Press Release

MIDLAND, Texas, Nov. 07, 2016 (GLOBE NEWSWIRE) -- Diamondback Energy, Inc. (NASDAQ:FANG) ("Diamondback" or the "Company") today announced financial and operating results for the third quarter ended September 30, 2016.

HIGHLIGHTS

• As previously announced, Q3 2016 production of 44.9 Mboe/d (73% oil), up 22% quarter over quarter and 32% year over year
  
• Cash operating costs of $9.15 per boe, including cash G&A of $0.88 per boe
  
• Previously increased full year 2016 production guidance to 41.0 to 42.0 Mboe/d, up from 38.0 to 40.0 Mboe/d
  
• Borrowing base increased to $1 billion, up 43% from Spring redetermination, with elected commitment remaining at $500 million
  
• Currently operating five horizontal rigs with plans to add a sixth rig in early 2017 targeting the Southern Delaware Basin
  
• 2017 production guidance of 52.0 to 58.0 Mboe/d from completion of 90 to 120 gross wells with an average lateral length of approximately 8,500 feet
  

"Our strong financial performance during the third quarter reflects our ability to execute and achieve accretive growth for our shareholders. Our disciplined strategy during the first half of 2016 allowed us to maintain our financial flexibility and maximize the value of our world class resource. In doing so, we were able to respond quickly when commodity prices improved and are now just beginning to bear the fruit of our activity ramp. We recently added a fifth rig to the Midland Basin and plan to add a sixth rig to begin developing our Southern Delaware Basin acreage in the coming months," stated Travis Stice, Chief Executive Officer of Diamondback.

Mr. Stice continued, "As we continue to prove ourselves as a leader in efficient, low-cost operations in the Midland Basin, we look to extend this track record into the Southern Delaware Basin. Our focus at Diamondback is converting high quality resource into cash flow in the most efficient manner possible. At current strip prices, we expect to deliver annual production growth of over 30% in 2017 at or near breakeven cash flow. Our Glasscock and Howard county positions continue to outperform our acquisition assumptions, and, in what may be an underappreciated story, Lower Spraberry performance in Andrews and Martin counties is comparable to Spanish Trail in Midland County. Diamondback continues to drive down costs on a per completed lateral foot basis, has under $10 cash operating costs per boe, and has built a robust inventory focused on long-lateral development to grow within cash flow for multiple years at current strip prices."

OPERATIONAL HIGHLIGHTS

As previously announced, Diamondback's Q3 2016 production was 44.9 Mboe/d, up 32% year over year from 34.1 Mboe/d in Q3 2015, and up 22% quarter over quarter from 36.8 Mboe/d in Q2 2016. Also, Diamondback has increased its full year 2016 production guidance to a range of 41.0 to 42.0 Mboe/d, up from 38.0 to 40.0 Mboe/d, as a result of continued strong well performance.

During the third quarter of 2016, Diamondback averaged four operated rigs and drilled 17 gross horizontal wells. The Company completed 21 operated horizontal wells with two completion crews. Operated completions consisted of ten Lower Spraberry wells, seven Wolfcamp B wells, two Wolfcamp A wells and two Middle Spraberry wells. In October 2016, Diamondback added its fifth operated horizontal rig and plans to add a sixth rig in early 2017 to begin development on the Company's recently acquired Southern Delaware Basin acreage. The Company anticipates completing essentially all of its remaining drilled but uncompleted wells ("DUCs") by the end of 2016.

As previously announced, Diamondback's preliminary full year 2017 production guidance is 52.0 to 58.0 Mboe/d, the midpoint of which is up over 30% from the midpoint of the 2016 guidance. The Company expects to complete 90 to 120 gross wells with an average lateral length of approximately 8,500 feet.

Diamondback continues to see strong well results across its asset base. During the third quarter, the Company completed a two-well Wolfcamp B pad in Glasscock County with an average completed lateral length of 10,050 feet. The Target B 3905WB and Target D 3904WB achieved an average 30-day flowing 2-stream initial production ("IP") rate of 1,425 boe/d (85% oil) per well. Additionally, the Company completed a second two-well Wolfcamp B pad with an average completed lateral length of 8,106 feet that had an average 30-day flowing IP rate of 1,067 boe/d (85% oil) per well. Two of the wells continue to flow naturally with all four wells outperforming the Company's prior Wolfcamp B wells in Glasscock County. Early results suggest these wells are tracking an average 7,500 foot lateral type curve of 1,000 Mboe.

