Energen's 2Q16 Production Exceeds Guidance Midpoint by 4%

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

For the 3 months ended June 30, 2016, Energen Corporation EGN reported GAAP net income from all operations of 36.8 million, or $0.38 per diluted share. Excluding mark-to-market derivatives losses, income from the sale of properties, and pension and reduction in force (RIF) settlement expenses, Energen's adjusted loss in 2Q16 totaled $27.1 million, or $(0.28) per diluted share. This compares with adjusted income in 2Q15 of $11.9 million, or $0.16 per diluted share.

The variance between the periods primarily is due to lower realized commodity prices partially offset by less depreciation, depletion and amortization expense (DD&A), lower net salaries and general and administrative expenses (SG&A), and lower lease operating, marketing and transportation expenses (LOE). [See "Non-GAAP Financial Measures" beginning on pp 9 for more information and reconciliation.]

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations
[See "Non-GAAP Financial Measures" beginning on pp 9 for more information]

				2Q16										2Q15
				$M					$/dil. sh.					$M					$/dil. sh.
Net Income/(Loss) All Operations (GAAP)				$	36,759				$	0.38				$	(111,601	)			$	(1.52	)
Less: Non-cash mark-to-market gains/(losses)					(39,109	)				(0.40	)				(75,133	)				(1.02	)
Less: Asset impairments					--					--					(37,644	)				(0.51	)
Less: Pension settlement and RIF settlement expenses					(559	)				(0.01	)				(701	)				(0.01	)
Less: Income/(loss) associated 2016 asset sales					103,540					1.06					(10,005	)				0.14
Adj. Income Continuing Operations (Non-GAAP)				$	(27,113	)			$	(0.28	)			$	11,882				$	0.16

Note: Per share amounts may not sum due to rounding

Energen's adjusted 2Q16 loss was substantially better than internal expectations largely due to significantly lower-than-expected LOE and better-than-expected production. LOE, including marketing and transportation, totaled $7.29 per boe and benefited largely from lower costs for water disposal, gathering, and electrical power, and from fewer workovers.

Production in 2Q16 totaled 56.0 thousand barrels of oil equivalents per day (mboepd) and exceeded the production guidance midpoint of 53.9 mboepd by 3.9 percent. Oil production was up almost 5 percent relative to the guidance midpoint. Actual and guidance production numbers exclude all 2016 property sales (closed and pending). The production increase was driven primarily by the outperformance of the company's Midland Basin horizontal plays, which are responding favorably to the Generation 2 frac design used to complete Energen's drilled but uncompleted (DUC) well inventory in the first half of 2016.

Energen's adjusted EBITDAX totaled $82.3 million in the 2nd quarter of 2016 and exceeded internal expectations by 30 percent. In the same period a year ago, Energen's adjusted EBITDAX totaled $169.8 million. [See "Non-GAAP Financial Measures" beginning on pp 9 for more information and reconciliation.]

2H16 Drilling Program Under Way in Permian Basin

Drilling is under way in the Midland and Delaware basins as Energen looks to end 2016 with 54-58 net DUCs that will be available for completion in 2017. Energen estimates that capital investment associated with drilling and development activity in 2016 will be approximately $450 million. In addition to drilling and development, Energen has invested approximately $37 million in 2016 (through July 31) to acquire acreage and renew leases, including adding more than 4,500 net acres in the core Delaware and Midland basins through bolt-on acquisitions. In July alone, Energen added 851 net acres in its core Delaware Basin footprint.

The majority of the new drills in 2H16 in the Midland Basin will be 10,000-plus foot lateral-length wells in Martin County targeting the Jo Mill, Middle Spraberry, Lower Spraberry and Wolfcamp A and B. The average working interest in the new drills is estimated to exceed 97 percent. Energen anticipates completing these new Midland Basin DUCs in the first half of 2017 using a new generation frac design with more sand per linear foot and tighter frac stages (MB Generation 3). [See 2Q16 Supplemental Slides at www.energen.com for the company's evolution in frac design.]

In the core central Delaware Basin, new drills will focus on the Wolfcamp A and B in Reeves and Loving counties, and all but two potential DUCs will have an average lateral length in excess of 9,500'. Energen's average working interest in the new drills in the Delaware Basin is approximately 100 percent. The new DUCs to be completed in 2017 likely will utilize a new generation frac design (DB Generation 3) and optimized surface facilities. [See 2Q16 Supplemental Slides at www.energen.com for the company's evolution in frac design.]

At year-end, the company estimates that it will have approximately 38-40 gross (37-39 net) horizontal DUCs in the Midland Basin, 1 (gross and net) vertical DUC in the Midland Basin, and 17-19 (gross and net) horizontal DUCs in the Delaware Basin.

