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INDEX TO FINANCIAL STATEMENTS

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As filed with the Securities and Exchange Commission on November 12, 2013

Registration No. 333-          

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



RSP Permian, Inc.
(Exact name of registrant as specified in its charter)



Delaware
(State or other jurisdiction of incorporation or organization)
  1311
(Primary Standard Industrial
Classification Code Number)
  90-1022997
(I.R.S. Employer
Identification Number)

3141 Hood Street, Suite 701
Dallas, Texas 75219
(214) 252-2700

(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Scott McNeill
Chief Financial Officer
3141 Hood Street, Suite 701
Dallas, Texas 75219
(214) 252-2700
(Name, address, including zip code, and telephone number, including area code, of agent for service)



Copies to:

Douglas E. McWilliams
Christopher G. Schmitt
Vinson & Elkins L.L.P.
1001 Fannin Street, Suite 2500
Houston, Texas 77002

 

J. Michael Chambers
David J. Miller
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002

          Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

          If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:    o

          If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o   Accelerated filer o
Non-accelerated filer ý (Do not check if a smaller reporting company)   Smaller reporting company o

CALCULATION OF REGISTRATION FEE

       
 
Title of Each Class of Securities
to be Registered

  Proposed Maximum
Aggregate Offering
Price(1)

  Amount of
Registration Fee

 

Common Stock, par value $0.01 per share

  $400,000,000   $51,520

 

(1)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

          The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

   


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The information in this prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell such securities, and it is not soliciting an offer to buy such securities, in any state or jurisdiction where such offer or sale is not permitted.

Subject to Completion, dated November 12, 2013

PROSPECTUS


Shares

LOGO

RSP Permian, Inc.

Common Stock


This is the initial public offering of our common stock. We are offering           shares of our common stock, and the selling stockholders identified in this prospectus are offering            shares. We will not receive any proceeds from sale of shares by the selling stockholders. No public market currently exists for our common stock. We are an "emerging growth company" and are eligible for reduced reporting requirements. Please see "Prospectus Summary—Emerging Growth Company."

We intend to apply to list our common stock on the New York Stock Exchange under the symbol "RSPP."

We anticipate that the initial public offering price will be between $             and $             per share.

Investing in our common stock involves risks. See "Risk Factors" beginning on page 24.

 
  Per share   Total  

Price to the public

  $     $    

Underwriting discounts and commissions

  $     $    

Proceeds to us (before expenses)

  $     $    

Proceeds to the selling stockholders (before expenses)

  $     $    

The selling stockholders have granted the underwriters the option to purchase up to           additional shares of common stock on the same terms and conditions set forth above if the underwriters sell more than           shares of common stock in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares on or about                                        throug h the book-entry facilities of The Depository Trust Company.


Barclays

Tudor, Pickering, Holt & Co.

   

Prospectus dated                                        


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PROSPECTUS SUMMARY

    1  

RISK FACTORS

    24  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

    49  

USE OF PROCEEDS

    51  

DIVIDEND POLICY

    52  

CAPITALIZATION

    53  

DILUTION

    55  

SELECTED HISTORICAL AND PRO FORMA COMBINED FINANCIAL DATA

    57  

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

    60  

BUSINESS

    84  

MANAGEMENT

    113  

EXECUTIVE COMPENSATION

    118  

PRINCIPAL AND SELLING STOCKHOLDERS

    125  

RECENT EVENTS AND FORMATION TRANSACTIONS

    127  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

    131  

DESCRIPTION OF CAPITAL STOCK

    134  

SHARES ELIGIBLE FOR FUTURE SALE

    137  

MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

    139  

UNDERWRITING

    143  

LEGAL MATTERS

    149  

EXPERTS

    149  

WHERE YOU CAN FIND MORE INFORMATION

    149  

INDEX TO FINANCIAL STATEMENTS

    F-1  

ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS

    A-1  



        You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to the information which we have referred you. Neither we, the selling stockholders nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We, the selling stockholders and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

        This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements."

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Industry and Market Data

        The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we, the selling stockholders nor the underwriters have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled "Risk Factors." These and other factors could cause results to differ materially from those expressed in these publications.


Trademarks and Trade Names

        We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties' trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

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PROSPECTUS SUMMARY

        This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully before making an investment decision, including the information included under the headings "Risk Factors," "Cautionary Statement Regarding Forward-Looking Statements" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical and pro forma combined financial statements and the notes to those financial statements appearing elsewhere in this prospectus. The information presented in this prospectus assumes (i) an initial public offering price of $            per common share (the midpoint of the price range set forth on the cover of this prospectus) and (ii) unless otherwise indicated, that the underwriters do not exercise their option to purchase additional shares of common stock.

        In connection with this offering, pursuant to the terms of a corporate reorganization, all of the interests in RSP Permian, L.L.C. will be exchanged for common stock of RSP Permian, Inc., a recently formed Delaware corporation and the issuer of common stock in this offering. Additionally, in connection with this offering, certain owners of working interests and net profits interests in RSP Permian, L.L.C.'s oil and natural gas properties will contribute all or substantially all of such interests to RSP Permian, Inc. in exchange for shares of common stock. See "Recent Events and Formation Transactions" for more information regarding these contributions. These contributions and the other transactions described in "Recent Events and Formation Transactions" are collectively referred to in this prospectus as the "Transactions." Except as expressly stated or the context otherwise requires, references to our operations and assets give effect to the Transactions, and the terms "we," "us," "our," and "RSP" refer, prior to the Transactions, to RSP Permian, L.L.C. and, after the Transactions, to RSP Permian, Inc. and its subsidiary.

        This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in Annex A to this prospectus.


Our Company

        We are 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 Basin, a sub-basin of the Permian Basin, primarily in the adjacent counties of Midland, Martin, Andrews, Dawson and Ector.

        Since our inception in 2010, we have participated in the drilling of over 300 vertical Wolfberry wells and served as the operator of over 180 of those wells. In late 2012, our primary focus shifted to drilling horizontal wells. We believe horizontal drilling provides more attractive returns on a majority of our acreage. We target the multiple oil and natural gas producing stratigraphic horizons, or stacked pay zones, on our properties. Beginning in 2012, we were among the first operators to successfully drill and complete a horizontal well in the core of the Midland Basin targeting the Wolfcamp B formation. In addition, we are the operator of what we believe is the first horizontal well completed in the Middle Spraberry shale in the Midland Basin, which came on production in the fourth quarter of 2013. We also believe we were the first operator to successfully drill and complete a horizontal well targeting the Lower Spraberry shale in the Permian Basin. Other operators have drilled successful horizontal wells targeting the Wolfcamp A formation in close proximity to our properties.

        Since initiating our horizontal drilling program, we have participated in the drilling and completion of 32 horizontal wells (14 of which we operate), which have targeted the Middle Spraberry, Lower Spraberry, Wolfcamp B, Wolfcamp D (Cline) and Clearfork formations on our properties. In addition, we believe that our properties provide horizontal opportunities in several other intervals, such as the Jo Mill, Dean, Wolfcamp A, Strawn, Atoka, Mississippian and Devonian formations.

        We believe our vertical drilling program is a strong complement to our horizontal drilling program, and we plan to continue to drill vertical Wolfberry wells. In areas where we drill horizontal wells, vertical drilling, in concert with horizontal drilling, allows us to optimize total hydrocarbon recovery on

 

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our acreage, while continuing to provide attractive returns on a standalone basis. In addition, on certain sections of our acreage, vertical drilling provides the most attractive returns. Further, vertical drilling enables us to hold our acreage through our continuous development program.

        We are currently operating two horizontal rigs and one vertical rig and expect to add another horizontal rig in the first half of 2014. We expect that approximately        % of our 2014 drilling and completion budget will be devoted to the drilling of horizontal wells.

        The Permian Basin is an attractive operating area due to its multiple horizontal and vertical target horizons, favorable operating environment, high oil and liquids-rich natural gas content, substantial existing infrastructure, well-developed network of oilfield service providers, long-lived reserves with consistent reservoir quality and historically high drilling success rates. Operators in the Permian Basin have produced more than 29 billion barrels of oil and 75 trillion cubic feet of natural gas over the past 90 years, and the Permian Basin is estimated to contain recoverable oil and natural gas reserves exceeding that which has already been produced. With oil production of over 900 MBbls/d from over 80,000 wells during the six months ended June 30, 2013, production from the Permian Basin represented 57% of the crude oil produced in Texas and approximately 17% of the crude oil produced onshore in the continental United States during such period. According to the Energy Information Administration of the U.S. Department of Energy, the Spraberry Trend Area, which encompasses the Midland Basin, ranks as the largest onshore oilfield in the continental United States by proved reserves and oil production.

        We were formed in October 2010 by our management team and an affiliate of Natural Gas Partners ("NGP"), a family of energy-focused private equity investment funds. Prior to our formation, the founding members of our management team successfully built and sold multiple NGP-sponsored oil and natural gas companies. In December 2010, we acquired 15,800 net acres in the Permian Basin with production at the time of acquisition of approximately 1,500 net Boe/d from 107 wells. See "—Recent Events and Formation Transactions" for information regarding our acquisitions and other transactions since December 2010.

        We have assembled a multi-year inventory of horizontal and vertical drilling projects. As of September 30, 2013, we had identified 1,169 horizontal drilling locations in multiple horizons across our acreage based on five wells per 640 acres for short laterals and five wells per 960 acres for long laterals. Additionally, based on our evaluation of applicable geologic and engineering data as of September 30, 2013, we had 307 identified vertical drilling locations on 40-acre spacing and an additional 500 identified vertical drilling locations based on 20-acre downspacing. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our properties and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

        The following table provides a summary of our target horizontal zones and vertical drilling inventory as of September 30, 2013. While our near term drilling program will be focused primarily on the Middle Spraberry, Lower Spraberry and Wolfcamp B intervals underlying our properties, based on our and other operators' well results and our analysis of geologic and engineering data, we believe the Wolfcamp A and Wolfcamp D (Cline) intervals are prospective and expect they will be integrated into our future drilling program. We also believe we have the potential to increase our multi-year drilling inventory with additional horizontal locations in zones not included in our target horizontal zones, such as the Clearfork, Jo Mill, Dean, Strawn, Atoka, Mississippian and Devonian formations. We believe our

 

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large, contiguous acreage position allows us to optimize our horizontal and vertical development programs to maximize our resource recovery on a per 640-acre section basis, and thus our returns.

