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, Energens 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.]

Energens 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 companys 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 Energens continued strong performance in the 3rd quarter as a leading operator in the Permian Basin, said James McManus, Energens 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 plays 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					58	%							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					0	%							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					23	%							5,323					58,495
	San Juan Basin/Other					502					5,457					497					5,402					1	%							483					5,308
	Total					5,893					64,054					4,896					53,217					20	%							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 Energens Wolfcamp development program led to a 58 percent increase in Midland Basin production and a 23 percent increase in total Permian Basin production.
• The companys 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 Energens borrowing base resulted in a $200 million reduction in its line of credit. The Companys 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 programs 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.

Energens 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.
											Drilled*					Completed										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

Energens 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 companys 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 companys 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 Energens acreage footprint in the Midland Basin. [See cumulative oil performance over time and potential economics of the companys 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

21

1,049

74

14

12

818

75

13

12

* Represents distance from vertical departure to toe

The last of 8 gross (8 net) appraisal wells in Energens 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 companys 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 companys 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										%
						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					60	%
	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					(8	)%
	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					20	%
	San Juan Basin/Other					1.9					5,205					1.8					4,929					6	%
	Total					22.7					62,252					19.1					52,320					19	%
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	null				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^th quarter 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