New Energen Wells with Generation 3 Fracs Significantly Outperforming

For the 3 months ended March 31, 2017, Energen Corporation (NYSE: EGN) reported GAAP net income from all operations of $33.4 million, or $0.34 per diluted share. Adjusting for a non-cash gain on mark-to-market derivatives and a small non-cash impairment loss, Energen had an adjusted loss in 1Q17 of $(12.4 million), or $(0.13) per diluted share. This compares with an adjusted loss in 1Q16 of $(53.6 million), or $(0.62) per diluted share. [See “Non-GAAP Financial Measures” beginning on pp 10 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 10 for more information]

				1Q17										1Q16
				$M					$/dil. sh.					$M					$/dil. sh.
Net Income/(Loss) All Operations (GAAP)				$	33,403				$	0.34				$	(203,116	)			$	(2.34	)
Less: Non-cash mark-to-market gains/(losses)					46,692					0.48					(166	)			nm
Less: Asset impairments					(939	)				(0.01	)				(121,420	)				(1.40	)
Less: Pension settlement and other expenses					--					--					(4,801	)				(0.06	)
Less: Income/(loss) associated with asset sales					--					--					(23,132	)				(0.27	)
Adj. Income Continuing Operations (Non-GAAP)				$	(12,350	)			$	(0.13	)			$	(53,597	)			$	(0.62	)

Note: Per share amounts may not sum due to rounding

Energen’s adjusted 1Q17 per-share loss was less than internal expectations by $3.8 million, or $0.04 per diluted share, largely due to above-budget production and lower-than-expected net salaries and general and administrative expense (SG&A), partially offset by increased depreciation, depletion, and amortization expense (DD&A) largely due to increased volumes and to the timing of exploration expense.

Production in 1Q17 totaled 52.8 thousand barrels of oil equivalents per day (mboepd) and exceeded guidance of 50.2 mboepd by 5.2 percent mainly due to the impact of new wells completed with Generation 3 fracs. Total oil production was up 6 percent over guidance largely due to stronger-than-expected oil volumes in the Delaware Basin. Net SG&A expenses were lower due to a variety of cost reductions, including non-cash compensation and legal services.

Energen’s adjusted EBITDAX totaled $95.6 million in the 1st quarter of 2017 and exceeded internal expectations by approximately 15 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $44.0 million. [See “Non-GAAP Financial Measures” beginning on pp 10 for more information and reconciliation.]

Comments from the Chairman

“We are very encouraged by the performance of the wells we have completed with our Generation 3 frac design,” said James McManus, Energen’s chairman and chief executive officer. “For those Gen 3 wells with at least 75 days of production history, cumulative production by formation is outperforming the type curves associated with the highest potential EURs we have identified.

“Since our ranges of EUR outcomes are based on the performance of pre-Gen 3 wells, one of our major goals for Gen 3 fracs is to achieve well results that meet or surpass the high end of these ranges. We are very excited to see that early results are doing just that.”

1^st Quarter 2017 Results

Production (excludes asset sales) (mboepd)

Commodity				1Q17										1Q16
				Actual			Guidance			% Change
Oil				33.3			31.4			6				33.6
NGL				8.9			9.1			(2	)			8.3
Natural Gas				10.6			9.7			10				10.4
Total				52.8			50.2			5				52.3

Area				1Q17									1Q16
				Actual			Guidance			% Change
Midland Basin				31.8			30.6			4			33.0
Delaware Basin				12.8			11.3			13			10.3
Central Basin/Other				8.3			8.3			--			9.0
Total				52.8			50.2			5			52.3

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



Average Realized Sales Prices (excludes asset sales)

Commodity				1Q17				1Q16				% Change
Oil (per barrel)				$	46.95			$	32.34			45
NGL (per gallon)				$	0.42			$	0.22			91
Natural Gas (per mcf)				$	2.39			$	1.66			44

Average Prices before Effects of Hedges (excludes asset sales)