Diamondback also recently completed a three-well pad in Howard County targeting three distinct zones (Lower Spraberry, Wolfcamp A and Wolfcamp B) with an average completed lateral length of 9,725 feet. The Reed 1A 1WA and the Reed 1A 1WB achieved respective peak 24-hour IP rates of 2,149 boe/d (89% oil) and 1,801 boe/d (90% oil), while the Lower Spraberry well is producing 797 boe/d (89% oil) and still cleaning up. All three wells were completed using a high-density near-wellbore frac design and appear to be outperforming the Company's first three-well pad completed in Q2 2016. After four months of production history, the Phillips-Hodnett Unit 1WA is tracking a 7,500 foot lateral type curve of over 1,000 Mboe, while the Phillips-Hodnett Unit 1WB and the Phillips-Hodnett Unit 1LS are each tracking a nearly 900 Mboe type curve.

Diamondback continues to decrease drilling times, lower costs and achieve new Company records. Leading-edge costs to drill, complete and equip Midland Basin wells remain below $6.0 million for a 10,000-foot lateral well and below $5.0 million for a 7,500-foot lateral well.

During the third quarter of 2016, Diamondback drilled two wells in Glasscock County and one well in Martin County with average lateral lengths of 10,980 feet in an average of 11.5 days from spud to total depth. Diamondback also successfully drilled two wells in Midland County with lateral lengths over 13,000 feet, the Company's longest horizontal wells drilled to date.

FINANCIAL HIGHLIGHTS

Diamondback's third quarter 2016 net loss was $2 million, or ($0.03) per diluted share. Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $42 million, or $0.54 per share.

Third quarter 2016 Adjusted EBITDA (as defined and reconciled below) was $102 million, up 31% from $78 million in Q2 2016. Third quarter 2016 revenues were $142 million, up 26% from $112 million in Q2 2016.

Diamondback's cash operating costs for the third quarter of 2016 were $9.15 per boe, including cash general and administrative expenses of $0.88 per boe. Total lease operating expenses ("LOE") of $59.1 million for the first nine months of 2016 decreased 9% versus the first nine months of 2015, despite production increasing 27% over the same period. The Company has lowered its full year 2016 LOE guidance range to $5.50 to $6.00 per boe from a prior range of $5.50 to $6.25 per boe.

As of September 30, 2016, Diamondback had $167 million in cash and an undrawn credit facility. In connection with its Fall 2016 redetermination, Diamondback's lenders recently approved a borrowing base increase to $1 billion from $700 million previously; however, the Company has again elected to limit the lenders' aggregate commitment to $500 million.

During the third quarter of 2016, Diamondback spent approximately $75 million on drilling and completion, $7 million on infrastructure and $9 million on non-operated properties. Additionally, the Company spent $701 million on acquisitions during the third quarter of 2016, including $126 million attributable to Viper.

On October 20, 2016, Diamondback priced $500 million of 4.75% Senior Notes due 2024, with proceeds used primarily to repurchase the Company's prior outstanding 7.625% Senior Notes due 2021.

FULL YEAR 2016 GUIDANCE

Below is Diamondback's full year 2016 guidance, which was updated in October to reflect higher production, an updated completion cadence and lower LOE expense. The Company is reiterating its 2016 capital expenditure guidance for drilling, completion and infrastructure of $350 to $425 million.

	2016 Guidance
	Diamondback Energy, Inc.					Viper Energy Partners LP
Total Net Production - MBoe/d	41.0 - 42.0			6.0 - 6.5
Unit costs ($/boe)
Lease operating expenses, including workovers	$5.50 - $6.00			n/a
Gathering & Transportation	$0.50 - $1.00			$0.25-$0.50
G&A
Cash G&A	$1.00 - $2.00			$0.50-$1.50
Non-cash equity-based compensation	$1.50 - $2.50			$2.00-$3.00
DD&A	$11.00 - $13.00			$12.00-$14.00
Interest expense (net of interest income)	$2.50 - $3.50
Production and ad valorem taxes (% of revenue)(a)		8.0	%			8.0	%
($ - million)
Gross horizontal well costs(b)	$5.0 - $5.5			n/a
Horizontal wells completed (net)	65 - 70 (55 - 60)
Capital Budget ($ - million)
Horizontal drilling and completion	$305 - $360			n/a
Infrastructure	$30 - $40			n/a
Non-op and other	$15 - $25			n/a
2016 Capital Spend	$350 - $425			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.

PRELIMINARY FULL YEAR 2017 GUIDANCE

Below is Diamondback's preliminary 2017 guidance, which was introduced in October. Diamondback expects full year 2017 production to be between 52.0 Mboe/d and 58.0 Mboe/d. During 2017, the Company plans to complete 90 to 120 gross horizontal wells with an estimated total capital spend of $500 to $650 million from a five to seven rig program, should WTI prices remain above $45 per barrel.

