Energen (EGN) 8-K Energen’s New Gen 3 Wells Delivering Outstanding Resultsin All Key Areasof Permian Operations

Exhibit 99.1 ENERGEN CORPORATION 605 Richard Arrington Jr. Blvd. N. Birmingham, AL 35203-2707 For Release: 6:00 a.m. ET                                                                                                                        Contacts: Julie S. Ryland Tuesday, August 8, 2017                                                                                                                                                  205.326.8421 ENERGEN’S NEW GEN 3 WELLS DELIVERING OUTSTANDING RESULTSIN ALL KEY AREASOF PERMIAN OPERATIONS 2Q17 Production Beats June Revised Guidance On Continued Strength of Gen 3 Results Per-Unit LOE and SG&A Decrease Substantially in 2Q17 Bolt-on Lease Acquisitions Expanding Footprint, Helping Increase Inventory in Midland and Delaware Basins ****NOTE: 2Q17 conference call slides available at www.energen.com**** BIRMINGHAM, Alabama – Energen Corporation (NYSE: EGN) (“Energen” or the “company”) today announced financial and operating results for the second quarter ended June 30, 2017. FINANCIAL AND OPERATING HIGHLIGHTS 2Q17 •     Production beats June revised guidance by 2% and May guidance by 17% •     On track to generate 29% YOY growth in total production and 37% YOY growth in Midland and Delaware production •     Adjusted EBITDAX grows 49% from 1Q17 and beats internal expectations •     Per-unit LOE (including marketing and transportation) beats June revised guidance midpoint by 8.1% •     Per unit SG&A beats June revised guidance midpoint by 10.4% •     Lease acquisitions in first six months of 2017 total 9,732 net acres for≈$215 mm •     Energen adds 158 net locations to Wolfcamp/Spraberry/Cline inventory and identifies 413 net locations in other Delaware Basin formations for total identified inventory of 4,116 net locations 2Q17 WELL RESULTS •     45 gross and net wells in the Midland and Delaware basins were turned to production in 2Q17 and generated excellent initial production rates in all key areas of operational focus in 2017; 78% are multi-zone pattern wells completed in batches •     59 Gen 3 wells are outperforming the highest EUR type curve and significantly outperforming the midpoint EUR type curve; 76% are multi-zone pattern wells completed in batches •     Public data shows Gen 3 wells in Midland and Delaware basins outperforming other operators’ wells

Comments from the CEO “The success we are achieving with our Generation 3 frac design and multi-zone pattern wells completed in batches has set the stage for 2017 to be the break-out year we have been working toward, underscoring our top-tier assets and solid execution,” said Energen Chief Executive Officer James McManus. “We are delivering outstanding well performance in all our areas of operational focus in the Midland and Delaware basins; and we continue to drive down our operating costs and G&A and are competitive with the best in the Midland and Delaware basins.

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“Importantly, our Gen 3 wells are outperforming wells completed by other operators. The public well data also supports our position that the best way to maximize the full development of our assets is to complete them in multi-zone batches at original reservoir pressure,” McManus said. “We expect our Gen 3 multi-zone pattern wells to continue driving production growth as we move forward.

“We have continued executing on our bolt-on acquisition program, which we believe has created significant value for Energen. Over the last 18 months, we have added approximately 19,000 net acres in prime Delaware and Midland basin locations for an average price of about $17,600 an acre,” McManus said. “This includes some 9,700 net acres acquired in the first six months of this year that helped contribute to an increase in our inventory of identified locations.

“We are pleased with our performance this quarter and excited about our future prospects as we successfully implement our 2017 drilling and development program. We plan to maintain our focus on the further optimization of well performance and returns, and we are confident that Energen is well-positioned to continue delivering strong results and creating shareholder value in 2017 and beyond.”

Operations Update

In the second quarter of 2017, Energen turned to production 27 gross (27 net) wells in the Midland Basin and 18 gross (18 net) wells in the Delaware Basin; 78 percent are multi-zone pattern wells completed in batches. The company operated an average of 6.5 horizontal drilling rigs and an average of 4 frac crews. In the first six months of 2017, Energen turned to production 49 net wells in its 60-net well DUC inventory at year-end 2016.

