MIDLAND, Texas, Aug. 01, 2017 (GLOBE NEWSWIRE) -- Diamondback Energy, Inc. (NASDAQ:FANG) (“Diamondback” or the “Company”) today announced financial and operating results for the second quarter ended June 30, 2017, corrected for a change to adjusted net income from the prior release.

HIGHLIGHTS

• Q2 2017 net income of $158 million, or $1.61 per diluted share (adjusted net income of $123 million, or $1.25 per diluted share; corrected from prior released adjusted net income of $137 million, or $1.40 per diluted share)
• Q2 2017 production of 77.0 Mboe/d (75% oil), up 25% over Q1 2017 (15% organic growth)
• Increasing full year 2017 production guidance to 74.0 - 78.0 Mboe/d, up 5% from prior full year guidance midpoint
• Lowering full year 2017 CAPEX guidance to $800 - $950 million from $800 million - $1.0 billion previously
• Q2 2017 cash operating costs of $7.66/boe, including LOE of $4.14/boe, cash G&A of $0.82/boe and taxes and transportation of $2.70/boe
• Lowering full year 2017 LOE guidance to $3.75 - $4.75 per boe and cash G&A to $0.75 - $1.25 per boe
• Two ReWard Wolfcamp A wells had average peak 30-day flowing 2-stream initial production ("IP") rates of 191 boe/d per 1,000' (83% oil)
• First completed Upper Wolfcamp A well in Pecos County had peak 30-day flowing IP rate of 219 boe/d per 1,000' (85% oil)
• First completed Lower Second Bone Spring well in Pecos County had peak 30-day flowing IP rate of 190 boe/d per 1,000' (91% oil)

“Diamondback has continued to build on its strong execution track record by increasing full year production guidance while decreasing CAPEX and cash cost guidance. We believe these results continue to affirm the strength of our business plan. Today we are positioned with acreage and well locations that provide many years of visible production growth. Our growth rate is determined by returns to shareholders, without reliance on the capital markets to fund our development plan. Our balance sheet remains strong and provides us the operational flexibility to increase and decrease activity as commodity price dictates, allowing us to grow differentially within cash flow," stated Travis Stice, Chief Executive Officer of Diamondback.

Mr. Stice continued, “We are impressed with the initial operated results out of the Wolfcamp A in the Southern Delaware Basin, and are extremely excited about our initial Second Bone Spring result on our Pecos acreage, providing us another zone that can compete for capital in our current portfolio. We will continue to lower well costs in the Delaware Basin with our organization’s relentless focus on capital efficiency and full cycle economics."

OPERATIONAL HIGHLIGHTS

Diamondback’s Q2 2017 production was 77.0 Mboe/d (75% oil), up 109% year over year from 36.8 Mboe/d in Q2 2016, and up 25% quarter over quarter from 61.6 Mboe/d in Q1 2017, with 15% organic growth excluding the effect of production acquired in the Brigham transaction.

During the second quarter of 2017, Diamondback averaged eight operated rigs, drilled 34 gross horizontal wells and turned 35 operated horizontal wells to production. Operated completions consisted of 16 Lower Spraberry wells, 12 Wolfcamp A wells, five Wolfcamp B wells and two Second Bone Spring wells. In May 2017, the Company added a ninth operated rig, which began operating in the Midland Basin. Diamondback plans to maintain an eight to nine rig cadence in the current commodity price environment.

Additionally, the Company signed a long-term proppant supply agreement with a local sand provider, with first use in Diamondback wells expected in early 2018. Diamondback expects to save approximately 5% from current Midland Basin well costs by using locally sourced proppant with its current completion design.

DELAWARE BASIN OPERATIONS UPDATE

In the ReWard area, Diamondback completed its second operated Wolfcamp A well in Reeves County with a 10,252 foot lateral. The Waler State Unit 4 1WA achieved a peak 30-day flowing IP rate of 205 boe/d per 1,000' (80% oil). The Coldblood 7372 Unit 1WA, the Company's first operated Wolfcamp A well in Ward County, achieved a peak 30-day flowing IP rate of 176 boe/d per 1,000' (87% oil).