 
  Identified Drilling Locations(1)  
 
    
Target Horizontal Locations
 
 
  Short Laterals(2)   Long Laterals(2)   Total  

Target Horizontal Zones(3):

                   

Middle Spraberry

    140     138     278  

Lower Spraberry

    139     138     277  

Wolfcamp A

    88     88     176  

Wolfcamp B

    126     111     237  

Wolfcamp D (Cline)

    98     103     201  
               

Total Target Horizontal Locations

    591     578     1,169  
               

 

 
  Vertical Locations  
 
  40-acre   20-acre   Total  

Vertical Locations

    307     500     807  
                   

Total Target Horizontal and Vertical Locations

               
1,976

(4)
                   

(1)
Our total identified drilling locations include 338 locations associated with proved undeveloped reserves as of June 30, 2013. We have estimated our drilling locations based on well spacing assumptions for the areas in which we operate and other criteria. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our ability to add additional proved reserves to our existing proved reserves. See "Risk Factors—Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations."

(2)
Our target horizontal location count implies five wells per 640 acres for short laterals, which we define as horizontal lateral lengths of approximately 4,500 feet, and five wells per 960 acres for long laterals, which we define as horizontal lateral lengths of approximately 7,500 feet.

(3)
In addition to these target horizontal zones, we believe we have the potential to increase our multi-year drilling inventory with additional horizontal locations in the Clearfork, Jo Mill, Dean, Strawn, Atoka, Mississippian and Devonian formations.

(4)
As of June 30, 2013, one, 79 and 113 of our 1,976 total target horizontal and vertical locations are associated with acreage that will expire in 2013, 2014 and 2015, respectively, unless either production is established within the spacing units covering such acreage or the lease is renewed or extended under continuous drilling provisions prior to such dates. Based on our current drilling schedule, we do not expect the acreage associated with any of our 1,976 target locations to expire. In the event leases for such acreage expire, however, we would lose our right to develop the related locations. See "Risk Factors—Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their

 

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    drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations."

    As of June 30, 2013, none of our 338 locations associated with proved undeveloped reserves is associated with acreage that will expire prior to scheduled drilling.

        Our 2013 capital budget for drilling, completion, recompletion and infrastructure is approximately $220.0 million. Our capital budget excludes acquisitions. As of June 30, 2013, we had spent approximately $94.7 million to drill and complete operated wells, $17.6 million for our participation in the drilling and completion of non-operated wells and $4.1 million on infrastructure. We currently estimate our 2014 capital budget for drilling, completion, recompletion and infrastructure will be approximately $             million. We intend to allocate these expenditures approximately as follows:

    $             million for the drilling and completion of operated wells, of which approximately        % is allocated to horizontal wells;

    $             million for our participation in the drilling and completion of non-operated wells; and

    $             million for infrastructure.

        Because we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures are largely discretionary. We could choose to defer a portion of these planned 2014 capital expenditures depending on a variety of factors, including the success of our drilling activities; prevailing and anticipated prices for oil, natural gas and NGLs; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the level of participation by other working interest owners.

        For the month ended June 30, 2013, our average net daily production was 8,286 Boe/d (approximately 68% oil, 16% natural gas and 16% NGLs), of which 18% was from horizontal well production and 82% was from vertical well production. As of June 30, 2013, we produced from ten horizontal and 314 vertical wells and were the operator of approximately 95% of our net acreage.

        The following chart provides information regarding our production growth and the increasing proportion of our horizontal well production since the beginning of 2011 on a pro forma basis, giving effect to the Transactions discussed under "—Recent Events and Formation Transactions" as if they had taken place at the beginning of 2011.

GRAPHIC

 

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        The following table provides a summary of what we believe to be our combined horizontal acreage position that is prospective for hydrocarbon production across our target horizontal zones underneath our total surface acreage of 42,428 gross (33,933 net) acres. Our belief is based upon our evaluation of our initial horizontal drilling results and those of other operators in our area to date, combined with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of vertical wells that have penetrated our target horizontal zones. We have also analyzed data from various industry studies detailing the geology and geochemistry of our target horizontal zones, both within and beyond the boundaries of our leases in order to evaluate and compare the drilling results of other operators' known productive wells and areas to our expected results. In addition, to evaluate the prospectivity of our combined horizontal acreage, we have used 3-D seismic data and performed open-hole and mud log evaluations, core analysis and drill cuttings analysis. We refer to the summation of our horizontal acreage across the multiple target zones as our "Effective Horizontal Acreage." We believe this acreage metric more accurately conveys our horizontal drilling opportunities in our target zones, and we believe our analysis of engineering, geological, geochemical and seismic data is based on industry standards.

 
  Effective Horizontal
Acreage(1)
 
 
  Gross   Net  

Target Horizontal Zones:

             

Middle Spraberry

    41,791     33,359  

Lower Spraberry

    42,428     33,933  

Wolfcamp A

    26,493     19,892  

Wolfcamp B

    35,957     27,984  

Wolfcamp D (Cline)

    32,327     25,267  
           

Total Effective Horizontal Acreage

    178,996     140,435  
           

(1)
Our calculation of our Effective Horizontal Acreage is an inexact estimate. We cannot assure you that any amount of our Effective Horizontal Acreage listed above in each of our target horizontal zones is prospective for that zone. Additionally, we cannot ascertain what portion of our Effective Horizontal Acreage will ever be drilled. See "Risk Factors—Our Effective Horizontal Acreage is based on our and other operators' current drilling results and our interpretation of available geologic and engineering data and therefore is an inexact estimate subject to various uncertainties."

        Additionally, based on data we have collected from our horizontal and vertical drilling programs, we believe our acreage could also be prospective for horizontal drilling opportunities in the Clearfork, Jo Mill, Dean, Strawn, Atoka, Mississippian and Devonian formations.

        As of June 30, 2013, our estimated proved oil and natural gas reserves were 52,164 MBoe based on a reserve report prepared by Ryder Scott Company, L.P. ("Ryder Scott"), our independent reserve engineer. Of these reserves, approximately 38% were classified as proved developed producing ("PDP"). Proved undeveloped reserves ("PUDs") included in this estimate are from 322 vertical well locations and 16 horizontal well locations. As of June 30, 2013, these proved reserves were approximately 62% oil, 17% natural gas and 21% NGLs.

        The following table provides summary information regarding our proved reserves as of June 30, 2013 and production for the month ended June 30, 2013. As estimated by Ryder Scott, our estimated ultimate recoveries ("EURs") from our nine producing Wolfcamp B horizontal wells, which have an average lateral length of 5,867 feet, range from approximately 454 MBoe (approximately 67% oil, 19% natural gas and 14% NGLs) to approximately 626 MBoe (approximately 65% oil, 20% natural gas and

 

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15% NGLs), and our EUR for our producing Lower Spraberry well, which has a lateral length of 4,888 feet, is approximately 569 MBoe (approximately 62% oil, 20% natural gas and 18% NGLs).

 
  Estimated Total Proved Reserves    
   
 
 
  Oil
(MMbls)
  Natural
Gas (Bcf)
  NGLs
(MMbls)
  Total
(MMBoe)
  %
Oil
  %
Liquids(1)
  %
Developed
  Average Net
Production
(Boe/d)
  R/P Ratio
(Years)(2)
 

Midland Basin

    32.5     51.6     11.1     52.2     62     83     38     8,286(3 )   17.2  

(1)
Includes both oil and NGLs.

(2)
Represents the number of years proved reserves would last assuming production continued at the average rate for the month ended June 30, 2013. Because production rates naturally decline over time, the R/P Ratio is not a useful estimate of how long properties should economically produce.

(3)
Consisted of approximately 68% oil, 16% natural gas and 16% NGLs.

Our Business Strategy

        Our business strategy is to increase stockholder value through the following:

    Grow reserves, production and cash flow by developing our oil-rich resource base in the core of the Midland Basin.    We intend to actively drill and develop our acreage in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital. Currently, we are operating two horizontal drilling rigs focused on the Wolfcamp B and Lower Spraberry target zones and one vertical rig targeting the Wolfberry play. We plan to accelerate our growth by adding an additional horizontal drilling rig in the first half of 2014.

    Apply horizontal drilling technology in multiple pay zones to increase production.    In 2014, we plan to spend approximately        % of our drilling and completion budget on horizontal drilling to develop multiple target zones. Our recent well results and the results of other operators demonstrate that the Midland Basin contains multiple pay zones for the drilling of horizontal wells. As of September 30, 2013, we had drilled or were currently drilling 14 horizontal wells as the operator and had participated in 18 additional horizontal wells as a non-operator. Of these 32 total horizontal wells, 25 are Wolfcamp B wells, one is a Wolfcamp D (Cline) well, one is a Middle Spraberry well, four are Lower Spraberry wells and one is a Clearfork well.

    Strengthen hydrocarbon recovery from vertical drilling and increased well density drilling.    We believe our vertical drilling program complements our horizontal drilling program and generates attractive returns on invested capital. We also believe increased well density drilling opportunities exist across our acreage base for both our horizontal and vertical drilling programs. We closely monitor industry trends with respect to higher well density drilling, which could increase the recovery factor per section and provide additional attractive opportunities for capital deployment.

    Pursue strategic acquisition opportunities with oil-weighted resource potential.    We have made, and intend to continue to make, opportunistic acquisitions of acreage in the Permian Basin that have substantial oil-weighted resource potential from which we believe we can achieve attractive returns on invested capital. We evaluate acquisition opportunities on a variety of criteria, including expected rate of return, location, resource potential and the presence of multiple pay zones where we can utilize our horizontal drilling experience. We intend to grow our position around and within our concentrated acreage position in the Midland Basin through leasing activity and acquisitions.

    Maintain a high degree of operational control in order to continuously improve operating and cost efficiencies.    We seek operational control of our properties in order to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate

 

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      hydrocarbon recovery by continuous improvement of our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, operatorship allows us to more efficiently manage the pace of development activities, including our horizontal development program, and the gathering and marketing of our production. Further, to support our operations, we have built infrastructure that allows us to significantly reduce our operating costs. For example, we have laid approximately 85 miles of oil, natural gas and water transport lines to support gathering and transportation activities on our properties, drilled eight water source wells into the Santa Rosa formation in West Texas, operated three saltwater disposal wells on our properties and have an additional two saltwater disposal wells in the permitting process.