2016 Capital Summary

			2016e Capital ($MM)					Wells to be Drilled			Wells Completions
								Operated Gross (Net)			Operated Gross (Net)
Midland Basin			$	300				48 (46) – 50 (48) *			55 (54) †
Delaware Basin			$	130				21 (21) – 23 (23) **			4 (4)
Net Carry/ARO/Other			$	20
Drilling & Development Capital			$	450	¹			69 (67) – 73 (71)			59 (58)

¹ Includes approximately $35 mm for facilities in the Midland Basin, $25 mm for facilities in the Delaware Basin and $10 mm for non-operated activities and miscellaneous items
* Includes 6 gross (6 net) vertical wells to hold acreage and 3 gross (2 net) horizontal wells to hold new leasehold, 1 gross (1 net) well to complete a pad, and 38-40 gross (37-39) net DUC drills in 2H16
** Includes 4 gross (4 net) horizontal wells to hold acreage and 17-19 gross and net DUC drills in 2H16
† Includes 5 gross (5 net) vertical wells, 3 gross (2 net) horizontal wells to hold new leasehold, 47 gross (47 net) development program completions, virtually all of which comprised the company's YE15 DUC inventory

Energen Sees Attractive EURs in the Core Central Delaware Basin

Energen's decision to allocate increasing amounts of capital in its core Delaware Basin is the result of strong performances by 5 wells it drilled in the core and from approximately 20 wells drilled by offset operators as well as from the expectation of continued efficiency gains. All of these factors have combined to support outstanding internal rates of return (IRRs) in the Wolfcamp A and Wolfcamp B in the core Delaware Basin, with expected ultimate recoveries (EURs) estimated to approach 1.1 mmboe for a 4,500' lateral, 1.5 mmboe for a 7,500' lateral, and 2.0 mmboe for a 10,000' lateral.

The 377-day average cumulative production of the 5 Energen Wolfcamp wells, normalized to 7,500', is closely tracking the 1.5 mmboe EUR type curve. These Reeves County wells have been producing for approximately 12-24 months, and include Wolfcamp A, B, and C targets. The majority of them were completed with the DB Generation 1 frac design. [See 2Q16 Supplemental Slides at www.energen.com for graph of average cumulative production of the 5 wells and for details on the company's evolution in frac design.]

Energen has increased its estimated IRRs for 7,500' and 10,000' lateral-length Wolfcamp A and Wolfcamp B wells in its core Delaware Basin as the result of increasing flow rates primarily by optimizing surface facilities. The return for a 10,000' lateral-length well drilled and completed for $8 million at a $45 oil price is now estimated to be 86 percent. [See 2Q16 Supplemental Slides at www.energen.com for estimated Delaware Basin Wolfcamp A and Wolfcamp B IRRs at varying oil prices.]

Energen currently is drilling its fourth well to hold acreage in the core Delaware Basin footprint; three of these wells will be completed in 3Q16 and the fourth well is scheduled to be completed in 4Q16. These four wells utilize optimized surface facilities and will be completed with the DB Generation 3 frac design.

Underscoring the strides it continues to make in drilling efficiency in the Delaware Basin, Energen drilled one of these wells -- a 9,000' lateral well targeting the Wolfcamp A -- in just 22.4 days from spud to TD and estimates the drill and complete cost will be $7.2 million.

Midland Basin Development Program Outperforms

Energen completed its remaining DUC inventory of 14 gross (14 net) net wells in the Midland Basin during the second quarter. Together with 15 wells completed in the first quarter but not yet on production, Energen placed on production in the second quarter a total of 24 DUCs: 22 in Martin County targeting the Lower Spraberry, Wolfcamp A, and Wolfcamp B zones and 2 in Glasscock County targeting the Wolfcamp A and Wolfcamp B. The lateral length of the Martin County wells placed on production averaged approximately 6,700 feet, and the Glasscock County wells had an average lateral length of approximately 7,600 feet.

Based on early production results, these wells are outperforming internal expectations due, in large part, to the company's MB Generation 2 completions. In Martin County, for example, 6 Lower Spraberry DUCs with more than 60 days of productive history are averaging a 900 mboe EUR estimate. In their first 90 days of production, the 9 Glasscock County DUCs completed in 1H16 have outperformed the type curve.

As strong as production has been, the full extent of the Martin County DUCs' performance was hampered in June when the salt water disposal facility servicing that area was damaged by lightning. This caused a temporary interruption in production. Intermittent storm-related power outages also were experienced in Martin and Glasscock counties in July. The direct impact of weather on annual production is estimated to be less than 500 boepd.

Efficiency gains continue to be realized in the Midland Basin, where Energen drilled a 7,500' Wolfcamp A DUC in Glasscock County in 13.1 days, spud to TD; the well was completed in 1H16 with MB Generation 3 frac design for $5.2 mm.