	2017 Guidance
	Diamondback Energy, Inc.
Total Net Production - MBoe/d	52.0 - 58.0
($ - million)
Gross horizontal well costs - Midland Basin(a)	$5.0 - $5.5
Gross horizontal well costs - Delaware Basin(a)	$6.0 - $7.0
Gross horizontal wells completed(b)	90 - 120
Capital Budget ($ - million)
2017 Capital Spend	$500 - $650

(a) Assumes a 7,500' average lateral length.
(b) Assumes an average lateral length of approximately 8,500'

CONFERENCE CALL

Diamondback and Viper will host a joint conference call and webcast for investors and analysts to discuss their results for the third quarter of 2016 on Tuesday, November 8, 2016 at 9:00 a.m. CT. Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and use the confirmation code 7883814. A telephonic replay will be available from 12:00 p.m. CT on Tuesday, November 8, 2016 through Sunday, November 13, 2016 at 12:00 p.m. CT. To access the replay, call (855) 859-2056 (United States/Canada) or (404) 537-3406 (International) and enter confirmation code 7883814. 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, including specifically the statements regarding the pending acquisition announced above. 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 September 30,								Nine Months Ended September 30,
		2016				2015				2016				2015
Revenues
Oil, natural gas liquids and natural gas		$	142,131			$	111,946			$	342,095			$	332,410
Operating Expenses
Lease operating expenses		22,180				22,189				59,080				65,117
Production and ad valorem taxes		9,123				8,966				25,244				25,036
Gathering and transportation		2,843				1,688				8,064				4,343
Depreciation, depletion and amortization		44,746				52,375				126,686				169,148
Impairment of oil and natural gas properties		46,368				273,737				245,536				597,188
General and administrative expenses		9,908				7,526				32,411				23,446
Asset retirement obligation accretion expense		270				238				770				588
Total expenses		135,438				366,719				497,791				884,866
Income (loss) from operations		6,693				(254,773		)		(155,696		)		(552,456		)
Net interest expense		(10,234		)		(10,633		)		(30,266		)		(31,404		)
Other income		907				300				1,647				1,248
Gain (loss) on derivative instruments, net		2,034				27,603				(8,665		)		26,834
Total other expense, net		(7,293		)		17,270				(37,284		)		(3,322		)
Loss before income taxes		(600		)		(237,503		)		(192,980		)		(555,778		)
Provision for (benefit from) income taxes		—				(81,461		)		368				(194,823		)
Net loss		(600		)		(156,042		)		(193,348		)		(360,955		)
Net income (loss) attributable to non-controlling interest		1,630				739				(2,716		)		2,264
Net loss attributable to Diamondback Energy, Inc.		$	(2,230	)		$	(156,781	)		$	(190,632	)		$	(363,219	)
Basic earnings per common share		$	(0.03	)		$	(2.40	)		$	(2.60	)		$	(5.88	)
Diluted earnings per common share		$	(0.03	)		$	(2.40	)		$	(2.60	)		$	(5.88	)
Weighted average number of basic shares outstanding		77,167				65,251				73,318				61,727
Weighted average number of diluted shares outstanding		77,167				65,251				73,318				61,727

Diamondback Energy, Inc.
Selected Operating Data
(unaudited)
					Three Months Ended September 30,								Nine Months Ended September 30,
					2016				2015				2016				2015
			Production Data:
			Oil (MBbl)		3,001				2,296				8,055				6,440
			Natural gas (MMcf)		2,673				2,122				7,556				5,524
			Natural gas liquids (MBbls)		687				486				1,657				1,260
			Oil Equivalents (MBOE)(1)(2)		4,133				3,136				10,971				8,620
			Average daily production (BOE/d)(2)		44,923				34,082				40,042				31,576
			% Oil		73		%		73		%		73		%		74		%
			Average sales prices:
			Oil, realized ($/Bbl)		$	42.11			$	44.12			$	38.08			$	46.87
			Natural gas realized ($/Mcf)		2.37				2.67				1.91				2.61
			Natural gas liquids ($/Bbl)		13.76				10.22				12.63				12.80
			Average price realized ($/BOE)		34.39				35.70				31.18				38.56
			Oil, hedged ($/Bbl)(3)		41.98				59.59				38.60				63.08
			Average price, hedged ($/BOE)(3)		34.30				47.03				31.56				50.67
			Average Costs per BOE:
			Lease operating expense		$	5.37			$	7.08			$	5.38			$	7.55
			Production and ad valorem taxes		2.21				2.86				2.30				2.90
			Gathering and transportation expense		0.69				0.54				0.73				0.50
			General and administrative - cash component		0.88				1.01				1.07				1.14
			Total operating expense - cash		$	9.15			$	11.49			$	9.48			$	12.09
			General and administrative - non-cash component		$	1.52			$	1.39			$	1.88			$	1.58
			Depreciation, depletion, and amortization		10.83				16.70				11.55				19.62
			Interest expense		2.48				3.39				2.76				3.64
	(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 on derivative instruments, net, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense and income tax (benefit) 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, 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 September 30,																Nine Months Ended September 30,
																2016										2015						2016										2015
Net income (loss)																$							(600	)		$			(156,042	)		$							(193,348	)		$			(360,955	)
Non-cash loss on derivative instruments, net																(2,425								)		7,901						12,858										77,532
Interest expense																10,234										10,633						30,266										31,404
Depreciation, depletion and amortization																44,746										52,375						126,686										169,148
Impairment of oil and gas properties																46,368										273,737						245,536										597,188
Non-cash equity-based compensation expense																7,181										5,936						26,168										18,784
Capitalized equity-based compensation expense																(916								)		(1,534				)		(5,525								)		(5,125				)
Asset retirement obligation accretion expense																270										238						770										588
Income tax (benefit) provision																—										(81,461				)		368										(194,823				)
Consolidated Adjusted EBITDA																$							104,858			$			111,783			$							243,779			$			333,741
EBITDA attributable to noncontrolling interest																(2,614								)		(1,912				)		(5,830								)		(5,780				)
Adjusted EBITDA attributable to Diamondback Energy, Inc.																$							102,244			$			109,871			$							237,949			$			327,961

