U.S. Markets close in 2 hrs 40 mins

RSP Permian, Inc. Announces Fourth Quarter and Year-End 2016 Financial and Operating Results, Year-End 2016 Proved Reserves, 2017 Guidance and 2018 and 2019 Production Outlook

DALLAS, Feb. 27, 2017 /PRNewswire/ -- RSP Permian, Inc. ("RSP" or the "Company") (RSPP) today reported financial and operating results for the quarter and year ended December 31, 2016, year-end 2016 proved reserves, 2017 guidance and 2018 and 2019 production outlook.  In addition, the Company filed its Annual Report on Form 10-K for the year ended December 31, 2016 with the Securities and Exchange Commission (the "SEC") and posted an updated presentation on its website at www.rsppermian.com.

Highlights for the Fourth Quarter and Full Year 2016:

  • 4Q16 production increased 48% to 35.8 MBoe/d (71% oil, 88% liquids), compared to 4Q15
  • Full year 2016 production increased 39% to 29.2 MBoe/d (73% oil, 89% liquids), compared to 2015
  • 4Q16 net income of $1.4 million, or $0.01 per diluted share. Adjusted net income, which does not include certain items, was $13.4 million, or $0.10 per diluted share
  • 4Q16 adjusted EBITDAX increased 22% to $90.5 million compared to 4Q15
  • 4Q16 cash operating expenses of $9.11/Boe, 23% below 2015 average of $11.85
  • 4Q16 development capital expenditures of $95.5 million
  • Full year 2016 development capital expenditures of $294.2 million
  • Entry into the Delaware Basin with previously announced $2.4 billion acquisition of Silver Hill Energy Partners, LLC ("SHEP I") and pending acquisition of Silver Hill E&P II, LLC ("SHEP II"), expected to close March 1, 2017
  • Maintained strong year-end liquidity position and balance sheet, pro forma closing of SHEP II with $109 million of cash and no borrowings outstanding under revolving credit facility
    • Amended and restated credit facility, extending maturity date to December 2021, increasing borrowing base to $1.1 billion upon closing SHEP II, and increasing lender's commitments to $2.5 billion
  • Pro forma proved reserves increased by 78% to 283 MMBoe(1) (70% oil, 88% liquids) over 2015
  • Achieved low drill-bit finding and development cost of $4.05/Boe with an 848% reserve replacement ratio and a 684% organic reserve replacement ratio(2)

Recent Midland Basin Well Results

  • Mask 1004/1005 two-well pad in Midland County: Two 9,500' lateral wells, targeting the Lower Spraberry and Wolfcamp B formations, flowed naturally producing almost 200,000 Boe before being put on electric submersible pump ("ESP") and establishing peak 30-day average rate of 2,932 Boe/d (73% oil)
  • Spanish Trail 344 two-well pad and Spanish Trail 341 two-well pad: Four 6,500' lateral wells, with two wells each targeting the Wolfcamp A and Wolfcamp B formations, established a peak 30-day average rate of 6,212 Boe/d (79% oil) and produced in excess of 250,000 Boe in less than 60 days

2017 Guidance and 2018 and 2019 Production Outlook

  • Average net daily production range of 53.0 - 57.0 MBoe/d in 2017, an 82% - 95% increase over 2016
  • Development capital expenditure range of $625 - $700 million (drilling, completion, infrastructure and other) with drilling and completion of $575 - $625 million and infrastructure and other of $50 - $75 million
  • 30%+ annual production growth profile in 2018 and 2019 with cash flow neutrality beginning in 2018 at $55 oil
  • Expanded hedge profile covering 55% of 2017E oil production and 64% of 2017E natural gas volumes at the midpoint. Entered into basis swaps to protect Midland-Cushing differentials and began layering in 2018 oil hedges

Steve Gray, Chief Executive Officer, commented, "I am pleased to report our fourth quarter and full year results, highlighted by annual production growth of nearly 40% with 25% less in capital expenditures as compared to last year.  Importantly, we continued to operate efficiently with strong cash margins and record low drill-bit finding and development costs.  During the year, we reduced our activity levels in response to depressed oil prices early in the year and remained patient on M&A opportunities until we identified high quality properties that would compete for capital in our existing portfolio.  With our recent entry into the Delaware Basin through our $2.4 billion acquisition of Silver Hill, we believe we have assembled one of the most focused and highest returning asset bases in the Permian Basin, solidifying our ability to achieve outstanding growth and strong operating and capital efficiency for years to come."