2017 First Production/Flow back (Horizontal Wells – Gross/Net)

	1Q17a		2Q17a		3Q17e		4Q17e		CY17e
Midland Basin		10/9		27/27		20/19		19/14		76/69
Delaware Basin		2/2		18/18		3/3		12/12		35/35

2Q17 Wells Turned to Production

Area	# of Wells			Average Completed Lateral Length		Avg. Peak 24- Hour IP				Avg. Peak 30-day IP
						Boepd		% Oil		Boepd			% Oil
Delaware Basin		18	Wolfcamp A (8) Wolfcamp B (10)		9,466’		2,338		59		1,889	1		60
Northern Midland Basin		11	MSB (4), Jo Mill (3), LSB (4)		10,531’		1,250		88		1,212	2		85
Northern Midland Basin		8	Wolfcamp A (3) Wolfcamp B (5)		10,510’		1,558		86		1,270	3		81
Central Midland Basin		8	Wolfcamp A (3) Wolfcamp B (5)		7,502’		1,671		79		1,126			66

¹  16 wells with 30-day data

²  4 wells with 30-day data

³ 7 wells with 30-day data

For 59 of the Gen 3 wells drilled to date (76 percent of which were multi-zone pattern wells completed in batches), the average cumulative production uplift of wells in each formation group (normalized to 10,000’) is exceeding the highest EUR type curve – and significantly outperforming the midpoint EUR type curve – identified for wells in that group completed with pre-Gen 3 frac designs. These are key measures of success for Energen’s latest frac design.

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Relative to the midpoint EUR type curve, the average cumulative production uplift of the Gen 3 wells normalized to 10,000’ is:

• ≈31% over a 1.75 MMBOE type curve at 270 days for 20 Delaware Basin Wolfcamp A and B wells – 9 of 20 are multi-zone pattern wells completed in batches

• ≈40% over a 1.2 MMBOE type curve at 90 days for 11 wells in the Spraberry package – all are multi-zone pattern wells completed in batches

• ≈11% over a 1.2 MMBOE type curve at 240 days for 10 northern Midland Basin Wolfcamp A and B wells – 7 of 10 are multi-zone pattern wells completed in batches

• ≈21% over a 1.2 MMBOE type curve at 170 days for 16 central Midland Basin Wolfcamp A and B wells – all are multi-zone pattern wells in batches

• ≈47% over a 850 MBOE type curve at 160 days for 2 central Midland Basin Lower Spraberry wells – both are multi-zone pattern wells completed in batches

In another assessment of success, the average cumulative production of Energen’s Midland Basin Gen 3 multi-zone pattern wells completed in batches is outperforming other operators’ pattern wells; and the average cumulative production of Energen’s Gen 3 wells (pattern and stand-alone) in the Midland and Delaware basins is outperforming other operators’ wells with comparable proppant loads of 1,700-2,500 pounds per foot.

The company attributes this outperformance to completing the wells in multi-zone batches instead of completing them as offset pattern wells. Utilizing simultaneous, multi-zone pattern development allows all wells to be completed at the original reservoir pressure, which should maximize reservoir productivity. In offset pattern well development, the original stand-alone well causes the reservoir pressure to drop and reduces the productivity of all subsequent wells drilled.

Bolt-on Lease Acquisitions Continue, Inventory Grows

In the first six months of 2017, Energen has acquired more than 9,700 net acres for approximately $215 million, or an average price of some $22,000 per acre. These acquisitions helped contribute to the addition of 158 net locations in its Wolfcamp, Spraberry, and Cline inventory (after moving 32 net locations into the drilled category). The company also has identified 413 net locations in other Delaware Basin formations, giving the company a new identified inventory of 4,116 net locations.

The company also has purchased 690 net mineral acres in the Delaware Basin in the first six months of 2017 for approximately $20 million.

Over the last 18 months (CY16 and YTD17), the company’s bolt-on acquisition program has added approximately 19,000 net lease acres in prime Delaware and Midland basin locations for an average price of approximately $17,600 an acre.

2017 Capital Overview

Energen’s estimate of capital spending for drilling and development in 2017 remains unchanged at $850-$900 million.

Capital Summary by Basin	2017e Capital ($MM)
Midland Basin	$	470 - 490
Delaware Basin	$	375 - 405
Central Basin, ARO, Other	$	5
Drilling & Development Capital	$	850 - 900
Acquisitions/Unproved Leasehold	$	235
Total Capital Expenditures	$	1,085 - 1,135

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Liquidity and Leverage Update

As of June 30, 2017, Energen had cash of $0.5 million, long-term debt of $544.7 million, and $131.5 million drawn on its $1.05 billion line of credit, and its borrowing base currently is $1.4 billion. Energen estimates that its year-end 2017 total net debt-to-2017 adjusted EBITDAX will range from 1.3x - 1.4x.

