News Releases

RSP Permian, Inc. Announces First Quarter 2017 Financial and Operating Results

DALLAS, May 2, 2017 /PRNewswire/ -- RSP Permian, Inc. ("RSP" or the "Company") (NYSE: RSPP) today reported financial and operating results for the quarter ended March 31, 2017.  In addition, the Company filed its Quarterly Report on Form 10-Q 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.

First Quarter 2017 Highlights

  • Production increased 84% to 45.2 MBoe/d (75% oil, 88% liquids), compared to 1Q16 and increased 26% compared to 4Q16
  • Net income of $38.9 million, or $0.26 per diluted share. Adjusted net income, which does not include certain items, was $24.2 million, or $0.16 per diluted share
  • Adjusted EBITDAX increased to $124.5 million, a 249% increase compared to 1Q16 and a 37% increase compared to 4Q16
  • Development capital expenditures (drilling, completion, infrastructure and other) of $115.6 million
  • Cash operating expenses of $10.49 per Boe, including lease operating expenses of $5.40 (before gathering and transportation) and $6.25 per Boe including gathering and transportation
  • On March 1, 2017, closed previously announced SHEP II acquisition for approximately $646 million of cash and 16.0 million shares of RSP common stock
  • Maintained strong liquidity position, with $54 million of cash and no borrowings outstanding under revolving credit facility ($1.1 billion borrowing base, $900 million Company-elected commitment)

Recent Well Results

  • Drilled and completed first horizontal well in the Delaware Basin. The Crockett Reese St #2403H, a 6,900' lateral well that targeted the lower interval of the Wolfcamp A, has established a peak 7-day average rate of 1,882 boe/d (71% oil), still cleaning up with ~2,500 psi of flowing pressure
  • Drilled and completed the furthest west Wolfcamp A horizontal well on our Midland Basin properties, located in Ector County. The Parks Bell 3924H, a 7,000' lateral well that targeted the Wolfcamp A, has established a peak 30-day average rate of 1,552 Boe/d (83% oil)
  • Reported one of RSP's best performing Midland Basin wells to date, on a per lateral foot basis. The Spanish Trail 344 1H, a 6,500' lateral well that targeted the Wolfcamp A, and had a peak 30-day average rate of 1,940 Boe/d (83% oil), produced 147 MBoe in 90 days

Steve Gray, Chief Executive Officer, commented, "I'm pleased to report solid quarterly results, particularly given we only recently closed SHEP II and assumed full operational control over our Delaware Basin assets.  The second quarter will include the full contribution of these assets to our operating and financial results.  Our operations team has made significant progress enhancing efficiency and coordinating infrastructure additions on the Delaware assets to accommodate higher activity levels during the second half of this year. We have accelerated the build-out of infrastructure projects in the second quarter on these properties and we anticipate adding a third horizontal rig in the Delaware Basin in May, bringing our total operated rig count to seven."

Mr. Gray continued, "We recently placed our first RSP-drilled and completed Delaware Basin horizontal well on production, which achieved a strong initial rate.  This well, along with recent non-operated and offset wells, highlight the robust potential of our Delaware properties.  We also reported an excellent result from the furthest west Wolfcamp A well drilled on our Midland Basin properties to date, in an area where we did not previously hold Wolfcamp wells in our drilling inventory.  Although recent market attention has been focused on our newly acquired Delaware assets, the strong and consistent well results from our Midland Basin portfolio continue to generate attractive rates of return and capital efficient growth at current commodity prices."

Operational Results


Three Months Ended March 31,
2017


2017


2016

Production data:




Oil (MBbls)

3,032



1,703


Natural gas (MMcf)

2,926



1,465


NGLs (MBbls)

547



293


Total (MBoe)

4,067



2,240


Average net daily production (Boe/d)

45,189



24,615


Average prices before effects of hedges (1) (2):




Oil (per Bbl)

$

50.01



$

30.35


Natural gas (per Mcf)

2.52



1.64


NGLs (per Bbl)

19.96



5.88


Total (per Boe)

$

41.78



$

24.92


Average realized prices after effects of hedges (1) (2):




Oil (per Bbl)

$

49.02



$

31.50


Natural gas (per Mcf)

2.59



1.64


NGLs (per Bbl)

19.96



5.88


Total (per Boe)

$

41.09



$

25.79


Average costs (per Boe):




Lease operating expenses (excluding gathering and transportation)

$

5.40



$

5.54


Gathering and transportation

0.85



0.31


Production and ad valorem taxes

2.33



1.85


Depreciation, depletion and amortization

15.01



19.89


General and administrative - recurring cash component

1.91



2.19


General and administrative - recurring stock comp (3)

0.96



1.38




(1)

Average prices shown in the table reflect prices both before and after the effects of our cash payments/receipts on our commodity derivative transactions. Our 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. No transportation costs are associated with NGL production and sales. 