Mr. Gray continued, "I am also pleased to announce that our shareholders have overwhelmingly approved our issuance of RSP common stock to partially fund the SHEP II transaction which we expect to close Wednesday.   We have already begun to integrate the Silver Hill assets into our inventory and are working towards achieving efficient, multi-zone horizontal development on the acquired properties.  In addition, we recently acquired the underlying water disposal infrastructure supporting our operations in the Delaware.  We are currently expanding these facilities and developing new facilities to support our growing operations and lower our operating costs.  We are also working diligently with our various midstream partners and expect to be in position to ramp our drilling program beginning in the second half of 2017.  Recent strong well results, which span five horizontal zones on the properties, highlight the attractive return profile in multiple stacked horizontal zones on our Delaware acreage position."

(1) Includes SHEP II.  Pro forma proved reserves prepared by Netherland Sewell & Associates, Inc. (NSAI).
(2) See "Drill-Bit F&D and Reserve Replacement Ratios" below for calculations.

Operational Results


Three Months Ended December 31,


Twelve Months Ended December 31,


2016


2015


2016


2015

Production data:








Oil (MBbls)

2,337



1,683



7,790



5,805


Natural gas (MMcf)

2,278



1,554



7,188



4,991


NGLs (MBbls)

576



289



1,685



1,045


Total (MBoe)

3,293



2,231



10,673



7,682


Average net daily production (Boe/d)

35,793



24,250



29,161



21,047


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








Oil (per Bbl)

$

47.23



$

40.00



$

41.28



$

45.36


Natural gas (per Mcf)

2.24



1.91



1.94



2.11


NGLs (per Bbl)

12.94



11.13



10.87



9.75


Total (per Boe)

$

37.33



$

32.95



$

33.15



$

36.97


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








Oil (per Bbl)

$

46.20



$

53.74



$

41.06



$

61.22


Natural gas (per Mcf)

2.24



1.91



1.94



2.11


NGLs (per Bbl)

12.94



11.13



10.87



9.75


Total (per Boe)

$

36.60



$

43.31



$

32.99



$

48.96


Average costs (per Boe):








Lease operating expenses (excluding gathering and transportation)

$

4.41



$

4.76



$

4.93



$

6.46


Gathering and transportation

0.57



0.42



0.48



0.46


Production and ad valorem taxes

2.01



2.56



2.03



2.60


Depreciation, depletion and amortization

15.94



17.88



18.21



20.05


General and administrative - recurring cash component

2.11



2.24



2.10



2.33


General and administrative - recurring stock comp (3)

0.98



0.93



1.23



1.03


General and administrative - non-recurring stock comp (4)



0.15



0.06



0.19




(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.

(4)

Non-recurring stock comp in 2015 includes compensation expense related to the successful completion of the Company's initial public offering and related expenses associated with one-time restricted stock awards.  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, 2016 averaged 35,793 Boe/d or a total of 3,293 MBoe, an increase of 48% over prior year's fourth quarter of 24,250 Boe/d.  Production for the fourth quarter of 2016 was comprised of 71% crude oil, 12% natural gas and 17% NGLs.  RSP's average realized commodity price per barrel of oil equivalent for the fourth quarter of 2016, before the effects of hedges, was $37.33.  RSP's average realized oil price for the fourth quarter of 2016, before the effects of hedges, was $47.23 per barrel, a negative $2.06 differential compared to average NYMEX WTI pricing of $49.29 per barrel for the same period, or 96% of NYMEX WTI pricing. RSP's average realized natural gas price for the fourth quarter of 2016, before the effects of hedges, was $2.24 per Mcf, a negative $0.74 differential compared to average NYMEX Henry Hub pricing of $2.98 per MMBtu for the same period, or 75% of NYMEX Henry Hub pricing.  RSP's average realized NGL price for the fourth quarter of 2016, before the effects of hedges, was $12.94 per Bbl, or 26% 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 $9.11 per Boe, an 9% decrease from prior year's comparable quarter.

