Energen's First Middle Spraberry Wells Generate Solid Early Rates

BIRMINGHAM, Ala.--(BUSINESS WIRE)--

For the 3 months ended September 30, 2015, Energen Corporation 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.]

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 3rd 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."

3rd Quarter Financial Review


Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations [See "Non-GAAP Financial Measures" beginning on pp 12 for more information]

		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
Note: Per share amounts may not sum due to rounding


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

	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
Note: Totals may not sum due to rounding

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

Area

3Q15

3Q14

Change

2Q15

MBOE

boepd

MBOE

boepd

MBOE

boepd

Midland Basin

2,970

32,283

1,877

20,402

2,956

32,484

Wolfcamp/Spraberry

1,944

21,130

586

6,370

1,777

19,527

Wolfberry

1,026

11,152

1,291

14,033

1,179

12,956

Delaware Basin

1,519

16,511

1,524

16,565

1,449

15,923

3^rd Bone Spring/Other

997

10,837

1,219

13,250

963

10,582

Wolfcamp

522

5,674

305

3,315

486

5,341

Central Basin Platform

902

9,804

998

10,848

(10

918

10,088

Total Permian Basin

5,391

58,598

4,399

47,815

5,323

58,495

San Juan Basin/Other

502

5,457

497

5,402

483

5,308

Total

5,893

64,054

4,896

53,217

5,806

63,802

Note: Totals may not sum due to rounding


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

	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	%
* Prior period hedges were left unallocated for current-year San Juan Basin divestiture; as reported last year, the average realized sales price of natural gas in 3Q14 was $4.27 per Mcf.


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

	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 from Continuing Operations and Excluding San Juan Basin Assets sold March 31, 2015 (per BOE, except interest expense)

	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	)%
* Production costs + workovers and repairs + marketing and transportation
† Excludes $0.16 per BOE for pension and pension settlement expenses

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

The success of Energen's Wolfcamp development program led to a 58 percent increase in Midland Basin production and a 23 percent increase in total Permian Basin production.
The company's average realized oil price fell 15 percent to $71.64 per barrel, while the realized price of NGL dropped 65 percent. Excluding the impact of commodity and differential hedges, the average realized price of oil would have been $44.47 per barrel.
LOE per unit declined 13 percent to $9.26 per barrel largely due to lower workover and repair expense, lower power costs, and lower water disposal costs, partially offset increased equipment rental expenses. Per-unit production and ad valorem taxes declined 49 percent.
Per-unit DD&A expense was essentially unchanged.
Per-unit net G&A expense of $3.85 per BOE (excluding pension and pension settlement expenses) declined 34 percent from the same period a year ago largely due decreased stock-based compensation and lower expenses for professional and legal services.
Interest expense declined 12 percent largely due to a prior year write off of debt issuance costs associated with our $600 million Senior Term Loans.

Liquidity Update

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.

Midland Basin Development Program Results


	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

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.

Midland and Delaware Basin Appraisal Program Results

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]


Midland Basin (3-Stream Results)

	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
* Represents distance from vertical departure to toe
Note: Totals may not foot due to rounding

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.

Delaware Basin (3-Stream Results)

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

Falcon State 28-36 #1H

WCA/Winkler

4,895

4,389

1,049

818

* Represents distance from vertical departure to toe

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).

San Juan Basin Mancos Appraisal Program

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.

Capital, Production, and Financial Guidance

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).


2015 Capital Summary

		2015e Capital ($MM)			Operated Wells to Be Drilled 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

Note: "Facilities" capital includes artificial lift and central gathering facilities; "Other" Capital includes payadds and refracs


Production by Product (Excluding San Juan Basin Divestiture)

	Commodity	2015e Midpoint		2014		%
	Commodity	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	%
NOTE: Totals may not sum due to rounding

Production by Play (Excluding San Juan Basin Divestiture)

Area

2015e Midpoint

2014

Change (boepd)

