin.

Average realized sales prices from continuing operations in the second quarter were essentially flat, year-over-year, with respect to NGL and natural gas. Realized oil prices were lower by 4 percent, primarily due to the impact of wider WTI Midland to WTI Cushing and WTS Midland to WTI Cushing differentials.

In the second quarter of 2014, LOE (i.e., production costs, marketing, and transportation) was essentially unchanged from the same period a year ago at $10.20 per BOE. Per-unit production taxes and ad valorem taxes in the second quarter of 2014 increased approximately 10 percent over the same period in 2013 to $4.42 per BOE.

Per-unit DD&A expense from continuing operations in the second quarter of 2014 totaled $21.31 per BOE, increasing approximately 12 percent from the same period last year largely due to year-over-year increases in development costs.

Per-unit net G&A expense of $5.29 was approximately 12 percent higher than in the same period a year ago largely due to increased salaries and stock-based compensation.

Interest expense in the second quarter of 2014 totaled $8 million, down $2.2 million from the same period last year. This primarily was the result of a reclassification of certain interest expense in each period to discontinued operations. On a per-unit basis, interest expense decreased approximately 28 percent in the second quarter of 2014 (from the same period last year) to $1.26 per BOE.

Year-to-Date Earnings

For the 6 months ended June 30, 2014, Energen reported consolidated net income from all operations (GAAP) of $45.4 million, or $0.62 per diluted share. After adjusting for non-cash items and discontinued operations, Energen’s adjusted income from continuing operations in the year-to-date 2014 totaled $72.2 million, or $0.99 per diluted share. This compares with adjusted income from continuing operations in the year-to-date 2013 of $81.3 million, or $1.12 per diluted share.

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

[See “Non-GAAP Financial Measures” beginning on pp. 16 for more information]

	YTD14						YTD13
	$M			$/dil. sh.			$M		$/dil. sh.
Net Income All Operations (GAAP)	$	45,363		$	0.62		$	139,759	$	1.93
Less: Non-cash Mark-to-Market gain/(loss)		(59,667	)		(0.82	)		9,544		0.13
Adjusted Net Income All Operations (Non-GAAP)	$	105,030		$	1.44		$	130,215	$	1.80
Less: Discontinued Operations
Gain (Loss) on Disposal of E&P Assets		(1,050	)		(0.01	)		—		—
Income (Loss) from E&P Discontinued Operations		(1,029	)		(0.01	)		4,451		0.06
Income (Loss) from Utility Discontinued Operations		34,949			0.48			44,467		0.61
Adj. Income Continuing Operations (Non-GAAP)	$	72,160		$	0.99		$	81,297	$	1.12

Note: Per share amounts may not sum due to rounding

Energen’s adjusted EBITDAX from continuing operations totaled $408.5 million in the year-to-date 2014, up approximately 13 percent from $361.8 million in the same period last year.[See “Non-GAAP Financial Measures” beginning on pp 16 for more information and reconciliation.]

Production by Commodity (MBOE)

Commodity	YTD14		YTD13		Change
Continuing Operations
Oil		5,584		4,906		14	%
NGL		1,968		1,471		34	%
Natural Gas		4,800		4,760		1	%
Total Continuing Operations		12,352		11,137		11	%

Production from Continuing Operations by Area (MBOE)

Area	YTD14		YTD13		Change
Midland Basin		3,292		2,208		49	%
Wolfberry		2,845		2,205
Wolfcamp/Cline		447		3
Delaware Basin		2,892		2,143		35	%
3rd Bone Spring/Other		2,385		2,029
Wolfcamp		507		114
Central Basin Platform		2,076		2,222		(7	)%
Total Permian Basin		8,260		6,573		26	%
San Juan Basin/Other		4,092		4,564		(10	)%
Total Continuing Operations		12,352		11,137		11	%

Average Realized Sales Prices from Continuing Operations

Commodity	YTD14		YTD13		Change
Oil (per barrel)	$	85.23	$	86.42		(1	)%
NGL (per gallon)	$	0.72	$	0.73		(1	)%
Natural Gas (per Mcf)	$	4.38	$	4.18		5	%

For the six months ending June 30, 2014, per-unit LOE declined approximately 5 percent from the same period a year ago to $10.70 per BOE. Per-unit production taxes and ad valorem taxes in the year-to-date 2014 increased approximately 6 percent over the same period last year to $4.48 per BOE.