Production volumes for the year ended December 31, 2016 averaged 29,161 Boe/d or a total of 10,673 MBoe, an increase of 39% over prior year's total of 21,047 Boe/d.  Production for 2016 was comprised of 73% crude oil, 11% natural gas and 16% NGLs.  RSP's average realized commodity price per barrel of oil equivalent for 2016, before the effects of hedges, was $33.15.  RSP's average realized oil price for 2016, before the effects of hedges, was $41.28 per barrel, a negative $2.04 differential compared to average NYMEX WTI pricing of $43.32 per barrel for the same period, or 95% of NYMEX WTI pricing. RSP's average realized natural gas price for 2016, before the effects of hedges, was $1.94 per Mcf, a negative $0.52 differential compared to average NYMEX Henry Hub pricing of $2.46 per MMBtu for the same period, or 79% of NYMEX Henry Hub pricing.  RSP's average realized NGL price for 2016, before the effects of hedges, was $10.87 per Bbl, or 25% 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 $9.54 per Boe, a 19% decrease from prior year's comparable total.

Operational Update

The Company operated three horizontal rigs in the Midland Basin during the fourth quarter, and upon closing the acquisition of SHEP I, operated one rig in the Delaware Basin during December.  RSP utilized one full-time completion crew during the fourth quarter in the Midland Basin and a part-time crew in the Delaware Basin during December.  RSP drilled 13 operated horizontal wells and completed 14 operated horizontal wells (seven Lower Spraberry, three Wolfcamp A, three Wolfcamp B and one Avalon) and two operated vertical wells during the fourth quarter.  The Company began the quarter with 12 operated horizontal drilled but uncompleted wells ("DUCs") and exited the quarter with a total of 11 operated horizontal DUCs.  During 2016, RSP drilled 46 and completed 53 operated horizontal wells (one Middle Spraberry, 35 Lower Spraberry, eight Wolfcamp A, eight Wolfcamp B and one Avalon) and drilled four and completed six operated vertical wells.




4Q16 Wells


2016 Wells




Drilled


Completed


Drilled but
Uncompleted
Wells (DUCs)


Drilled


Completed














Operated Wells












Horizontal


13



14



11



46



53



Vertical




2





4



6



     Total Operated


13



16



11



50



59















Non-Operated Wells












Horizontal


6



13



11



35



37



Vertical








1



1



     Total Non-Operated


6



13



11



36



38















Total Wells












Horizontal


19



27



22



81



90



Vertical




2





5



7



     Total Wells


19



29



22



86



97



 

Financial Results

(In thousands, except per share data)



Three Months Ended


Twelve Months Ended


December 31,


December 31,


2016

2015


2016

2015

Total Revenues

$

122,934


$

73,508



$

353,857


$

283,992


  Net Cash from Derivative Instruments

(2,398)


23,122



(1,732)


92,118


  Adjusted Total Revenues

120,536


96,630



352,125


376,110








Net Income (Loss)

$

1,381


$

(20,751)



$

(24,851)


$

(18,254)


  Net Income (Loss) per Common Share - Diluted

0.01


(0.21)



(0.23)


(0.21)








Adjusted Net Income (Loss) (1)

13,395


12,074



(7,358)


48,630


  Adjusted Net Income (Loss) per Common Share - Diluted

0.10


0.12



(0.07)


0.56








Adjusted EBITDAX (1)

