RSP Permian, Inc. Announces Fourth Quarter and Full-Year 2017 Financial and Operating Results, Year-End 2017 Proved Reserves and 2018 Guidance

RSP Permian, Inc. (“RSP” or the “Company”) (NYSE: RSPP) today reported financial and operating results for the quarter and year ended December 31, 2017, year-end 2017 proved reserves and 2018 guidance. In addition, the Company filed its Annual Report on Form 10-K for the year ended December 31, 2017 with the Securities and Exchange Commission (the “SEC”) and posted a presentation that supplements the information in this release to its website at www.rsppermian.com.

Highlights for the Fourth Quarter and Full Year 2017:

• 4Q17 production increased 74% to 62.4 MBoe/d (71% oil, 88% liquids) compared to 4Q16 and full year 2017 production increased 89% to 55.3 MBoe/d (72% oil, 88% liquids) compared to 2016
• 4Q17 net income was $140.8 million, or $0.89 per diluted share and adjusted net income (non-GAAP), which does not include certain items, was $50.1 million, or $0.32 per diluted share. Full year 2017 net income was $232.1 million, or $1.49 per diluted share and adjusted net income (non-GAAP), which does not include certain items, was $128.6 million, or $0.83 per diluted share
• 4Q17 adjusted EBITDAX (non-GAAP) increased 102% to $182.4 million compared to 4Q16, and increased 26% compared to 3Q17. Full year 2017 adjusted EBITDAX (non-GAAP) increased 134% to $587.0 million compared to 2016
• Full year 2017 development capital expenditures of $673.3 million
• Maintained strong year-end liquidity position of $561.2 million, including $523.1 million of available borrowing capacity under the Company's revolving credit facility and $38.1 million of cash
• Proved reserves increased by 59% to 376 MMBoe (70% oil, 87% liquids) compared to 2016; achieved low drill-bit finding and development cost of $6.26/Boe, with a 771% reserve replacement ratio and a 536% organic reserve replacement ratio

Adjusted net income and adjusted EBITDAX are non-GAAP measures. See "Use of Non-GAAP Financial Measures" below for definitions and reconciliations. In addition, see below for Company's definition of liquidity and calculations of "Drill-Bit F&D and Reserve Replacement Ratios."

Operational Highlights

Midland Basin

• Spanish Trail 333 01H Wolfcamp A well (8,600’) established a peak 30-day average rate of 1,821 Boe/d or 212 Boe/d per 1,000’ (84% oil)
• Basin leader in the development of the Wolfcamp A target horizon. Full development underway in several sections, including Spanish Trail Section 3-10; four of eight planned Wolfcamp A wells averaged peak 30-day rates of 261 Boe/d per 1,000' (78% oil)

Delaware Basin

• Recent Brunson D 3-well pad pilot tested variations to completion design. Brunson D 1203H Wolfcamp A well (7,500') established a peak 24-hour rate of 3,342 Boe/d or 446 Boe/d per 1,000' (67% oil); Brunson D 1201H Wolfcamp B well (6,800') established a peak 24-hour rate of 2,460 Boe/d or 362 Boe/d per 1,000' (73% oil); Brunson D 1204H Third Bone Spring well (8,500') established a peak 24-hour rate of 1,498 Boe/d or 176 Boe/d per 1,000' (71% oil)
• Rudd Draw 29 03 01H Third Bone Spring well (4,400') established a peak 30-day average rate of 1,724 Boe/d or 392 Boe/d per 1,000’ (71% oil)

2018 Guidance and 2019-2020 Preliminary Outlook

• Average net daily production range of 72.0 - 78.0 MBoe/d in 2018, a 30% - 41% increase over 2017
• Expect to generate cash flow in excess of development spending by the fourth quarter of 2018, with Net Debt / LTM EBITDAX of 2.0x or less by year-end at a $50 average oil price
• Development capital expenditure range of $815 - $895 million (drilling, completion, infrastructure and other) with drilling and completion of $725 - $785 million and infrastructure and other of $90 - $110 million
• Expanded hedge profile covering approximately 60% of 2018E oil production volumes at the midpoint
• Expecting 30%-plus annual production growth in 2019 and 2020 with substantial free cash flow generated at a $50 oil price

Steve Gray, Chief Executive Officer, commented, "I am proud of our Company's accomplishments in 2017. We delivered on our annual guidance objectives while nearly doubling the size of the Company, integrating a new operating area in the Delaware Basin and building out the infrastructure and team to accommodate our increased activity levels and production growth in 2018. We continue to see impressive well results in both our Midland and Delaware Basin assets and this increased well productivity enabled us to meet the mid-point of our production guidance despite completing twenty fewer horizontal wells than we originally budgeted.