(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.

Production volumes for the quarter ended March 31, 2017 averaged 45,189 Boe/d, or a total of 4,067 MBoe, an increase of 84% over prior year's first quarter of 24,615 Boe/d.  Production for the first quarter of 2017 was comprised of 75% crude oil, 12% natural gas and 13% NGLs.  RSP's average realized oil price for the first quarter of 2017, before the effects of hedges, was $50.01 per barrel, a negative $1.90 differential compared to average NYMEX WTI pricing of $51.91 per barrel for the same period, or 96% of NYMEX WTI pricing. RSP's average realized natural gas price for the first quarter of 2017, before the effects of hedges, was $2.52 per Mcf, a negative $0.80 differential compared to average NYMEX Henry Hub pricing of $3.32 per MMBtu for the same period, or 76% of NYMEX Henry Hub pricing.  RSP's average realized NGL price for the first quarter of 2017, before the effects of hedges, was $19.96 per Bbl, or 38% of NYMEX WTI pricing for the same time period.  RSP's average realized commodity price per barrel of oil equivalent for the first quarter of 2017, before the effects of hedges, was $41.78.  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 $10.49 per Boe.

Operational Update

The Company operated four horizontal rigs in the Midland Basin during the majority of the first quarter of 2017, adding a fourth rig in January.  In the Delaware Basin, the Company added a second horizontal rig upon closing the SHEP II acquisition on March 1, 2017.  RSP utilized one full-time completion crew during the first quarter in the Midland Basin and a part-time crew in the Delaware Basin.  RSP drilled 21 operated horizontal wells and completed 14 operated horizontal wells (Midland: two Lower Spraberry, five Wolfcamp A, five Wolfcamp B; Delaware: one Wolfcamp A, one Wolfcamp XY).  The Company began the quarter with 11 operated horizontal drilled but uncompleted wells ("DUCs") and exited the quarter with a total of 18 operated horizontal DUCs.

Financial Results


Three Months Ended



March 31,

December 31,



2017

2016

2016



(In thousands, except for per share data)






Total Revenues

$

169,931


$

55,815


$

122.934



  Net Cash from Derivative Instruments

(2,812)


1,950


(2,398)



  Adjusted Total Revenues

167,119


57,765


120,536








Net Income (Loss)

$

38,934


$

(17,416)


$

1,381



  Net Income (Loss) per Common Share - Diluted

0.26


(0.17)


0.01








Adjusted Net Income (Loss) (1)

$

24,212


$

(16,231)


$

13,395



  Adjusted Net Income (Loss) per Common Share - Diluted

0.16


(0.16)


0.10








Adjusted EBITDAX (1)

$

124,451


$

35,610


$

90,529






(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 March 31, 2017, total revenues, excluding the revenue impact from realized derivative instruments, were $169.9 million, a 204% increase over the prior year quarter of $55.8 million.  Adjusted total revenues, including the net cash from derivative instruments, were $167.1 million, a 189% increase from the prior year quarter of $57.8 million.  Net income for the first quarter of 2017 was $38.9 million, or $0.26 per diluted share, while net loss for the prior year quarter was $17.4 million, or negative $0.17 per diluted share.  Adjusted net income for the first quarter of 2017 was $24.2 million, or $0.16 per diluted share, compared to an Adjusted net loss for the prior year quarter of $16.2 million or negative $0.16 per diluted share.  Adjusted EBITDAX was $124.5 million, a 249% increase from the prior year quarter of $35.6 million

Capital Expenditures

RSP's development capital expenditures, which includes our investment in drilling and completing wells, infrastructure, capitalized workovers, and other, but excludes the cost of acquisitions, for the quarter ended March 31, 2017 totaled $115.6 million ($110.5 million of drilling and completion and $5.1 million of infrastructure and other).  Of the development capital, approximately $11.6 million, or 10%, was spent on non-operated properties.