$

90,529


$

74,367



$

250,326


$

285,058




(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, 2016, total revenues, excluding the revenue impact from realized derivative instruments, were $122.9 million, a 67% increase over the prior year quarter of $73.5 million.  Adjusted total revenues, including the net cash from derivative instruments, were $120.5 million, an increase of 25% over the prior year quarter of $96.6 million.  Net income for the fourth quarter of 2016 was $1.4 million, or approximately one cent per diluted share, while net loss for the fourth quarter of 2015 was $20.8 million, or negative $0.21 per diluted share.  Adjusted net income for the quarter was $13.4 million, or $0.10 per diluted share, compared with adjusted net income for the prior year quarter of $12.1 million or $0.12 per diluted share.  Adjusted EBITDAX for the quarter ended was $90.5 million, an increase of 22% over the prior year quarter of $74.4 million. 

For the year ended December 31, 2016, total revenues, excluding the revenue impact from realized derivative instruments, were $353.9 million, a 25% increase over the prior year of $284.0 million.  Adjusted total revenues, including the net cash from derivative instruments, were $352.1 million, an decrease of 6% from the prior year of $376.1 million.  Net loss for the year ended 2016 was $24.9 million, or negative $0.23 per diluted share, while net loss for the year ended 2015 was $18.3 million, or negative 0.21 per diluted share.  Adjusted net loss for the year ended 2016 was  $7.4 million, or negative $0.07 per diluted share, compared with adjusted net income for the prior year of $48.6 million or $0.56 per diluted share.  Adjusted EBITDAX for the year ended 2016 was $250.3 million, a decrease of 12% from the prior year ended 2015 of $285.1 million. 

Proved Reserves Summary

RSP's proved reserves summary as of December 31, 2016 and pro forma proved reserved summary as of December 31, 2016 were prepared by Netherland, Sewell & Associates, Inc.

Our December 31, 2016 proved reserves summary included reserves from the SHEP I acquisition that closed on November 28, 2016 and totaled 236.9 MMBoe.  Pro forma for the SHEP II acquisition, which is expected to close on March 1, 2017, our total proved reserves as of December 31, 2016 were 283.3 MMBoe. The Company removed its remaining economic reserves associated with vertical proved undeveloped locations from its proved reserve base due to the superior economics of horizontal drilling locations which are expected to be drilled in front of the vertical locations over the next five years.  This resulted in a 23.4 MMBoe downward revision to proved reserves offset by positive revisions from horizontal wells that are performing above previous estimates, resulting in total downward revisions of previous estimates of 17.8 MMBoe.

The following table presents the Company's estimated net proved oil and natural gas reserves as of December 31, 2016 (excluding SHEP II acquisition) and net proved oil and natural gas reserves as of December 31, 2015, and in each case, 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 December 31, 2015

111,135



133,507



25,787



159,173


Revisions of previous estimates

(14,115)



(30,284)



1,412



(17,750)


Extensions, discoveries and other additions

46,017



45,541



11,631



65,238


Purchases of minerals in place

29,481



35,210



5,551



40,900


Production

(7,790)



(7,188)



(1,685)



(10,673)


As of December 31, 2016

164,728



176,786



42,696



236,888


The following table presents the Company's estimated net proved oil and natural gas reserves as of December 31, 2016, 2015 and 2014, as well as our pro forma net proved oil and natural gas reserves as of December 31, 2016, after giving effect to the SHEP II acquisition as if it had occurred before December 31, 2016.



Pro Forma
2016


2016


2015


2014










Proved developed reserves:









Oil (MBbls)


75,341



65,025



44,128



27,716


Natural gas (MMcf)


86,475



76,255



56,640



35,921


NGLs (MBbls)


20,864



18,759



11,020



8,221


Total (MBoe)


110,617



96,493



64,588



41,924


Proved undeveloped reserves:









Oil (MBbls)


123,601



99,703



67,007



41,557


Natural gas (MMcf)


122,959



100,531



76,867



56,501


NGLs (MBbls)


28,575



23,937



14,767



13,518


Total (MBoe)


172,669



140,395



94,585



64,492


Total proved reserves:









Oil (MBbls)


198,942



164,728



111,135



69,273


Natural gas (MMcf)


209,434



176,786



133,507



92,422


NGLs (MBbls)


49,439



42,696



25,787



21,739


Total (MBoe)


283,286



236,888



159,173



106,416


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, 2016 totaled $294 million ($275 million of drilling and completion and $19 million of infrastructure and other).  The Company spent approximately $57 million, or 19% of development capital, on non-operated properties.  Additionally, during 2016 the Company closed approximately $69 million of acquisitions and additions to leasehold in the Midland Basin and closed the SHEP I acquisition for approximately 15 million shares of RSP stock and $604 million in cash.