MMBOE

boepd

MMBOE

boepd

Midland Basin

11.8

32,373

7.4

20,293

Wolfcamp/Spraberry

7.7

21,142

2.1

5,827

Wolfberry

4.1

11,230

5.3

14,466

Delaware Basin

5.4

14,764

5.8

15,995

3^rd Bone Spring/Other

3.7

10,038

4.6

12,731

Wolfcamp

1.7

4,726

1.2

3,264

Central Basin Platform

3.6

9,910

4.1

11,104

(11

Total Permian Basin

20.8

57,047

17.3

47,392

San Juan Basin/Other

1.9

5,205

1.8

4,929

Total

22.7

62,252

19.1

52,320

NOTE: Totals may not sum due to rounding


Production by Basin/Quarter (Excluding San Juan Divestiture)

	Basin	1Q15a		2Q15a		3Q15a		4Q15e Midpoint
		MMBOE	boepd	MMBOE	boepd	MMBOE	boepd	MMBOE	boepd
	Midland Basin	2.3	1 25,778	3.0	32,484	3.0	32,283	3.6	38,804
	Delaware Basin	1.2	1 13,611	1.4	15,923	1.5	16,511	1.2	13,000
	Central Basin Platform/Other	0.9	1 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
NOTE: Totals may not sum due to rounding


Production by Commodity/Quarter (Excluding San Juan Basin Divestiture)

	Commodity	1Q15a		2Q15a		3Q15a		4Q15e Midpoint
		MMBOE	boepd	MMBOE	boepd	MMBOE	boepd	MMBOE	boepd
	Oil	3.2	35,922	3.6	39,505	3.6	39,239	3.8	41,772
	NGL	0.7	8,133	1.1	11,648	1.1	11,478	1.1	12,087
	Gas	0.9	10,044	1.2	12,648	1.2	13,337	1.2	13,033
	Total Production	4.9	54,100	5.8	63,802	5.9	64,054	6.2	66,891
NOTE: Totals may not sum due to rounding

4Q15 AND CY15 FINANCIAL GUIDANCE


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

	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%
* Subject to year-end, 4(th) quarter, look-back adjustment
† Excludes $5.19 per BOE in 4Q15 and $1.63 per BOE in CY15 for pension and pension settlement expenses.

4Q15 Hedges

The company's hedge position for the last three months of 2015 is:

Commodity

Hedge Volumes

Production @ Midpoint

Hedge %

NYMEXe Price

Oil

3.5 MMBO

3.8 MMBO

91%

78.28 per barrel

Natural Gas

7.0 Bcf

7.2 Bcf

97%

4.25 per Mcf

NGL

1.1 MMBOE

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 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:

Crude oil (% of NYMEX/WTI)									94%
Natural gas (% of NYMEX/Henry Hub)									87%
NGL (after T&F) (% of NYMEX/WTI)									27%

Conference Call

Energen will hold its quarterly conference call Friday, November 6, at 11:00 a.m. ET. 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.


	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 impairment losses, income associated with certain divestments, gains and losses on disposal of discontinued operations and income and losses from discontinued operations. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.

Quarter Ended 9/30/2015

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

Net Income

Per Diluted
Share

Net Income (Loss) All Operations (GAAP)

(227.9

)

(2.89

)

Non-cash mark-to-market losses (net of $0.4 tax)

0.8

0.01

Asset impairment, other (net of $144.2 tax)

255.7

3.25

Loss associated w/ San Juan Basin divestment (net of $0.0 tax)

0.0

0.00

Adjusted Income from Continuing Operations (Non-GAAP)

28.6

0.36

Quarter Ended 9/30/2014

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

Net Income

Per Diluted
Share

Net Income (Loss) All Operations (GAAP)

457.3

6.22

Non-cash mark-to-market gains (net of $53.1 tax)

(94.1

)

(1.28

)

Asset impairment, other (net of $67.6 tax)

118.8

1.62

Income associated w/ San Juan Basin divestment (net of $3.6 tax)

(6.4

)

(0.09

)

Adjusted Net Income from All Operations (Non-GAAP)

475.5

6.47

Loss from discontinued operations (net of $2.5 tax)

3.5

0.05

Gain from discontinued operations (net of $286.3 tax)

(440.1

)

(5.99

)

Adjusted Income from Continuing Operations (Non-GAAP)

38.9

0.53

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 associated with certain divestments, impairment losses, certain non-cash mark-to-market derivative financial instruments, income and losses from discontinued operations and gains and losses on disposal of discontinued operations. Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies.

