Energen Production in 2Q18 Exceeds Guidance Midpoint by 7%

Energen Corporation (NYSE: EGN) (“Energen” or the “company”) today announced financial and operating results for the second quarter ended June 30, 2018.

HIGHLIGHTS:

OUTPERFORMANCE BY GEN 3-COMPLETED WELLS CONTINUES DRIVING GROWTH

• 2Q18 production of 97.4 mboepd beats guidance midpoint by 7% and top end of guidance range by 3%
• 2Q18 production increases ≈5 % from 1Q18
• Oil production in 2Q18 of 56.7 mbopd surpasses guidance midpoint by 7%
• Continued well outperformance drives 5% increase in CY18 production guidance midpoint; new guidance range is 97.0-104.0 mboepd
• CY18 production now estimated to increase 32% YoY (at guidance midpoint)
• 3Q18 and 4Q18 production guidance midpoints increased approximately 6.5% and 4%, respectively
• 4Q17 to 4Q18 exit rate now estimated to increase 14% (at guidance midpoint)
• 2Q18 per-unit net SG&A expense of $2.47 per boe beats guidance midpoint by 8.5%
• Per-unit net SG&A expense in 2018 estimated to further improve to $2.40 per boe at guidance midpoint, reflecting a 21% year-over-year decline
• 2Q18 adjusted EBITDAX totals $244.8 million, exceeding internal expectations by ≈11%
• 66% of estimated oil production and 58% of estimated oil basis differential (at guidance midpoint) hedged for ROY
• Differential hedges of 18.1 mmbo in place in 2019 at average price of $(5.13)/barrel; differential hedging initiated in 2020 for 15.1 mmbo at average price of $(1.20)/barrel
• Bolt-on acquisitions in 2Q18 add ≈670 net leasehold acres for ≈$9.5 million
• Ten new Gen 3 Wolfcamp wells in Delaware Basin deliver average peak 24-hour IP rates of >300 boepd/1,000’
• Eight Howard County Wolfcamp A wells highlight Midland Basin results with average peak 24-hour IP rates of 283 boepd/1,000’ and 90% oil

Comments from the CEO

“In the second quarter of 2018, Energen continued to build on its track record of execution, growth, and financial strength,” said James McManus, Energen’s chairman and chief executive officer. “Wells completed with our Generation 3 frac design drove a 7 percent production beat to our guidance midpoint; and with three more months of outperformance and solid execution in hand, we are very pleased to be raising our estimated production targets for the remainder of 2018.

“At the midpoint of our new guidance range for 2018, Energen will reach a milestone by producing more than 100,000 boe per day for the first time in company history,” McManus added. “Our hedge program helps mitigate the negative impact of a temporary widening of basis differentials, and we have solid arrangements in place to provide flow assurance for our oil and gas production. These factors, together with the rigs and services we need in place, will allow us to continue focusing on execution as we implement our robust drilling and development plans.

“In short, we are extremely pleased with our performance in the quarter and confident that Energen is well-positioned to continue delivering strong results and creating shareholder value,” McManus said.

2Q18 Operations Update

Outstanding well performance led to 2Q18 production of 97.4 mboepd, which was 7 percent higher than the guidance midpoint of 91.0 mboepd and 5 percent higher than 1Q18 production. Oil production in 2Q18 also outpaced the guidance midpoint by 7 percent. Energen placed on production 11 gross (10 net) wells in the Midland Basin and 10 gross (9 net) wells in the Delaware Basin.