2nd Quarter 2016 Results

Production (excluding 2016 asset sales) (mboepd)

Commodity							2Q16			2Q15					1Q16
Oil							36.5			36.5					33.6
NGL							9.4			9.5					8.3
Natural Gas							10.2			9.5					10.4
Total							56.0			55.4					52.3

Area				2Q16			2Q15					1Q16
Midland Basin				37.1			32.5					33.0
Horizontal				28.5			19.6					23.3
Vertical				8.6			12.9					9.7
Delaware Basin				9.8			12.9					10.3
Central Basin/Other				9.1			10.0					9.0
Total				56.0			55.4					52.3

Note: Totals in production tables above may not sum due to rounding.

Average Realized Sales Prices (excluding 2016 asset sales)

Commodity					2Q16				2Q15				% Change
Oil (per barrel)					$	39.52			$	69.39			(43	)
NGL (per gallon)					$	0.32			$	0.34			(6	)
Natural Gas (per Mcf)					$	1.68			$	4.22			(60	)

Average Prices Before Effects of Hedges (excluding 2016 asset sales)

Commodity				2Q16				2Q15				% Change
Oil (per barrel)				$	41.42			$	52.75			(22	)
NGL (per gallon)				$	0.32			$	0.34			(6	)
Natural Gas (per Mcf)				$	1.49			$	2.17			(31	)

Expenses (excluding 2016 asset sales)

Per BOE, except where noted				2Q16				2Q15				% Change
LOE (including marketing and transportation)				$	7.29			$	9.09			(20	)
Production & ad valorem taxes				$	1.97			$	2.31			(15	)
DD&A				$	21.46			$	26.92			(20	)
Net SG&A†				$	4.45			$	7.34			(39	)
Interest ($MM)				$	9.0			$	11.2			(20	)

† Excludes $0.17 per boe in 2Q16 for RIF settlement expenses and $0.22 per BOE in 2Q15 for pension and pension settlement expenses.

Liquidity Update

As of June 30, 2016, Energen had cash of $309.9 million and long-term debt of $551.2 million; the company had nothing drawn on its $1.05 billion line of credit. Energen estimates that is total net debt-to-2016 adjusted EBITDAX will be approximately 0.5x.

3Q16 and CY16 Financial and Production Guidance

Energen's Estimated Expenses (excluding 2016 asset sales):

Per BOE, except where noted					3Q16				CY16
LOE (production costs, marketing & transportation)					$8.60-$9.00				$8.25- $8.65
Production & ad valorem taxes (% of revenues, excluding hedges)					7.1%				7.3%
DD&A expense					$20.50-$21.00				$21.30-$21.70
Salaries and general & administrative expense, net					$4.35-$4.70				$4.35-$4.70†
Exploration expense (seismic, delay rentals, etc.)					$0.42-$0.47				$0.30-$0.35
Interest expense ($MM)					$8.8-$9.2				$36.5-$37.5
FF&E depreciation ($MM)					$1.2-$1.4				$5.0-$5.2
Accretion of discount on ARO ($MM)					$1.5-$1.7				$6.1-$6.3
Effective tax rate (%)					33%-35%				33%-35%

† Excludes $0.45 per boe in CY16 for pension settlement and RIF settlement expenses

LOE per boe in CY16 is estimated to range from $5.95-$6.35 in the Midland Basin, $8.25-$8.65 in the Delaware Basin, and $17.20-$17.60 in the Central Basin Platform. Production and ad valorem taxes in CY16, as a percent of revenues excluding hedges, are estimated to be 7.0 percent in the Midland Basin and Central Basin Platform and 8.4 percent in the Delaware Basin.

Net SG&A per boe in CY16 (excluding pension settlement and RIF settlement expenses) is estimated to be comprised of cash of $3.50-$3.70 per boe and non-cash, equity-based compensation of $0.85-$1.00 per boe.

Production is estimated to range from 55.2-55.6 mboepd in 3Q16 and from 52.0-52.4 mboepd in 4Q16. The company's 4Q15 to 4Q16 exit rate decline continues to shrink and now is estimated (at midpoint) to be 8 percent. The production guidance midpoint for the year has been increased approximately 2%, or some 900 boepd, within a range of 53.6-54.4 mboepd. For all applicable periods, production excludes 2016 asset sales.