In Pecos County,  the State McGary 16-1H achieved a peak 30-day flowing IP rate of 219 boe/d per 1,000' (85% oil) after commencing with a peak 24-hour IP rate of 243 boe/d per 1,000' (85% oil). Additionally, Diamondback recently completed its first operated Lower Second Bone Spring well with a 4,724 foot lateral. The Kelley State 2H achieved a peak 30-day flowing IP rate of 190 boe/d per 1,000' (91% oil). Most recently, the Company completed its first operated two-well pad targeting the Upper and Lower Wolfcamp A with an average lateral length of 7,553 feet. The State Neal Lethco 36-3201WA and State Neal Lethco 36-3202WA commenced with current average 24-hour flowing IP rates of 153 boe/d per 1,000' (89% oil) per well, with production on both wells continuing to increase.

MIDLAND BASIN OPERATIONS UPDATE

Throughout the Midland Basin, Diamondback continues to see strong performance from wells using a high-density near-wellbore completion design. In Howard County, the Company's latest four Wolfcamp A wells were completed with an average lateral length of 8,633 feet and achieved average peak 30-day rates of 203 boe/d per 1,000' (88% oil) per well.

In Andrews County, Diamondback recently conducted its first test of 500 foot inter-lateral spacing in the Lower Spraberry with encouraging results. The UL Mason East Unit 3LS, UL Mason East Unit 4LS and UL Mason East Unit 5LS wells were completed with an average lateral length of 10,234 feet and achieved an average peak 30-day IP rate of 124 boe/d per 1,000' (90% oil) per well. These results compare favorably to nearby operated Lower Spraberry completions with 660 foot inter-lateral spacing.

FINANCIAL HIGHLIGHTS

Diamondback's second quarter 2017 net income was $158 million, or $1.61 per diluted share. Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $123 million, or $1.25 per share.

Second quarter 2017 Adjusted EBITDA (as defined and reconciled below) was $218 million, up 25% from $175 million in Q1 2017. Second quarter 2017 revenues were $269 million, up 15% from $235 million in Q1 2017.

Second quarter 2017 average realized prices were $45.43 per barrel of oil, $2.57 per Mcf of natural gas and $17.83 per barrel of natural gas liquids, resulting in a total equivalent price of $38.18/boe, down 9% from the Q1 2017 total equivalent price of $41.93/boe.

Diamondback's cash operating costs for the second quarter 2017 were $7.66 per boe, including lease operating expenses ("LOE") of $4.14 per boe, cash general and administrative expenses of $0.82 per boe and taxes and transportation of $2.70 per boe. On a per-unit basis, Q2 2017 cash operating costs declined 18% versus Q1 2017 costs of $9.31 per boe.

As of June 30, 2017, Diamondback had $15 million in standalone cash and $84 million outstanding on its $750 million credit facility.

During the second quarter of 2017, Diamondback's spent $157.3 million on drilling and completion, and $18.3 million on infrastructure and non-operated properties.

FULL YEAR 2017 GUIDANCE

Below is Diamondback's full year 2017 guidance, which has been updated to reflect higher production, a narrowed capital budget and lower expenses.