Commodity				1Q17				1Q16				% Change
Oil (per barrel)				$	48.96			$	30.67			60
NGL (per gallon)				$	0.46			$	0.22			109
Natural Gas (per mcf)				$	2.46			$	1.55			59

Expenses (excludes asset sales)

Per BOE, except where noted				1Q17										1Q16
				Actual					Guidance Mdpt.
LOE*				$	8.68				$	9.25				$	8.43
Production & ad valorem taxes**					7.3	%				7.5	%				8.8	%
DD&A				$	20.71				$	20.95				$	23.15
Net SG&A†				$	4.29				$	5.10				$	4.52
Exploration††				$	0.76				$	0.35				$	0.03
Interest ($mm)				$	9.0				$	$8.9				$	9.8

* Production costs, marketing & transportation
** % of revenues, excluding hedges
† Excludes $1.56 per BOE in 1Q16 for pension settlement and other expenses
†† Includes seismic, delay rentals, etc.

Operations Update

During the first quarter, Energen turned to production 10 gross (9 net) wells drilled in Glasscock County in the central Midland Basin and 2 gross (2 net) wells in the Delaware Basin. All 12 of these wells were part of Energen’s DUC inventory at YE16. The company set casing on 19 gross (17 net) wells in the first quarter. The company operated an average of 6.5 horizontal drilling rigs in the first quarter and an average of 6 frac crews.

Drilling efficiencies continued in the first quarter, with two new “internal best times” for days to drill from spud to total depth. In only 15 days, Energen drilled a 9,856-foot lateral Wolfcamp B well in the northern Midland Basin; and in just under 15 days, the company drilled a 10,733-foot lateral Middle Spraberry well.

Positive Response to Early Generation 3 Completions

For those Gen 3 wells with at least 75 days of production history, the average cumulative production by formation outperformed the type curves associated with the highest potential EURs identified by the company. Because the ranges of EURs are based on the performance of pre-Gen 3 wells, the company hopes to achieve Gen 3 well results that meet or surpass the high end of these ranges.

Energen’s first two Midland Basin wells utilizing a Generation 3 frac design (the “Tiger Unit” wells) -- continued to respond very well. The average cumulative production of the two Wolfcamp B, stand-alone wells in Martin County exceeded the 1 mmboe type curve for a 7,500-lateral by an average of approximately 20 percent through 165 days. Oil comprised 82 percent of the product mix.

At 75 days of production, five new Glasscock County completions were approximately 15 percent above the 1.3 mmboe EUR type curve for a 10,000’ lateral. Oil comprised 77 percent of the product mix. The company considers this a particularly attractive result since four of the wells are producing from the Wolfcamp B; the fifth well is producing from the Wolfcamp A. The five wells had an average 24-hour IP of 1,684 boepd (74% oil) and peak 30-day average of 1,465 boepd (74% oil); their average completed lateral length was 9,541’.

Cumulative production from the Checkers St. 54-12-21 701H well in the Delaware Basin continued to outperform the 2.0 mmboe EUR type curve for a 10,000’ lateral length by 6 percent through 195 days. The Checkers St. well is producing from the Wolfcamp B interval in Reeves County. Oil comprised 55 percent of the product mix.

The two Delaware Basin wells placed on production in the first quarter were 4,600 foot laterals; normalized to 10,000 feet, these two wells averaged 80 percent above the 2.0 mmboe EUR type curve for a 10,000’ lateral through 80 days. Oil comprised 61 percent of the product mix. The two Delaware Basin wells had an average 24-hour IP of 2,033 boepd (62% oil) and peak 30-day average of 1,825 boepd (60% oil); their average completed lateral length was 4,654’.

2017 Capital and Operating Overview

Energen estimates that it will invest an additional $60-$65 million in 2017 for 4 more gross completions and to participate in an additional 2.8 net non-operated wells, for increased working interests, and for facilities. Since the end of 1Q17, Energen has seen rising pressure on the costs of a wide variety of completion services; without off-setting efficiencies or other savings, the company estimates that it could see capital spending for drilling and development increase another $45-$50 million.