    Leverage our experience operating in the Permian Basin to maximize returns for stockholders.    Our executive and core technical team has an average of approximately 25 years of energy industry experience per person, most of which has been in the Permian Basin. Our team regularly evaluates our operating results against those of other operators in our area in order to improve our performance and identify opportunities to optimize our drilling and completion techniques and make informed decisions about our capital program and drilling activity levels. Additionally, our experienced management team focuses on creating stockholder value by identifying, evaluating and completing acquisitions that we believe will generate attractive rates of return. We intend to leverage our management's and technical team's experience in applying unconventional drilling and completion techniques in an effort to optimize operating results.

    Maintain financial flexibility and apply a disciplined approach to capital allocation.    We carefully manage our liquidity through internal cash flow modeling that includes forecasts for each well we are scheduled to drill. We conservatively use debt financing and intend to maintain what we consider modest leverage levels. Further, as a complement to our disciplined approach to financial management, we have an active commodity hedging program to reduce our exposure to oil price variability.

Our Competitive Strengths

        We believe that the following strengths will help us achieve our business goals:

    Attractively positioned in the oil-rich core of the Midland Basin.    All of our leasehold acreage is located in the Permian Basin in West Texas, and substantially all of our current properties are well-positioned in what we believe to be the core of the Midland Basin where horizontal drilling activity has increased by 300% since January 2012. Based on industry data, we believe the Permian Basin offers some of the most attractive returns among our nation's producing oil and natural gas plays. As of June 30, 2013, our estimated net proved reserves were comprised of approximately 62% oil, 17% natural gas and 21% NGLs. In the current commodity price environment, our oil and liquids-rich asset base provides attractive rates of return.

    Contiguous acreage position with high degree of operational control.    The vast majority of our acreage is located on contiguous blocks in what we believe to be the core of the Midland Basin. We believe this large, contiguous acreage position allows us to optimize our horizontal and vertical development programs to maximize our resource recovery on a per section basis, and thus our returns. In particular, our contiguous acreage blocks allow us the flexibility to adjust our drilling and completion techniques, primarily the length of our horizontal laterals, in order to optimize our well results, drilling costs and returns. As the operator of approximately 95% of our net acreage, we retain the ability to adjust our development program, including the selection of specific drilling locations, the timing of the development and the drilling and completion techniques used to efficiently develop our significant resource base. This operating control also enables us to exchange data with other offset operators, which we believe contributes to reducing the risks associated with drilling the multiple horizontal zones of our acreage.

 

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    Significant horizontal drilling experience in multiple pay zones in the Midland Basin.    We believe our horizontal drilling experience targeting multiple pay zones in the Midland Basin provides us a competitive advantage in these areas. Our initial horizontal focus was on the Wolfcamp B formation in Midland County. We were among the first operators in the core of the Midland Basin to successfully drill and complete a horizontal well in the Wolfcamp B formation. In addition, we believe we were the first operator to successfully drill and complete a horizontal well targeting the Middle Spraberry shale in the Midland Basin. We also believe we were the first operator to successfully drill and complete a horizontal well targeting the Lower Spraberry shale in the Permian Basin. Additionally, our technical team has been drilling horizontal wells in North America since the early 1990s and applies this decades-long experience when drilling our target zones in the Midland Basin.

    Multi-year horizontal drilling inventory.    We have identified a multi-year inventory of horizontal drilling locations that we believe provides attractive growth and return opportunities. Based on our initial horizontal drilling results and those of other operators in our area to date, combined with our interpretation of various geologic and engineering data, as of September 30, 2013, we had identified 1,169 horizontal drilling locations on our acreage based on five wells per 640 acres for short laterals and five wells per 960 acres for long laterals. These locations exist across most of our acreage blocks and in multiple target zones. We also believe that as we execute our horizontal drilling program, we will identify additional horizontal drilling locations. Of the 1,169 identified horizontal drilling locations, 278 are in the Middle Spraberry horizon, 277 are in the Lower Spraberry horizon, 176 are in the Wolfcamp A horizon, 237 are in the Wolfcamp B horizon and 201 are in the Wolfcamp D (Cline) horizon. Additionally, we believe our acreage could be prospective for horizontal drilling of the Clearfork, Jo Mill, Dean, Strawn, Atoka, Mississippian and Devonian horizons.

    Low-risk vertical development program.    The Permian Basin is historically a conventional play with substantial de-risking around our mostly contiguous acreage position with over 11,500 active and producing vertical wells drilled in the Midland Basin from 2010 to date. Since the beginning of our development program in 2010, we have participated in the drilling of over 300 operated vertical Wolfberry wells across our concentrated leasehold position. As of September 30, 2013, our vertical Wolfberry play drilling plan included 307 identified drilling locations based on 40-acre spacing and an additional 500 identified drilling locations based on 20-acre downspacing.

    Experienced, incentivized and proven management team.    We believe that the experience of our management and technical teams in horizontal drilling and completions will help reduce the execution risk associated with unconventional drilling. We believe the significant collective experience of our management and technical teams has enabled us to recognize the potential in the core of the Midland Basin and to assemble a portfolio of assets that has been, and we believe will continue to be, highly productive. Further, our executive team has extensive experience in identifying acquisition targets and evaluating resource potential through its involvement in successfully building and selling several companies that executed acquisitions and divestitures as part of their growth strategy. We believe this significant experience identifying and closing acquisitions and divestitures will help us identify additional attractive acquisition opportunities in the future. Our management team has a meaningful economic interest in us, which we believe will provide significant incentives to grow the value of our business for the benefit of all stockholders.

    Financial flexibility to fund expansion.    We have a conservative balance sheet, which will allow us to actively develop our drilling, exploitation and exploration activities in the Midland Basin and maximize the present value of our oil-weighted resource potential. After giving effect to the Transactions, this offering and the use of proceeds from this offering, we expect to have $             million in debt outstanding under our revolving credit facility, and we expect the

 

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      borrowing base will be $             million, providing $             million of available borrowing capacity. We believe this borrowing capacity, along with our cash flow from operations, will provide us with sufficient liquidity to execute on our current capital program.

Recent Events and Formation Transactions

    Recent Acquisitions and Dispositions

        Resolute Disposition.    Pursuant to a transaction that closed in part in December 2012 and in part in March 2013, we sold all of our working interests in approximately 2,600 net acres and 80 producing wells in the Permian Basin to Resolute Natural Resources Southwest, L.L.C. ("Resolute") for approximately $214 million (the "Resolute Disposition").

        Spanish Trail Acquisition.    On September 10, 2013, we acquired additional working interests in certain of our existing properties in the Permian Basin (the "Spanish Trail Acquisition") from Summit Petroleum, LLC ("Summit") and EGL Resources, Inc. ("EGL"). Together with the working interests acquired pursuant to the preferential purchase rights and to be contributed to us in connection with this offering, as described in "—Corporate Formation Transactions," the Spanish Trail Acquisition increased our working interests in approximately 5,400 gross acres and 70 gross producing wells (the "Spanish Trail Assets"). As of June 30, 2013, the estimated proved oil and natural gas reserves associated with the Spanish Trail Assets were approximately 8,451 MBoe (approximately 64% oil, 17% natural gas and 19% NGLs), and for the month ended June 30, 2013, average net daily production associated with the Spanish Trail Assets was approximately 1,255 Boe/d (approximately 73% oil, 12% natural gas and 15% NGLs).

        The aggregate purchase price for the Spanish Trail Assets agreed to by us and the sellers was $155 million. Subsequent to the signing of the purchase agreement and prior to the closing of the Spanish Trail Acquisition, Ted Collins, Jr. ("Collins") and Wallace Family Partnership, LP ("Wallace LP"), non-operating working interest owners in the Spanish Trail Assets, exercised preferential purchase rights granted under a joint operating agreement among the working interest owners in the Spanish Trail Assets. The preferential purchase rights gave Collins and Wallace LP the right to purchase a portion of the working interests sold by Summit and EGL. Collins and Wallace LP completed this acquisition through a newly-formed entity, Collins & Wallace Holdings, LLC, and will contribute these acquired assets, along with other non-operated working interests in substantially all of our assets, for shares of RSP Permian, Inc.'s common stock, as described in "—Corporate Formation Transactions—The Contributions." The exercise of the preferential purchase rights reduced our purchase price from $155 million to $121 million. The Spanish Trail Acquisition was funded with a $70 million term loan, borrowings under our revolving credit facility and the issuance of a net profits interest ("NPI") as further described below.

        In addition, simultaneously with the closing of the Spanish Trail Acquisition, we conveyed a 25% NPI in the Spanish Trail Assets taken as a whole, excluding the portion acquired by Collins & Wallace Holdings, LLC, to ACTOIL, LLC ("ACTOIL") in exchange for cash equal to 25% of our $121 million purchase price, pursuant to ACTOIL's exercise of a right of first refusal granted by us in the agreement that governs the NPI investment. ACTOIL will contribute this NPI, along with the other NPI in our assets, for shares of RSP Permian, Inc.'s common stock, as described in "—Corporate Formation Transactions—The ACTOIL NPI Repurchase."

        Verde Acquisition.    On October 10, 2013, we acquired leasehold interests in 9,464 gross (8,098 net) acres in the Midland Basin located just to the north of the Dawson and Martin county line toward the eastern half of Dawson County. We are the operator on 100% of this acreage. We believe that this leasehold is prospective for the target horizontal zones of Middle Spraberry, Lower Spraberry, Wolfcamp A and Wolfcamp B. We have identified approximately 234 gross horizontal drilling locations on this acreage, of which 78 are located in the Wolfcamp B zone, 78 are located in the Middle

 

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Spraberry zone and 78 are located in the Lower Spraberry zone. We expect the lateral lengths of the horizontal wells we drill in this area to range from approximately 4,500 feet to 7,500 feet. As a result of our detailed technical analysis of the area, we believe its geology and petrochemical attributes to be similar to our other leaseholds in the core of the Midland Basin.

    Corporate Formation Transactions

        Corporate Reorganization.    RSP Permian, L.L.C. was formed as a Delaware limited liability company in October 2010 by our management team and an affiliate of NGP to engage in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. NGP, which was founded in 1988, is a family of energy-focused private equity investment funds with aggregate committed capital under management since inception of over $10 billion. Prior to the transactions discussed below, RSP Permian, L.L.C. had approximately 13,900 net acres and working interests in approximately 324 gross producing wells in the Permian Basin. As of June 30, 2013 and without giving effect to the Transactions, RSP Permian, L.L.C.'s estimated proved oil and natural gas reserves were 26,934 MBoe (approximately 62% oil, 16% natural gas and 22% NGLs), and for the month ended June 30, 2013, RSP Permian, L.L.C.'s average net daily production was 4,344 Boe/d (approximately 67% oil, 17% natural gas and 16% NGLs).