		2017 Guidance
		Diamondback Energy, Inc.		Viper Energy Partners LP
Total Net Production – MBoe/d		74.0 – 78.0 (from 69.0 – 76.0)		10.0 – 11.0 (from 8.5 – 9.5)
Unit costs ($/boe)
Lease operating expenses, including workovers		$3.75 - $4.75 (from $4.75 - $5.75)		n/a
Gathering & Transportation		$0.25 - $0.75 (from $0.50 - $1.00)		$0.15 - $0.25 (from $0.25 - $0.50)
G&A
Cash G&A		$0.75 - $1.25 (from $1.00 - $2.00)		$0.50 - $1.50
Non-cash equity-based compensation		$1.00 - $2.00 (from $1.50 - $2.50)		$0.50 - $1.50
DD&A		$9.00 - $11.00		$8.00 - $10.00
Interest expense (net of interest income)		$1.00 - $2.00 (from $1.50 - $2.50)
Production and ad valorem taxes (% of revenue)(a)		7.0%		7.0%
Corporate tax rate (% of pre-tax income)		0% - 5%		n/a
($ - million)
Gross horizontal well costs - Midland Basin(b)		$5.0 - $5.5		n/a
Gross horizontal well costs - Delaware Basin(b)		$6.0 - $8.0
Horizontal wells completed (net)		115 - 135 (98 - 115)
		from 130 - 165 (110 - 140)
Capital Budget ($ - million)
Horizontal drilling and completion		$650 - $775 (from $650 - $825)		n/a
Infrastructure		$150 - $175		n/a
2017 Capital Spend		$800 - $950 (from $800 - $1,000)		n/a

(a) Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes.
(b) Assumes a 7,500’ average lateral length.

CONFERENCE CALL

Diamondback will host a conference call and webcast for investors and analysts to discuss its financial and operating results for the second quarter of 2017 on Wednesday, August 2, 2017 at 10:00 a.m. CT.  Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and use the confirmation code 58265190. A telephonic replay will be available from 1:00 p.m. CT on Wednesday, August 2, 2017 through Wednesday, August 9, 2017 at 1:00 p.m. CT. To access the replay, call (855) 859-2056 (United States/Canada) or (404) 537-3406 (International) and enter confirmation code 58265190. A live broadcast of the earnings conference call will also be available via the internet at www.diamondbackenergy.com under the “Investor Relations” section of the site. A replay will also be available on the website following the call.

About Diamondback Energy, Inc.

Diamondback is an independent oil and natural gas Company headquartered in Midland, Texas focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback’s activities are primarily focused on the horizontal exploitation of multiple intervals within the Wolfcamp, Spraberry, Clearfork, Bone Spring and Cline formations.

Forward Looking Statements

This news release contains forward-looking statements within the meaning of the federal securities laws. All statements, other than historical facts, that address activities that Diamondback assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of Diamondback. Information concerning these risks and other factors can be found in Diamondback’s filings with the Securities and Exchange Commission, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the Securities and Exchange Commission’s web site at http://www.sec.gov. Diamondback undertakes no obligation to update or revise any forward-looking statement.

Diamondback Energy, Inc.
Consolidated Statements of Operations
(unaudited, in thousands, except share amounts and per share data)
	Three Months Ended June 30,								Six Months Ended June 30,
	2017				2016				2017				2016
Revenues
Oil, natural gas liquids and natural gas	$	267,434			$	112,483			$	499,932			$	199,964
Lease bonus	583				—				2,185				—
Midstream services	1,417				—				2,547				—
Total revenues	269,434				112,483				504,664				199,964
Operating expenses
Lease operating expenses	28,989				18,677				55,615				36,900
Production and ad valorem taxes	15,879				8,159				31,604				16,121
Gathering and transportation	3,015				2,432				5,634				5,221
Midstream services	1,828				—				2,682				—
Depreciation, depletion and amortization	75,173				39,871				134,102				81,940
Impairment of oil and natural gas properties	—				168,352				—				199,168
General and administrative expenses(1)	11,892				9,524				25,636				22,503
Asset retirement obligation accretion	350				254				673				500
Total expenses	137,126				247,269				255,946				362,353
Income (loss) from operations	132,308				(134,786		)		248,718				(162,389		)
Interest expense	(8,245		)		(10,019		)		(20,470		)		(20,032		)
Other income	8,324				177				9,469				740
Gain (loss) on derivative instruments, net	33,320				(12,125		)		71,021				(10,699		)
Total other income (expense), net	33,399				(21,967		)		60,020				(29,991		)
Income (loss) before income taxes	165,707				(156,753		)		308,738				(192,380		)
Provision for income taxes	1,579				368				3,536				368
Net income (loss)	164,128				(157,121		)		305,202				(192,748		)
Net income (loss) attributable to non-controlling interest	5,723				(1,631		)		10,524				(4,346		)
Net income (loss) attributable to Diamondback Energy, Inc.	$	158,405			$	(155,490	)		$	294,678			$	(188,402	)
Earnings per common share:
Basic	$	1.61			$	(2.17	)		$	3.08			$	(2.64	)
Diluted	$	1.61			$	(2.17	)		$	3.07			$	(2.64	)
Weighted average common shares outstanding:
Basic		98,142				71,719				95,665				71,372
Diluted	98,354				71,719				95,925				71,372