Production by Basin (excluding 2016 asset sales) (mboepd)

Area				3Q16e Guidance Midpoint			4Q16e Guidance Midpoint			2016e Guidance Midpoint
Midland Basin				36.9			32.9			34.9
Horizontal				28.4			24.8			26.2
Vertical				8.5			8.1			8.7
Delaware Basin				9.5			10.4			10.0
Central Basin Platform/Other				9.0			8.9			9.1
Total				55.4			52.2			54.0
NOTE: Totals may not sum due to rounding

Production by Commodity (excluding 2016 asset sales) (mboepd)

Commodity				3Q16e Guidance Midpoint			4Q16e Guidance Midpoint			2016e Guidance Midpoint
Oil				35.9			33.4			34.9
NGL				9.4			9.1			9.0
Gas				10.1			9.7			10.1
Total Production				55.4			52.2			54.0
NOTE: Totals may not sum due to rounding

3Q16 Hedge Position

Commodity

Hedge Volumes

Production @ Midpoint

Hedge %

NYMEXe Price

Oil

2.5 mmbo

3.3 mmbo

76

$ 44.73 per barrel

Natural Gas

1.8 bcf

5.6 bcf

32

$ 2.51 per mcf

NOTE: Includes known actuals

Differential				Hedge Volumes			Avg. Price (per barrel)
WTS Midland to WTI Cushing (sour)				0.5 mmbo			$ (1.64)
WTI Midland to WTI Cushing (sweet)				1.9 mmbo			$ (1.92)
NOTE: Approximately 79% of 3Q16 oil production is "sweet"

July-December 2016 Hedge Position

Commodity

Hedge Volumes

Production @ Midpoint

Hedge %

NYMEXe Price

Oil

4.4 mmbo

6.4 mmbo

69

$ 44.72 per barrel

Natural Gas

3.6 bcf

10.9 bcf

33

$ 2.47 per mcf

NOTE: Includes known actuals

Differential				Hedge Volumes			Avg. Price (per barrel)
WTS Midland to WTI Cushing (sour)				1.0 mmbo			$ (1.64)
WTI Midland to WTI Cushing (sweet)				3.8 mmbo			$ (1.92)
NOTE: Approximately 79% of July-December 2016 oil production is "sweet"

In the tables 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.

Estimated Price Realizations (pre-hedge):

				3Q16			CY16
Crude oil (% of NYMEX/WTI)				93%			90%
NGL (after T&F) (% of NYMEX/WTI)				28%			29%
Natural gas (% of NYMEX/Henry Hub)				79%			78%

Average realized prices will reflect commodity and basis hedges; oil transportation charges of approximately $2.19 per barrel; NGL transportation and fractionation fees of approximately $0.12 per gallon; gas and oil basis differentials applicable to unhedged production. In addition, natural gas and NGL production is subject to a percent of proceeds contract of approximately 85%.

Energen's assumed commodity prices for unhedged production for the remainder of the year are: $45.00 per barrel of oil (July-December); $0.49 per gallon of NGL (July-December), and $2.80 per Mcf of gas (August-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (August-December) are $(0.45) and $(0.90), respectively. And assumed gas basis assumptions for all open contracts (August-December) are $(0.13) per Mcf.

Relative to the company's price assumptions: every $1.00 per barrel change in the price of oil for the remainder of the year is estimated to impact the company's cash flows by approximately $1.7 million; every $0.01 per gallon change in the average price of NGL for the remainder of the year is estimated to have an impact of approximately $0.6 million; and every $0.10 per Mcf change in the price of natural gas for the remainder of the year is estimated to have an impact of approximately $0.4 million.

2017 Hedge Position Strengthened

Energen continued to increase its 2017 oil hedge position in the second quarter by adding 3-way collars for 1.1 million barrels of oil production at an average call price of $65.67 per barrel, an average put price of $45 per barrel, and an average short put price of $35 per barrel. This brings the company's total oil volumes hedged in 2017 to 8.2 million barrels.

Energen's total oil hedge position for 2017 is as follows:

Oil				2017 Hedge Volumes¹			Avg. NYMEX Price
Swaps				4.1 mmbo			$ 47.97 per barrel
Three way Collars²				4.1 mmbo
Call Price							$ 62.25 per barrel
Put Price							$ 45.00 per barrel
Short Put Price							$ 35.00 per barrel

¹ Hedges are distributed equally throughout the year by month
² When the NYMEX price is above the call price, Energen receives the call price; when the NYMEX price is between the call price and the put price, Energen receives the NYMEX price; when the NYMEX price is between the put price and the short put price, Energen receives the put price; and when the NYMEX price is below the short put price, Energen receives the NYMEX price plus the difference between the put price and the short put price.

Energen also added 2.4 Bcf of Permian Basin-specific contracts to its 2017 natural gas hedge position at an average contract price of $3.00 per Mcf. This brings Energen's total natural gas hedge position in 2017 to 13.2 Bcf of basin-specific gas at an average contract price of $2.85 per Mcf. Assuming a $0.15 per Mcf differential, the company's NYMEX-equivalent price for its 2017 natural gas hedges is $3.00 per Mcf.

Supplemental Slides and Conference Call

2Q16 Supplemental Slides associated with Energen's quarterly release and conference call are available at www.energen.com. Energen will hold its quarterly conference call Tuesday, August 9, 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 via www.energen.com.

Energen Corporation is an oil-focused exploration and production company with operations in the Permian Basin in west Texas. For more information, go to www.energen.com.