        Pursuant to the terms of a corporate reorganization that will be completed in connection with this offering, the members of RSP Permian, L.L.C. will contribute all of their interests in RSP Permian, L.L.C. to RSP Permian, Inc., a recently formed Delaware corporation and the issuer of common stock in this offering. As a result of the reorganization, RSP Permian, L.L.C. will become a wholly owned subsidiary of RSP Permian, Inc.

        The Rising Star Acquisition.    In connection with this offering, we will acquire from Rising Star Energy Development Co., L.L.C. ("Rising Star") working interests (the "Rising Star Assets") in certain acreage and wells in the Permian Basin in which RSP Permian, L.L.C. already has working interests (the "Rising Star Acquisition"). In exchange, Rising Star will receive shares of RSP Permian, Inc. common stock. The Rising Star Acquisition will increase our average working interest in approximately 3,250 gross acres and 34 gross producing wells in the Permian Basin. As of June 30, 2013, Ryder Scott estimated the proved oil and natural gas reserves associated with the Rising Star Assets to be 1,696 MBoe (approximately 65% oil, 17% natural gas and 18% NGLs), and for the month ended June 30, 2013, the average net daily production associated with the Rising Star Assets was 249 Boe/d (approximately 62% oil, 16% natural gas and 22% NGLs). The Rising Star Assets represented substantially all of Rising Star's production and revenues for each of the year ended December 31, 2012 and the six months ended June 30, 2013.

        The Contributions.    Collins, Wallace LP and a newly-formed entity, Collins & Wallace Holdings, LLC, that is owned equally by Collins and Wallace LP have agreed to contribute to us certain working interests (collectively, the "Contributions") in certain of RSP Permian, L.L.C.'s existing properties in the Permian Basin in exchange for shares of RSP Permian, Inc.'s common stock. The Contributions will occur in connection with this offering.

        These contributed working interests consist of the following: (i) Collins' non-operated working interest in substantially all of the oil and natural gas properties that RSP Permian, L.L.C. owned prior to the Spanish Trail Acquisition; (ii) Wallace LP's non-operated working interest in substantially all of the oil and natural gas properties that RSP Permian, L.L.C. owned prior to the Spanish Trail Acquisition; and (iii) Collins & Wallace Holdings, LLC's non-operated working interest in the Spanish Trail Assets. As of June 30, 2013, Ryder Scott estimated proved oil and natural gas reserves associated with these properties (excluding the properties to be contributed by Collins & Wallace Holdings, LLC, which are reflected in the Spanish Trail Assets reserves described above) to be 15,083 MBoe (approximately 62% oil, 16% natural gas and 22% NGLs), and for the month ended June 30, 2013, the

 

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average net daily production associated with these properties (excluding the properties to be contributed by Collins & Wallace Holdings, LLC, which are reflected in the Spanish Trail Assets production described above) was approximately 2,438 Boe/d (approximately 68% oil, 16% natural gas and 16% NGLs).

        The ACTOIL NPI Repurchase.    In July 2011, we sold to ACTOIL a 25% NPI in substantially all of our oil and natural gas properties taken as a whole. In addition, as discussed above under "—Recent Acquisitions and Dispositions—Spanish Trail Acquisition," we sold to ACTOIL a 25% NPI in the oil and natural gas properties acquired by RSP Permian, L.L.C. in the Spanish Trail Acquisition. ACTOIL has agreed to contribute both 25% NPIs to us (the "ACTOIL NPI Repurchase") in exchange for shares of RSP Permian, Inc. common stock. This contribution is expected to occur in connection with this offering.

        The oil and natural gas properties that underpin ACTOIL's NPIs remain owned and controlled by us. The NPIs entitle ACTOIL to 25% of the relevant properties' cumulative revenues in excess of their cumulative direct operating expenses and capital expenditures. Because the cumulative revenues have not yet exceeded the cumulative direct operating expenses and capital expenditures, we have included the resultant net cash flow and the reserves associated with ACTOIL's NPIs in our historical proved reserves estimates.

        For more information on our corporate reorganization, the Transactions and the ownership of our common stock by our principal and selling stockholders, see "—Our Ownership and Organizational Structure," "Recent Events and Formation Transactions" and "Principal and Selling Stockholders."

Our Ownership and Organizational Structure

        Following the completion of the corporate reorganization and the Transactions described above, immediately before the completion of this offering, our existing investors (the "Existing Investors") will consist of the following:

Existing Investor Name
  Number of
Shares Owned
Before this
Offering(1)
  Shares to be
Offered in this
Offering(2)
  Number of
Shares Owned
After this
Offering(2)

RSP Permian Holdco, L.L.C.(3)

           

Rising Star Energy Development Co., L.L.C. 

           

Ted Collins, Jr. 

           

Wallace Family Partnership, LP

           

Collins & Wallace Holdings, LLC

           

ACTOIL, LLC

           
             

Total

           
             

(1)
Based on the assumed initial public offering price of $                per share of common stock (the midpoint of the price range set forth on the cover of this prospectus). While the total number of shares that will be owned by the Existing Investors will not change based on the initial public offering price, the allocation of shares among the Existing Investors is dependent on the equity valuation of RSP Permian, Inc., which will be determined based on the initial public offering price.

(2)
Assumes no exercise of the underwriters' option to purchase additional shares of our common stock.

(3)
RSP Permian Holdco, L.L.C. is owned by Production Opportunities II, L.P. ("Production Opportunities"), an entity affiliated with NGP, certain members of our management team and certain of our employees. Certain members of our management team and certain of our employees

 

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    also own incentive units in RSP Permian Holdco, L.L.C. that may entitle them to a portion of the proceeds to be received by the owners of RSP Permian Holdco, L.L.C. upon sales of shares of our common stock after such owners have received certain rates of return on their aggregate capital contributions.

            The following diagram indicates our ownership structure after giving effect to our corporate reorganization, the Transactions and this offering (assuming no exercise of the underwriters' option to purchase additional shares of our common stock). For information on our corporate reorganization and the Transactions, please see "Recent Events and Formation Transactions."

    Ownership Structure After Giving Effect to the Transactions and this Offering

    GRAPHIC

    Risk Factors

            Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. You should read carefully the section of this prospectus entitled "Risk Factors" beginning on page 24 for an explanation of these risks before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment:

    Our business is difficult to evaluate because of our limited operating history.

    The volatility of oil and natural gas prices due to factors beyond our control may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

    Our exploitation, development and exploration projects require substantial capital that we may be unable to obtain, which could lead to a loss of properties and a decline in our reserves.

    Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present values of our reserves.

 

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    Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with a concentration of operations in a single geographic area.

    Development of our PUDs may take longer than expected and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.

    Our future cash flows and results of operations are highly dependent on our ability to find, develop or acquire additional oil and natural gas reserves.

    We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could adversely affect our revenues in the short-term.

    Our operations are subject to operational hazards for which we may not be adequately insured.

    Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could disrupt our business and hinder our ability to grow.

    Our operations are subject to various governmental regulations that require compliance that can be burdensome and expensive and adversely affect the feasibility of conducting our operations.

    Any failure by us to comply with applicable environmental laws and regulations, including those relating to hydraulic fracturing, could result in governmental authorities taking actions that adversely affect our operations and financial condition.

    Our business is susceptible to the potential difficulties associated with managing rapid growth and expansion.

    Our Existing Investors will collectively hold      % of our common stock after completion of this offering and their interests may conflict with yours.

        For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, see "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements."

Emerging Growth Company

        We are an "emerging growth company" as defined in the Jumpstart Our Business Startups Act (the "JOBS Act"). For as long as we are an emerging growth company, unlike public companies that are not emerging growth companies under the JOBS Act, we are not required to:

    provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

    provide more than two years of audited financial statements and related management's discussion and analysis of financial condition and results of operations;

    comply with any new requirements adopted by the Public Company Accounting Oversight Board (the "PCAOB") requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

    provide certain disclosure regarding executive compensation required of larger public companies or hold shareholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"); or

    obtain shareholder approval of any golden parachute payments not previously approved.

 

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        We will cease to be an "emerging growth company" upon the earliest of:

    the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;

    the date on which we become a "large accelerated filer" (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30);

    the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

    the last day of the fiscal year following the fifth anniversary of our initial public offering.

        In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the "Securities Act"), for complying with new or revised accounting standards, but we hereby irrevocably opt out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

Principal Executive Offices and Internet Address

        Our principal executive offices are located at 3141 Hood Street, Suite 701, Dallas, Texas 75219, and our telephone number at that address is (214) 252-2700. Our website address is                                                   and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the "SEC") available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. The information on, or otherwise accessible through, our website or any other website does not constitute a part of this prospectus.

 

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The Offering

Issuer

  RSP Permian, Inc.

Shares of common stock offered by us

 

                shares.

Shares of common stock offered by the selling stockholders

 

                shares (or          shares, if the underwriters exercise in full their option to purchase additional shares).

Shares of common stock to be outstanding after this offering

 

                shares.

Shares of common stock owned by the Existing Investors after this offering

 

                shares (or          shares, if the underwriters exercise in full their option to purchase additional shares).

Option to purchase additional shares

 

Our selling stockholders have granted the underwriters an option to purchase up to an aggregate of          additional shares of our common stock to the extent the underwriters sell more than          shares of common stock in this offering.

Use of proceeds

 

We expect to receive approximately $          of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

 

We intend to use a portion of the net proceeds from this offering to fully repay our $70 million term loan and any remaining net proceeds to reduce amounts drawn under our revolving credit facility, approximately $          million of which was outstanding as of                , 2013. We will not receive any proceeds from the sale of shares by the selling stockholders. Please read "Use of Proceeds."

Dividend policy

 

We do not anticipate paying any cash dividends on our common stock. In addition, our revolving credit facility places restrictions on our ability to pay cash dividends. Please read "Dividend Policy."

Directed share program

 

The underwriters have reserved for sale at the initial public offering price up to 5% of the common stock being offered by this prospectus for sale to our employees, executive officers, directors, director nominees, business associates and related persons who have expressed an interest in purchasing common stock in this offering. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. Please read "Underwriting."