(1) Includes non-cash expense of $6,168 and $6,029 for the three months ended June 30, 2017 and 2016, respectively, and $13,231 and $14,378 for the six months ended June 30, 2017 and 2016, respectively.

Diamondback Energy, Inc.
Selected Operating Data
(unaudited)
			Three Months Ended June 30,								Six Months Ended June 30,
			2017				2016				2017				2016
		Production Data:
		Oil (MBbl)	5,236				2,420				9,395				5,054
		Natural gas (MMcf)	4,939				2,567				8,622				4,883
		Natural gas liquids (MBbls)	945				505				1,718				971
		Oil Equivalents (MBOE)(1)(2)	7,005				3,353				12,550				6,839
		Average daily production (BOE/d)(2)	76,977				36,841				69,336				37,575
		% Oil	75		%		72		%		75		%		74		%
		Average sales prices:
		Oil, realized ($/Bbl)	$	45.43			$	41.88			$	47.36			$	35.68
		Natural gas realized ($/Mcf)	2.57				1.60				2.62				1.67
		Natural gas liquids ($/Bbl)	17.83				13.95				18.83				11.84
		Average price realized ($/BOE)	38.18				33.55				39.84				29.24
		Oil, hedged ($/Bbl)(3)	46.32				41.66				47.68				36.59
		Natural gas, hedged ($ per MMbtu)(3)	3.52				1.39				2.97				2.60
		Average price, hedged ($/BOE)(3)	38.85				33.39				40.08				29.91
		Average Costs per BOE:
		Lease operating expense	$	4.14			$	5.57			$	4.43			$	5.40
		Production and ad valorem taxes	2.27				2.43				2.52				2.36
		Gathering and transportation expense	0.43				0.73				0.45				0.76
		General and administrative - cash component	0.82				1.04				0.99				1.19
		Total operating expense - cash	$	7.66			$	9.77			$	8.39			$	9.71
		General and administrative - non-cash component	$	0.88			$	1.80			$	1.05			$	2.10
		Depreciation, depletion, and amortization	10.73				11.89				10.69				11.98
		Interest expense	1.18				2.99				1.63				2.93
(1	)	Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2	)	The volumes presented are based on actual results and are not calculated using the rounded numbers in the table above.
(3	)	Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as net income (loss) plus non-cash loss (gain) on derivative instruments, net, interest expense, depreciation, depletion and amortization, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense and income tax provision. Adjusted EBITDA is not a measure of net income (loss) as determined by United States’ generally accepted accounting principles ("GAAP"). Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate the Company’s operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company adds the items listed above to net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Adjusted net income is a non-GAAP financial measure equal to net income (loss) attributable to Diamondback Energy, Inc. plus non-cash (gain) loss on derivative instruments, net, (gain) loss on the sale of assets, net, other income, impairment of oil and gas properties and related income tax adjustments. The Company’s computations of Adjusted EBITDA and adjusted net income may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income.