"We are well positioned for strong returns in 2018 as we continue to increase our capital efficiency levels and accelerate the completion of our drilled but uncompleted wells carried over from last year's drilling program. We also expect to generate cash flow in excess of our development spending by the fourth quarter of 2018 while growing production 35% at the mid-point of our guidance."

Operational Results
			Three Months Ended December 31,										Twelve Months Ended December 31,
			2017					2016					2017					2016
Production data:
Oil (MBbls)			4,078					2,337					14,445					7,790
Natural gas (MMcf)			4,210					2,278					15,126					7,188
NGLs (MBbls)			957					576					3,202					1,685
Total (MBoe)			5,737					3,293					20,168					10,673
Average net daily production (Boe/d)			62,359					35,793					55,255					29,161
Average prices before effects of hedges (1) (2):
Oil (per Bbl)			$	53.50				$	47.23				$	48.79				$	41.28
Natural gas (per Mcf)			2.21					2.24					2.39					1.94
NGLs (per Bbl)			22.50					12.94					19.57					10.87
Total (per Boe)			$	43.41				$	37.33				$	39.85				$	33.15
Average realized prices after effects of hedges (1) (2):
Oil (per Bbl)			$	51.35				$	46.20				$	47.75				$	41.06
Natural gas (per Mcf)			2.27					2.24					2.43					1.94
NGLs (per Bbl)			22.50					12.94					19.57					10.87
Total (per Boe)			$	41.92				$	36.60				$	39.12				$	32.99
Average costs (per Boe):
Lease operating expenses (excluding gathering and transportation)			$	5.25				$	4.41				$	5.13				$	4.93
Gathering and transportation			0.89					0.57					0.96					0.48
Production and ad valorem taxes			2.79					2.01					2.43					2.03
Depreciation, depletion and amortization			13.45					15.94					13.87					18.21
General and administrative - recurring cash component			1.19					2.11					1.50					2.10
General and administrative - recurring stock comp (3)			0.77					0.98					0.85					1.23
General and administrative - non-recurring stock comp (4)			—					—					—					0.06

		(1)		Average prices shown in the table reflect prices both before and after the effects of our cash payments/receipts on the Company's commodity derivative transactions. The calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period, if applicable.
		(2)		Average prices for oil are net of transportation costs. Average prices for natural gas do not include transportation costs; instead, transportation costs related to our natural gas production and sales are included in gathering and transportation which is included in lease operating expenses in our consolidated statements of operations.
		(3)		Represents compensation expense related to restricted stock awards and performance share awards granted as part of the Company’s ongoing compensation and retention programs.
		(4)		The non-recurring 2016 amount is a compensation charge associated with the retirement of an officer of the Company.

Production volumes for the quarter ended December 31, 2017 averaged 62,359 Boe/d or a total of 5,737 MBoe, an increase of 74% over prior year’s fourth quarter of 35,793 Boe/d. Production for the fourth quarter of 2017 was comprised of 71% oil, 12% natural gas and 17% NGLs. RSP’s average realized oil price for the fourth quarter of 2017, before the effects of hedges, was $53.50 per barrel, a negative $1.90 differential compared to average NYMEX WTI pricing of $55.40 per barrel for the same period, or 97% of NYMEX WTI pricing. RSP’s average realized natural gas price for the fourth quarter of 2017, before the effects of hedges, was $2.21 per Mcf, a negative $0.72 differential compared to average NYMEX Henry Hub pricing of $2.93 per MMBtu for the same period, or 75% of NYMEX Henry Hub pricing. RSP’s average realized NGLs price for the fourth quarter of 2017 was $22.50 per Bbl, or 41% of NYMEX WTI pricing for the same time period. Per unit cash operating expenses excluding interest expense but including lease operating expense, gathering and transportation expense, production and ad valorem taxes and recurring cash general and administrative expenses were $10.12 per Boe.

