EX-99.1

The company’s adjusted 3rd quarter earnings exceeded internal expectations by more than 50 percent largely due to the impact of decreased stock-based compensation on G&A expenses, lower-than-expected lease operating, marketing and transportation expenses (LOE), increased production, and lower production and ad valorem taxes, partially offset by lower commodity prices and higher DD&A. Production in the 3^rd quarter of 2015 exceeded the guidance range midpoint by 2 percent (approximately 1,200 boepd) primarily due to better-than-expected well performance from Wolfcamp wells in the Delaware Basin.

“Exciting, positive well results, together with better-than-expected production, expenses, and earnings, underscored Energen’s continued strong performance in the 3^rd quarter as a leading operator in the Permian Basin,” said James McManus, Energen’s chairman and chief executive officer.

“We are very pleased with the results of our first two Middle Spraberry wells, both of which were drilled in Martin County. The early results are very solid and have high oil content. We have another Middle Spraberry well in Martin County currently in the early stages of flow back. I believe the Middle Spraberry is another target in the Midland Basin that will add to our existing, extensive inventory of engineered, unrisked locations.

“Our three, 10,000 foot lateral wells in Glasscock County generated very strong 24-hour and peak 30-day average rates from the three Wolfcamp benches targeted. We will be monitoring closely the performance of these wells but believe that the internal rates of return of the Wolfcamp A and B at $60 flat oil prices could be at least 15 percentage points higher than returns on comparable 7,500 foot lateral wells. We are working now to identify how many 10,000 foot lateral wells our acreage can support and will certainly move forward to incorporate as many as we can in our future development plans.

“Our latest Lower Spraberry appraisal well in southern Martin County – together with the cumulative performances of the other Lower Spraberry wells drilled earlier this year in the northern part of our Midland Basin acreage footprint – continue to support this play’s attractive return potential.

“Our development well program in Glasscock County continued to generate solid results in the 3^rd quarter, and we continue to see drill-and-complete costs for a 7,500 foot lateral Wolfcamp A well trending down toward $5.6 million. We also have now expanded our development program to Martin County, where we are drilling Lower Spraberry wells along with Wolfcamp A and B.

“As we look ahead to 2016, we will be return-driven, financially disciplined, and flexible. Based on strip prices for 2016 in the January timeframe, we will focus our capital on those projects that generate the highest internal rates of return and at a level of investment that allows us to maintain a debt-to-EBITDAX multiple of 2.0-2.5 times,” McManus said. “Our strong balance sheet provides us with excellent flexibility to adjust as conditions change. We have outstanding assets in the Midland and Delaware Basins that support a rich inventory of opportunities, and we plan to develop those assets in a manner that supports long-term value creation for our shareholders.”

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

[See “Non-GAAP Financial Measures” beginning on pp 12 for more information]

Production from Continuing Operations (excludes production associated with San Juan divestiture)

Average Realized Sales Prices from Continuing Operations (excludes production associated with San Juan divestiture)

Average Prices from Continuing Operations Before Effects of Hedges (excludes production associated with San Juan divestiture)

Expenses from Continuing Operations and Excluding San Juan Basin Assets sold March 31, 2015

3rd Quarter Comparisons, 2015 vs 2014 (excluding San Juan Basin assets sold March 31, 2015)

The Fall 2015 redetermination of Energen’s borrowing base resulted in a $200 million reduction in its line of credit. The Company’s new line of credit is $1.4 billion.

As of September 30, 2015, Energen had borrowings of $196.5 million on its line of credit and cash/cash equivalents of $0.7 million, for total liquidity available on the new borrowing base of $1.2 billion. Long-term debt at the end of September totaled $553.6 million.

In its 2-well, pad-drilling development program in Glasscock County, Energen tested 18 Wolfcamp A and B wells with lateral lengths of 6,700 feet and 7,500 feet during the 3rd quarter of 2015. These wells generated average peak 24-hour IP rates (3-stream) of 1,050 boepd (76% oil) and peak 30-day average rates (3-stream) of 704 boepd (62% oil). These average rates were generally comparable to the development wells tested in the 2nd quarter and higher than those tested in the 1^st quarter; the gassier product mix reflects the area where these wells were drilled. These latest wells used a similar completion design that continues to generate encouraging results as the company works to further enhance the economics of its development program.

Since the development program’s inception in 2014, Energen has tested 75 gross (74 net) wells that generated average peak 24-hour IPs (3-stream) of 959 boepd (80% oil) and peak 30-day average rates (3-stream) of 733 boepd (71% oil). A supplemental slide posted at www.energen.com shows that the average production from these wells — normalized to a 7,000’ lateral length.

During the 3^rd quarter, Energen expanded its development program to Martin County, where it has drilled 27 gross (27 net) Lower Spraberry, Wolfcamp A, and Wolfcamp B wells. Another 10 gross (10 net) wells are slated to be drilled in Martin County in the 4^th quarter.