Diamondback Energy, Inc.
Reconciliation of Adjusted EBITDA to Net Income
(unaudited, in thousands)
	Three Months Ended June 30,								Six Months Ended June 30,
	2017				2016				2017				2016
Net income (loss)	$	164,128			$	(157,121	)		$	305,202			$	(192,748	)
Non-cash (gain) loss on derivative instruments, net	(28,635		)		11,592				(68,010		)		15,283
Interest expense	8,245				10,019				20,470				20,032
Depreciation, depletion and amortization	75,173				39,871				134,102				81,940
Impairment of oil and natural gas properties	—				168,352				—				199,168
Non-cash equity-based compensation expense	8,069				7,874				17,475				18,987
Capitalized equity-based compensation expense	(1,901		)		(1,845		)		(4,244		)		(4,609		)
Asset retirement obligation accretion expense	350				254				673				500
Income tax provision	1,579				368				3,536				368
Consolidated Adjusted EBITDA	$	227,008			$	79,364			$	409,204			$	138,921
EBITDA attributable to noncontrolling interest	(8,574		)		(1,795		)		(15,519		)		(3,216		)
Adjusted EBITDA attributable to Diamondback Energy, Inc.	$	218,434			$	77,569			$	393,685			$	135,705

Adjusted net income is a performance measure used by management to evaluate performance, prior to non-cash (gain) loss on derivative instruments, net, (gain) on sale of assets, net, other income, impairment of oil and gas properties and related income tax adjustments.

The following table presents a reconciliation of adjusted net income to net income:

Diamondback Energy, Inc.
Adjusted Net Income
(unaudited, in thousands, except share amounts and per share data)
	Three Months Ended June 30,								Six Months Ended June 30,
	2017				2016				2017				2016
Net income (loss) attributable to Diamondback Energy, Inc.	$	158,405			$	(155,490	)		$	294,678			$	(188,402	)
Plus:
Non-cash (gain) loss on derivative instruments, net	(28,635		)		11,592				(68,010		)		15,283
Gain on sale of assets, net	(55		)		(28		)		(67		)		(28		)
Other income	(7,500)				—				(7,500)				—
Impairment of oil and gas properties*	—				162,831				—				193,647
Income tax adjustment for above items**	344				—				903				—
Adjusted net income (loss) attributable to Diamondback Energy, Inc.	$	122,559			$	18,905			$	220,004			$	20,500
Adjusted net income per common share:
Basic	$	1.25			$	0.26			$	2.30			$	0.29
Diluted	$	1.25			$	0.26			$	2.29			$	0.29
Weighted average common shares outstanding:
Basic	98,142				71,719				95,665				71,372
Diluted	98,354				71,719				95,925				71,372

*Impairment has been adjusted for Viper's noncontrolling interest.
**The tax impact is computed utilizing the Company's effective federal and state income tax rates. The income tax rate for the three months ended June 30, 2017 was approximately 0.95%.

Derivatives

As of the filing date, the Company had the following outstanding derivative contracts. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Crude Oil (Bbs/day), $/Bbl)
	Q3 2017				Q4 2017				Q1 2018				Q2 2018				Q3 2018				Q4 2018				Q1 2019				Q2 2019				Q3 2019				Q4 2019
Swaps	14,000				14,000				22,000				20,000				16,000				16,000				2,000				2,000				2,000				2,000
	$	53.43			$	53.37			$	51.42			$	50.92			$	50.07			$	50.12			$	49.65			$	49.65			$	49.65			$	49.65
Basis Swaps		24,000				24,000				15,000				15,000				15,000				15,000			—				—				—				—
	$	(0.72	)		$	(0.72	)		$	(0.88	)		$	(0.88	)		$	(0.88	)		$	(0.88	)		—				—				—				—
Costless Collars Floor		16,000				18,000				6,000			—				—				—				—				—				—				—
	$	47.13			$	47.11			$	47.00			—				—				—				—				—				—				—
Costless Collars Ceiling		8,000				9,000				3,000			—				—				—				—				—				—				—
	$	56.89			$	56.05			$	56.34			—				—				—				—				—				—				—

	Natural Gas (Mmbtu/day, $/Mmbtu)
	Q3 2017				Q4 2017				Q1 2018				Q2 2018				Q3 2018				Q4 2018
Swaps	30,000				30,000				25,000				10,000				10,000				10,000
	$	3.23			$	3.26			$	3.39			$	3.07			$	3.07			$	3.07

Investor Contact:
Adam Lawlis
+1 432.221.7467
alawlis@diamondbackenergy.com