Additionally, during the first quarter of 2017 the Company acquired $16.5 million of oil and gas properties, exclusive of the SHEP II acquisition, along with $18.8 million of water infrastructure assets which service the Delaware Basin properties.

Liquidity

As of March 31 2017, the Company had $54.3 million of cash and no borrowings outstanding on its revolving credit facility, which has a $1.1 billion borrowing base and a $900 million Company-elected commitment. 

Hedging

The summary below includes all hedges in place for the remainder of 2017 and for 2018, as of May 2, 2017.


(Bbl, $/Bbl)


Q2 2017


Q3 2017


Q4 2017


2018

Three-Way Collars(1)









3,160,000


Ceiling








$

65.06


Floor








$

50.00


Short Put








$

40.00











Costless Collars(1)



1,137,500




1,150,000




1,150,000




Ceiling


$

60.05



$

60.05



$

60.05




Floor


$

45.00



$

45.00



$

45.00













Deferred Premium Puts(1)



910,000




920,000



920,000




Floor


$

48.50



$

48.50



$

48.50




Deferred Premium(2)


$

(4.00)



$

(4.00)



$

(4.00)













Total Hedge Volumes



2,047,500




2,070,000




2,070,000




3,160,000


Weighted Average Floor(3)



44.78




44.78




44.78



$

50.00











Mid-Cush Differential Swaps:



2,548,000




920,000




276,000




Swap(4)


$

(0.11)



$

(0.38)



$

(0.50)






(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)

The deferred premium is not paid until expiration date, aligning cash inflows and outflows with the settlement of the derivative contract.

(3)

Weighted average floor assumes the long put in three way collars and put spreads and reflects the impact of premiums paid

(4)

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.

 

Natural Gas Hedges

(MMBtu, $/MMBtu)


Q2 2017


Q3 2017


Q4 2017

Costless Collars(1)


2,366,000



2,422,000



2,545,000


Ceiling


$

3.86



$

3.86



$

3.86


Floor


$

3.00



$

3.00



$

3.00




(1)

The natural gas derivative contracts are settled based on the last trading day's closing price for the front month contract relevant to each period.

2017 Annual Guidance



First Quarter 2017
Actual Results


2017 Guidance


Completions






Operated Gross Horizontal Completions


14


85 - 95


  Operated Average Working Interest


83%


88%


  Midland Basin Average Lateral Length


~8,200'


~8,500'


  Delaware Basin Average Lateral Length


~6,700'


~6,250'








Production






Average Daily Production (Boe/d)


45,189


53,000 - 57,000


  % Oil


75%


71% - 73%


  % Natural Gas


12%


11% - 13%


  % NGLs


13%


15% - 17%








Development Capital Expenditures ($ in MM)






Drilling and Completion (D&C)


$110.5


$575 - $625


Infrastructure, Capitalized Workovers & Other


$5.1


$50 - $75


Total Development Capital Expenditures


$115.6


$625 - $700


  % Midland Basin


80%


60% - 70%


  % Delaware Basin


20%


30% - 40%


  % Non-Operated


10%


5% - 10%








Income Statement ($/Boe)






Lease operating expenses (including workovers)


$5.40


$4.50 - $5.50


Gathering and transportation


$0.85


$1.10 - $1.40


Exploration expenses


$0.63


$0.40 - $0.60


General and administrative - recurring cash component


$1.91


$1.25 - $1.75


General and administrative - recurring stock comp


$0.96


$0.70 - $0.90


Depreciation, depletion, and amortization


$15.01


$14.00 - $16.00


Production and ad valorem taxes (% of oil and gas revenues)


5.6%


6.0% - 8.0%


First Quarter 2017 Earnings Release and Conference Call

RSP will host a conference call for investors at 1:00 PM Central Time on Wednesday, May 3, 2017, to discuss first quarter 2017 results.  Hosting the call will be Steve Gray, Chief Executive Officer, Scott McNeill, Chief Financial Officer and other members of RSP's management team.