The company’s revised capital budget of $850-$900 million for drilling and development activities supports completion of 128 gross/118 net operated wells, including 124 gross/115 net horizontal wells. All horizontal wells are scheduled to be completed with a Generation 3 frac design.

Horizontal completions include 61 gross/60 net wells drilled but not completed (DUC) at year-end 2016 and 63 gross/55 net horizontal wells that are scheduled to be drilled and completed in 2017 with the company’s 6- to 7-rig drilling program. Another 24 gross/22 net horizontal wells are set to be drilled and awaiting completion at year end. Energen also plans to drill 7 gross/6 net vertical wells in the Midland Basin and complete 4 gross/3 net of them.

Energen’s non-operated opportunities have increased, and the company has agreed to participate in a total of 4 net wells. Such opportunities are difficult to predict and, therefore, are not budgeted until the company has visibility on an operator’s plans.

2017 Operated Horizontal Program				Gross/Net Wells			Avg. Lateral Length			Average WI
Midland Basin
YE16 DUC Completions				44/43			9,600’			98%
New Drills				54/46			8,330’			84%
New Drill Completions				39/32
YE17 DUCs				15/14
Delaware Basin
YE16 DUC Completions				17/17			8,765’			98%
New Drills				33/31			8,410’			95%
New Drill Completions				24/23
YE17 DUCs				9/8

Note: In addition to the above, Energen plans to drill 7 gross/6 net vertical wells in the Midland Basin and complete 4 gross/3 net of them.

Acquisitions/Unproved Leasehold

In the first four months of 2017, Energen acquired a total of 6,923 net lease acres, primarily in the Delaware Basin, for approximately $147 million; the company also has purchased 690 net mineral acres in the Delaware Basin for approximately $20 million. The company does not budget for acquisitions.

Capital Summary by Basin				2017e Capital ($MM)
Midland Basin				$	470 - 500
Delaware Basin				$	375 - 395
Central Basin, ARO, Other				$	5
Drilling & Development Capital				$	850 - 900
Acquisitions/Unproved Leasehold				$	167
Total Capital Expenditures				$	1,017 - 1,067

Liquidity Update

As of March 31, 2017, Energen had cash of $88.7 million and debt of $544.6 million; the company had nothing drawn on its $1.05 billion line of credit, and its borrowing base currently is $1.4 billion. Energen estimates that its total net debt-to-2017 adjusted EBITDAX will range from 1.2x - 1.3x.

CY17 Guidance

Production (mboepd)

Guidance by Basin			1Q17a			2Q17e			3Q17e			4Q17e			CY17e
Midland Basin			31.8			34.2			38.6			42.3			36.8
Delaware Basin			12.8			19.8			24.6			28.4			21.4
Central Basin Platform/Other			8.3			8.2			8.1			7.9			8.1
Total			52.8			62.2			71.3			78.6			66.3

Guidance by Commodity			1Q17a			2Q17e			3Q17e			4Q17e			CY17e
Oil			33.3			40.6			46.6			52.1			43.2
NGL			8.9			10.5			11.9			12.8			11.0
Gas			10.6			11.1			12.8			13.7			12.1
Total			52.8			62.2			71.3			78.6			66.3

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

Estimated 2017 production of 66.3 mboepd reflects a 1 percent increase over prior guidance as a result of 1Q17 actual results. Production guidance for the remainder of the year is unchanged and reflects estimated production with Generation 2 fracs. Given that all wells completed in 2017 will use the Generation 3 frac design, if the associated production response continues to be positive, year-over-year production growth could be higher than the current estimate of 21 percent. Oil is expected to comprise 65 percent of the company’s total production mix in 2017, with natural gas liquids (NGL) and natural gas production estimated to make up 17 percent and 18 percent, respectively.