2Q18 Production (mboepd)
Commodity					2Q18 Actual			2Q18 Guidance Midpoint			% ∆			2Q18 Actual			1Q18 Actual			% ∆
Oil					56.7			53.0			7.0			56.7			55.4			2.3
NGL					20.4			18.0			13.3			20.4			18.2			12.1
Natural Gas					20.3			20.0			1.5			20.3			19.3			5.2
Total					97.4			91.0			7.0			97.4			92.9			4.8

2Q18 Wells Turned to Production
Area			# Wells						Avg. Completed Lateral Length			Avg. Peak 24-Hr IP										Avg. Peak 30-Day IP
												Boepd			Boepd/ 1,000’			% Oil				Boepd				Boepd/ 1,000’				% Oil
Delaware Basin			10			Wolfcamp A (5) Wolfcamp B (4) Wolfcamp BC (1)			7,420’			2,323			313			57	%			1,769				238				54	%
N. Midland Basin			8			Wolfcamp A			7,363’			2,083			283			90	%			1,577	1			214	1			87	%1
N. Midland Basin			1			Lower Spraberry2			9,572’			1,425			149			87	%			1,204				126				82	%
N. Midland Basin			1			Jo Mill2,3			9,272’			950			102			92	%			529				57				88	%

¹ Peak 30-day data shown for 7 wells with sufficient production history
² Placed on production in 1Q18 but data not previously disclosed due to insufficient production history
³ Performance impacted by mechanical issue

Note: Table excludes three 2Q18 Midland Basin wells for which there is insufficient production history

Of the wells placed on production in 2Q18, 43 percent are multi-zone pattern wells completed in batches at original reservoir pressure. During 2Q18 Energen utilized 10 horizontal drilling rigs and 4 frac crews. The company currently is running 10 drilling rigs and 5 frac crews.

Among the operating highlights in the quarter was a 9,542’ lateral Wolfcamp A well in the Delaware Basin that was drilled in a record 22.75 days (spud to total depth). The company also drilled its longest lateral length well to date in the Midland Basin at 11,178’. In addition, drilling and completion down time continued to decline.

2Q18 Financial Results

For the 3 months ended June 30, 2018, Energen reported GAAP net income from all operations of $68.3 million, or $0.70 per diluted share. Adjusting for non-cash items, including a $7.7 million loss on mark-to-market derivatives and a $0.6 million gain associated primarily with a property swap, Energen had adjusted income in 2Q18 of $75.4 million, or $0.77 per diluted share. This compares with adjusted income in 2Q17 of $5.4 million, or $0.06 per diluted share. [See “Non-GAAP Financial Measures” beginning on p. 9 for more information and reconciliation.]

Energen’s adjusted 2Q18 earnings exceeded internal expectations by $0.13 per diluted share primarily due to substantially higher production and greater-than-expected commodity prices partially offset by increased depreciation, depletion and amortization (DD&A) expense and higher-than-expected ad valorem and production taxes. The company’s adjusted EBITDAX totaled $244.8 million in 2Q18, exceeding internal expectations by approximately 11 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $142.4 million. [See “Non-GAAP Financial Measures” beginning on p. 9 for more information and reconciliation.]

Drilling and development capital investment in 2Q18 totaled $318 million and was within the company’s guidance range of $300-$330 million. Energen also invested approximately $9.5 million for 670 net acres of unproved leasehold, primarily in the Delaware Basin. Including lease renewals, FF&E, and miscellaneous, total capital spending in 2Q18 totaled $334.4 million.

2Q18 Expenses
Per BOE, except where noted					2Q18
					Actual				Guidance Midpoint				% ∆
LOE (production costs, marketing & transportation)					$	6.54			$	6.90			(5	)
Production & ad valorem taxes (% of revenues excl. hedges)						6.7				6.2			8
DD&A					$	15.00			$	15.00			‒
SG&A					$	2.47			$	2.70			(9	)
Exploration (incudes seismic, delay rentals, etc.)					$	0.13			$	0.18			(28	)
Effective tax rate (%)						22				23 23			(4	)

2Q18 Average Realized Prices
Commodity				With Hedges				W/O Hedges
Oil (per barrel)				$	57.91			$	61.21
NGL (per gallon)				$	0.46			$	0.54
Natural Gas (per mcf)				$	1.32			$	1.21

Liquidity and Leverage Update

As of June 30, 2018, Energen had cash of $1.2 million, long-term debt of $528.0 million, and line of credit borrowings of $301.0 million. The company estimates that its total net debt-to-adjusted EBITDAX at year end will be approximately 1.1x.