2Q17 Financial Results

For the 3 months ended June 30, 2017, Energen reported GAAP net income from all operations of $29.5 million, or $0.30 per diluted share. Adjusting for a non-cash gain on mark-to-market derivatives and a small, non-cash impairment loss, Energen had adjusted net income in 2Q17 of $5.4 million, or $0.06 per diluted share. This compares with an adjusted loss in 2Q16 of $(27.1 million), or $(0.28) per diluted share.[See “Non-GAAP Financial Measures” beginning on pp 8 for more information and reconciliation.]

Energen’s adjusted 2Q17 net income of $5.4 million exceeded internal expectations by $1.6 million largely due to:

• Less-than-expected lease operating expense (LOE) largely due to lower power and chemical costs;

• Higher production due to continued positive impact of Gen 3 completions;

• Lower salaries and general and administrative expense (SG&A) primarily due to lower non-cash compensation; and

• Decreased production and ad valorem taxes.

Partially offsetting these gains were lower realized sales prices and increased depreciation, depletion, and amortization expense (DD&A) largely due to increased production.

Energen’s adjusted EBITDAX totaled $142.4 million in the 2nd quarter of 2017, increased 49 percent from the first quarter, and exceeded internal expectations by 4 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $82.3 million.[See “Non-GAAP Financial Measures” beginning on pp 8 for more information and reconciliation.]

2Q17 Production (mboepd)

Commodity	2Q17											1Q17
	Actual		June Rev. Guidance		% D		May Guidance		% D
Oil		45.1		44.9		0		40.6		11			33.3
NGL		13.5		12.8		5		10.5		29			8.9
Natural Gas		13.9		13.5		3		11.1		25			10.6
Total		72.5		71.1		2		62.2		17			52.8
Area	2Q17											1Q17
	Actual		June Rev. Guidance		%D		May Guidance		%D
Midland Basin		41.3		40.5		2		34.2		21			31.8
Delaware Basin		23.4		22.9		2		19.8		18			12.8
Central Basin/Other		7.9		7.7		3		8.2		(4	)		8.3
Total		72.5		71.1		2		62.2		17			52.8

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

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2Q17 Expenses

Per BOE, except where noted	2Q17						1Q17
	Actual			June Guidance Midpoint
LOE (production costs, marketing & transportation)	$	6.66		$	7.25		$	8.68
Production & ad valorem taxes (% of revenues exc. hedges)		6.0	%		6.9	%		7.3	%
DD&A	$	18.25		$	18.30		$	20.71
SG&A	$	3.00		$	3.35		$	4.29
Exploration (includes seismic, delay rentals, etc.)	$	0.30		$	0.25		$	0.76
Interest ($mm)	$	9.1		$	9.2		$	9.0

2Q17 Average Realized Prices

Commodity	With Hedges		W/O Hedges
Oil (per barrel)	$	44.58	$	44.54
NGL (per gallon)	$	0.36	$	0.36
Natural Gas (per mcf)	$	2.38	$	2.29

CY17 Guidance

Production (mboepd)

By Basin	1Q17a		2Q17a		3Q17e		4Q17e		CY17e
Midland Basin		31.8		41.3		40.6		42.1		39.0
Delaware Basin		12.8		23.4		26.2		31.9		23.6
Central Basin Platform/Other		8.3		7.9		8.0		7.8		8.0
Total		52.8		72.5		74.8		81.9		70.6
By Commodity	1Q17a		2Q17a		3Q17e		4Q17e		CY17e
Oil		33.3		45.1		47.9		53.4		45.0
NGL		8.9		13.5		12.9		13.7		12.3
Gas		10.6		13.9		13.9		14.7		13.3
Total		52.8		72.5		74.8		81.9		70.6

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

Operating Expenses

Per BOE, except where noted	1Q17a			2Q17a			3Q17e			4Q17e			CY17e
LOE*	$	8.68		$	6.66		$	7.00-$7.30		$	6.85-$7.15		$	7.05-$7.45
Production & ad valorem taxes**		7.3	%		6.0	%		6.4	%		6.3	%		6.5	%
DD&A expense†	$	20.71		$	18.25		$	17.05-$17.45		$	15.25-$15.75		$	17.45-$17.85
SG&A	$	4.29		$	3.00		$	3.10-$3.40		$	2.55-$2.85		$	3.00-$3.40
Exploration††	$	0.76		$	0.30		$	0.10-$0.15		$	0.15-$0.20		$	0.25-$0.35
Interest ($mm)	$	9.0		$	9.1		$	9.5-$10.5		$	10.0-$11.0		$	38.5-$39.5
Effective tax rate		32	%		35	%		37%-39	%		36%-38	%		37%-39	%

* Production costs, marketing & transportation

** % of revenues, excluding hedges

† 4Q17 and CY17 does not include estimate of 4Q17 DD&A look-back adjustment

†† Includes seismic, delay rentals, etc.