Capital Markets Transactions and Amended and Restated Credit Agreement

On October 13, 2016, the Company priced an underwritten public offering of 25.3 million shares of RSP common stock, including the exercise of the underwriters' option to purchase additional shares, raising approximately $1.0 billion in net proceeds.  On December 12, 2016, RSP priced $450 million aggregate principal amount of 5.25% senior unsecured notes due 2025 at par.  RSP used a portion of the net proceeds raised in these offerings to fund the cash portion of the SHEP I acquisition and will use the balance of the proceeds to fund the cash portion of the SHEP II acquisition.

On December 20, 2016, RSP announced it entered into an amended and restated credit agreement with respect to the Company's senior secured revolving credit facility. The amended and restated credit agreement extended the maturity date of the facility until December 19, 2021, increased the borrowing base under the facility to $950 million and increased the maximum commitments of the lenders from $1.0 billion to $2.5 billion. The $950 million borrowing base only reflected the reserve growth from the Company's Midland Basin assets and the previously closed SHEP I acquisition. Upon closing the SHEP II acquisition, RSP's borrowing base will automatically increase to $1.1 billion. RSP elected an aggregate commitment amount of $900 million under the facility and will leave this amount unchanged upon the closing of SHEP II.

As of December 31, 2016, the Company had no borrowings outstanding on its revolving credit facility and had $691 million of cash on hand.  Pro forma for closing the acquisition of SHEP II, as of December 31, 2016, the Company had $109 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 full year 2017 and 2018, as of February 27, 2017.

Crude Oil Hedges

(Bbl, $/Bbl)


Q1 2017


Q2 2017


Q3 2017


Q4 2017


2018

Three-Way Collars(1)


675,000









3,160,000


Ceiling


$

54.25









$

65.06


Floor


$

45.00









$

50.00


Short Put


$

35.00









$

40.00













Costless Collars(1)


450,000



1,137,500



1,150,000



1,150,000




Ceiling


$

59.75



$

60.05



$

60.05



$

60.05




Floor


$

45.00



$

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)















Deferred Premium Put Spreads(1)


675,000










Floor


$45.00










Short Put


$35.00










Deferred Premium(2)


($2.32)





















Total Hedge Volumes


1,800,000



2,047,500



2,070,000



2,070,000



3,160,000


Weighted Average Floor(3)


$

44.13



$

44.78



$

44.78



$

44.78



$

50.00













Mid-Cush Differential Swaps:


1,881,000



2,548,000



920,000



276,000




Swap(4)


$

(0.14)



$

(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)


Q1 2017


Q2 2017


Q3 2017


Q4 2017

Costless Collars(1)


1,955,000



2,366,000



2,422,000



2,545,000


Ceiling


$

3.83



$

3.86



$

3.86



$

3.86


Floor


$

3.00



$

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

RSP's operating plan is expected to build momentum in the back half of 2017.  After growing production an estimated 82% - 95% in 2017, both organically and with the production volumes associated with the Silver Hill acquisition, the Company anticipates it will deliver annual production growth in excess of 30% in both 2018 and 2019 while being cash flow neutral beginning in 2018 at a $55 oil price.

As a result of the staggered closing of the Silver Hill transactions and the anticipated rig additions during the year, the investment of capital expenditures is expected to be approximately 60 - 70% in the Midland Basin and 30 - 40% in the Delaware Basin for a total developmental capital budget of $625 million to $700 million.