Energen’s total 2015 Midland Basin development program calls for the drilling of 98 gross (97 net) wells in Glasscock and Martin counties. As of September 30, 81 gross (80 net) wells had been drilled to total depth, leaving 17 gross (17 net) wells to be drilled in the 4th quarter. Three development rigs are expected to run in the 4^th quarter. No further development well completions are slated in 2015.

The company currently estimates that 48 gross (48 net) wells in the 2015 program will be completed in 2016 including all 37 gross (37 net) Martin County development wells.

Energen tested seven new appraisal wells in the Permian Basin during the 3rd quarter of 2015, including three, 10,000 foot lateral wells in Glasscock County and its first two Middle Spraberry wells, both in Martin County. [See locator maps at www.energen.com]

Energen’s three, 10,000 foot lateral wells drilled in Glasscock County generated very strong 24-hour and average 30-day peak rates from the Wolfcamp A, Wolfcamp B, and Wolfcamp C. These three wells averaged a peak 30-day average rate of more than 1,135 boepd, with the oil content ranging from 70 percent in the Wolfcamp A to 64 percent in the Wolfcamp B to 39 percent in the Wolfcamp C.

Energen also tested its first two Middle Spraberry wells, both of which were drilled in different areas of Martin County. The early results of these two wells are very strong, with high oil content and modest declines from their peak 24-hour rates to their peak 30-day average rates.

The company’s most recent Lower Spraberry appraisal well was drilled in southern Martin County near the heart of a vertical Spraberry field. It generated a strong peak 24-hour IP rate of 963 boepd (78% oil) and a peak 30-day average rate of 672 boepd (76% oil). The strength of this well suggests that the company’s exposure to areas of the greatest Spraberry depletion associated with older vertical drilling is limited to approximately 2,000 net acres in northern Midland County (as compared with an earlier estimate of 5,000 net acres).

Together with the cumulative performances of the four Lower Spraberry wells drilled earlier this year in Martin, Midland, and Howard counties, this well further supports the attractive return potential of the Lower Spraberry in the northern part of Energen’s acreage footprint in the Midland Basin. [See cumulative oil performance over time and potential economics of the company’s four northern Midland Basin Lower Spraberry wells at www.energen.com]

Energen currently is drilling its last of 8 gross (8 net) Wolfcamp shale wells in its Midland Basin appraisal program for 2015 — a Wolfcamp A test in Midland County. The final six Spraberry wells in the 2015 appraisal program are in various stages of completion and flow back; three are in Glasscock County and three in Martin County.

The last of 8 gross (8 net) appraisal wells in Energen’s 2015 Delaware Basin drilling program was the Falcon State 28-36 #1H. Drilled into the Wolfcamp A in Winkler County in the northeastern portion of the Texas Delaware Basin, the well generated strong early results with a peak 24-hour IP of 1,049 (74% oil) and peak 30-day average of 818 boepd (75% oil).

Energen currently is drilling its fourth Mancos oil formation appraisal well in the San Juan Basin. The first two wells are currently flowing back, and a third well currently is completing. The first two wells were drilled in Rio Arriba County; the others are located in San Juan County. The company plans to drill and complete 7 gross (7 net) wells by year-end 2015; an eighth planned well will be drilled and completed in early 2016. These wells are designed to test the company’s 91,000 net acres with Mancos oil potential.

Energen today said its 2015 drilling and development capital is now estimated to be $1.0 billion, or $43 million lower than the prior estimate. This is largely the result of the addition of three net Lower Spraberry development wells, a decrease in development program costs, and other miscellaneous adjustments.

The company’s production guidance range for the year remains 22.2 - 23.2 MMBOE (60,882-63,622 boepd), with a midpoint of 22.7 MMBOE (62,252 boepd). This reflects an increase of approximately 19 percent from comparable, adjusted 2014 production volumes of 19.1 MMBOE (52,320 boepd).

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

Energen’s estimated expenses, excluding San Juan Basin divestiture, are as follows:

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 4^thquarter oil transportation charges of $2.22 per barrel; 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 for the remainder of the year.

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 0.5 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 1.9 million barrels at an average price of -$4.55 per barrel. Energen estimates that approximately 80 percent of its oil production for the remainder of the year will be sweet. Gas basis assumptions for all open contracts (November-December) are -$0.09 per Mcf (basis actuals in October were approximately -$0.14 per Mcf).

Energen’s assumptions for the commodity prices of unhedged production for the remainder of 2015 are $48.35 per barrel of oil (October-December), $2.57 per Mcf of gas (November-December), and $0.47 per gallon of NGL (October-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (October-December) are +$0.34 and +$0.40, respectively. Every 1-cent change in the average price of NGL from $0.47 per gallon is estimated to have a cash flows impact of approximately $300,000.