Risk factors

 

You should carefully read and consider the information set forth under the heading "Risk Factors" beginning on page 24 and all other information set forth in this prospectus before deciding to invest in our common stock.

 

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Listing and trading symbol

 

We intend to apply to list our common stock on the New York Stock Exchange (the "NYSE") under the symbol "RSPP."

        The information above does not include shares of common stock reserved for issuance pursuant to our equity incentive plan.

        Unless we indicate otherwise or the context otherwise requires, all information in this prospectus:

    assumes no exercise of the underwriters' option to purchase additional shares of our common stock; and

    assumes that the initial public offering price of the shares of our common stock will be $            per share (which is the midpoint of the price range set forth on the cover page of this prospectus).

 

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Summary Historical and Pro Forma Combined Financial Data

        RSP Permian, Inc. was formed in September 2013 and does not have historical financial operating results. The following table shows summary historical combined financial data of our accounting predecessor, which reflects the combined results of RSP Permian, L.L.C. and Rising Star Energy Development Co., L.L.C., and summary unaudited pro forma combined financial data of RSP Permian, Inc. for the periods and as of the dates indicated. Due to the factors described in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Pro Forma Results of Operations to the Historical Results of Operations of Our Predecessor," our future results of operations will not be comparable to the historical results of our predecessor.

        The summary historical combined financial data of our predecessor as of and for the years ended December 31, 2012 and 2011 were derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The summary historical interim combined financial data of our predecessor as of June 30, 2013 and for the six months ended June 30, 2013 and 2012 were derived from the unaudited interim combined financial statements of our predecessor included elsewhere in this prospectus.

        The summary unaudited pro forma combined financial data of RSP Permian, Inc. as of and for the six months ended June 30, 2013 and for the year ended December 31, 2012 were derived from the unaudited pro forma combined financial statements included elsewhere in this prospectus. The pro forma combined financial data assumes that this offering and the transactions to be effected prior to, or in connection with, this offering and described under "Recent Events and Formation Transactions" had taken place on June 30, 2013, in the case of the unaudited pro forma combined balance sheet data, and on January 1, 2012, in the case of the pro forma combined statement of operations data for the six months ended June 30, 2013 and the year ended December 31, 2012. These transactions include:

    the exclusion of the Rising Star assets and liabilities that we are not acquiring in the Rising Star Acquisition;

    the Resolute Disposition;

    the Spanish Trail Acquisition;

    our corporate reorganization;

    the Contributions; and

    the ACTOIL NPI Repurchase.

        You should read the following table in conjunction with "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Recent Events and Formation Transactions," the historical combined financial statements of our predecessor and the unaudited pro forma combined financial statements of RSP Permian, Inc. included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma combined financial

 

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statements include more detailed information regarding the basis of presentation for the following information.

 
  Our Predecessor   RSP Permian, Inc.
Pro Forma
 
 
  Six Months Ended
June 30,
  Year Ended
December 31,
 
 
  Six Months
Ended
June 30,
2013
   
 
 
  Year Ended
December 31,
2012
 
 
  2013   2012   2012   2011  
 
  (Unaudited)
   
   
  (Unaudited)
 
 
  (In thousands, except per share data)
 

Statement of Operations Data

                                     

Revenues:

                                     

Oil sales

  $ 44,365   $ 44,675   $ 91,441   $ 56,772   $     $    

Natural gas sales

    2,562     1,596     4,284     7,217              

NGL sales(1)

    2,876     4,462     8,702                  
                           

Total revenues

  $ 49,803   $ 50,733   $ 104,427   $ 63,989   $     $    
                           

Operating expenses:

                                     

Lease operating expenses

  $ 7,456   $ 7,645   $ 15,290   $ 6,803   $     $    

Production, severance and ad valorem taxes

    2,419     2,508     5,139     3,101              

Depreciation, depletion and amortization

    22,234     13,923     48,803     16,612              

Exploration expense

                             

Asset retirement obligation accretion

    51     36     115     46              

Impairments

                2,241              

General and administrative expenses

    1,624     1,271     2,859     3,509              
                           

Total operating expenses

    33,784     25,383     72,206     32,312              
                           

(Gain) on sale of assets

    (6,045 )   (27 )   (6,734 )   (105,333 )            
                           

Operating income

  $ 22,064   $ 25,377   $ 38,955   $ 137,010   $     $    
                           

Other income (expense):

                                     

Other income

  $ 565   $ 505   $ 884   $ 163   $     $    

Gain (loss) on derivative instruments

    (735 )   5,269     (796 )   (1,979 )            

Interest expense

    (1,101 )   (1,373 )   (3,474 )   (3,472 )            
                           

Total other income (expense)

  $ (1,271 ) $ 4,401   $ (3,386 ) $ (5,288 ) $     $    
                           

Income before taxes

    20,793     29,778     35,569     131,722              

Income tax (expense) benefit

    (68 )   (41 )   339     (550 )            
                           

Net Income

  $ 20,725   $ 29,737   $ 35,908   $ 131,172   $     $    
                           

(1)
In 2011, we did not track NGLs as a separate product category; instead, NGL production and sales were included in our natural gas production and sales.

 

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  Our Predecessor   RSP Permian, Inc.
Pro Forma
 
 
  Six Months Ended
June 30,
  Year Ended
December 31,
 
 
  Six Months
Ended
June 30,
2013
   
 
 
  Year Ended
December 31,
2012
 
 
  2013   2012   2012   2011  
 
  (Unaudited)
   
   
  (Unaudited)
 
 
  (In thousands, except per share data)
 

Per share data (unaudited):

                                     

Net earnings (loss) per common share:

                                     

Basic

                          $     $    

Diluted

                                     

Weighted average common shares outstanding:

                                     

Basic

                                     

Diluted

                                     

Pro forma C corporation data (unaudited)(2):

                                     

Net income (loss)

  $ 20,725         $ 35,908         $     $    

Pro forma for income taxes

    (7,461 )         (12,927 )                  
                               

Pro forma net income (loss)

  $ 13,264         $ 22,981         $     $    
                               

Cash Flow Data:

                                     

Net cash provided by operating activities

  $ 31,416   $ 27,470   $ 72,803   $ 26,243   $     $    

Net cash provided by (used in) investing activities

    27,234     (87,152 )   (113,220 )   83,846              

Net cash provided by (used in) financing activities

    (93,851 )   60,500     81,583     (105,155 )            

Other Financial Data:

                                     

Adjusted EBITDAX(3)

  $ 36,295   $ 37,644   $ 78,745   $ 48,698   $     $    
                           

(2)
RSP Permian, L.L.C. was formed in October 2010, and did not conduct any material business operations until December 2010. RSP Permian, Inc. is a subchapter C corporation ("C-corp") under the Internal Revenue Code of 1986, as amended (the "Code"), and will be subject to federal and State of Texas income taxes. The Company computed a pro forma income tax provision for the year ended December 31, 2012 and for the six months ended June 30, 2013, as if our predecessor was subject to income taxes since January 1, 2012, using an effective tax rate of 36%. For 2013 and 2012 comparative purposes, we have included pro forma financial data to give effect to income taxes assuming the earnings of our predecessor had been subject to federal and state income taxes as a C-corp since inception. The unaudited pro forma data is presented for informational purposes only and does not purport to project our results of operations for any future period or our financial position as of any future date. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences.

(3)
Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income, see "—Non-GAAP Financial Measure" below.

 

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  Our Predecessor   RSP Permian, Inc.
Pro Forma
 
 
   
  Year Ended
December 31,
   
 
 
  As of June 30,
2013
  As of June 30,
2013
 
 
  2012   2011  
 
  (Unaudited)
   
   
  (Unaudited)
 
 
  (In thousands)
 

Balance Sheet Data:

                         

Cash and cash equivalents

  $ 16,031   $ 51,232   $ 10,066   $    

Other current assets

    20,871     31,124     27,362        
                   

Total current assets

    36,902     82,356     37,428        

Property, plant and equipment, net

    377,350     421,412     349,598        

Other long-term assets

    11,504     9,470     8,636        
                   

Total assets

  $ 425,756   $ 513,238   $ 395,662   $    
                   

Current liabilities

    15,001     28,165     27,916        

Long-term debt

    27,086     111,586     46,586        

Deferred revenue

    36,931     16,583            

Other long-term liabilities

    1,870     3,061     3,225        

Total members'/stockholders' equity                             

    344,868     353,843     317,935        
                   

Total liabilities and members'/stockholders' equity

  $ 425,756   $ 513,238   $ 395,662   $    
                   

Non-GAAP Financial Measure

        Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation, asset retirement obligation accretion expense, gains and losses from the sale of assets and other non-cash operating items. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles ("GAAP").

        Management believes Adjusted EBITDAX is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX 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 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 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 presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

 

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        The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income for each of the periods indicated.

 
  Our Predecessor   RSP Permian, Inc.
Pro Forma
 
 
  Six Months Ended
June 30,
  Year Ended
December 31,
   
   
 
 
  Six Months
Ended
June 30, 2013
  Year Ended
December 31,
2012
 
 
  2013   2012   2012   2011  
 
  (Unaudited)
   
   
  (Unaudited)
 
 
  (In thousands)
 

Adjusted EBITDAX reconciliation to net income:

                                     

Net income

  $ 20,725   $ 29,737   $ 35,908   $ 131,172   $     $    

Interest expense

    1,101     1,373     3,474     3,472              

Income tax expense (benefit)

    68     41     (339 )   550              

Depreciation, depletion and amortization

    22,234     13,923     48,803     16,612              

Exploration expense

                             

(Gain) loss on derivative instruments

    735     (5,269 )   796     1,979              

Net cash receipts (payments) on settled derivative instruments

    (328 )   (769 )   (474 )   (856 )            

Premiums paid for put options that settled during the period(1)

    (2,246 )   (1,401 )   (2,804 )   (1,185 )            

Impairments

                2,241              

Non-cash equity based compensation

                             

Asset retirement obligation accretion

    51     36     115     46              

(Gain) on sale of assets

    (6,045 )   (27 )   (6,734 )   (105,333 )            
                           

Adjusted EBITDAX

  $ 36,295   $ 37,644   $ 78,745   $ 48,698   $     $    
                           

(1)
Represents premiums paid at inception for put options that settled during the respective period.

 

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Summary Pro Forma Reserve and Operating Data

        The following tables present summary data with respect to our estimated pro forma net proved oil and natural gas reserves and pro forma operating data as of the dates indicated giving effect to the Transactions.