Production volumes for the year ended December 31, 2017 averaged 55,255 Boe/d or a total of 20,168 MBoe, an increase of 89% over prior year's total of 29,161 Boe/d. Production for 2017 was comprised of 72% oil, 12% natural gas and 16% NGLs. RSP’s average realized oil price for 2017, before the effects of hedges, was $48.79 per barrel, a negative $2.16 differential compared to average NYMEX WTI pricing of $50.95 per barrel for the same period, or 96% of NYMEX WTI pricing. RSP’s average realized natural gas price for 2017, before the effects of hedges, was $2.39 per Mcf, a negative $0.72 differential compared to average NYMEX Henry Hub pricing of $3.11 per MMBtu for the same period, or 77% of NYMEX Henry Hub pricing. RSP’s average realized NGLs price for 2017 was $19.57 per Bbl, or 38% of NYMEX WTI pricing for the same period. Per unit cash operating expenses excluding interest expense but including lease operating expense, gathering and transportation expense, production and ad valorem taxes and recurring cash general and administrative expenses were $10.02 per Boe.

Operational Update

The Company operated three horizontal rigs in the Midland Basin and three horizontal rigs in the Delaware Basin, and one horizontal rig servicing both basins throughout the fourth quarter of 2017. RSP utilized two full-time completion crews during the fourth quarter. RSP drilled 26 gross operated horizontal wells and completed 16 gross operated horizontal wells (Midland: five Wolfcamp B, four Wolfcamp A and two Lower Spraberry; Delaware: three Wolfcamp A, one Wolfcamp B and one Third Bone Spring). The Company began the quarter with 26 operated horizontal drilled but uncompleted wells ("DUCs") and exited the quarter with a total of 36 gross operated horizontal DUCs. During 2017, RSP drilled 95 gross and completed 70 gross operated horizontal wells (Midland: 21 Wolfcamp A, 16 Wolfcamp B, 13 Lower Spraberry and one Middle Spraberry; Delaware: 12 Wolfcamp A, two Wolfcamp B, two Wolfcamp XY, two Third Bone Spring and one Second Bone Spring). The following table summarizes the Company's gross wells drilled and completed during the periods:

			4Q17 Wells												2017 Wells
			Drilled				Completed				Drilled but Uncompleted Wells (DUCs)				Drilled				Completed
Operated Wells
Midland			17				11				27				68				51
Delaware			9				5				9				27				19
Total Operated			26				16				36				95				70
Non-Operated Wells
Midland			9				13				9				34				35
Delaware			1				3				—				7				8
Total Non-Operated			10				16				9				41				43
Total Wells
Midland			26				24				36				102				86
Delaware			10				8				9				34				27
Total Wells			36				32				45				136				113

Financial Results
			Three Months Ended December 31,										Twelve Months Ended December 31,
(in thousands, except per share data)			2017					2016					2017					2016
Total Revenues			$	249,023				$	122,934				$	803,708				$	353,857
Net Cash from Derivative Instruments			(8,566		)			(2,398		)			(14,661		)			(1,732		)
Adjusted Total Revenues			240,457					120,536					789,047					352,125
Net Income (Loss)			$	140,786				$	1,381				$	232,136				$	(24,851	)
Net Income (Loss) per Common Share - Diluted			0.89					0.01					1.49					(0.23		)
Adjusted Net Income (Loss) (1)			50,122					13,395					128,568					(7,358		)
Adjusted Net Income (Loss) per Common Share - Diluted			0.32					0.10					0.83					(0.07		)
Adjusted EBITDAX (1)			$	182,425				$	90,529				$	586,988				$	250,326

		(1)		Adjusted EBITDAX and Adjusted Net Income are non-GAAP financial measures. For a definition of Adjusted EBITDAX and Adjusted Net Income and a reconciliation of Adjusted EBITDAX and Adjusted Net Income to Net Income, see “Use of Non-GAAP financial measures” and our quarterly statements of operations at the end of this release.

For the quarter ended December 31, 2017, total revenues, excluding the revenue impact from realized derivative instruments, were $249.0 million, a 103% increase over the prior year quarter of $122.9 million. Adjusted total revenues, including the net cash from derivative instruments, were $240.5 million, a 99% increase over the prior year quarter of $120.5 million. Net income for the fourth quarter of 2017 was $140.8 million, or $0.89 per diluted share, while net income for the prior year quarter was $1.4 million, or $0.01 per diluted share. The Company recorded a one-time income tax benefit of $144.4 million during the fourth quarter of 2017 as a result of the enactment of the U.S. Tax Cuts and Jobs Act which lowered the federal corporate tax rate to 21% from 35%. Adjusted net income for the fourth quarter of 2017 was $50.1 million, or $0.32 per diluted share, compared with adjusted net income for the prior year quarter of $13.4 million or $0.10 per diluted share. Adjusted EBITDAX was $182.4 million, a 102% increase from the prior year quarter of $90.5 million.