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 13659950.  The replay will be available until May 17, 2017. 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 our 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


(In thousands, except per share data)



Three Months
Ended March 31,


Three Months
Ended December 31,


2017


2016


2016

Revenues:






  Oil sales

$

151,637



$

51,690



$

110,376


  Natural gas sales

7,378



2,403



5,103


  NGL sales

10,916



1,722



7,455








           Total revenues

169,931



55,815



122,934








Operating expenses:






  Lease operating expenses

$

25,411



$

13,091



$

16,419


  Production and ad valorem taxes

9,469



4,153



6,630


  Depreciation, depletion, and amortization

61,040



44,558



52,484


  Asset retirement obligation accretion

153



113



118


  Impairments

125



173



579


  Exploration

2,580



64



265


  General and administrative expenses

11,712



8,005



10,173


  Acquisition Costs

4,052





6,374








           Total operating expenses

$

114,542



$

70,157



$

93.042








Operating income (loss)

$

55,389



$

(14,342)



$

29,892








Other income (expense)






  Other income, net

$

720



$

173



$

1,246


  Net gain (loss) on derivative instruments

17,121



396



(17,538)


  Interest expense

(19,224)



(12,941)



(13,683)








           Total other income (expense)

(1,383)



(12,372)



(29,975)








Income (loss) before income taxes

54,006



(26,714)



(83)








Income tax benefit (expense)

(15,072)



9,298



1,464








Net income (loss)

$

38,934



$

(17,416)



$

1,381








  Net income (loss) per common share - Basic

$

0.27



$

(0.17)



$

0.01


  Net income (loss) per common share - Diluted

$

0.26



$

(0.17)



$

0.01








Weighted Average Common Shares Outstanding:






Basic

146,054



100,060



128,811


Diluted

147,005



100,060



128,811


 

Summary Balance Sheet


(In thousands)



March 31, 2017

December 31, 2016





Cash and cash equivalents

$

54,260


$

690,776

Other current assets

91,817


85,486

Total current assets

146,077


776,262

Property, plant and equipment, net

5,529,103


4,129,635

Other long-term assets

50,694


90,530

Total assets

$

5,725,874


$

4,996,427





Current liabilities

113,169


108,269

Long-term debt

1,132,358


1,132,275

Other long-term liabilities

363,920


338,571

Total stockholders' equity

4,116,427


3,417,312

Total liabilities and stockholders' equity

$

5,725,874


$

4,996,427











Use of Non-GAAP Financial Measures

We define 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 us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving at Adjusted EBITDAX and Adjusted Net Income because these amounts can vary substantially from company to company within our 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 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 EBITDAX. Our 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


(In thousands)



Three Months Ended
March 31,


Three Months Ended
December 31,


2017


2016


2016







Net income (loss)

38,934



(17,416)



$

1,381


Interest expense

19,224



12,941



13,683


Income tax expense (benefit)

15,072



(9,298)



(1,464)


Depreciation, depletion, and amortization

61,040



44,558



52,484


Asset retirement obligation accretion

153



113



118


Exploration

2,580



64



265


Acquisition Costs

4,052





6,374


Impairments

125



173



579


Loss (gain) on derivative instruments

(17,121)



(396)



17,538


Net Settled Derivative Instruments

(2,812)



1,950



(2,398)


Stock-based compensation, net

3,924



3,094



3,215


Other income, net

(720)



(173)



(1,246)


Adjusted EBITDAX

$

124,451



$

35,610



$

90,529


 

Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)


(In thousands)



Three Months Ended
March 31,


Three Months Ended
December 31,


2017


2016


2016







Net income (loss)

$

38,934



$

(17,416)



$

1,381


Acquisition Costs

4,052





6,374


Impairments

125



173



579


Loss (gain) on derivative instruments

(17,121)



(396)



17,538


Net Settled Derivative Instruments

(2,812)



1,950



(2,398)


Other income, net

(720)



(173)



(1,246)


Income tax benefit (expense) for above items

1,754



(369)



(8,833)


Adjusted Net Income (Loss)

$

24,212



$

(16,231)



$

13,395


 

 

SOURCE RSP Permian, Inc.

For further information: Investor Contact: Scott McNeill, Chief Financial Officer, 214-252-2700; Alyssa Stephens, Director, Investor Relations, 214-252-2764; Investor Relations: IR@rsppermian.com, 214-252-2790
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