The Company recently deployed a fourth operated rig on its Midland Basin properties earlier than anticipated in mid-January and plans to operate at least four rigs on its Midland assets for the balance of the year.  RSP is currently operating one rig on its Delaware properties and will have a second operated rig working upon closing SHEP II.  RSP anticipates adding a third operated rig on its Delaware properties after enhancing infrastructure to enable more efficient horizontal development.  Additionally, RSP anticipates adding an additional operated rig during the fourth quarter and at that time will have a total of eight operated rigs.

The following table summarizes the Company's guidance for 2017.




2017 Guidance


Completions




Operated Gross Horizontal Completions


85 - 95


  Operated Average Working Interest


88%


  Midland Basin Average Lateral Length


~8,500'


  Delaware Basin Average Lateral Length


~6,250'






Production




Average Daily Production (Boe/d)


53,000 - 57,000


  % Oil


71% - 73%


  % Natural Gas


11% - 13%


  % NGLs


15% - 17%






Development Capital Expenditures ($ in MM)




Drilling and Completion (D&C)


$575 - $625


Infrastructure, Capitalized Workovers & Other


$50 - $75


Total Development Capital Expenditures


$625 - $700


  % Midland Basin


60% - 70%


  % Delaware Basin


30% - 40%


  % Non-Operated


5% - 10%






Income Statement ($/Boe)




Lease operating expenses (including workovers)


$4.50 - $5.50


Gathering and transportation


$1.10 - $1.40


Exploration expenses


$0.40 - $0.60


General and administrative - cash component


$1.25 - $1.75


General and administrative - recurring stock comp


$0.70 - $0.90


Depreciation, depletion, and amortization ($/Boe)


$14.00 - $16.00


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 1:00 PM Central Time on Tuesday, February 28, 2017, to discuss fourth quarter and full-year 2016 results.  Hosting the call will be Steve Gray, Chief Executive Officer, Zane Arrott, Chief Operating Officer and Scott McNeill, Chief Financial Officer.

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 13654848.  The replay will be available until March 14, 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
December 31,


Twelve Months Ended
December 31,


2016


2015


2016


2015

Revenues:








  Oil sales

$

110,376



$

67,318



$

321,588



$

263,286


  Natural gas sales

5,103



2,973



13,945



10,517


  NGL sales

7,455



3,217



18,324



10,189










           Total revenues

122,934



73,508



353,857



283,992










Operating expenses:








  Lease operating expenses

$

16,419



$

11,546



$

57,778



53,124


  Production and ad valorem taxes

6,630



5,722



21,615



19,995


  Depreciation, depletion, and amortization

52,484



39,887



194,360



154,039


  Asset retirement obligation accretion

118



84



472



336


  Impairments

579



30,031



4,901



34,269


  Exploration

265



96



1,093



2,380


  General and administrative expenses

10,173



7,404



36,170



27,317


  Acquisition Costs

6,374





6,374












           Total operating expenses

93,042



94,770



322,763



291,460










  Loss on sale of assets

$



$

302



$



$

306










Operating income (loss)

$

29,892



$

(21,564)



$

31,094



$

(7,774)










Other income (expense)








  Other income, net

$

1,246



$

242



$

1,833



469


  Net gain (loss) on derivative instruments

(17,538)



3,439



(23,760)



20,906


  Interest expense

(13,683)



(13,175)



(52,724)



(43,538)










           Total other income (expense)

(29,975)



(9,494)



(74,651)



(22,163)










Income (loss) before income taxes

(83)



(31,058)



(43,557)



(29,937)










Income tax benefit (expense)

1,464



10,307



18,706



$

11,683










Net income (loss)

$

1,381



$

(20,751)



$

(24,851)



$

(18,254)










  Net income (loss) per common share - Basic

$

0.01



$

(0.21)



$

(0.23)



$

(0.21)


  Net income (loss) per common share - Diluted

$

0.01



$

(0.21)



$

(0.23)



$

(0.21)










Weighted Average Common Shares Outstanding:








Basic

128,811



98,556



107,324



86,770


Diluted

128,811



98,556



107,324



86,770


 