For the year ended December 31, 2017, total revenues, excluding the revenue impact from realized derivative instruments, were $803.7 million, a 127% increase over the prior year of $353.9 million. Adjusted total revenues, including the net cash from derivative instruments, were $789.0 million, a 124% increase from the prior year of $352.1 million. Net income for the year ended 2017 was $232.1 million, or $1.49 per diluted share, while net loss for the prior year was $24.9 million, or negative $0.23 per diluted share. Adjusted net income for the year ended 2017 was $128.6 million, or $0.83 per diluted share, compared with adjusted net loss for the prior year of $7.4 million or negative $0.07 per diluted share. Adjusted EBITDAX was $587.0 million, a 134% increase from the prior year of $250.3 million.

Proved Reserves Summary

RSP’s proved reserves summary as of December 31, 2017 was prepared by RSP and audited by Netherland, Sewell & Associates, Inc.

The Company's proved oil and natural gas reserves increased from 236.9 MMBoe at January 1, 2017 to 375.9 MMBoe, or 59%, primarily due to extensions and discoveries related to the Company's development of the Midland Basin and Delaware Basin assets and the Silver Hill E&P II, LLC ("SHEP II") acquisition in the first quarter of 2017. Oil and NGLs reserves, in aggregate, equaled 87% of the Company's total proved reserves. At December 31, 2017, 58% of the Company's total proved reserves were undeveloped.

The following table summarizes the changes in the Company's estimated net proved oil and natural gas reserves from January 1, 2017 to December 31, 2017 prepared in accordance with the rules and regulations of the SEC.

		Oil (MBbls)			Natural Gas (MMcf)			NGLs (MBbls)			Total (MBoe)
Proved developed and undeveloped reserves:
As of January 1, 2017		164,728			176,786			42,696			236,888
Production		(14,445	)		(15,126	)		(3,202	)		(20,168	)
Extensions and discoveries		64,925			73,698			16,009			93,217
Purchases of minerals in place		34,997			33,772			6,859			47,485
Revisions of previous estimates		11,130			25,889			3,075			18,520
As of December 31, 2017		261,335			295,019			65,437			375,942

The following table presents the Company's estimated net proved oil and natural gas reserves as of December 31, 2017, 2016 and 2015.

			2017				2016				2015
Proved developed reserves:
Oil (MBbls)			106,668				65,025				44,128
Natural gas (MMcf)			133,116				76,255				56,640
NGLs (MBbls)			30,162				18,759				11,020
Total (MBoe)			159,016				96,493				64,588
Proved undeveloped reserves:
Oil (MBbls)			154,667				99,703				67,007
Natural gas (MMcf)			161,903				100,531				76,867
NGLs (MBbls)			35,275				23,937				14,767
Total (MBoe)			216,926				140,395				94,585
Total proved reserves:
Oil (MBbls)			261,335				164,728				111,135
Natural gas (MMcf)			295,019				176,786				133,507
NGLs (MBbls)			65,437				42,696				25,787
Total (MBoe)			375,942				236,888				159,173

Capital Expenditures

RSP’s development capital expenditures, which includes our investment in drilling and completing wells, infrastructure, capitalized workovers, and other, but excludes acquisitions, for the year ended December 31, 2017 totaled $673.3 million ($610.6 million of drilling and completion and $62.7 million of infrastructure and other). The Company spent $78.9 million, or 12% of development capital, on non-operated properties. The SHEP II acquisition closed on March 1, 2017 for a purchase price of $1.3 billion, before purchase price adjustments, that included cash consideration of $646.0 million, and approximately 16.0 million shares of RSP Inc. common stock, valued at $663.9 million based on our closing common share price of $41.44 per share on March 1, 2017. In addition, we spent $279.0 million on acquisitions of undeveloped acreage and additional mineral interests.

Liquidity

In October 2017, the Company's borrowing base under its revolving credit facility increased to $1.5 billion from $1.1 billion, and the Company maintained its elected commitment amount of $900.0 million. At December 31, 2017, the Company had $523.1 million of borrowing capacity under its revolving credit facility and $38.1 million of cash on hand.