Energen estimates that price realizations in the 4th quarter of 2015 (pre-hedge) will be approximately:

Energen will hold its quarterly conference call Friday, November 6, 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: All statements, other than statements of historical fact, appearing in this release constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. Forward-looking statements may include words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”, “foresee”, “intend”, “may”, “plan”, “potential”, “predict”, “project”, “seek”, “will” or other words or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this filing. Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. We base our forward-looking statements on information currently available to us, and we undertake no obligation to correct or update these statements whether as a result of new information, future events or otherwise. Additional information regarding our forward-looking statements and related risks and uncertainties that could affect future results of Energen, can be found in the Company’s periodic reports filed with the Securities and Exchange Commission and available on the Company’s website - www.energen.com.

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


	3Q15						3Q14
	$M			$/dil. sh.			$M			$/dil. sh.
Net Income/(Loss) All Operations (GAAP)	$	(227,904	)	$	(2.89	)	$	457,251		$	6.22
Less: Non-cash mark-to-market gains/(losses)		(784	)		(0.01	)		94,142			1.28
Less: Asset impairments, dry hole expenses		(255,703	)		(3.25	)		(118,823	)		(1.62	)
Less: Income/(loss) associated w/ San Juan Basin divestment		(41	)		0.00			6,443			0.09
Less: Discontinued operations		—			—			436,620			5.94

Adj. Income Continuing Operations (Non-GAAP)	$	28,624		$	0.36		$	38,869		$	0.53


Commodity	3Q15				3Q14				Change			2Q15
	MBOE		boepd		MBOE		boepd					MBOE		boepd
Oil		3,610		39,239		3,011		32,728		20	%		3,595		39,505
NGL		1,056		11,478		890		9,674		19	%		1,060		11,648
Natural Gas		1,227		13,337		995		10,815		23	%		1,151		12,648

Total		5,893		64,054		4,896		53,217		20	%		5,806		63,802


Commodity	3Q15		3Q14			Change
Oil (per barrel)	$	71.64	$	84.34			(15	)%
NGL (per gallon)	$	0.25	$	0.71			(65	)%
Natural Gas (per Mcf)	$	3.69	$	3.70	*		0	%


Commodity	3Q15		3Q14		Change
Oil (per barrel)	$	44.47	$	86.34		(49	)%
NGL (per gallon)	$	0.25	$	0.68		(63	)%
Natural Gas (per Mcf)	$	2.29	$	3.69		(38	) %


Expenses	3Q15			3Q14		Change
LOE*	$	9.26		$	10.59		(13	)%
Production & ad valorem taxes	$	2.25		$	4.43		(49	)%
DD&A	$	25.17		$	25.05		1	%
Net G&A	$	3.85	†	$	5.80		(34	)%
Interest ($MM)	$	10.1		$	11.5		(12	)%


		Exhibit 99.1 ENERGEN CORPORATION 605 Richard Arrington, Jr. Boulevard North Birmingham, Alabama 35203-2707 Telephone (205) 326-2700
		For Release: 4:30 p.m. ET Contacts: Julie S. Ryland Thursday, November 5, 2015 205.326.8421
		ENERGEN’S FIRST MIDDLE SPRABERRY WELLS GENERATE SOLID EARLY RATES *10,000’ Lateral Wells in Glasscock County Generate Excellent Results in Wolfcamp A, B and C* 3Q15 Production Tops 64,000 BOEPD Highlights • Results of three 10,000’ laterals in Glasscock County underscore capital efficiency of longer lateral length wells. • Two Middle Spraberry wells generate exciting early results in Martin County. • Latest Lower Spraberry result in Martin County, together with continued performance of Lower Spraberry wells drilled earlier this year, support the play’s attractive return potential. • Development drilling program begins in Martin County; 27 Lower Spraberry, Wolfcamp A and Wolfcamp B wells drilled with 10 more to be drilled in 4^th quarter. • 3Q15 production totaled 64,054 boepd, exceeding guidance midpoint by 2%. • 3Q15 oil production grew 20% from same period last year. • CY15 production guidance midpoint reaffirmed at 22.7 MMBOE (62,252 boepd). • Drilling continues in New Mexico to assess Mancos oil potential on company’s San Juan Basin acreage. • D&C costs of 7,500’ lateral Wolfcamp A in Glasscock County trending down to $5.6 million. BIRMINGHAM, Alabama – For the 3 months ended September 30, 2015, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $227.9 million, or $(2.89) per diluted share. Excluding mark-to-market derivatives losses, commodity price-related impairments primarily of proved properties in the Central Basin Platform, and other items, Energen’s adjusted income in the 3rd quarter of 2015 totaled $28.6 million, or $0.36 per diluted share. This compares with adjusted income from continuing operations in the 3rd quarter of 2014 of $38.9 million, or $0.53 per diluted share. The variance between the periods largely is attributable to a 20 percent decline in realized oil and natural gas liquids (NGL) prices and higher depreciation, depletion, and amortization expense (DD&A) associated with increased drilling activity, partially offset by a 20 percent increase in production, lower production and ad valorem taxes, lower effective tax rate, and decreased net general and administrative expenses (G&A). [See “Non-GAAP Financial Measures” beginning on pp 12 for more information and reconciliation.] Energen’s adjusted EBITDAX totaled $204.4 million in the 3rd quarter of 2015, up 2 percent from adjusted EBITDAX from continuing operations in the same period last year of $199.9 million. [See “Non-GAAP Financial Measures” beginning on pp 12 for more information and reconciliation.]