Operating Expenses

Per BOE, except where noted				1Q17a			2Q17e			3Q17e			4Q17e			CY17e
LOE*				$8.68			$8.10-$8.40			$7.35-$7.65			$6.90-$7.20			$7.60-$8.00
Production & ad valorem taxes**				7.3%			6.9%			6.6%			6.5%			6.8%
DD&A expense†				$20.71			$17.95-$18.35			$17.20-$17.60			$15.50-$15.90			$17.50-$17.90
SG&A, net				$4.29			$3.70-$4.00			$3.10-$3.40			$2.70-$3.00			$3.25-$3.65
Exploration††				$0.76			$0.20-$0.30			$0.30-$0.40			$0.05-$0.15			$0.30-$0.40
Interest ($mm)				$9.0			$9.0-$9.4			$9.3-$9.7			$9.5-$9.9			$37.0-$38.0
Effective tax rate				32%			37%-39%			36%-38%			35%-37%			36%-38%

* 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.

LOE per boe in CY17 is estimated to range $5.65-$5.95 in the Delaware Basin, $6.25-$6.55 in the Midland Basin, and $19.50-$19.80 in the Central Basin Platform. Production and ad valorem taxes in CY17, as a percent of revenues excluding hedges, are estimated to be 6.1 percent in the Delaware Basin, 6.9 percent in the Midland Basin, and 7.8 percent in the Central Basin Platform.

Net SG&A per boe in CY17 is estimated to be comprised of cash compensation of $2.60-$2.80 per boe and non-cash, equity-based compensation of $0.65-$0.85 per boe.

Hedges

For the remaining 9 months of 2017, approximately 68 percent of the company’s estimated oil production of 12.8 MMBOE is hedged as well as 46 percent of its estimated NGL production and 59 percent of its natural gas production. Hedges also are in place that limit the company’s exposure to the Midland to Cushing oil differential. Energen has hedged the WTI Midland to WTI Cushing (sweet oil) differential for 7.6 million barrels at an average price of $(0.64) per barrel. Energen estimates that approximately 86 percent of its oil production for the remainder of the year will be sweet.

Energen’s total oil hedge position for the remainder of 2017 is as follows:

Oil			2017 Hedge Volumes			Avg. NYMEX Price
Swaps			5.0 mmbo			$ 50.13 per barrel
Three way Collars¹			3.6 mmbo
Call Price						$ 62.18 per barrel
Put Price						$ 45.00 per barrel
Short Put Price						$ 35.00 per barrel

¹ 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’s total natural gas and NGL hedge positions for the remainder of 2017 are as follows:

Commodity

Hedge Volumes

Production Guidance

% Hedged

Avg. NYMEXe Price

NGL

62.4 mm gallons

135.6 mm gallons

46%

$ 0.57 per gallon

Natural gas

12.3 bcf

20.7 bcf

59%

$ 3.28 per Mcf

Note: Includes known actuals

2Q17 Hedges

Energen’s total oil hedge position for 2Q17 is as follows:

Oil			2Q17 Hedge Volumes			Avg. NYMEX Price
Swaps			1.0 mmbo			$ 47.97 per barrel
Three way Collars			1.2 mmbo
Call Price						$ 62.18 per barrel
Put Price						$ 45.00 per barrel
Short Put Price						$ 35.00 per barrel

Energen’s total natural gas and NGL hedge positions for 2Q17 as follows:

Commodity

Hedge Volumes

Production Guidance

Hedge %

NYMEXe Price

NGL

20.8 mm gallons

40.0 mm gallons

52%

$ 0.57 per gallon

Natural Gas

3.6 bcf

6.1 bcf

59%

$ 3.31 per mcf

Note: Includes known actuals

Energen also has hedged the Midland to Cushing differential on 2.0 million barrels (approximately 66 percent) of its estimated 2Q17 sweet oil production at an average price of $(0.58).