The following table summarizes the Company's liquidity position as of December 31, 2017:

(in thousands)			December 31, 2017
Revolving Credit Facility elected commitment amount			$	900,000
Revolving Credit Facility borrowings			(375,000		)
Letters of credit			(1,933		)
Available borrowing capacity			523,067
Cash and cash equivalents			38,102
Liquidity			$	561,169

Hedging

The summary below includes all hedges in place for the full year 2018 and 2019, as of February 27, 2018.

Crude Oil Hedges
(Bbl, $/Bbl)			Q1 2018					Q2 2018					Q3 2018					Q4 2018					2019
Three-Way Collars(1)			2,219,000					1,941,000					1,319,000					1,227,000					—
Ceiling			$	58.81				$	59.07				$	60.56				$	60.96				$	—
Floor			$	46.96				$	47.11				$	47.79				$	48.00				$	—
Short Put			$	36.96				$	37.11				$	37.79				$	38.00				$	—
Costless Collars(1)			571,000					516,000					1,212,000					1,058,000					2,555,000
Ceiling			$	60.19				$	60.20				$	60.10				$	60.11				$	58.04
Floor			$	45.00				$	45.00				$	46.33				$	46.52				$	52.50
Crude Oil Swaps(1)			—					698,000					322,000					322,000					2,555,000
Swap			$	—				$	62.97				$	55.77				$	55.77				$	55.74
Total Hedged Volumes			2,790,000					3,155,000					2,853,000					2,607,000					5,110,000
Weighted Average Floor(2)			$	46.56				$	50.27				$	48.07				$	48.36				$	54.12
Mid-Cush Differential Swaps:			2,390,000					2,730,000					2,760,000					2,760,000					2,555,000
Swap(3)			$	(0.47	)			$	(0.42	)			$	(0.42	)			$	(0.42	)			$	(0.29	)

			(1)		The crude oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of West Texas Intermediate Light Sweet Crude.
			(2)		Weighted average floor assumes the long put in three way collars.
			(3)		The Mid-Cush swap contracts are settled based on the difference in the arithmetic average during the calculation period of WTI MIDLAND ARGUS and WTI ARGUS prices in the Argus Americas Crude publication for the relevant period.

2018 Annual Guidance

RSP anticipates spending $815 to $895 million in development capital in 2018, generating production growth of 35% at the midpoint of the production guidance range. At a $50 average oil price, the Company expects to generate cash flow in excess of development spending by the fourth quarter and exit the year at less than 2.0x Net Debt / LTM EBITDAX.

The Company is running seven operated rigs currently, and with an expected rig addition in April, will target four rigs running in each basin going forward. RSP is currently running three completion crews, two full-time and one spot crew, and expects to add a third full-time crew in May to replace the spot crew. With 19 wells completed in the first two months of 2018, RSP is off to a strong start towards its guided range of 100-120 operated completions for the full year 2018.

The following table summarizes the Company’s guidance for 2018.

				2018 Guidance
Completions
Operated Gross Horizontal Completions				100 - 120
Operated Average Working Interest				89%
Midland Basin Average Lateral Length				~8,100'
Delaware Basin Average Lateral Length				~6,300'
Production
Average Daily Production (Boe/d)				72,000 - 78,000
% Oil				70% - 72%
% Natural Gas				12% - 14%
% NGLs				15% - 17%
Development Capital Expenditures ($ in MM)
Drilling and Completion (D&C)				$725 - $785
Infrastructure, Capitalized Workovers & Other				$90 - $110
Total Development Capital Expenditures				$815 - $895
% Midland Basin				45% - 55%
% Delaware Basin				45% - 55%
% Non-Operated				8% - 10%
Income Statement ($/Boe)
Lease operating expenses (including workovers)				$5.00 - $5.50
Gathering and transportation				$0.90 - $1.20
Exploration expenses				$0.10 - $0.20
General and administrative - cash component				$1.25 - $1.75
General and administrative - recurring stock comp				$0.75 - $0.95
Depreciation, depletion, and amortization ($/Boe)				$12.50 - $14.50
Production and ad valorem taxes (% of oil and gas revenues)				6.0% - 8.0%

Conference Call

RSP will host a conference call for investors at 9:00 AM Central Time on Wednesday, February 28, 2017, to discuss fourth quarter and full-year 2017 results. Hosting the call will be Steve Gray, Chief Executive Officer, Zane Arrott, Chief Operating Officer, Scott McNeill, Chief Financial Officer and Alyssa Stephens, Director of Investor Relations.