Per-unit DD&A expense from continuing operations in the year-to-date 2014 totaled $20.93 per BOE, increasing approximately 13 percent from the same period last year largely due to year-over-year increases in development costs.

Per-unit net G&A expense in the first six months of 2014 totaled $5.32 per BOE, or approximately 6 percent higher than in the same period a year ago.

Interest expense in the year-to-date 2014 totaled $15.9 million, down $4.2 million from the same period last year. This primarily was the result of a reclassification of certain interest expense in each period to discontinued operations. On a per-unit basis, interest expense decreased approximately 29 percent in the first six months of 2014 (from the same period last year) to $1.28 per BOE.

2014 Capital, Production and Financial Guidance Update

Energen has tweaked its capital plans for 2014 to reflect additional projects/changes in scope, increased non-operated working interest, year-to-date acquisitions/unproved leasehold, and other miscellaneous items. Guidance for production from continuing operations remains unchanged at 24.9-25.9 MMBOE, with a midpoint of 25.4 MMBOE; however, a delay in the company’s Midland Basin Wolfcamp development program resulting from a drill pipe-related issue has lowered third-quarter production estimates and altered the contribution by formation to total Midland Basin production.

2014e Capital & Drilling Summary

	2014e Capital ($ MM)		Operated Wells Gross (Net)
Midland Basin	$	870		133 (126	)
Wolfcamp/Cline		665		79 (76	)
Wolfberry/Other		125		54 (50	)
Facilities/Other		80
Delaware Basin	$	415		42 (38	)
3rd Bone Spring/Other		185		27 (24	)
Wolfcamp		180		15 (14	)
Facilities/Other		50
Other Permian	$	43		26 (22	)*
Waterfloods/CO2 floods		17		26 (22	)*
Facilities/Other		26
San Juan Basin/Other	$	26		0 (0	)
Facilities/Other		26
Acquisitions/Unproved Leasehold YTD	$	23
Net Carry In/Carry Out	$	23
TOTAL – Contg. Ops	$	1,400		201 (186	)

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

* Includes 10 gross (9 net) injectors

Production from Continuing Operations by Area (MMBOE)

	2014e Midpoint						2013
Area	Revised		Prior		Original
Midland Basin		7.6		7.7		7.4		5.1
Wolfcamp/Cline		2.3		2.8		2.2		0.0
Wolfberry		5.3		4.9		5.2		5.1
Delaware Basin		5.6		5.6		5.4		4.7
3rd Bone Spring/Other		4.4		4.5		4.5		4.2
Wolfcamp		1.2		1.1		0.9		0.5
Central Basin Platform		3.9		3.8		3.7		4.4
Total Permian Basin		17.1		17.1		16.5		14.2
San Juan Basin/Other		8.3		8.3		8.4		9.1
Total Continuing Operations		25.4		25.4		24.9		23.3

Production from Continuing Operations by Product (MMBOE)

Commodity	2014e Midpoint (Revised)		2013		2013 vs Revised 2014e (% change)
Oil		11.6		10.4		12	%
NGL		4.1		3.2		28	%
Natural Gas		9.7		9.7		—
Total Continuing Operations		25.4		23.3		9	%

Production from Continuing Operations by Basin and Product (MMBOE)

	Oil				NGL				Gas				Total
Basin	2014e		2013		2014e		2013		2014e		2013		2014e		2013
Midland Basin		4.5		3.2		1.6		1.0		1.5		0.9		7.6		5.1
Delaware Basin		3.4		3.1		1.0		0.7		1.2		0.9		5.6		4.7
Central Basin Platform/Other		3.5		3.9		0.2		0.2		0.2		0.2		3.9		4.4
San Juan Basin/Other		0.2		0.1		1.3		1.3		6.8		7.7		8.3		9.1
Total Continuing Operations		11.6		10.4		4.1		3.2		9.7		9.7		25.4		23.3

NOTE: 2014e production reflects the midpoint of guidance

Production from Continuing Operations by Basin per Quarter (MMBOE)