FORWARD LOOKING STATEMENTS: 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 the timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, the nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, the 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. Among other forward-looking statements in this release are statements regarding our intention to engage in certain assets sales and the estimated proceeds thereof. These sales processes are at preliminary stages, and we do not have binding agreements for any transactions; as a result, the estimate of proceeds from these transactions is preliminary and may not be realized. Our ability to consummate any transactions and their timing are subject to market conditions and other factors, and we may not be able to consummate these transactions at all or for the net proceeds we are estimating. 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 news release. 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.

CAUTIONARY STATEMENTS: The SEC permits oil and gas companies to disclose in SEC filings only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. Outside of SEC filings, we use the terms "estimated ultimate recovery" or "EUR," reserve or resource "potential," "contingent resources" and other descriptions of volumes of non-proved reserves or resources potentially recoverable through additional drilling or recovery techniques. These estimates are inherently more speculative than estimates of proved reserves and are subject to substantially greater risk of actually being realized. We have not risked EUR estimates, potential drilling locations, and resource potential estimates. Actual locations drilled and quantities that may be ultimately recovered may differ substantially from estimates. We make no commitment to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of our on-going drilling program, which will be directly affected by the availability of capital, drilling, and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approvals, and geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per-well EURs, and resource potential may change significantly as development of our oil and gas assets provides additional data. Additionally, initial production rates contained in this news release are subject to decline over time and should not be regarded as reflective of sustained production levels.

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 the effects of certain non-cash mark-to-market derivative financial instruments. Adjusted  income from continuing operations further excludes impairment losses, expenses related to the 2016 reductions in force, certain pension and pension settlement expenses and income and losses associated with 2016 property sales (closed and pending). 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.
			Three Months Ended 6/30/2016
Energen Net Income ($ in millions except per share data)			Net Income			Per Diluted Share
Net Income All Operations (GAAP)			36.8			0.38
Non-cash mark-to-market losses (net of $21.5 tax)			39.1			0.40
Reduction in force expenses (net of $0.3 tax)			0.6			0.01
Income associated with 2016 property sales (net of $58.2 tax)			(103.5	)		(1.06	)
Adjusted Income from Continuing Operations (Non-GAAP)			(27.1	)		(0.28	)
			Three Months Ended 6/30/2015
Energen Net Income ($ in millions except per share data)			Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)			(111.6	)		(1.52	)
Non-cash mark-to-market losses (net of $41.7 tax)			75.1			1.02
Asset impairment, other (net of $21.1 tax)			37.6			0.51
Pension and pension settlement expenses (net of $0.4 tax)			0.7			0.01
Loss associated with 2016 property sales (net of $5.8 tax)			10.0			0.14
Adjusted Income from Continuing Operations (Non-GAAP)			11.9			0.16
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 expenses related to the 2016 reductions in force, certain pension and pension settlement expenses, income and losses associated with  2016 property sales (closed and pending), impairment losses and certain non-cash mark-to-market derivative financial  instruments. 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			Three Months Ended 6/30
($ in millions)			2016			2015
Energen Net Income (Loss) (GAAP)			36.8			(111.6	)
(Income) Loss associated with 2016 property sales, net of tax			(103.5	)		10.0
Net Income (Loss) Excluding 2016 Property Sales (Non-GAAP)			(66.8	)		(101.6	)
Interest expense			9.0			11.2
Income tax expense (benefit) *			(35.1	)		(55.5	)
Depreciation, depletion and amortization *			110.6			137.2
Accretion expense *			1.5			1.4
Exploration expense *			1.5			0.3
Adjustment for asset impairment *			0.0			58.7
Adjustment for mark-to-market losses			60.6			116.9
Adjustment for reduction in force and pension and pension settlement expenses			0.9			1.1
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)			82.3			169.8
Note: Amounts may not sum due to rounding
* Amount adjusted to exclude held for sale assets in either current or prior period. See reconciliation to GAAP Information for the Three Months Ended 6/30/2016 and 6/30/2015.