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LOE per boe in CY17 is estimated to range from $5.20-$5.50 in the Delaware Basin, $5.85-$6.15 in the Midland Basin, and $18.60-$18.90 in the Central Basin Platform. Production and ad valorem taxes in CY17, as a percent of revenues excluding hedges, are estimated to be 6.3 percent in the Delaware Basin, 6.4 percent in the Midland Basin, and 7.4 percent in the Central Basin Platform. SG&A per boe in CY17 is estimated to be comprised of cash and other of $2.50-$2.70 per boe and non-cash, equity-based compensation of $0.50-$0.70 per boe.

Hedges

For the last six months of 2017, 69 percent of the company’s estimated oil production of 9.3 mmbo is hedged. Swaps for 4.0 mmbo have an average NYMEX price of $50.68 per barrel, and 3-way collars for 2.4 mmbo have average call, put, and short put prices of $62.18, $45.00, and $35.00 per barrel, respectively. Approximately 40 percent of Energen’s estimated NGL production is hedged at an average price of $0.57 per gallon, and 55 percent of its estimated gas production is hedged at an average NYMEX-equivalent price of $3.31 per Mcf. Energen also has hedged the WTI Midland to WTI Cushing (sweet oil) differential for 5.6 million barrels at an average price of $(0.66) per barrel; approximately 87 percent of Energen’s oil production for the remainder of the year is estimated to be sweet.

In 3Q17, approximately 73 percent of the company’s estimated oil production of 4.4 mmbo is hedged. Swaps for 2.0 mmbo have an average NYMEX price of $50.68 per barrel, and 3-way collars for 1.2 mmbo have average call, put, and short put prices of $62.18, $45.00, and $35.00 per barrel, respectively. Approximately 42 percent of Energen’s estimated NGL production is hedged at an average price of $0.57 per gallon, and 57 percent of its estimated gas production is hedged at an average NYMEXe price of $3.30 per Mcf. Energen also has hedged the Midland to Cushing differential for 2.6 million barrels at an average price of $(0.64) per barrel; approximately 68 percent of Energen’s estimated oil production in 3Q17 is estimated to be sweet.

Basis Differentials

Energen’s average realized prices in the last six months of CY17 will reflect commodity and basis hedges, oil transportation charges of approximately $2.00 per barrel, NGL T&F fees of approximately $0.12 per gallon, and basis differentials applicable to unhedged production. Natural gas and NGL production also is subject to a percent of proceeds contract of approximately 85%.

The assumed gas basis for all open contracts for August-December 2017 is $(0.45) per Mcf, and assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (August-December) are $(1.45) and $(1.30), respectively. Energen’s assumed commodity prices for unhedged production are approximately $47.30 per barrel of oil (July-December), $0.60 per gallon of NGL (July-December), and $3.15 per Mcf of gas (August-December).

Estimated Price Realizations (pre-hedge):

	3Q17		ROY 2017
Crude oil (% of NYMEX/WTI)		93		93
NGL (after T&F) (% of NYMEX/WTI)		37		34
Natural gas (% of NYMEX/Henry Hub)		74		74

2018 Hedges

Oil	2018 Hedge Volumes		Avg. NYMEX Price
Three way Collars		13.5 mmbo
Call Price			$	60.04 per barrel
Put Price			$	45.47 per barrel
Short Put Price			$	35.47 per barrel

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Commodity	Hedge Volumes		NYMEXe Price
NGL		105.8 mm gallons	$	0.59 per gallon
Natural Gas		3.6 bcf	$	3.10 per mcf

Energen also has hedged the Midland to Cushing differential on 7.6 million barrels of its estimated 2018 sweet oil production at an average price of $(1.10).

Conference Call

2Q17 slides associated with Energen’s quarterly release and conference call are available atwww.energen.com. Energen will hold its quarterly conference call Tuesday, August 8, at 8:30 a.m. EDT. Investment community members 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 viawww.energen.com.

Energen Corporation is an oil-focused exploration and production company with operations in the Permian Basin in west Texas and New Mexico. For more information, go towww.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. 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.

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