The call may be accessed live over the telephone by dialing (877) 705-6003, or for international callers, (201) 493-6725. A replay will be available shortly after the call and can be accessed by dialing (844) 512-2921, or for international callers (412) 317-6671. The passcode for the replay is 13676620. The replay will be available until March 14, 2018. Interested parties may also listen to a simultaneous webcast of the conference call by logging onto RSP's website at www.rsppermian.com in the Investor Relations section. A replay of the webcast will also be available following the call.

About RSP Permian, Inc.

RSP is an independent oil and natural gas company focused on the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of the Company's acreage is located on large, contiguous acreage blocks in the core of the Midland and Delaware Basins, sub-basins of the Permian Basin. The Company's common stock is traded on the NYSE under the ticker symbol "RSPP." For more information, visit www.rsppermian.com.

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 RSP assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. 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 RSP. Information concerning these risks and other factors can be found in RSP's filings with the SEC, including its Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, which can be obtained free of charge on the SEC's web site located at http://www.sec.gov. RSP undertakes no obligation to update or revise any forward-looking statement.

Statements of Operations
			Three Months Ended															Twelve Months Ended
(in thousands, except per share data)			December 31, 2017					September 30, 2017					December 31, 2016					December 31, 2017					December 31, 2016
Revenues:			(Unaudited)					(Unaudited)					(Unaudited)
Oil sales			$	218,182				174,624					$	110,376				$	704,838				$	321,588
Natural gas sales			9,308					9,661					5,103					36,206					13,945
NGL sales			21,533					17,369					7,455					62,664					18,324
Total revenues			249,023					201,654					122,934					803,708					353,857
Operating expenses:
Lease operating expenses			35,205					33,385					16,419					122,893					57,778
Production and ad valorem taxes			16,016					13,281					6,630					48,908					21,615
Depreciation, depletion, and amortization			77,159					73,408					52,484					279,711					194,360
Asset retirement obligation accretion			151					151					118					605					472
Impairments of oil and natural gas properties			52,935					705					579					59,077					4,901
Exploration expenses			825					1,497					265					7,771					1,093
General and administrative expenses			11,233					12,120					10,173					47,408					36,170
Acquisition costs			42					30					6,374					4,525					6,374
Total operating expenses			193,566					134,577					93,042					570,898					322,763
Operating income			55,457					67,077					29,892					232,810					31,094
Other income (expense)
Other income, net			1,021					1,106					1,246					3,436					1,833
Net loss on derivative instruments			(46,968		)			(21,626		)			(17,538		)			(39,279		)			(23,760		)
Interest expense			(22,174		)			(21,553		)			(13,683		)			(82,459		)			(52,724		)
Total other expense			(68,121		)			(42,073		)			(29,975		)			(118,302		)			(74,651		)
Income (loss) before income taxes			(12,664		)			25,004					(83		)			114,508					(43,557		)
Income tax benefit (expense)			153,450					(3,678		)			1,464					117,628					18,706
Net income (loss)			$	140,786				$	21,326				$	1,381				$	232,136				$	(24,851	)
Earnings (loss) per common share - Basic			$	0.89				$	0.14				$	0.01				$	1.50				$	(0.23	)
Earnings (loss) per common share - Diluted			$	0.89				$	0.14				$	0.01				$	1.49				$	(0.23	)
Weighted Average Common Shares Outstanding:
Basic			156,874					156,864					128,811					154,162					107,324
Diluted			158,060					157,837					128,811					155,526					107,324

Summary Balance Sheet
(in thousands)			December 31, 2017					December 31, 2016
Cash and cash equivalents			$	38,102				$	690,776
Other current assets			111,221					85,486
Total current assets			149,323					776,262
Property, plant and equipment, net			6,080,719					4,129,635
Other long-term assets			40,144					90,530
Total assets			$	6,270,186				$	4,996,427
Current liabilities			206,561					108,269
Long-term debt			1,509,128					1,132,275
Other long-term liabilities			232,139					338,571
Total stockholders' equity			4,322,358					3,417,312
Total liabilities and stockholders' equity			$	6,270,186				$	4,996,427

Drill-Bit F&D Costs and Reserve Replacement Ratios
				2017
Production (MBoe)		(A)			20,168
Proved Reserves (MBoe)
Price revisions					3,712
Non-price revisions		(B)			14,808
Purchases					47,485
Extensions and discoveries		(C)			93,217
Total additions					159,222
Total additions (excluding price revisions)		(D)			155,510
Costs Incurred (thousands)
Property acquisition costs
Proved				$	339,895
Unproved					1,253,326
Exploration		(E)			—
Development		(F)			675,988
Total costs incurred		(G)		$	2,269,209
Drill-Bit F&D and Reserve Replacement Ratios (1)
Drill-bit F&D ($/Boe)		(E+F) / (B+C)		$	6.26
Reserve replacement ratio		(D) / (A)			771	%
Organic reserve replacement ratio		(C+B) / (A)			536	%

			(1)		Exclude impact of price revisions.