Summary Balance Sheet


(In thousands)



December 31, 2016


December 31, 2015





Cash and cash equivalents

$

690,776



$

142,741


Other current assets

85,486



44,799


Total current assets

776,262



187,540


Property, plant and equipment, net

4,129,635



2,758,630


Other long-term assets

90,530



21,263


Total assets

$

4,996,427



$

2,967,433






Current liabilities

108,269



77,402


Long-term debt

1,132,275



686,512


Other long-term liabilities

339,155



344,935


Total stockholders' equity

3,416,728



1,858,584


Total liabilities and stockholders' equity

$

4,996,427



$

2,967,433


 

Drill-Bit F&D Costs and Reserve Replacement Ratios





2016

Production (MBoe)


(A)

10,673






Proved Reserves (MBoe)




Non-price revisions (1)


(B)

(15,619)


Purchases



40,900


Extensions and discoveries


(C)

65,238


Total additions


(D)

90,519






Non-Price Revision Detail (MBoe)




Revisions from vertical PUD write off


(V)

(23,359)


Other non-price revisions


(N)

7,740


Total non-price revisions


(B)

(15,619)






Costs Incurred (thousands)




Property acquisition costs




Proved



$

210,977


Unproved



1,063,109


Exploration


(E)

1,811


Development


(F)

293,833


Total costs incurred


(G)

$

1,569,730






Drill-bit F&D ($/Boe)


(E+F) / (B+C)

$5.96


Drill-bit F&D excluding vertical PUD write off ($/Boe)


(E+F) / (B+C-V)

$4.05


All sources F&D ($/Boe)


(G) / (D)

$17.34


Reserve replacement ratio


(D) / (A)

848%


Organic reserve replacement ratio


(C+N) / (A)

684%




(1)

Total negative revisions for 2016 were 17,750 MBoe, including negative non-price related revisions of 15,619 MBoe and negative price related revisions of 2,131 MBoe.

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
December 31,


Twelve Months Ended
December 31,


2016


2015


2016


2015









Net income (loss)

$

1,381



$

(20,751)



$

(24,851)



$

(18,254)


Interest expense

13,683



13,175



52,724



43,538


Income tax expense (benefit)

(1,464)



(10,307)



(18,706)



(11,683)


Depreciation, depletion, and amortization

52,484



39,887



194,360



154,039


Asset retirement obligation accretion

118



84



472



336


Exploration

265



96



1,093



2,380


Acquisition Costs

6,374





6,374




Impairments

579



30,031



4,901



34,269


Loss (gain) on derivative instruments

17,538



(3,439)



23,760



(20,906)


Net Settled Derivative Instruments

(2,398)



23,122



(1,732)



92,118


Stock-based compensation, net

3,215



2,409



13,764



9,384


Other income, net

(1,246)



(242)



(1,833)



(469)


Loss (gain) on sale of assets




302






306


Adjusted EBITDAX

$

90,529



$

74,367



$

250,326



$

285,058


 

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


(In thousands)



Three Months Ended
December 31,


Twelve Months Ended
December 31,


2016


2015


2016


2015









Net income (loss)

$

1,381



$

(20,751)



$

(24,851)



$

(18,254)


Acquisition Costs

6,374





6,374




Impairments

579



30,031



4,901



34,269


Loss (gain) on derivative instruments

17,538



(3,439)



23,760



(20,906)


Net Settled Derivative Instruments

(2,398)



23,122



(1,732)



92,118


Stock-based compensation - non-recurring





682




Other income, net

(1,246)



(242)



(1,833)



(469)


Loss (gain) on sale of assets



302





306


Income tax benefit (expense) for above items

(8,833)



(16,949)



(14,659)



(38,434)


Adjusted Net Income (Loss)

$

13,395



$

12,074



$

(7,358)



$

48,630


 

 

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/rsp-permian-inc-announces-fourth-quarter-and-year-end-2016-financial-and-operating-results-year-end-2016-proved-reserves-2017-guidance-and-2018-and-2019-production-outlook-300414285.html