2018 Overview

Estimated total capital spending for drilling and development activities in 2018 remains unchanged from prior guidance at $1.1 billion to $1.3 billion. The company noted, however, that higher potential costs associated with ancillary services and steel tariffs as well as additional non-operated activity likely will lead to capital investment near the high end of the range.

The company expects to drill approximately 122 gross/112 net operated horizontal wells in 2018 and complete approximately 123 gross/114 net horizontal wells, including 30 gross/28 net year-end 2017 drilled but uncompleted wells (DUCs). The average lateral length of wells scheduled for completion in 2018 (including known completed lateral lengths) is approximately 8,000’; and the working interest of completed wells in 2018 has increased to approximately 93 percent.

The company estimates its YE18 DUCs will total approximately 29 gross/26 net wells. Energen also plans to drill and complete 4 gross/3 net vertical wells in the Midland Basin.

2018 Production Guidance

Energen today substantially raised its guidance ranges for CY18 to reflect the impact of 2Q18 actual results and the expectation that Gen 3 well outperformance will continue. CY18 production is now estimated to range from 97.0-104.0 mboepd, for a 5 percent increase over the midpoint of prior guidance. Oil production guidance at midpoint in 2018 increased 4 percent over prior guidance. Given higher expected production in 2018, year-over-year production growth from CY17 is now estimated to be 32% (at guidance midpoint).

Energen raised its estimates for 3Q18 and 4Q18 production today by approximately 6.5 percent and 4 percent, respectively, at the midpoint of each quarter’s range. With 4Q18 production of 111.5 mboepd at the guidance midpoint, Energen now estimates that its 4Q17-to-4Q18 exit rate will reflect an increase of 14 percent.

2018 Production by Quarter
					1Q18a			2Q18a			3Q18e			4Q18e			CY18e
Oil					55.4			56.7			57.5 - 60.5			67.5 - 70.5			58.5 - 61.5
NGL					18.2			20.4			18.0 - 20.0			19.5 - 21.5			18.5 - 20.5
Gas					19.3			20.3			20.0 - 22.0			21.0 - 23.0			20.0 - 22.0
Total					92.9			97.4			95.5 - 102.5			108.0 - 115.0			97.0 - 104.0

2018 First Production/Flow back (Operated Horizontal Wells – Gross/Net)

1Q18a

2Q18a

3Q18e

4Q18e

CY18e

Midland Basin

15/13

11/10

28/24

11/10

65/58

Delaware Basin

10/10

10/9

14/13

19/19

53/51

CY18 Operating Expenses
Per BOE, except where noted					1Q18a				2Q18a				3Q18e				4Q18e				CY18e
LOE					$	6.30			$	6.54			$	6.60 - $6.80			$	6.10 - $6.30			$	6.30 - $6.50
Prod. & ad valorem taxes*						6.3				6.7				6.6				6.6				6.6
DD&A expense					$	14.72			$	15.00			$	13.95 - $14.45			$	13.35 - $13.85			$	14.10 - $14.60
SG&A, net					$	2.66			$	2.47			$	2.30 - $2.70			$	1.90 - $2.30			$	2.20 - $2.60
Exploration expense					$	0.14			$	0.13			$	0.15 - $0.20			$	0.15 - $0.20			$	0.15 - $0.20
Effective tax rate (%)						23				22				22 - 24				21 - 23				22 - 24
* % of revenues, excluding hedges

LOE per boe in CY18 is estimated to range from $5.20-$5.40 in the Midland and Delaware basins and $20.60-$20.80 in the Central Basin Platform/Northeast Shelf areas. Net SG&A per boe in CY18 is estimated to be comprised of cash of $1.80-$2.00 per boe and non-cash, equity-based compensation of $0.40-$0.60 per boe.

Hedges

Since disclosing prior-quarter earnings in early May, Energen has continued to strengthen its 2018 and 2019 financial derivatives position by adding commodity and differential hedges to help mitigate the negative impacts of price volatility on its oil and gas revenues. In addition, the company has capitalized on opportunities in 2020 to hedge the Midland to Cushing differential on 15.12 million barrels of oil at an average price of $(1.20) per barrel. The company’s natural gas hedges cover both the commodity and the basis.