Basis Differentials and Sensitivities

The company’s average realized prices will reflect commodity and basis hedges; oil transportation charges of approximately $2.00 per barrel in the last nine months of CY17 ($2.03 per barrel in 2Q17), NGL transportation and fractionation fees of approximately $0.13 per gallon for the remainder of the year ($0.13 per gallon in 2Q17), and 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%.

The assumed gas basis for all open contracts for the remainder of 2017 is $(0.40) per Mcf, and assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil are $(1.30) and $(1.85), respectively. Energen’s assumed commodity prices for unhedged production for the last nine months of 2017 are: $52.00 per barrel of oil, $0.60 per gallon of NGL, and $3.30 per Mcf of gas (May-December).

Estimated Price Realizations (pre-hedge):

			2Q17			ROY 2017
Crude oil (% of NYMEX/WTI)			93			93
NGL (after T&F) (% of NYMEX/WTI)			32			33
Natural gas (% of NYMEX/Henry Hub)			74			76

2018 Hedges

Energen’s total oil hedge position for 2018 is as follows:

Oil			2018 Hedge Volumes			Avg. NYMEX Price
Three way Collars			7.4 mmbo
Call Price						$ 63.85 per barrel
Put Price						$ 50.00 per barrel
Short Put Price						$ 40.00 per barrel

Energen’s total natural gas and NGL hedge positions for 2018 as follows:

Commodity			Hedge Volumes			NYMEXe Price
NGL			105.8 mm gallons			$ 0.59 per gallon
Natural Gas			3.6 bcf			$ 3.06 per mcf

Supplemental Slides and Conference Call

1Q17 supplemental slides associated with Energen’s quarterly release and conference call are available at www.energen.com. Energen will hold its quarterly conference call Friday, May 5, at 11:00 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 via www.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 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. 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, certain prior period pension settlement expenses and losses associated with a reduction in force, and income associated with divestitures. 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 3/31/17
Energen Net Income ($ in millions except per share data)			Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)			33.4			0.34
Non-cash mark-to-market gains (net of $25.7 tax)			(46.7	)		(0.48	)
Asset impairment, other (net of $0.5 tax)			0.9			0.01
Adjusted Income from Continuing Operations (Non-GAAP)			(12.4	)		(0.13	)
			Three Months Ended 3/31/16
Energen Net Income ($ in millions except per share data)			Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)			(203.1	)		(2.34	)
Non-cash mark-to-market losses (net of $0.1 tax)			0.2			nm
Asset impairment, other (net of $67.2 tax)			121.4			1.40
Pension settlement and other expenses (net of $2.6 tax)			4.8			0.06
Loss associated with property sales (net of $13.1 tax)			23.1			0.27
Adjusted Income from Continuing Operations (Non-GAAP)			(53.6	)		(0.62	)
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 impairment losses, certain non-cash mark-to-market derivative financial instruments,  prior period pension settlement expenses and losses associated with a reduction in force, and losses associated with  divestitures.  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 3/31
($ in millions)			2017			2016
Energen Net Income (Loss) (GAAP)			33.4			(203.1	)
Loss associated with property sales, net of tax			0.0			23.1
Net Income (Loss) Excluding Property Sales (Non-GAAP)			33.4			(180.0	)
Interest expense			9.0			9.8
Income tax expense (benefit) *			19.4			(95.3	)
Depreciation, depletion and amortization *			99.7			111.5
Accretion expense *			1.4			1.5
Exploration expense *			3.6			0.2
Adjustment for asset impairment *			1.5			188.6
Adjustment for mark-to-market (gains)/ losses			(72.4	)		0.3
Adjustment for pension settlement and other expenses			0.0			7.4
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)			95.6			44.0
Note: Amounts may not sum due to rounding
* Amount adjusted to exclude property sales in prior period. See reconciliation to GAAP Information for the Three Months Ended 3/31/16.