Development program wells drilled in 3Q15 (gross/net)			18/18
Development program wells completed in 3Q15 (gross/net)			31/30
Development program wells awaiting completion at end of 3Q15 (gross/net)			31/31
Development program wells awaiting completion at YE15e (gross/net)			48/48


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
Cole Ranch 35 #107H	WCA/Glasscock		10,366		9,749		46		1,385		74		15		11		1,145		70		17		13
Cole Ranch 35 #207H	WCB/Glasscock		10,428		9,805		44		1,651		65		19		16		1,197		64		20		17
Cole Ranch 35 #307H	WCC/Glasscock		10,366		9,924		46		1,447		40		36		25		1,065		39		36		25
Dickenson SN 20-17 03 #503H	LSB/Martin		6,996		6,509		31		963		78		13		10		672		76		14		11
Dickenson SN 20-17 03 #603H	MSB/Martin		7,013		6,408		30		790		78		13		9		634		76		14		10
Jones Holton #601H	MSB/Martin		7,473		7,068		33		948		79		12		9		858		79		12		9


	2015e Capital ($MM)			Operated Wells to Be Drilled
	2015e Capital ($MM)			Gross (Net)
Midland Basin	$	810			125	(123	)
Wolfcamp
Development		460			83	(82	)
Appraisal		66			8	(8	)
Spraberry
Development		90			15	(15	)
Appraisal		83			12	(12	)
Wolfberry		16			7	(6	)
SWD/Facilities		84
Non-operated/Other		11

Delaware Basin	$	135			14	(13	)
Bone Spring		17			3	(2	)
Wolfcamp		69			8	(8	)
Wolfbone		15			3	(3	)
SWD/Facilities		26
Non-operated/Other		8

Other Permian	$	6			0	(0	)
Waterflood injectors		0
Facilities/C02		0
Non-operated/Other		6

San Juan Basin/Other	$	60			7	(7	)
Mancos		30			7	(7	)
Facilities		13
Non-operated/Other		17

Net Carry/ARO/Other	$	(9	)

Drilling & Development	$	1,002			146	(143	)
Acquisitions/Lease	$	66

Total Capital	$	1,068


Commodity	2015e Midpoint				2014				% change
	MMBOE		boepd		MMBOE		boepd		% change
Oil		14.3		39,126		11.8		32,323		21	%
NGL		4.0		10,847		3.4		9,337		16	%
Natural Gas		4.5		12,279		3.9		10,660		15	%

Total Continuing Operations		22.7		62,252		19.1		52,320		19	%


Basin	1Q15a				2Q15a				3Q15a				4Q15e Midpoint
	MMBOE		boepd		MMBOE		boepd		MMBOE		boepd		MMBOE		boepd
Midland Basin		2.3		25,778		3.0		32,484		3.0		32,283		3.6		38,804
Delaware Basin		1.2		13,611		1.4		15,923		1.5		16,511		1.2		13,000
Central Basin Platform/Other		0.9		10,100		0.9		10,088		0.9		9,804		0.9		9,652
San Juan Basin/Other		0.4		4,611		0.5		5,308		0.5		5,457		0.5		5,435

Total Production		4.9		54,100		5.8		63,802		5.9		64,054		6.2		66,891


Per BOE, except where noted	4Q15	CY15
LOE (production costs, marketing & transportation)	$9.75-$10.15	$9.50-$10.10
Production & ad valorem taxes (% of revenues, excluding hedges)	7.8%
DD&A expense*	$23.75-$24.25	$24.55-$25.60
General & administrative expense, net†	$4.60-$5.00	$5.00-$5.50
Exploration expense (seismic, delay rentals, etc.)	$0.80-$0.90	$0.40-$0.50
Interest expense ($MM)	$9.5-$10.5	$40.0-$46.0
FF&E ($MM)	$1.5-$1.9	$6.0-$6.4
Accretion of discount on ARO ($MM)	$1.5-$1.9	$6.5-$6.9
Effective tax rate (%)	34-36%	33-35%