3Q18 Hedge Position

Energen’s total hedge positions for the three months ending September 30, 2018, are as follows:

Oil

Hedge Volumes

% Hedged*

Avg. NYMEX Price

Swaps

0.48 mmbo

9%

$ 60.28 per barrel

Three way Collars1

3.38 mmbo

62%

Call Price

$ 60.04 per barrel

Put Price

$ 45.47 per barrel

Short Put Price

$ 35.47 per barrel

Oil Differential

Midland to Cushing2

3.42 mmbo

63%

$ (1.42) per barrel

NGL

Swaps

34.02 mm gallons

46%

$ 0.61 per gallon

Gas

Swaps3

2.70 bcf

23%

$ 1.98 per Mcf

* At guidance midpoint

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.
² In addition to swaps, the Midland to Cushing differential reflects an effective contractual differential of approximately $(1.00) on an estimated 0.27 mmbo of production.
³ The average price reflected for gas hedges represents a basin-specific net Permian price.

4Q18 Hedge Position

Energen’s total hedge positions for the three months ending December 31, 2018, are as follows:

Oil

Hedge Volumes

% Hedged*

Avg. NYMEX Price

Swaps

0.54 mmbo

9%

$ 60.25 per barrel

Three way Collars1

3.38 mmbo

53%

Call Price

$ 60.04 per barrel

Put Price

$ 45.47 per barrel

Short Put Price

$ 35.47 per barrel

Oil Differential

Midland to Cushing2

3.39 mmbo

53%

$ (1.42) per barrel

NGL

Swaps

34.02 mm gallons

43%

$ 0.61 per gallon

Gas

Swaps3

2.70 bcf

22%

$ 1.98 per mcf

* At guidance midpoint

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.
² In addition to swaps, the Midland to Cushing differential reflects an effective contractual differential of approximately $(1.00) on an estimated 0.24 mmbo of production.
³ The average price reflected for gas hedges represents a basin-specific net Permian price.

The company’s average realized prices in the last six months of 2018 will reflect commodity and basis hedges, oil transportation charges of approximately $2.05 per barrel, NGL transportation and fractionation fees of approximately $0.15 per gallon, and basis differentials applicable to unhedged production. Natural gas and NGL production are also subject to percent of proceeds contracts of approximately 85%.

Based on recent strip prices, Energen’s assumed gas basis for open months is $(1.05) per Mcf for August-December; $(0.88) per Mcf for August-September; and $(1.16) per Mcf for 4Q18. The assumed per-unit Midland to Cushing basis differentials for unhedged sweet and sour production are approximately $(15.50) for August-December; approximately $(13.65) for August-September; and approximately $(16.75) for 4Q18. Energen’s assumed commodity prices for unhedged volumes for the last six months of 2018 are: $66.75 per barrel of oil, $0.80 per gallon of NGL, and $2.75 per Mcf of gas (August-December).

Estimated Price Realizations (pre-hedge):
					3Q18			4Q18			CY18
Crude oil (% of NYMEX/WTI)					81			73			84
NGL (after T&F) (% of NYMEX/WTI)					35			35			34
Natural gas (% of NYMEX/Henry Hub)					48			43			49

2019 Hedges
Energen’s total hedge positions for 2019 are as follows (contracts are pro rata):
Oil				2019 Hedge Volumes				Avg. NYMEX Price
Swaps				7.56 mmbo				$ 61.14 per barrel
Three-way Collars1				5.76 mmbo
Call Price								$ 61.65 per barrel
Put Price								$ 45.94 per barrel
Short Put Price								$ 35.94 per barrel
Oil Differential
Midland to Cushing2				18.13 mmbo				$ (5.13) per barrel
NGL
Swaps				115.92 mm gallons				$ 0.65 per gallon

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.
² In addition to swaps, the Midland to Cushing differential reflects an effective contractual differential of approximately $(1.00) on an estimated 1.57 mmbo of production.