Adjusted net income is a performance measure used by management to evaluate performance, prior to non-cash losses on derivative instruments, (gain) on sale of assets, net, 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 September 30,																Nine Months Ended September 30,
																2016										2015						2016										2015
Net income (loss) attributable to Diamondback Energy, Inc.																$							(2,230	)		$			(156,781	)		$							(190,632	)		$			(363,219	)
Plus:
Non-cash (gain) loss on derivative instruments, net																(2,425								)		7,901						12,858										77,532
(Gain) loss on sale of assets, net																(9								)		(91				)		(37								)		(91				)
Impairment of oil and gas properties*																46,368										273,737						240,015										597,188
Income tax adjustment for above items**																—										(98,541				)		—										(236,120				)
Adjusted net income attributable to Diamondback Energy, Inc.																$							41,704			$			26,225			$							62,204			$			75,290
Adjusted net income per common share:
Basic																$							0.54			$			0.40			$							0.85			$			1.22
Diluted																$							0.54			$			0.40			$							0.85			$			1.22
Weighted average common shares outstanding:
Basic																77,167										65,251						73,318										61,727
Diluted																77,167										65,251						73,318										61,727

*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 September 30, 2016 was approximately 0% while it was approximately 35% for the three months ended September 30, 2015.

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.

														2016
														Volume (Bbls/MMBtu)						Fixed Price Swap (per Bbl/MMBtu)
Fourth Quarter
Oil Swaps														3,000					$	43.52
Oil Basis Swaps														14,000					$	(0.67	)
	2017												2018
	Volume (Bbls/MMBtu)					Fixed Price Swap (per Bbl/MMBtu)							Volume (Bbls/MMBtu)							Fixed Price Swap(per Bbl/MMBtu)
First Quarter
Oil Swaps	3,000						$			45.86
Oil Basis Swaps	24,000						$			(0.72	)		12,000						$	(0.88	)
Natural Gas Swaps	20,000						$			3.30
Second Quarter
Oil Swaps	3,000						$			45.86
Oil Basis Swaps	24,000						$			(0.72	)		12,000						$	(0.88	)
Natural Gas Swaps	20,000						$			3.14
Third Quarter
Oil Swaps	3,000						$			45.86
Oil Basis Swaps	24,000						$			(0.72	)		12,000						$	(0.88	)
Natural Gas Swaps	20,000						$			3.14
Fourth Quarter
Oil Swaps	3,000						$			45.86
Oil Basis Swaps	24,000						$			(0.72	)		12,000						$	(0.88	)
Natural Gas Swaps	20,000						$			3.19
	2016
	Floor													Ceiling
	Volume (Bbls)						Fixed Price (per Bbl)							Volume (Bbls)					Fixed Price (per Bbl)
November-December
Costless Collars	10,000							$		45.00				5,000					$	54.95
	2017
	Floor													Ceiling
	Volume (Bbls)							Fixed Price (per Bbl)						Volume (Bbls)					Fixed Price (per Bbl)
First Quarter
Costless Collars	10,000							$		45.00				5,000					$	54.46
Second Quarter
Costless Collars	10,000							$		45.00				5,000					$	54.25

Investor Contact:

Adam Lawlis

+1 432.221.7467

alawlis@diamondbackenergy.com

Source: Diamondback Energy, Inc.

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