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 divestitures 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 Property Sales
Reconciliation to GAAP Information
			Three Months Ended
			March 31, 2016
(in thousands except per share and production data)
			GAAP				$/BOE			Property Sales				Non-GAAP				$/BOE
Revenues
Oil, natural gas liquids and natural gas sales			$	122,764						$	13,178			$	109,586
Gain (loss) on derivative instruments				5,455							-				5,455
Total Revenues				128,219							13,178				115,041
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production				47,727			$	8.55			7,613				40,114			$	8.43
Production and ad valorem taxes				11,170			$	2.00			1,523				9,647			$	2.03
O&G Depreciation, depletion and amortization				118,020			$	21.15			7,783				110,237			$	23.15
FF&E Depreciation, depletion and amortization				1,342			$	0.24			82				1,260			$	0.26
Asset impairment				220,025							31,407				188,618
Exploration				242			$	0.04			79				163			$	0.03
General and administrative †				29,525			$	5.29			565				28,960			$	6.08
Accretion of discount on asset retirement obligations				1,757							252				1,505
(Gain) loss on sale of assets and other				222							143				79
Total costs and expenses				430,030							49,447				380,583
Operating Income (Loss)				(301,811	)						(36,269	)			(265,542	)
Other Income/(Expense)
Interest expense				(9,833	)						-				(9,833	)
Other income				95							38				57
Total other expense				(9,738	)						38				(9,776	)
Loss Before Income Taxes				(311,549	)						(36,231	)			(275,318	)
Income tax expense (benefit)				(108,433	)						(13,099	)			(95,334	)
Net Income (Loss)			$	(203,116	)					$	(23,132	)		$	(179,984	)
Diluted Earnings Per Average Common Share			$	(2.34	)					$	-			$	(2.34	)
Basic earning Per Average Common Share			$	(2.34	)					$	-			$	(2.34	)
Oil				3,386							328				3,058
NGL				953							197				756
Natural Gas				1,241							294				947
Total Production (mboe)				5,580							819				4,761
Total Production (boepd)				61,319							9,000				52,319
Note: Amounts may not sum due to rounding
† General and administrative includes $7,443 or $1.56 per BOE of pension settlement expense and expense related to a reduction in force.

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) For the 3 months ending March 31, 2017 and 2016
				1st Quarter
(in thousands, except per share data)				2017					2016					Change
Revenues
Oil, natural gas liquids and natural gas sales				$	176,375				$	122,764				$	53,611
Gain on derivative instruments, net					64,546					5,455					59,091
Total revenues					240,921					128,219					112,702
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production					41,288					47,727					(6,439	)
Production and ad valorem taxes					12,820					11,170					1,650
Depreciation, depletion and amortization					99,652					119,362					(19,710	)
Asset impairment					1,460					220,025					(218,565	)
Exploration					3,636					242					3,394
General and administrative (including non-cash stock based compensation of $3,197 and $2,471 for the three months ended March 31, 2017, and 2016, respectively)					20,399					29,525					(9,126	)
Accretion of discount on asset retirement obligations					1,414					1,757					(343	)
(Gain) loss on sale of assets and other					(1,175	)				222					(1,397	)
Total operating costs and expenses					179,494					430,030					(250,536	)
Operating Income (Loss)					61,427					(301,811	)				363,238
Other Income (Expense)
Interest expense					(8,966	)				(9,833	)				867
Other income					383					95					288
Total other expense					(8,583	)				(9,738	)				1,155
Income (Loss) Before Income Taxes					52,844					(311,549	)				364,393
Income tax expense (benefit)					19,441					(108,433	)				127,874
Net Income (Loss)				$	33,403				$	(203,116	)			$	236,519
Diluted Earnings Per Average Common Share				$	0.34				$	(2.34	)			$	2.68
Basic Earnings Per Average Common Share				$	0.34				$	(2.34	)			$	2.68
Diluted Average Common Shares Outstanding					97,607					86,632					10,975
Basic Average Common Shares Outstanding					97,140					86,632					10,508