Supplemental Slides and Conference Call

2Q18 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 7, at 8:30 a.m. ET. 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 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 and income associated with acreage swaps. 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 6/30/18
Energen Net Income ($ in millions except per share data)			Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)			68.3			0.70
Non-cash mark-to-market losses (net of $2.1 tax)			7.7			0.08
Asset impairment, other (net of tax) *			nm			nm
Income associated with 2018 acreage swaps (net of $0.1 tax)			(0.5	)		(0.01	)
Adjusted Income from Continuing Operations (Non-GAAP)			75.4			0.77
			Three Months Ended 6/30/17
Energen Net Income ($ in millions except per share data)			Net Income			Per Diluted Share
Net Income (Loss) All Operations (GAAP)			29.5			0.30
Non-cash mark-to-market gains (net of $13.2 tax)			(24.1	)		(0.25	)
Asset impairment, other (net of tax) *			nm			nm
Adjusted Income from Continuing Operations (Non-GAAP)			5.4			0.06
Note: Amounts may not sum due to rounding
*This may include impairments, lease expirations, and dry hole expense.

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 impairments, certain non-cash mark-to-market derivative financial instruments,and income associated with acreage swaps.  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)			2018			2017
Energen Net Income (Loss) (GAAP)			68.3			29.5
Interest expense			10.8			9.2
Income tax expense (benefit)			19.8			16.1
Depreciation, depletion and amortization			134.0			121.5
Accretion expense			1.6			1.4
Exploration expense			1.2			2.0
Adjustment for asset impairment, other *			(0.1	)		nm
Adjustment for mark-to-market (gains)/ losses			9.9			(37.3	)
Income associated with 2018 acreage swaps			(0.7	)		0.0
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)			244.8			142.4
Note: Amounts may not sum due to rounding
*This may include impairments, lease expirations, and dry hole expense.

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) For the 3 months ending June 30, 2018 and 2017
					2nd Quarter
(in thousands, except per share data)					2018					2017					Change
Revenues
Oil, natural gas liquids and natural gas sales					$	371,567				$	218,723				$	152,844
Gain (loss) on derivative instruments, net						(31,919	)				38,101					(70,020	)
Total revenues						339,648					256,824					82,824
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production						57,958					43,909					14,049
Production and ad valorem taxes						24,733					13,218					11,515
Depreciation, depletion and amortization						134,011					121,549					12,462
Asset impairment						73					29					44
Exploration						1,059					1,998					(939	)
General and administrative (including stock-based compensation of $4,618 and $3,191 for the three months ended June 30, 2018 and 2017, respectively)						21,933					19,908					2,025
Accretion of discount on asset retirement obligations						1,567					1,443					124
(Gain) loss on sale of assets and other, net						(113	)				172					(285	)
Total operating costs and expenses						241,221					202,226					38,995
Operating Income						98,427					54,598					43,829
Other Income (Expense)
Interest expense						(10,803	)				(9,202	)				(1,601	)
Other income						465					218					247
Total other expense						(10,338	)				(8,984	)				(1,354	)
Income Before Income Taxes						88,089					45,614					42,475
Income tax expense						19,815					16,133					3,682
Net Income					$	68,274				$	29,481				$	38,793
Diluted Earnings Per Average Common Share					$	0.70				$	0.30				$	0.40
Basic Earnings Per Average Common Share					$	0.70				$	0.30				$	0.40
Diluted Average Common Shares Outstanding						98,080					97,693					387
Basic Average Common Shares Outstanding						97,433					97,189					244