Reconciliation To GAAP Information

Quarter Ended 9/30

($ in millions)

2015

2014

Energen Net Income (Loss) (GAAP)

(227.9

)

457.3

(Income) Loss associated w/ San Juan Basin divestment, net of tax

0.0

(6.4

)

Adjusted Net Income from Continuing Operations (Non-GAAP)

(227.9

)

450.8

Interest expense

10.1

11.5

Income tax expense (benefit) *

(130.3

)

12.5

Depreciation, depletion and amortization *

149.8

123.9

Accretion expense *

1.7

1.5

Exploration expense *

0.0

(2.9

)

Dry hole expense *

0.5

7.5

Adjustment for asset impairment

399.4

178.9

Adjustment for mark-to-market (gains) losses *

1.2

(147.3

)

Adjustment for loss from discontinued operations, net of tax

0.0

3.5

Adjustment for gain on disposal from discontinued operations, net of tax

0.0

(440.1

)

Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)

204.4

199.9

Note: Amounts may not sum due to rounding

* Amount adjusted to exclude San Juan Basin divestment in either current or prior period. See reconciliation to GAAP Information for the Quarter Ended 9/30/2015 and 9/30/2014.


	Non-GAAP Financial Measures

	The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes excluding information associated with the divestment of assets held in the San Juan Basin provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations. Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.


Energen Net Income (Loss) Excluding San Juan Divestment
Reconciliation to GAAP Information	Quarter Ended
	September 30, 2015
(in thousands except per share and production data)
	GAAP			$/BOE		San Juan Basin			$/BOE		Non-GAAP			$/BOE
Revenues
Oil, natural gas liquids and natural gas sales	$	188,398				$	(2	)			$	188,400
Gain (loss) on derivative instruments		107,173					-					107,173
Total Revenues		295,571					(2	)				295,573
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production		54,598		$	9.26		4		$	0.00		54,594		$	9.26
Production and ad valorem taxes		13,366		$	2.27		80		$	0.00		13,286		$	2.25
O&G Depreciation, depletion and amortization		148,298		$	25.17		-		$	0.00		148,298		$	25.17
FF&E Depreciation, depletion and amortization		1,483		$	0.25		-		$	0.00		1,483		$	0.25
Asset impairment		399,394					-					399,394
Exploration		493					-					493
General and administrative		23,631		$	4.01		-		$	0.00		23,631		$	4.01
Accretion of discount on asset retirement obligations		1,700					-					1,700
(Gain) loss on sale of assets and other		822					(22	)				844
Total costs and expenses		643,785					62					643,723
Operating Income (Loss)		(348,214	)				(64	)				(348,150	)
Other Income/(Expense)
Interest Expense		(10,084	)				-					(10,084	)
Other income		56					-					56
Total other expense		(10,028	)				-					(10,028	)

Income (Loss) from Continuing Operations Before Income Taxes		(358,242	)				(64	)				(358,178	)
Income tax expense (benefit)		(130,338	)				(23	)				(130,315	)
Income (Loss) From Continuing Operations		(227,904	)				(41	)				(227,863	)
Discontinued Operations, net of tax
Income (loss) from discontinued operations		-					-					-
Gain on Disposal of discontinued ops		-					-					-
Income from discontinued ops		-					-					-
Net Income (Loss)	$	(227,904	)			$	(41	)			$	(227,863	)

Diluted Earnings Per Average Common Share
Continuing Operations	$	(2.89	)			$	-				$	(2.89	)
Discontinued Operations	$	-				$	-				$	-
Net Income (Loss)	$	(2.89	)			$	-				$	(2.89	)