Use of Non-GAAP Financial Measures

The Company defines Adjusted EBITDAX as oil and gas revenues including net cash receipts (payments) on settled derivative instruments and premiums paid on put options that settled during the period, less lease operating expenses, production and ad valorem taxes, and general and administrative expenses excluding stock based compensation. Adjusted Net Income deducts from Adjusted EBITDAX depreciation, depletion, and amortization, accretion on asset retirement obligations, exploration expenses, interest expense, stock-based compensation, acquisition costs and adjusted income tax expense.

Management believes Adjusted EBITDAX and Adjusted Net Income are useful because they allow the Company to more effectively evaluate its operating performance and compare the results of its operations from period to period without regard to financing methods or capital structure. The Company excludes the items listed above in arriving at Adjusted EBITDAX and Adjusted Net Income because these amounts can vary substantially from company to company within the Company's industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX and Adjusted Net Income should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX and Adjusted Net Income are significant components in understanding and assessing the Company’s financial performance, such as Company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. The Company's computations of Adjusted EBITDAX and Adjusted Net Income may not be comparable to other similarly titled measures of other companies.

The following tables include a reconciliation of the non-GAAP financial measures of Adjusted EBITDAX and Adjusted Net Income to the GAAP financial measure of net income.

Reconciliation of Net Income (Loss) to Adjusted EBITDAX
			Three Months Ended															Twelve Months Ended
(in thousands)			December 31, 2017					September 30, 2017					December 31, 2016					December 31, 2017					December 31, 2016
Net income (loss)			$	140,786				$	21,326				$	1,381				$	232,136				$	(24,851	)
Interest expense			22,174					21,553					13,683					82,459					52,724
Income tax expense (benefit)			(153,450		)			3,678					(1,464		)			(117,628		)			(18,706		)
Depreciation, depletion, and amortization			77,159					73,408					52,484					279,711					194,360
Asset retirement obligation accretion			151					151					118					605					472
Exploration expenses			825					1,497					265					7,771					1,093
Acquisition costs			42					30					6,374					4,525					6,374
Impairments of oil and natural gas properties			52,935					705					579					59,077					4,901
Loss on derivative instruments			46,968					21,626					17,538					39,279					23,760
Net settled derivative Instruments			(8,566		)			(2,567		)			(2,398		)			(14,661		)			(1,732		)
Stock-based compensation			4,422					4,361					3,215					17,150					13,764
Other income, net			(1,021		)			(1,106		)			(1,246		)			(3,436		)			(1,833		)
Adjusted EBITDAX			$	182,425				$	144,662				$	90,529				$	586,988				$	250,326

Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)
			Three Months Ended															Twelve Months Ended
(in thousands)			December 31, 2017					September 30, 2017					December 31, 2016					December 31, 2017					December 31, 2016
Net income (loss)			$	140,786				$	21,326				$	1,381				$	232,136				$	(24,851	)
Acquisition Costs			42					30					6,374					4,525					6,374
Impairments of oil and natural gas properties			52,935					705					579					59,077					4,901
Loss on derivative instruments			46,968					21,626					17,538					39,279					23,760
Net settled derivative Instruments			(8,566		)			(2,567		)			(2,398		)			(14,661		)			(1,732		)
Stock-based compensation - non recurring			—					—					—					—					682
Other income, net			(1,021		)			(1,106		)			(1,246		)			(3,436		)			(1,833		)
Adjustment to income taxes for above items			(181,022		)			(11,827		)			(8,833		)			(188,352		)			(14,659		)
Adjusted Net Income (Loss)			$	50,122				$	28,187				$	13,395				$	128,568				$	(7,358	)

View source version on businesswire.com: http://www.businesswire.com/news/home/20180227006591/en/

Source: Business Wire (February 27, 2018 - 4:15 PM EST)

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