        The reserve estimates attributable to our properties at June 30, 2013 presented in the table below are based on a reserve report prepared by Ryder Scott, our independent reserve engineers. All of these reserve estimates were prepared in accordance with the SEC's rules regarding oil and natural gas reserve reporting that are currently in effect. The following tables also contain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties.

        Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business—Oil and Natural Gas Data—Proved Reserves" in evaluating the material presented below.

 
  RSP Permian, Inc.
Pro Forma(1)
 
 
  June 30, 2013  

Proved Reserves:

       

Oil (MBbls)

    32,480  

Natural gas (MMcf)

    51,574  

NGLs (MBbls)

    11,088  
       

Total proved reserves (MBoe)(2)

    52,164  

Proved Developed Reserves:

       

Oil (MBbls)

    12,029  

Natural gas (MMcf)

    20,969  

NGLs (MBbls)

    4,040  
       

Total proved developed reserves (MBoe)

    19,564  

Proved developed reserves as a percentage of total proved reserves

    38 %

Proved Undeveloped Reserves:

       

Oil (MBbls)

    20,451  

Natural gas (MMcf)

    30,605  

NGLs (MBbls)

    7,048  
       

Total proved undeveloped reserves

    32,600  

Oil and Natural Gas Prices:

       

Oil—NYMEX—WTI per Bbl

  $ 91.60  

Natural gas—NYMEX—Henry Hub per MMBtu

    3.44  

(1)
Our estimated pro forma net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance.

(2)
One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

 

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  RSP Permian, Inc.
Pro Forma
 
 
  Six Months
Ended
June 30, 2013
  Year Ended
December 31,
2012
 
 
  (Unaudited)
 

Production and operating data:

             

Net production volumes:

             

Oil (MBbls)

    826     1,278  

Natural gas (MMcf)

    1,098     1,629  

NGLs (MBbls)

    190     313  
           

Total (MBoe)

    1,199     1,862  
           

Average net daily production (Boe/d)

    6,627     5,089  

Average sales price before effects of hedges:(1)

             

Oil (per Bbl)

  $ 90.54   $ 92.48  

Natural gas (per Mcf)

    3.43     2.86  

NGLs (per Bbl)

    25.36     35.25  

Average price per Boe

    69.54     71.88  

Average sales price after effects of hedges:(1)

             

Oil (per Bbl)

  $ 90.64   $ 92.21  

Natural gas (per Mcf)

    3.43     2.86  

NGLs (per Bbl)

    25.36     35.25  

Average price per Boe

    69.61     71.69  

Average unit costs per Boe:

             

Lease operating expenses

  $ 9.85   $ 10.30  

Production, severance and ad valorem taxes

    3.40     3.54  

Depreciation, depletion and amortization

             

General and administrative expenses(2)

    1.35     1.46  

(1)
Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains or losses on cash settlements for commodity derivative transactions.

(2)
Pro forma general and administrative expenses do not include additional expenses we would have incurred as a result of being a public company.

 

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RISK FACTORS

        Investing in our common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under "Cautionary Statement Regarding Forward-Looking Statements," and the following risks before making an investment decision. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business

Our business is difficult to evaluate because we have a limited operating history.

        We were formed in October 2010 by our management team and an affiliate of NGP. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

Oil and natural gas prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

        The prices we receive for our oil, natural gas and NGLs production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

    worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGLs;

    the price and quantity of foreign imports;

    political and economic conditions in or affecting other producing countries, including the Middle East, Africa, South America and Russia;

    the ability of members of the Organizational of Petroleum Countries to agree to and maintain oil price and production controls;

    the level of global exploration and production;

    the level of global inventories;

    prevailing prices on local price indexes in the areas in which we operate;

    the proximity, capacity, cost and availability of gathering and transportation facilities;

    localized and global supply and demand fundamentals and transportation availability;

    the cost of exploring for, developing, producing and transporting reserves;

    weather conditions and other natural disasters;

    technological advances affecting energy consumption;

    the price and availability of alternative fuels;

    expectations about future commodity prices; and

    domestic, local and foreign governmental regulation and taxes.

        Lower commodity prices may reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves

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as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically.

        If commodity prices decrease, a significant portion of our exploitation, development and exploration projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Our exploitation, development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow reserves.

        The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development and acquisition of oil and natural gas reserves. We currently estimate our 2014 capital budget for drilling, completion, recompletion and infrastructure will be approximately $             million. Our capital budget excludes acquisitions. We expect to fund 2014 capital expenditures with cash generated by operations, borrowings under our revolving credit facility and possibly through asset sales or additional capital market transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our near-term capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

        Our cash flow from operations and access to capital are subject to a number of variables, including:

    our proved reserves;

    the level of hydrocarbons we are able to produce from existing wells;

    the prices at which our production is sold;

    our ability to acquire, locate and produce new reserves; and

    our ability to borrow under our revolving credit facility.

        If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.

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Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

        Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

    landing our wellbore in the desired drilling zone;

    staying in the desired drilling zone while drilling horizontally through the formation;

    running our casing the entire length of the wellbore; and

    being able to run tools and other equipment consistently through the horizontal wellbore.

        Risks that we face while completing our wells include, but are not limited to, the following:

    the ability to fracture stimulate the planned number of stages;

    the ability to run tools the entire length of the wellbore during completion operations; and

    the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

        The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

        Our future financial condition and results of operations will depend on the success of our exploitation, development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

        Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see "—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves." In addition, our cost of drilling, completing and operating wells is often uncertain.

        Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

    delays imposed by or resulting from compliance with regulatory requirements including limitations resulting from wastewater disposal, discharge of greenhouse gases ("GHGs") and limitations on hydraulic fracturing;

    pressure or irregularities in geological formations;

    shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

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Table of Contents

    equipment failures or accidents;

    lack of available gathering facilities or delays in construction of gathering facilities;

    lack of available capacity on interconnecting transmission pipelines;

    adverse weather conditions;

    issues related to compliance with environmental regulations;

    environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

    declines in oil and natural gas prices;

    limited availability of financing at acceptable terms;

    title problems; and

    limitations in the market for oil and natural gas.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

        Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our revolving credit facility, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

        If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

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Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

        Our revolving credit facility contains a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:

    incur additional indebtedness;

    make loans to others;

    make investments;

    merge or consolidate with another entity;

    make certain payments;

    hedge future production or interest rates;

    incur liens;

    sell assets; and

    engage in certain other transactions without the prior consent of the lenders.

        In addition, our revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our revolving credit facilities impose on us.

        A breach of any covenant in our revolving credit facility would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under our revolving credit facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

        Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based, among other things, upon projected revenues from, and asset values of, the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. The borrowing base under our revolving credit facility is $             million as of                 , 2013, with lender commitments of $500 million. Our next scheduled borrowing base redetermination is expected to occur in November 2013.

        In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender's portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to

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repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

Our derivative activities could result in financial losses or could reduce our earnings.

        We enter into derivative instrument contracts for a significant portion of our oil production. As of September 30, 2013, we had entered into hedging contracts through December 31, 2015 covering a total of approximately 1,745 MBbl of our projected oil production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

        Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

    production is less than the volume covered by the derivative instruments;

    the counterparty to the derivative instrument defaults on its contractual obligations;

    there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

    there are issues with regard to legal enforceability of such instruments.

        The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

        As of June 30, 2013, the estimated fair value of our commodity derivative contracts was approximately $1.9 million. Any default by the counterparties to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations.

        In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

        The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

        In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

        Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than we estimate and may be rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors.

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        You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Our Effective Horizontal Acreage is based on our and other operators' current drilling results and our interpretation of available geologic and engineering data and therefore is an inexact estimate subject to various uncertainties.

        Our Effective Horizontal Acreage is equal to what we believe to be our combined horizontal acreage position that is prospective for hydrocarbon production across our target horizontal zones underneath our total surface acreage of 42,428 gross (33,933 net) acres. Our belief is based upon our evaluation of our initial horizontal drilling results and those of other operators in our area to date, combined with our interpretation of available geologic and engineering data. Although we believe this acreage metric more accurately conveys our horizontal drilling opportunities in our target zones, and we believe our analysis of engineering, geological, geochemical and seismic data is based on industry standards, our calculation of our Effective Horizontal Acreage is an inexact estimate. We cannot assure you that all or any portion of our Effective Horizontal Acreage is prospective for our target zones, that any portion of our Effective Horizontal Acreage will ever be drilled or that, if drilled, will result in commercially productive wells.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

        Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

        As of September 30, 2013, we had identified 1,169 horizontal drilling locations in multiple horizons across our acreage based on spacing of five wells per 640 acres for short laterals and five wells per 960 acres for long laterals. Additionally, based on our evaluation of applicable geologic and engineering data as of September 30, 2013, we had 307 identified vertical drilling locations on 40-acre spacing and an additional 500 identified vertical drilling locations based on 20-acre downspacing. As a result of the limitations described above, we may be unable to drill many of our drilling locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

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Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

        Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history, and as of August 2013, all of New Mexico is officially in a drought. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area.

        All of our producing properties are geographically concentrated in the Permian Basin of West Texas. At June 30, 2013, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

        The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by owned and third party gathering systems. Our purchasers then transport the oil by truck or pipeline for transportation. Our natural gas production is generally transported by gathering lines from the wellhead to a gas processing facility. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

We may incur losses as a result of title defects in the properties in which we invest.

        The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

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The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.

        As of June 30, 2013, 62% of our total estimated proved reserves were classified as proved undeveloped. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Further, we may be required to write down our PUDs if we do not drill those wells within five years after their respective dates of booking.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

        Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A writedown constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

        Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

Conservation measures and technological advances could reduce demand for oil and natural gas.

        Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We depend upon several significant purchasers for the sale of most of our oil and natural gas production.