Basic earning Per Average Common Share
Continuing Operations	$	(2.89	)			$	-				$	(2.89	)
Discontinued Operations	$	-				$	-				$	-
Net Income (Loss)	$	(2.89	)			$	-				$	(2.89	)

Oil		3,610					-					3,610
NGL		1,056					-					1,056
Natural Gas		1,227					-					1,227
Total Production (mboe)		5,893					-					5,893
Total Production (boepd)		64,054					-					64,054

Note: Amounts may not sum due to rounding


	Non-GAAP Financial Measures

	The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes excluding information associated with the divestment of assets held in the San Juan Basin provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations. Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

Energen Net Income (Loss) Excluding San Juan Divestment

Reconciliation to GAAP Information

Quarter Ended

September 30, 2014

(in thousands except per share and production data)

GAAP

$/BOE

San Juan Basin

$/BOE

Non-GAAP

$/BOE

Revenues

Oil, natural gas liquids and natural gas sales

350,773

43,205

307,568

Gain (loss) on derivative instruments

147,735

5,525

142,210

Total Revenues

498,508

48,730

449,778

Operating Costs and Expenses

Oil, natural gas liquids & natural gas production

67,720

10.18

15,887

9.05

51,833

10.59

Production and ad valorem taxes

25,729

3.87

4,034

2.30

21,695

4.43

O&G Depreciation, depletion and amortization

137,773

20.71

15,128

8.62

122,645

25.05

FF&E Depreciation, depletion and amortization

1,331

0.20

0.03

1,282

0.26

Asset impairment

178,912

Exploration

8,417

3,848

4,569

General and administrative

27,784

4.18

(606

)

($0.35

)

28,390

5.80

Accretion of discount on asset retirement obligations

1,924

394

1,530

(Gain) loss on sale of assets and other

747

Total costs and expenses

450,337

38,734

411,603

Operating Income (Loss)

48,171

9,996

38,175

Other Income/(Expense)

Interest Expense

(11,522

)

(11,522

)

Other income

Total other expense

(11,485

)

(11,485

)

Income (Loss) from Continuing Operations Before Income Taxes

36,686

9,996

26,690

Income tax expense (benefit)

16,055

3,553

12,502

Income (Loss) From Continuing Operations

20,631

6,443

14,188

Discontinued Operations, net of tax

Income (Loss) from discontinued operations

(3,485

)

(3,485

)

Gain on Disposal of discontinued ops

440,105

Income from discontinued ops

436,620

Net Income (Loss)

457,251

6,443

450,808

Diluted Earnings Per Average Common Share

Continuing Operations

0.28

0.09

0.19

Discontinued Operations

5.94

Net Income (Loss)

6.22

0.09

6.13

Basic earning Per Average Common Share

Continuing Operations

0.28

0.09

0.19

Discontinued Operations

5.98

0.01

5.97

Net Income (Loss)

6.26

0.10

6.16

Oil

3,017

3,011

NGL

1,108

218

890

Natural Gas

2,526

1,531

995

Total Production (mboe)

6,651

1,755

4,896

Total Production (boepd)

72,293

19,076

53,217

Note: Amounts may not sum due to rounding


	Non-GAAP Financial Measures

	Excluding production associated with certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes excluding data associated with the divestment of assets held in the San Juan Basin provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations. Further, this measure is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

Energen Production Excluding San Juan Divestment

Reconciliation to GAAP Information

Quarter Ended

June 30, 2015

GAAP

San Juan Basin

Non-GAAP

Oil

3,594

)

3,595

NGL

1,070

1,060

Natural Gas

1,189

1,151

Total Production (mboe)

5,853

5,806

Total Production (boepd)

64,319

516

63,802

Energen Production Excluding San Juan Divestment

Reconciliation to GAAP Information

Year-to-Date Ended

December 31, 2014

GAAP

San Juan Basin

Non-GAAP

Oil

11,814

11,798

NGL

4,103

695

3,408

Natural Gas

9,767

5,876

3,891

Total Production (mboe)

25,684

6,587

19,097

Total Production (boepd)