CONSOLIDATED BALANCE SHEETS (UNAUDITED) As of March 31, 2017 and December 31, 2016
(in thousands)				March 31, 2017				December 31, 2016
ASSETS
Current Assets
Cash and cash equivalents				$	88,658			$	386,093
Accounts receivable, net					90,100				73,322
Inventories, net					15,365				14,222
Derivative instruments					7,594				50
Income tax receivable					26,246				27,153
Prepayments and other					5,024				5,071
Total current assets					232,987				505,911
Property, Plant and Equipment
Oil and natural gas properties, net					4,298,911				4,016,683
Other property and equipment, net					45,606				44,869
Total property, plant and equipment, net					4,344,517				4,061,552
Other postretirement assets					3,607				3,619
Noncurrent derivative instruments					9,293				−
Other assets					8,311				8,741
TOTAL ASSETS				$	4,598,715			$	4,579,823
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year					17,000				24,000
Accounts payable					79,644				65,031
Accrued taxes					10,153				7,252
Accrued wages and benefits					14,047				25,089
Accrued capital costs					120,825				79,988
Revenue and royalty payable					44,314				51,217
Derivative instruments					8,324				65,467
Other					14,368				20,160
Total current liabilities					308,675				338,204
Long-term debt					527,557				527,443
Asset retirement obligations					83,256				81,544
Deferred income taxes					516,295				495,888
Noncurrent derivative instruments					−				3,006
Other long-term liabilities					8,381				13,136
Total liabilities					1,444,164				1,459,221
Total Shareholders’ Equity					3,154,551				3,120,602
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY				$	4,598,715			$	4,579,823

SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 3 months ending March 31, 2017 and 2016
				1st Quarter
(in thousands, except sales price and per unit data)				2017					2016					Change
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil				$	146,670				$	102,157				$	44,513
Natural gas liquids					15,634					8,589					7,045
Natural gas					14,071					12,018					2,053
Total				$	176,375				$	122,764				$	53,611
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil				$	58,058				$	(1,699	)			$	59,757
Natural gas liquids					7,087					−					7,087
Natural gas					7,224					1,442					5,782
Total				$	72,369				$	(257	)			$	72,626
Closed gains (losses) on derivative instruments
Oil				$	(6,010	)			$	5,094				$	(11,104	)
Natural gas liquids					(1,465	)				−					(1,465	)
Natural gas					(348	)				618					(966	)
Total				$	(7,823	)			$	5,712				$	(13,535	)
Total revenues				$	240,921				$	128,219				$	112,702
Production volumes
Oil (MBbl)					2,996					3,386					(390	)
Natural gas liquids (MMgal)					33.7					40.0					(6.3	)
Natural gas (MMcf)					5,730					7,446					(1,716	)
Total production volumes (MBOE)					4,754					5,580					(826	)
Average daily production volumes Oil (MBbl/d)					33.3					37.2					(3.9	)
Natural gas liquids (MMgal/d)					0.4					0.4					−
Natural gas (MMcf/d)					63.7					81.8					(18.1	)
Total average daily production volumes (MBOE/d)					52.8					61.3					(8.5	)
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)				$	46.95				$	31.67				$	15.28
Natural gas liquids (per gallon)				$	0.42				$	0.21				$	0.21
Natural gas (per Mcf)				$	2.39				$	1.70				$	0.69
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)				$	48.96				$	30.17				$	18.79
Natural gas liquids (per gallon)				$	0.46				$	0.21				$	0.25
Natural gas (per Mcf)				$	2.46				$	1.61				$	0.85
Costs per BOE
Oil, natural gas liquids and natural gas production expenses				$	8.68				$	8.56				$	0.12
Production and ad valorem taxes				$	2.70				$	2.00				$	0.70
Depreciation, depletion and amortization				$	20.96				$	21.39				$	(0.43	)
Exploration expense				$	0.76				$	0.04				$	0.72
General and administrative				$	4.29				$	5.29				$	(1.0	)
Capital expenditures (includes acquisitions)				$	384,135				$	124,088				$	260,047

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