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

Tuesday, February 27, 2018 3:15 pm CST

Dateline:

DALLAS

Public Company Information:

NYSE:
RSPP

DALLAS--(BUSINESS WIRE)--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 )
 

Contact:

RSP Permian, Inc.
Scott McNeill, 214-252-2700
Chief Financial Officer
or
Alyssa Stephens, 214-252-2764
Director, Investor Relations
or
Investor Relations, 214-252-2790
IR@rsppermian.com