70,367

18,047

52,320

Note: Amounts may not sum due to rounding


CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) For the 3 months ending September 30, 2015 and 2014

	3rd Quarter

(in thousands, except per share data)	2015			2014			Change

Revenues
Oil, natural gas liquids and natural gas sales	$	188,398		$	350,773		$	(162,375	)
Gain on derivative instruments, net		107,173			147,735			(40,562	)

Total revenues		295,571			498,508			(202,937	)

Operating Costs and Expenses
Oil, natural gas liquids and natural gas production		54,598			67,720			(13,122	)
Production and ad valorem taxes		13,366			25,729			(12,363	)
Depreciation, depletion and amortization		149,781			139,104			10,677
Asset impairment		399,394			178,912			220,482
Exploration		493			8,417			(7,924	)
General and administrative		23,631			27,784			(4,153	)
Accretion of discount on asset retirement obligations		1,700			1,924			(224	)
Loss on sale of assets and other		822			747			75

Total costs and expenses		643,785			450,337			193,448

Operating Income (Loss)		(348,214	)		48,171			(396,385	)

Other Income (Expense)
Interest expense		(10,084	)		(11,522	)		1,438
Other income		56			37			19

Total other expense		(10,028	)		(11,485	)		1,457

Income (Loss) From Continuing Operations Before Income Taxes		(358,242	)		36,686			(394,928	)
Income tax expense (benefit)		(130,338	)		16,055			(146,393	)

Income (Loss) From Continuing Operations		(227,904	)		20,631			(248,535	)

Discontinued Operations, net of tax
Loss from discontinued operations		−			(3,485	)		3,485
Gain on disposal of discontinued operations		−			440,105			(440,105	)

Income From Discontinued Operations		−			436,620			(436,620	)

Net Income (Loss)	$	(227,904	)	$	457,251		$	(685,155	)

Diluted Earnings Per Average Common Share
Continuing operations	$	(2.89	)	$	0.28		$	(3.17	)
Discontinued operations		−			5.94			(5.94	)

Net Income (Loss)	$	(2.89	)	$	6.22		$	(9.11	)

Basic Earnings Per Average Common Share
Continuing operations	$	(2.89	)		0.28		$	(3.17	)
Discontinued operations		−			5.98			(5.98	)

Net Income (Loss)	$	(2.89	)	$	6.26		$	(9.15	)

Diluted Avg. Common Shares Outstanding		78,742			73,507			5,235

Basic Avg. Common Shares Outstanding		78,742			73,093			5,649

Dividends Per Common Share	$	0.02		$	0.15		$	(0.13	)


CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) For the 9 months ending September 30, 2015 and 2014

	Year-to-date

(in thousands, except per share data)	2015			2014			Change

Revenues
Oil, natural gas liquids and natural gas sales	$	595,510		$	1,057,447		$	(461,937	)
Gain on derivative instruments, net		90,245			9,498			80,747

Total revenues		685,755			1,066,945			(381,190	)

Operating Costs and Expenses
Oil, natural gas liquids and natural gas production		175,933			199,861			(23,928	)
Production and ad valorem taxes		45,783			81,102			(35,319	)
Depreciation, depletion and amortization		434,005			399,568			34,437
Asset impairment		466,390			181,500			284,890
Exploration		12,274			21,218			(8,944	)
General and administrative		94,338			93,499			839
Accretion of discount on asset retirement obligations		5,379			5,650			(271	)
(Gain) loss on sale of assets and other		(26,046	)		1,809			(27,855	)

Total costs and expenses		1,208,056			984,207			223,849

Operating Income (Loss)		(522,301	)		82,738			(605,039	)

Other Income (Expense)
Interest expense		(33,086	)		(27,374	)		(5,712	)
Other income		143			1,047			(904	)

Total other expense		(32,943	)		(26,327	)		(6,616	)

Income (Loss) From Continuing Operations Before Income Taxes		(555,244	)		56,411			(611,655	)
Income tax expense (benefit)		(200,319	)		23,287			(223,606	)

Income (Loss) From Continuing Operations		(354,925	)		33,124			(388,049	)