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 2016 property sales (closed and pending) 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 2016 Property Sales (Closed and Pending)
Reconciliation to GAAP Information			Three Months Ended
			June 30, 2016
(in thousands except per share and production data)
			GAAP				$/BOE			2016 Property Sales				Non-GAAP				$/BOE
Revenues
Oil, natural gas liquids and natural gas sales			$	171,637						$	14,426			$	157,211
Gain (loss) on derivative instruments				(65,872	)						-				(65,872	)
Total Revenues				105,765							14,426				91,339
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production				42,840			$	7.33			5,660				37,180			$	7.29
Production and ad valorem taxes				11,265			$	1.93			1,236				10,029			$	1.97
O&G Depreciation, depletion and amortization				115,768			$	19.82			6,368				109,400			$	21.46
FF&E Depreciation, depletion and amortization				1,267			$	0.22			71				1,196			$	0.23
Asset impairment				-							-				-
Exploration				1,520							32				1,488
General and administrative †				23,548			$	4.03			10				23,538			$	4.62
Accretion of discount on asset retirement obligations				1,779							248				1,531
(Gain) loss on sale of assets and other				(161,097	)						(160,944	)			(153	)
Total costs and expenses				36,890							(147,319	)			184,209
Operating Income (Loss)				68,875							161,745				(92,870	)
Other Income/(Expense)
Interest expense				(9,038	)						-				(9,038	)
Other income				63							(1	)			64
Total other expense				(8,975	)						(1	)			(8,974	)
Loss Before Income Taxes				59,900							161,744				(101,844	)
Income tax expense (benefit)				23,141							58,204				(35,063	)
Net Income (Loss)			$	36,759						$	103,540			$	(66,781	)
Diluted Earnings Per Average Common Share			$	0.38						$	1.06			$	(0.69	)
Basic earning Per Average Common Share			$	0.38						$	1.06			$	(0.69	)
Oil				3,558							238				3,320
NGL				1,067							212				855
Natural Gas				1,216							292				924
Total Production (mboe)				5,841							742				5,099
Total Production (boepd)				64,187							8,154				56,033
Note: Amounts may not sum due to rounding
† General and administrative includes $866 or $0.17 per BOE of expense related to the reductions in force

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 2016 property sales (closed and pending) 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 2016 Property Sales (Closed and Pending)
Reconciliation to GAAP Information			Three Months Ended
			June 30, 2015
(in thousands except per share and production data)
			GAAP				$/BOE			2016 Property Sales				Non-GAAP				$/BOE
Revenues
Oil, natural gas liquids and natural gas sales			$	219,290						$	20,557			$	198,733
Gain (loss) on derivative instruments				(50,964	)						-				(50,964	)
Total Revenues				168,326							20,557				147,769
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production				53,581			$	9.15			7,706				45,875			$	9.09
Production and ad valorem taxes				13,352			$	2.28			1,692				11,660			$	2.31
O&G Depreciation, depletion and amortization				148,374			$	25.35			12,547				135,827			$	26.92
FF&E Depreciation, depletion and amortization				1,469			$	0.25			106				1,363			$	0.27
Asset impairment				60,413							1,725				58,688
Exploration				11,018							10,666				352
General and administrative †				38,652			$	6.60			525				38,127			$	7.56
Accretion of discount on asset retirement obligations				1,669							237				1,432
(Gain) loss on sale of assets and other				1,476							1,148				328
Total costs and expenses				330,004							36,352				293,652
Operating Income (Loss)				(161,678	)						(15,795	)			(145,883	)
Other Income/(Expense)
Interest expense				(11,244	)						-				(11,244	)
Other income				41							-				41
Total other expense				(11,203	)						-				(11,203	)
Loss Before Income Taxes				(172,881	)						(15,795	)			(157,086	)
Income tax expense (benefit)				(61,280	)						(5,790	)			(55,490	)
Net Income (Loss)			$	(111,601	)					$	(10,005	)		$	(101,596	)
Diluted Earnings Per Average Common Share			$	(1.52	)					$	(0.14	)		$	(1.38	)
Basic earning Per Average Common Share			$	(1.52	)					$	(0.14	)		$	(1.38	)
Oil				3,594							269				3,325
NGL				1,070							209				861
Natural Gas				1,189							330				859
Total Production (mboe)				5,853							808				5,045
Total Production (boepd)				64,319							8,879				55,440
Note: Amounts may not sum due to rounding
† General and administrative includes $1,090 or $0.22 per BOE of pension and pension settlement expense

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 2016 property sales (closed and pending) 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 2016 Property Sales (Closed and Pending)
Reconciliation to GAAP Information			Quarter Ended
			March 31, 2016
			GAAP		2016 Property Sales		Non-GAAP
Oil			3,386		325		3,061
NGL			953		199		754
Natural Gas			1,241		296		945
Total Production (mboe)			5,580		820		4,760
Total Production (boepd)			61,319		9,011		52,308
Note: Amounts may not sum due to rounding