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) For the 6 months ending June 30, 2018 and 2017
					Year-to-date
(in thousands, except per share data)					2018					2017					Change
Revenues
Oil, natural gas liquids and natural gas sales					$	729,433				$	395,098				$	334,335
Gain (loss) on derivative instruments, net						(33,614	)				102,647					(136,261	)
Total revenues						695,819					497,745					198,074
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production						110,593					85,197					25,396
Production and ad valorem taxes						47,301					26,038					21,263
Depreciation, depletion and amortization						258,221					221,201					37,020
Asset impairment						250					1,489					(1,239	)
Exploration						2,457					5,634					(3,177	)
General and administrative (including stock-based compensation of $8,763 and $6,388 for the six months ended June 30, 2018 and 2017, respectively)						44,190					40,424					3,766
Accretion of discount on asset retirement obligations						3,100					2,857					243
Gain on sale of assets and other, net						(33,836	)				(1,003	)				(32,833	)
Total operating costs and expenses						432,276					381,837					50,439
Operating Income						263,543					115,908					147,635
Other Income (Expense)
Interest expense						(21,051	)				(18,225	)				(2,826	)
Other income						692					775					(83	)
Total other expense						(20,359	)				(17,450	)				(2,909	)
Income Before Income Taxes						243,184					98,458					144,726
Income tax expense						55,995					35,574					20,421
Net Income					$	187,189				$	62,884				$	124,305
Diluted Earnings Per Average Common Share					$	1.91				$	0.64				$	1.27
Basic Earnings Per Average Common Share					$	1.92				$	0.65				$	1.27
Diluted Average Common Shares Outstanding						97,942					97,648					294
Basic Average Common Shares Outstanding						97,377					97,165					212

CONSOLIDATED BALANCE SHEETS (UNAUDITED) As of June 30, 2018 and December 31, 2017
(in thousands)					June 30, 2018				December 31, 2017
ASSETS
Current Assets
Cash and cash equivalents					$	1,188			$	439
Accounts receivable, net						166,467				158,787
Inventories, net						29,255				13,177
Derivative instruments						35,377				−
Income tax receivable						6,904				6,905
Prepayments and other						6,086				12,085
Total current assets						245,277				191,393
Property, Plant and Equipment
Oil and natural gas properties, net						5,089,320				4,718,939
Other property and equipment, net						43,896				44,581
Total property, plant and equipment, net						5,133,216				4,763,520
Other postretirement assets						2,609				2,646
Noncurrent derivative instruments						258				−
Noncurrent income tax receivable, net						70,716				70,716
Other assets						9,936				5,620
TOTAL ASSETS					$	5,462,012			$	5,033,895
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable					$	74,568			$	75,167
Accrued taxes						12,287				2,631
Accrued wages and benefits						11,428				26,170
Accrued capital costs						165,873				74,909
Revenue and royalty payable						68,154				54,072
Derivative instruments						80,996				71,379
Other						18,708				17,916
Total current liabilities						432,014				322,244
Long-term debt						829,068				782,861
Asset retirement obligations						92,588				88,378
Noncurrent derivative instruments						31,035				8,886
Deferred income taxes						442,225				387,807
Other long-term liabilities						6,223				5,262
Total liabilities						1,833,153				1,595,438
Total Shareholders’ Equity						3,628,859				3,438,457
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY					$	5,462,012			$	5,033,895

SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 3 months ending June 30, 2018 and 2017
					2nd Quarter
(in thousands, except sales price and per unit data)					2018					2017					Change
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil					$	316,082				$	182,701				$	133,381
Natural gas liquids						42,051					18,634					23,417
Natural gas						13,434					17,388					(3,954	)
Total					$	371,567				$	218,723				$	152,844
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil					$	6,182				$	31,067				$	(24,885	)
Natural gas liquids						(14,583	)				4,530					(19,113	)
Natural gas						(1,459	)				1,737					(3,196	)
Total					$	(9,860	)			$	37,334				$	(47,194	)
Closed gains (losses) on derivative instruments
Oil					$	(17,013	)			$	152				$	(17,165	)
Natural gas liquids						(6,249	)				(80	)				(6,169	)
Natural gas						1,203					695					508
Total					$	(22,059	)			$	767				$	(22,826	)
Total revenues					$	339,648				$	256,824				$	82,824
Production volumes
Oil (MBbl)						5,164					4,102					1,062
Natural gas liquids (MMgal)						77.9					51.6					26.3
Natural gas (MMcf)						11,058					7,596					3,462
Total production volumes (MBOE)						8,862					6,596					2,266
Average daily production volumes
Oil (MBbl/d)						56.7					45.1					11.6
Natural gas liquids (MMgal/d)						0.9					0.6					0.3
Natural gas (MMcf/d)						121.5					83.5					38.0
Total average daily production volumes (MBOE/d)						97.4					72.5					24.9
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)					$	57.91				$	44.58				$	13.33
Natural gas liquids (per gallon)					$	0.46				$	0.36				$	0.10
Natural gas (per Mcf)					$	1.32				$	2.38				$	(1.06	)
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)					$	61.21				$	44.54				$	16.67
Natural gas liquids (per gallon)					$	0.54				$	0.36				$	0.18
Natural gas (per Mcf)					$	1.21				$	2.29				$	(1.08	)
Costs per BOE
Oil, natural gas liquids and natural gas production expenses					$	6.54				$	6.66				$	(0.12	)
Production and ad valorem taxes					$	2.79				$	2.00				$	0.79
Depreciation, depletion and amortization					$	15.12				$	18.43				$	(3.31	)
Exploration expense					$	0.12				$	0.30				$	(0.18	)
General and administrative					$	2.47				$	3.02				$	(0.55	)
Capital expenditures (including acquisitions)					$	334,389				$	336,111				$	(1,722	)

SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 6 months ending June 30, 2018 and 2017
					Year-to-date
(in thousands, except sales price and per unit data)					2018					2017					Change
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil					$	620,077				$	329,371				$	290,706
Natural gas liquids						76,184					34,268					41,916
Natural gas						33,172					31,459					1,713
Total					$	729,433				$	395,098				$	334,335
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil					$	17,384				$	89,125				$	(71,741	)
Natural gas liquids						(8,817	)				11,617					(20,434	)
Natural gas						253					8,961					(8,708	)
Total					$	8,820				$	109,703				$	(100,883	)
Closed gains (losses) on derivative instruments
Oil					$	(33,680	)			$	(5,858	)			$	(27,822	)
Natural gas liquids						(10,230	)				(1,545	)				(8,685	)
Natural gas						1,476					347					1,129
Total					$	(42,434	)			$	(7,056	)			$	(35,378	)
Total revenues					$	695,819				$	497,745				$	198,074
Production volumes
Oil (MBbl)						10,148					7,098					3,050
Natural gas liquids (MMgal)						146.7					85.3					61.4
Natural gas (MMcf)						21,480					13,326					8,154
Total production volumes (MBOE)						17,220					11,350					5,870
Average daily production volumes
Oil (MBbl/d)						56.1					39.2					16.9
Natural gas liquids (MMgal/d)						0.8					0.5					0.3
Natural gas (MMcf/d)						118.7					73.6					45.1
Total average daily production volumes (MBOE/d)						95.1					62.7					32.4
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)					$	57.78				$	45.58				$	12.20
Natural gas liquids (per gallon)					$	0.45				$	0.38				$	0.07
Natural gas (per Mcf)					$	1.61				$	2.39				$	(0.78	)
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)					$	61.10				$	46.40				$	14.70
Natural gas liquids (per gallon)					$	0.52				$	0.40				$	0.12
Natural gas (per Mcf)					$	1.54				$	2.36				$	(0.82	)
Costs per BOE
Oil, natural gas liquids and natural gas production expenses					$	6.42				$	7.51				$	(1.09	)
Production and ad valorem taxes					$	2.75				$	2.29				$	0.46
Depreciation, depletion and amortization					$	15.00				$	19.49				$	(4.49	)
Exploration expense					$	0.14				$	0.50				$	(0.36	)
General and administrative					$	2.57				$	3.56				$	(0.99	)
Capital expenditures (including acquisitions)					$	594,922				$	720,246				$	(125,324	)

View source version on businesswire.com: https://www.businesswire.com/news/home/20180807005114/en/

Source: Business Wire (August 7, 2018 - 6:00 AM EDT)

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