Discontinued Operations, net of tax
Income from discontinued operations		−			30,435			(30,435	)
Gain on disposal of discontinued operations		−			439,055			(439,055	)

Income From Discontinued Operations		−			469,490			(469,490	)

Net Income (Loss)	$	(354,925	)	$	502,614		$	(857,539	)

Diluted Earnings Per Average Common Share
Continuing operations	$	(4.72	)	$	0.45		$	(5.17	)
Discontinued operations		−			6.41			(6.41	)

Net Income (Loss)	$	(4.72	)	$	6.86		$	(11.58	)

Basic Earnings Per Average Common Share
Continuing operations	$	(4.72	)	$	0.45		$	(5.17	)
Discontinued operations		−			6.45			(6.45	)

Net Income (Loss)	$	(4.72	)	$	6.90		$	(11.62	)

Diluted Avg. Common Shares Outstanding		75,125			73,238			1,887

Basic Avg. Common Shares Outstanding		75,125			72,861			2,264

Dividends Per Common Share	$	0.06		$	0.45		$	(0.39	)

CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of September 30, 2015 and December 31, 2014

(in thousands)

September 30, 2015

December 31, 2014

ASSETS

Current Assets

Cash and cash equivalents

701

1,852

Accounts receivable, net of allowance

99,297

157,678

Inventories

18,184

14,251

Assets held for sale

−

395,797

Derivative instruments

153,816

322,337

Prepayments and other

12,667

27,445

Total current assets

284,665

919,360

Property, Plant and Equipment

Oil and natural gas properties, net

5,182,497

5,152,748

Other property and equipment, net

48,739

46,389

Total property, plant and equipment, net

5,231,236

5,199,137

Other assets

15,646

19,761

TOTAL ASSETS

5,531,547

6,138,258

LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities

Accounts payable

79,623

101,453

Accrued taxes

27,555

5,530

Accrued wages and benefits

25,103

21,553

Accrued capital costs

101,486

207,461

Revenue and royalty payable

58,480

72,047

Liabilities related to assets held for sale

−

24,230

Pension liabilities

29,789

24,609

Deferred income taxes

9,908

79,164

Derivative instruments

3,079

988

Other

13,513

23,288

Total current liabilities

348,536

560,323

Long-term debt

750,081

1,038,563

Asset retirement obligations

100,781

94,060

Deferred income taxes

853,360

1,000,486

Noncurrent derivative instruments

2,924

−

Other long-term liabilities

10,968

30,222

Total liabilities

2,066,650

2,723,654

Total Shareholders' Equity

3,464,897

3,414,604

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY

5,531,547

6,138,258


SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 3 months ending September 30, 2015 and 2014

	3rd Quarter

(in thousands, except sales price and per unit data)	2015			2014			Change

Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
Oil	$	160,531		$	260,447		$	(99,916	)
Natural gas liquids		11,001			31,259			(20,258	)
Natural gas		16,866			59,067			(42,201	)
Total	$	188,398		$	350,773		$	(162,375	)

Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	5,760		$	128,346		$	(122,586	)
Natural gas liquids		−			1,276			(1,276	)
Natural gas		(6,924	)		17,665			(24,589	)
Total	$	(1,164	)	$	147,287		$	(148,451	)

Closed gains (losses) on derivative instruments
Oil	$	98,072		$	(6,012	)	$	104,084
Natural gas liquids		−			873			(873	)
Natural gas		10,265			5,587			4,678
Total	$	108,337		$	448		$	107,889
Total revenues	$	295,571		$	498,508		$	(202,937	)

Production volumes
Oil (MBbl)		3,610			3,017			593
Natural gas liquids (MMgal)		44.4			46.5			(2.1	)
Natural gas (MMcf)		7,362			15,156			(7,794	)
Total production volumes (MBOE)		5,893			6,651			(758	)

Average daily production volumes
Oil (MBbl/d)		39.2			32.8			6.4
Natural gas liquids (MMgal/d)		0.5			0.5			−
Natural gas (MMcf/d)		80.0			164.7			(84.7	)
Total average daily production volumes (MBOE/d)		64.1			72.3			(8.2	)

Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	71.64		$	84.33		$	(12.69	)
Natural gas liquids (per gallon)	$	0.25		$	0.69		$	(0.44	)
Natural gas (per Mcf)	$	3.69		$	4.27		$	(0.58	)

Average realized prices excluding effects of all derivative instruments
Oil (per barrel)	$	44.47		$	86.33		$	(41.86	)
Natural gas liquids (per gallon)	$	0.25		$	0.67		$	(0.42	)
Natural gas (per Mcf)	$	2.29		$	3.90		$	(1.61	)

Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	9.26		$	10.18		$	(0.92	)
Production and ad valorem taxes	$	2.27		$	3.87		$	(1.60	)
Depreciation, depletion and amortization	$	25.42		$	20.91		$	4.51
Exploration expense	$	0.08		$	1.27		$	(1.19	)
General and administrative*	$	4.01		$	4.18		$	(0.17	)
Net capital expenditures	$	230,900		$	356,725		$	(125,825	)

*Includes pension and pension settlement expenses of $0.16 and $0.53 for the three months ended September 30, 2015 and 2014, respectively.


SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 9 months ending September 30, 2015 and 2014

	Year-to-date

(in thousands, except sales price and per unit data)	2015			2014			Change

Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
Oil	$	491,158		$	776,952		$	(285,794	)
Natural gas liquids		36,616			90,625			(54,009	)
Natural gas		67,736			189,870			(122,134	)
Total	$	595,510		$	1,057,447		$	(461,937	)

Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	(149,743	)	$	40,710		$	(190,453	)
Natural gas liquids		−			1,603			(1,603	)
Natural gas		(27,939	)		11,672			(39,611	)
Total	$	(177,682	)	$	53,985		$	(231,667	)

Closed gains (losses) on derivative instruments
Oil	$	230,885		$	(46,568	)	$	277,453
Natural gas liquids		−			1,228			(1,228	)
Natural gas		37,042			853			36,189
Total	$	267,927		$	(44,487	)	$	312,414
Total revenues	$	685,755		$	1,066,945		$	(381,190	)

Production volumes
Oil (MBbl)		10,439			8,601			1,838
Natural gas liquids (MMgal)		125.5			129.2			(3.7	)
Natural gas (MMcf)		27,774			43,956			(16,182	)
Total production volumes (MBOE)		18,055			19,003			(948	)

Average daily production volumes
Oil (MBbl/d)		38.2			31.5			6.7
Natural gas liquids (MMgal/d)		0.5			0.5			−
Natural gas (MMcf/d)		101.7			161.0			(59.30	)
Total average daily production volumes (MBOE/d)		66.1			69.6			(3.50	)

Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	69.17		$	84.92		$	(15.75	)
Natural gas liquids (per gallon)	$	0.29		$	0.71		$	(0.42	)
Natural gas (per Mcf)	$	3.77		$	4.34		$	(0.57	)

Average realized prices excluding effects of all derivative instruments
Oil (per barrel)	$	47.05		$	90.33		$	(43.28	)
Natural gas liquids (per gallon)	$	0.29		$	0.70		$	(0.41	)
Natural gas (per Mcf)	$	2.44		$	4.32		$	(1.88	)

Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	9.75		$	10.52		$	(0.77	)
Production and ad valorem taxes	$	2.54		$	4.27		$	(1.73	)
Depreciation, depletion and amortization	$	24.04		$	21.03		$	3.01
Exploration expense	$	0.68		$	1.12		$	(0.44	)
General and administrative*	$	5.23		$	4.92		$	0.31
Net capital expenditures	$	891,491		$	950,993		$	(59,502	)

*Includes pension and pension settlement expenses of $0.28 and $0.71 for the nine months ended September 30, 2015 and 2014, respectively.

View source version on businesswire.com: http://www.businesswire.com/news/home/20151105006657/en/

Energen Corporation
Julie S. Ryland, 205-326-8421

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