	1st Quarter				2nd Quarter				3rd Quarter				4th Quarter
Basin	2014		2013		2014		2013		2014e		2013		2014e		2013
Midland Basin		1.5		1.0		1.8		1.2		1.8		1.4		2.5		1.5
Delaware Basin		1.4		1.0		1.5		1.2		1.3		1.3		1.4		1.2
Central Basin Platform/Other		1.0		1.1		1.1		1.1		0.9		1.1		0.9		1.1
San Juan Basin/Other		2.1		2.2		2.0		2.3		2.1		2.3		2.1		2.2
Total Production – Contg Ops		6.0		5.3		6.3		5.9		6.1		6.1		6.9		6.0

NOTE: 2014e production reflects the midpoint of guidance; totals may not sum due to rounding

Energen has revised its 2014 guidance for after-tax cash flows and earnings to reflect numerous adjustments including year-to-date results, timing and composition of annual production, increased assumptions for key basis differentials, and reduced interest expense. After-tax cash flows from continuing operations in 2014 are estimated to be $833-$855 million, and earnings are estimated to fall within a range of $2.00-$2.30 per diluted share.

Energen’s estimated expenses from continuing operations in 2014 on a per-BOE basis are:

Production costs, marketing, and transportation	$	10.25 - $ 10.50
Production and ad valorem taxes	$	4.20 - $ 4.60
DD&A expense	$	21.00 - $ 21.50
General & Administrative expense, net	$	4.80 - $ 5.20
Interest expense	$	1.50 - $ 1.80
Exploration expense (delay rentals, seismic, G&G, etc.)	$	0.90 - $ 1.00

Approximately 77 percent of the company’s total estimated midpoint of production from continuing operations for the remainder of 2014 is hedged. Assumed prices applicable to Energen Resources’ unhedged volumes for the remainder of the year are $95.00 per barrel of oil, $0.92 per gallon of NGL, and $4.50 per Mcf of natural gas.

Hedges also are in place that limit the company’s exposure in the second half of 2014 to the Midland to Cushing differential. Energen Resources has hedged the WTS Midland to WTI Cushing (sour oil) differential for 0.6 million barrels of oil production at an average price of $3.30 per barrel and the WTI Midland to WTI Cushing differential for 1.2 million barrels at an average price of $3.08 per barrel.

Energen’s 2014 guidance includes assumed prices applicable to Energen Resources’ unhedged oil basis differentials for the remainder of the year (including known actuals). They are $6.00 per barrel (WTS Midland to WTI Cushing, or sour) and $6.00 per barrel (WTI Midland to WTI Cushing, or sweet). Energen estimates that approximately 74 percent of its oil production for the remainder of 2014 will be sweet. Gas basis assumptions (including known actuals) are $0.05 per Mcf in the Permian and San Juan basins.

The company’s current hedge position for the remainder of 2014 is as follows:

Commodity	Hedge Volumes		2014e ROY Production (Contg Ops) Midpoint		Hedge %			NYMEXe Price
Oil		5.0 MMBO		6.0 MMBO		82	%	$	92.65 per barrel
NGL		35.8 MMgal		87.7 MMgal		41	%	$	0.93 per gallon
Natural Gas		25.7 Bcf		29.3 Bcf		88	%	$	4.46 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 Resources’ assumed San Juan and Permian basis differentials.

Average realized oil and gas prices for Energen Resources’ 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 oil transportation charges of approximately $2.65 per barrel for the remainder of 2014; 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.

As a result of Energen’s 2014 hedge position for the remainder of the year, changes in commodity prices will have a significantly lessened impact on Energen’s 2014 cash flows. Every $1.00 change in the average NYMEX price of oil from $95 per barrel for the remainder of the year represents an estimated net impact of $555,000; every 1-cent change in the average price of NGL from $0.92 per gallon is estimated to be approximately $230,000; and every 10-cent change in the average NYMEX price of gas from $4.50 represents an immaterial impact.

In addition to commodity sensitivities, Energen estimates that, for the last six months of 2014, every $1 change in the Midland to Cushing differentials for sweet and sour oil from $6 per barrel will impact net income by approximately $1.6 million and $0.5 million, respectively.

CONFERENCE CALL

Energen will hold its quarterly conference call Thursday, July 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 tohttp://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.