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) For the 3 months ending June 30, 2016 and 2015
				2nd Quarter
(in thousands, except per share data)				2016					2015					Change
Revenues
Oil, natural gas liquids and natural gas sales				$	171,637				$	219,290				$	(47,653	)
Loss on derivative instruments, net					(65,872	)				(50,964	)				(14,908	)
Total revenues					105,765					168,326					(62,561	)
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production					42,840					53,581					(10,741	)
Production and ad valorem taxes					11,265					13,352					(2,087	)
Depreciation, depletion and amortization					117,035					149,843					(32,808	)
Asset impairment					−					60,413					(60,413	)
Exploration					1,520					11,018					(9,498	)
General and administrative (including non-cash stock based compensation of $5,504 and $6,027 for the three months ended June 30, 2016, and 2015, respectively)					23,548					38,652					(15,104	)
Accretion of discount on asset retirement obligations					1,779					1,669					110
(Gain) loss on sale of assets and other					(161,097	)				1,476					(162,573	)
Total operating costs and expenses					36,890					330,004					(293,114	)
Operating Income (Loss)					68,875					(161,678	)				230,553
Other Income (Expense)
Interest expense					(9,038	)				(11,244	)				2,206
Other income					63					41					22
Total other expense					(8,975	)				(11,203	)				2,228
Income (Loss) Before Income Taxes					59,900					(172,881	)				232,781
Income tax expense (benefit)					23,141					(61,280	)				84,421
Net Income (Loss)				$	36,759				$	(111,601	)			$	148,360
Diluted Earnings Per Average Common Share				$	0.38				$	(1.52	)			$	1.90
Basic Earnings Per Average Common Share				$	0.38				$	(1.52	)			$	1.90
Diluted Average Common Shares Outstanding					97,389					73,452					23,937
Basic Average Common Shares Outstanding					97,067					73,452					23,615
Dividends Per Common Share				$	−				$	0.02				$	(0.02	)

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) For the 6 months ending June 30, 2016 and 2015
				Year-to-date
(in thousands, except per share data)				2016					2015					Change
Revenues
Oil, natural gas liquids and natural gas sales				$	294,401				$	407,112				$	(112,711	)
Loss on derivative instruments, net					(60,417	)				(16,928	)				(43,489	)
Total revenues					233,984					390,184					(156,200	)
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production					90,567					121,335					(30,768	)
Production and ad valorem taxes					22,435					32,417					(9,982	)
Depreciation, depletion and amortization					236,397					284,224					(47,827	)
Asset impairment					220,025					66,996					153,029
Exploration					1,762					11,781					(10,019	)
General and administrative (including non-cash stock based compensation of $7,975 and $11,107 for the six months ended June 30, 2016, and 2015, respectively)					53,073					70,707					(17,634	)
Accretion of discount on asset retirement obligations					3,536					3,679					(143	)
Gain (loss) on sale of assets and other					(160,875	)				(26,868	)				(134,007	)
Total operating costs and expenses					466,920					564,271					(97,351	)
Operating Loss					(232,936	)				(174,087	)				(58,849	)
Other Income (Expense)
Interest expense					(18,871	)				(23,002	)				4,131
Other income					159					87					72
Total other expense					(18,712	)				(22,915	)				4,203
Loss Before Income Taxes					(251,648	)				(197,002	)				(54,646	)
Income tax benefit					(85,291	)				(69,981	)				(15,310	)
Net Loss				$	(166,357	)			$	(127,021	)			$	(39,336	)
Diluted Earnings Per Average Common Share				$	(1.81	)			$	(1.74	)			$	(0.07	)
Basic Earnings Per Average Common Share				$	(1.81	)			$	(1.74	)			$	(0.07	)
Diluted Average Common Shares Outstanding					91,850					73,143					18,707
Basic Average Common Shares Outstanding					91,850					73,143					18,707
Dividends Per Common Share				$	−				$	0.04				$	(0.04	)

CONSOLIDATED BALANCE SHEETS (UNAUDITED) As of June 30, 2016 and December 31, 2015
(in thousands)				June 30, 2016				December 31, 2015
ASSETS
Current Assets
Cash and cash equivalents				$	309,889			$	1,272
Accounts receivable, net					76,119				63,097
Inventories					12,596				11,255
Assets held for sale					176,914				93,739
Derivative instruments					3,235				56,963
Prepayments and other					7,087				20,014
Total current assets					585,840				246,340
Property, Plant and Equipment
Oil and natural gas properties, net					3,858,918				4,302,332
Other property and equipment, net					45,755				48,358
Total property, plant and equipment, net					3,904,673				4,350,690
Other postretirement assets					4,358				3,881
Other assets					9,866				10,245
TOTAL ASSETS				$	4,504,737			$	4,611,156
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable					53,108			64,742
Accrued taxes					16,684			5,801
Accrued wages and benefits					13,386			28,563
Accrued capital costs					40,347			79,206
Revenue and royalty payable					57,979			60,493
Liabilities related to assets held for sale					13,279			12,789
Pension liabilities					−			15,685
Derivative instruments					46,452			459
Other					19,344			19,783
Total current liabilities					260,579			287,521
Long-term debt					551,245			773,550
Asset retirement obligations					91,473			89,990
Deferred income taxes					460,424			552,369
Noncurrent derivative instruments					12,875			−
Other long-term liabilities					11,910			11,866
Total liabilities					1,388,506			1,715,296
Total Shareholders' Equity					3,116,231			2,895,860
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY				$	4,504,737			$4,611,156

SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 3 months ending June 30, 2016 and 2015
				2nd Quarter
(in thousands, except sales price and per unit data)				2016					2015					Change
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil				$	146,360				$	188,599				$	(42,239	)
Natural gas liquids					13,928					14,781					(853	)
Natural gas					11,349					15,910					(4,561	)
Total				$	171,637				$	219,290				$	(47,653	)
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil				$	(54,729	)			$	(103,734	)			$	49,005
Natural gas					(5,896	)				(13,133	)				7,237
Total				$	(60,625	)			$	(116,867	)			$	56,242
Closed gains (losses) on derivative instruments
Oil				$	(6,297	)			$	55,330				$	(61,627	)
Natural gas					1,050					10,573					(9,523	)
Total				$	(5,247	)			$	65,903				$	(71,150	)
Total revenues				$	105,765				$	168,326				$	(62,561	)
Production volumes
Oil (MBbl)					3,558					3,594					(36	)
Natural gas liquids (MMgal)					44.8					44.9					(0.1	)
Natural gas (MMcf)					7,296					7,134					162
Total production volumes (MBOE)					5,841					5,853					(12	)
Average daily production volumes
Oil (MBbl/d)					39.1					39.5					(0.4	)
Natural gas liquids (MMgal/d)					0.5					0.5					−
Natural gas (MMcf/d)					80.2					78.4					1.8
Total average daily production volumes (MBOE/d)					64.2					64.3					(0.1	)
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)				$	39.37				$	67.87				$	(28.50	)
Natural gas liquids (per gallon)				$	0.31				$	0.33				$	(0.02	)
Natural gas (per Mcf)				$	1.70				$	3.71				$	(2.01	)
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)				$	41.14				$	52.48				$	(11.34	)
Natural gas liquids (per gallon)				$	0.31				$	0.33				$	(0.02	)
Natural gas (per Mcf)				$	1.56				$	2.23				$	(0.67	)
Costs per BOE
Oil, natural gas liquids and natural gas production expenses				$	7.34				$	9.15				$	(1.81	)
Production and ad valorem taxes				$	1.93				$	2.28				$	(0.35	)
Depreciation, depletion and amortization				$	20.04				$	25.60				$	(5.56	)
Exploration expense				$	0.26				$	1.88				$	(1.62	)
General and administrative				$	4.03				$	6.60				$	(2.57	)
Capital expenditures				$	92,962				$	300,178				$	(207,216	)

SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 6 months ending June 30, 2016 and 2015
				Year-to-Date
(in thousands, except sales price and per unit data)				2016					2015					Change
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil				$	248,517				$	330,627				$	(82,110	)
Natural gas liquids					22,517					25,615					(3,098	)
Natural gas					23,367					50,870					(27,503	)
Total				$	294,401				$	407,112				$	(112,711	)
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil				$	(56,428	)			$	(155,503	)			$	99,075
Natural gas					(4,454	)				(21,015	)				16,561
Total				$	(60,882	)			$	(176,518	)			$	115,636
Closed gains (losses) on derivative instruments
Oil				$	(1,203	)			$	132,813				$	(134,016	)
Natural gas					1,668					26,777					(25,109	)
Total				$	465				$	159,590				$	(159,125	)
Total revenues				$	233,984				$	390,184				$	(156,200	)
Production volumes
Oil (MBbl)					6,944					6,829					115
Natural gas liquids (MMgal)					84.8					81.1					3.7
Natural gas (MMcf)					14,742					20,412					(5,670	)
Total production volumes (MBOE)					11,421					12,162					(741	)
Average daily production volumes
Oil (MBbl/d)					38.2					37.7					0.5
Natural gas liquids (MMgal/d)					0.5					0.5					−
Natural gas (MMcf/d)					81.0					112.8					(31.8	)
Total average daily production volumes (MBOE/d)					62.8					67.2					(4.4	)
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)				$	35.62				$	67.86				$	(32.24	)
Natural gas liquids (per gallon)				$	0.27				$	0.32				$	(0.05	)
Natural gas (per Mcf)				$	1.70				$	3.80				$	(2.10	)
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)				$	35.79				$	48.42				$	(12.63	)
Natural gas liquids (per gallon)				$	0.27				$	0.32				$	(0.05	)
Natural gas (per Mcf)				$	1.59				$	2.49				$	(0.90	)
Costs per BOE
Oil, natural gas liquids and natural gas production expenses				$	7.93				$	9.98				$	(2.05	)
Production and ad valorem taxes				$	1.96				$	2.67				$	(0.71	)
Depreciation, depletion and amortization				$	20.70				$	23.37				$	(2.67	)
Exploration expense				$	0.15				$	0.97				$	(0.82	)
General and administrative				$	4.65				$	5.81				$	(1.16	)
Capital expenditures				$	217,050				$	678,282				$	(461,232	)

View source version on businesswire.com: http://www.businesswire.com/news/home/20160808006083/en/