        We normally sell our production to a relatively small number of customers, as is customary in the exploration, development and production business. For the six months ended June 30, 2013, two purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (28%) and Shell Trading (US) Company (39%). For the six months ended June 30, 2013, MidMar Gas, LLC

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("MidMar"), which was renamed Coronado Midstream, LLC in September 2013, accounted for 9% of our revenue. For the year ended December 31, 2012, two purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (76%) and MidMar (11%). For the year ended December 31, 2011, one purchaser accounted for more than 10% of our revenue: Plains Marketing, L.P. (78%). For the year ended December 31, 2011, MidMar accounted for 9% of our revenue. The loss of any of these purchasers could materially and adversely affect our revenues in the short-term.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

        We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and worker health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time resulting in longer waiting periods to receive permits and other regulatory approvals. These laws include, but are not limited to, the federal Clean Air Act (and comparable state laws and regulations that impose obligations related to air emissions), the federal Water Pollution Control Act ("Clean Water Act") and Oil Pollution Act ("OPA") (and comparable state laws and regulations that impose requirements related to discharges of pollutants into regulated bodies of water), the federal Resource Conservation and Recovery Act ("RCRA") (and comparable state laws that impose requirements for the handling and disposal of waste from our facilities), the federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and the community right to know regulations under Title III of the act (and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations we sent waste for disposal and that comparable state laws that require organization and/or disclosure of information about hazardous materials we use or produce), the federal Occupational Safety and Health Act (which establishes workplace standards for the protection of health and safety of employees and requires a hazardous communications program) and the Endangered Species Act (the "ESA") and the Migratory Bird Treaty Act (and comparable state laws that seek to ensure activities do not jeopardize endangered or threatened animals, fish, plant species; do not destroy or modify the critical habitat of such species; and do not result in the taking, killing or possessing migratory birds). Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

        Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and worker health and safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters. Also, new laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be materially and adversely affected.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

        We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

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        Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

    environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

    abnormally pressured formations;

    mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

    fires, explosions and ruptures of pipelines;

    personal injuries and death;

    natural disasters; and

    terrorist attacks targeting oil and natural gas related facilities and infrastructure.

        Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

    injury or loss of life;

    damage to and destruction of property, natural resources and equipment;

    pollution and other environmental damage;

    regulatory investigations and penalties;

    suspension of our operations; and

    repair and remediation costs.

        We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.

        Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

    unexpected drilling conditions;

    title problems;

    pressure or lost circulation in formations;

    equipment failure or accidents;

    adverse weather conditions;

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    compliance with environmental and other governmental or contractual requirements; and

    increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

        In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.

        The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

        In addition, our revolving credit facility imposes certain limitations on our ability to enter into mergers or combination transactions. Our revolving credit facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

        Our oil and natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages, as well injunctions limiting or prohibiting our activities. These regulations could change to our detriment. Our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.

        Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. These land use restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be precluded from the drilling of wells.

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Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, oil and natural gas. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

        Changes to existing or new regulations may unfavorably impact us, could result in increased operating costs and could have a material adverse effect on our financial condition and results of operations. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows. Further, the discharges of oil, natural gas, NGLs and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. See "Business—Regulation of Environmental and Occupational Safety and Health Matters" for a further description of laws and regulations that affect us.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

        The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire. Equipment shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

        Under the Domenici-Barton Energy Policy Act of 2005 ("EP Act of 2005"), the Federal Energy Regulatory Commission ("FERC") has civil penalty authority under the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act ("NGPA") to impose penalties for current violations of up to $1 million/d for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in "Business—Regulation of the Oil and Natural Gas Industry."

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

        In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the Environmental Protection Agency ("EPA") has

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adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration ("PSD"), construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. On July 12, 2012, the EPA issued a final rule that retained previously established emissions thresholds such that only these large stationary sources are subject to greenhouse gas permitting, but those thresholds could be adjusted downward in the future. And despite numerous legal challenges to the EPA's authority to regulate GHGs, federal courts have affirmed that the EPA does have the authority to regulate greenhouse gas emissions under the Clean Air Act. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the recently re-proposed September 2013 GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and natural gas industry remain a possibility. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

        While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. In any event, the Obama administration recently announced its Climate Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and natural gas agency. As part of the Climate Action Plan, the Obama Administration also announced that it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies in the coming years. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our exploration and production operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

        Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to

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fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act ("SDWA") over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. The EPA has yet to finalize its draft permitting guidance. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. To date, the EPA has not issued a Notice of Proposed Rulemaking; therefore, it is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.

        At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example in June 2011, Texas enacted a law requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission adopted rules and regulations applicable to all wells for which the Texas Railroad Commission issues an initial drilling permit on or after February 1, 2012. The new regulations require that well operators disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Furthermore, on May 23, 2013, the Texas Railroad Commission issued a "well integrity rule," which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule takes effect in January 2014. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

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        Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012, and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by late 2014. We may be subject to regulations that restrict our ability to discharge water produced as part of our production operations, and the ability to use injection wells as a disposal option not only will depend on federal or state regulations but also on whether available injection wells have sufficient storage capacities. For example, the EPA is developing effluent limitation guidelines that may impose federal pre-treatment standards on all oil and natural gas operators transporting wastewater associated with hydraulic fracturing activities to publicly owned treatment works for disposal. The EPA plans to propose such standards by 2014. In addition, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013, that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water. The opportunity for the public to comment on the revised proposed rule lapsed on August 23, 2013; therefore, the Department of Interior finalization of the revised proposed rule is not expected for some time. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

        Further, on April 17, 2012, the EPA released final rules that subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards ("NSPS") and the National Emission Standards for Hazardous Air Pollutants ("NESHAPS") programs. These rules became effective on October 15, 2012. The rules include NSPS standards for completions of hydraulically-fractured gas wells. The standards include the reduced emission completion techniques developed in the EPA's Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards will be applicable to newly drilled and fractured wells and wells that are refractured. Further, the rules under NESHAPS include Maximum Achievable Control Technology ("MACT") for glycol dehydrators and storage vessels at major source of hazardous air pollutants not currently subject to MACT standards. In October 2012, several challenges to the EPA's rules were filed. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. Depending on the outcome of such proceedings, the rules may be modified or rescinded or the EPA may issue new rules. Additionally, on December 11, 2012, seven states submitted a notice of intent to sue the EPA to compel the agency to make a determination as to whether standards or performance limiting methane emissions from oil and natural gas sources is appropriate and if so, to promulgate performance standards for methane emissions from existing oil and natural gas sources.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.

        Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number

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of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect operations.

        We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.

        We have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

    increased responsibilities for our executive level personnel;

    increased administrative burden;

    increased capital requirements; and

    increased organizational challenges common to large, expansive operations.

        Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.

Increases in interest rates could adversely affect our business.

        Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, as of                    , 2013, outstanding borrowings and letters of credit under our revolving credit facility were approximately $                 million, and a 1.0% increase in interest rates would result in an increase in annual interest expense of approximately $                 million, assuming the $                 million in debt was outstanding for the full year, before the effects of increased interest rates on the value of our interest rate swap contracts and income taxes. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

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We may be subject to risks in connection with acquisitions of properties.

        The successful acquisition of producing properties requires an assessment of several factors, including:

    recoverable reserves;

    future oil and natural gas prices and their applicable differentials;

    operating costs; and

    potential environmental and other liabilities.

        The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated, and additional state taxes on oil and natural gas extraction may be imposed, as a result of future legislation.

        The Fiscal Year 2014 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to: (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and natural gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

        The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

        Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

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Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities areas where we operate.

        Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material and adverse impact on our ability to develop and produce our reserves.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

        The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission ("CFTC") and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide derivative transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012 although the CFTC has stated that it will appeal the District Court's decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of "swap," "security-based swap," "swap dealer" and "major swap participant." The Dodd-Frank Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts and reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

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The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated oil and natural gas reserves.

        Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of our estimated reserves included in this prospectus should not be construed as accurate estimates of the current fair value of our proved reserves.

We may not be able to keep pace with technological developments in our industry.

        The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

Risks Related to this Offering and our Common Stock

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (or the "Exchange Act"), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

        As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

    institute a more comprehensive compliance function;

    comply with rules promulgated by the NYSE;

    continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

    establish new internal policies, such as those relating to insider trading; and

    involve and retain to a greater degree outside counsel and accountants in the above activities.

        Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2014, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an "emerging growth company" within the meaning of Section 2(a)(19)

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of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2019. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

        In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

        Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

        Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors' purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us, the selling stockholders and representatives of the underwriters, based on numerous factors which we discuss in "Underwriting," and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

        The following factors could affect our stock price:

    our operating and financial performance and drilling locations, including reserve estimates;

    quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

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    the public reaction to our press releases, our other public announcements and our filings with the SEC;

    strategic actions by our competitors;

    changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

    speculation in the press or investment community;

    the failure of research analysts to cover our common stock;

    sales of our common stock by us, the selling stockholders or other stockholders, or the perception that such sales may occur;

    changes in accounting principles, policies, guidance, interpretations or standards;

    additions or departures of key management personnel;

    actions by our stockholders;

    general market conditions, including fluctuations in commodity prices;

    domestic and international economic, legal and regulatory factors unrelated to our performance; and

    the realization of any risks describes under this "Risk Factors" section.

        The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company's securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management's attention and resources and harm our business, operating results and financial condition.

The Existing Investors will hold a substantial majority of our outstanding common stock.

        Immediately following the completion of this offering, the Existing Investors will collectively hold approximately        % of our common stock. See "Recent Events and Formation Transactions—The Existing Investors" for more information regarding the Existing Investors and their ownership of our common stock. The existence of significant stockholders may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, this concentration of stock ownership may adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.

Conflicts of interest could arise in the future between us, on the one hand, and NGP and its affiliates, including its portfolio companies, or the other Existing Investors or their respective affiliates, on the other hand, concerning, among other things, potential competitive business activities or business opportunities.

        NGP is a family of private equity investment funds in the business of making investments in entities primarily in the U.S. energy industry. In addition, certain Existing Investors and certain of their affiliates have made and may continue to make investments in the U.S. oil and gas industry from time to time. As a result, NGP, the Existing Investors or their respective affiliates have and may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as

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businesses that are significant existing or potential customers. NGP, the Existing Investors or their respective affiliates may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

        Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

    limitations on the removal of directors;

    limitations on the ability of our stockholders to call special meetings;

    establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

    providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and

    establishing advance notice and certain information requirements for nominations for election to our Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

Investors in this offering will experience immediate and substantial dilution of $            per share.

        Based on an assumed initial public offering price of $            per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $            per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of June 30, 2013 after giving effect to this offering would be $            per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See "Dilution."

We do not intend to pay dividends on our common stock, and our revolving credit facility places certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

        We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our revolving credit facility places certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay in this offering.

Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

        We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have outstanding shares of common stock. This number includes                shares that we and the

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selling stockholders are selling in this offering and                shares that the selling stockholders may sell in this offering if the underwriters' option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, and assuming full exercise of the underwriters' option to purchase additional shares, the Existing Investors will own                shares of our common stock, or approximately        % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between them and the underwriters described in "Underwriting," but may be sold into the market in the future. Certain of the Existing Investors will be party to a registration rights agreement, which will require us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. Employees will be subject to certain restrictions on the sale of their shares for 180 days after the date of this prospectus; however, after such period, and subject to compliance with the Securities Act or exemptions therefrom, these employees may sell such shares into the public market. See "Shares Eligible for Future Sale" and "Certain Relationships and Related Party Transactions—Registration Rights Agreement."

        In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of                shares of our common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

        We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

        All of our directors and executive officers, certain of our stockholders and the selling stockholders have entered into lock-up agreements with respect to their common stock, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. Barclays Capital Inc., at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then the common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

        Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

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For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

        In April 2012, President Obama signed into law the JOBS Act. We are classified as an "emerging growth company" under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosure regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

        To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

        The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

        The information in this prospectus includes "forward-looking statements." All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading "Risk Factors" included in this prospectus. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

        Forward-looking statements may include statements about our:

    business strategy;

    reserves;

    exploration and development drilling prospects, inventories, projects and programs;

    ability to replace the reserves we produce through drilling and property acquisitions;

    financial strategy, liquidity and capital required for our development program;

    realized oil and natural gas prices;

    timing and amount of future production of oil and natural gas;

    hedging strategy and results;

    future drilling plans;

    competition and government regulations;

    ability to obtain permits and governmental approvals;

    pending legal or environmental matters;

    marketing of oil and natural gas;

    leasehold or business acquisitions;

    costs of developing our properties;

    general economic conditions;

    credit markets;

    uncertainty regarding our future operating results; and

    plans, objectives, expectations and intentions contained in this prospectus that are not historical.

        We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of

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production, cash flow and access to capital, the timing of development expenditures and the other risks described under "Risk Factors" in this prospectus.

        Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

        Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

        All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

        Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

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USE OF PROCEEDS

        We expect to receive approximately $            of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We will not receive any proceeds from the sale of shares by the selling stockholders. The selling stockholders have granted the underwriters an option to purchase up to an aggregate of            additional shares of our common stock to the extent the underwriters sell more than            shares of common stock in this offering.

        We intend to use a portion of the net proceeds from this offering to fully repay our $70 million term loan and the remaining net proceeds of $       million to reduce amounts drawn under our revolving credit facility. As of                , 2013, we had $     million of outstanding borrowings under our revolving credit facility. Our term loan matures in April 2016 and bears interest of 5.5% plus LIBOR (with a floor of 1%), or 6.5%. Our revolving credit facility matures in September 2017 and bears interest at a variable rate, which was         % per annum at                        , 2013. The term loan was incurred to fund a portion of the Spanish Trail Acquisition, and the outstanding borrowings under our revolving credit facility were incurred to fund the Spanish Trail Acquisition and a portion of our 2013 capital budget. We may at any time reborrow amounts repaid under our revolving credit facility, and we expect to do so to fund our capital program.

        A $1.00 increase or decrease in the assumed initial public offering price of $        per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $       million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus remains the same. If the proceeds increase due to a higher initial public offering price, we would use the additional net proceeds to first reduce amounts drawn under our revolving credit facility and any remainder to fund a portion of our capital expenditure program or for general corporate purposes. If the proceeds decrease due to a lower initial public offering price, then we would reduce by a corresponding amount the net proceeds directed to repay outstanding borrowings under our revolving credit facility.

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DIVIDEND POLICY

        RSP Permian, Inc. has never declared and paid, and it does not anticipate declaring or paying, any cash dividends to holders of its common stock in the foreseeable future. RSP Permian, Inc. currently intends to retain future earnings, if any, to finance its operations and the growth of its business. Its future dividend policy is within the discretion of its board of directors and will depend upon then-existing conditions, including its results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on its ability to pay dividends and other factors its board of directors may deem relevant. In addition, its revolving credit facility places restrictions on its ability to pay cash dividends.

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CAPITALIZATION

        The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2013:

    on an actual basis for our predecessor;

    on a pro forma basis to give effect to the transactions described under "Recent Events and Formation Transactions," all of which will be completed immediately prior to, or contemporaneously with, the closing of this offering; and

    on a pro forma basis described above as adjusted to give effect to the sale of shares of our common stock in this offering at an assumed initial offering price of $      per share (which is the midpoint of the range set forth on the cover of this prospectus) and the application of the net proceeds from this offering as set forth under "Use of Proceeds."

        The pro forma as adjusted information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with, and is qualified in its entirety by reference to, "Use of Proceeds" and our historical audited and unaudited combined financial statements and the accompanying notes appearing elsewhere in this prospectus.

 
  As of June 30, 2013  
 
  Actual(1)   Pro Forma   Pro Forma As
Adjusted(2)
 
 
  (In thousands, except number of
shares and par value)

 

Cash and cash equivalents

  $ 16,031   $     $    

Long-term debt, including current maturities:

                   

Revolving credit facility(3)

    27,086              

Term loan(4)

                 
               

Total indebtedness

  $ 27,086   $     $    
               

Members' equity

    344,868              

Stockholders' equity:

                   

Preferred stock—$0.01 par value; no shares authorized, issued or outstanding, actual or pro forma;            shares authorized, no shares issued or outstanding, pro forma as adjusted

                 

Common stock—$0.01 par value; no shares authorized, issued or outstanding, actual;            shares authorized, shares issued and outstanding, pro forma; and            shares authorized, shares issued and outstanding, pro forma as adjusted

                 

Additional paid-in capital

                 

Accumulated deficit

                 
               

Total stockholders' equity

    344,868              
               

Total capitalization

  $ 371,954   $     $    
               

(1)
RSP Permian, Inc. was incorporated in September 2013. The data in this table has been derived from the historical combined financial statements included in this prospectus which pertain to the assets, liabilities, revenues and expenses of our accounting predecessor.

(2)
A $1.00 increase (decrease) in the assumed initial public offering price of $      per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would decrease

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    (increase) total indebtedness by approximately $     million and increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $     million, $     million and $     million, respectively, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares offered by us at an assumed offering price of $      per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would decrease (increase) total indebtedness by approximately $     million and increase (decrease) additional paid-in capital, total stockholders' equity and total capitalization by approximately $     million, $     million and $     million, respectively, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

(3)
As of                , 2013, the borrowing base was $     million, the outstanding amount totaled $     million, and we were able to incur approximately $     million of indebtedness under our revolving credit facility. After giving effect to the consummation of the Transactions and the application of the net proceeds of this offering, we expect the borrowing base to be $     million, providing $     million of available borrowing capacity under our revolving credit facility. No letters of credit are issued and outstanding under our revolving credit facility.

(4)
As of                , 2013, we had $     million of borrowings outstanding under the term loan.

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DILUTION

        Purchasers of our common stock in this offering will experience immediate and substantial dilution in the net tangible book value (tangible assets less total liabilities) per share of our common stock for accounting purposes. Our net tangible book value as of June 30, 2013, after giving pro forma effect to the transactions described under "Recent Events and Formation Transactions," was approximately $             million, or $            per share.

        Pro forma net tangible book value per share is determined by dividing our pro forma net tangible book value by our shares of common stock that will be outstanding immediately prior to the closing of this offering, including giving effect to the transactions described under "Recent Events and Formation Transactions." Assuming an initial public offering price of $            per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us), our adjusted pro forma net tangible book value as of June 30, 2013 would have been approximately $             million, or $            per share. This represents an immediate increase in the net tangible book value of $            per share to our existing stockholders and an immediate dilution to new investors purchasing shares in this offering of $            per share, resulting from the difference between the offering price and the pro forma as adjusted net tangible book value after this offering. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

Assumed initial public offering price per share

        $               

Pro forma net tangible book value per share as of June 30, 2013 (after giving effect to our corporate reorganization and the Transactions)

             

Increase per share attributable to new investors in this offering

             
             

As adjusted pro forma net tangible book value per share (after giving effect to our corporate reorganization, the Transactions and this offering)

             
             

Dilution in pro forma net tangible book value per share to new investors in this offering

        $               
             

        A $1.00 increase (decrease) in the assumed initial public offering price of $            per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $            and increase (decrease) the dilution to new investors in this offering by $            per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

        The following table summarizes, on an adjusted pro forma basis as of June 30, 2013, the total number of shares of common stock owned by existing stockholders and to be owned by new investors at $            per share, which is the midpoint of the price range set forth on the cover page of this prospectus, and the total consideration paid and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $            , the midpoint of the price

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range set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions.

 
   
   
  Total
Consideration
   
 
 
  Shares Acquired    
 
 
  Average
Price
Per Share
 
 
  Number   Percent   Amount   Percent  

Existing stockholders

                   %         $                %         $           

New investors in this offering

                               
                       

Total

                 100 % $              100 % $           
                       

        The data in the table excludes            shares of common stock reserved for issuance under our equity incentive plan (which amount may be increased each year in accordance with the terms of the plan). If the underwriters' option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to          , or approximately          % of the total number of shares of common stock.

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SELECTED HISTORICAL AND PRO FORMA COMBINED FINANCIAL DATA

        The following table shows selected historical combined financial data of our accounting predecessor and selected unaudited pro forma combined financial data of RSP Permian, Inc., for the periods and as of the dates indicated. Our accounting predecessor reflects the combined results of RSP Permian, L.L.C. and Rising Star. For more information regarding our predecessor, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Our Predecessor and RSP Permian, Inc."

        The selected historical combined financial data of our predecessor as of and for the years ended December 31, 2012 and 2011 were derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The selected historical interim combined financial data of our predecessor as of June 30, 2013 and for the six months ended June 30, 2013 and 2012 were derived from the unaudited interim combined financial statements of our predecessor included elsewhere in this prospectus.

        The selected unaudited pro forma combined financial data of RSP Permian, Inc. as of and for the six months ended June 30, 2013 and for the year ended December 31, 2012 were derived from the unaudited pro forma combined financial data included elsewhere in this prospectus. The pro forma combined financial data assumes that this offering and the transactions to be effected prior to, or in connection with, this offering and described under "Recent Events and Formation Transactions" had taken place on June 30, 2013, in the case of the unaudited pro forma combined balance sheet data, and on January 1, 2012, in the case of the pro forma combined statement of operations data for the six months ended June 30, 2013 and the year ended December 31, 2012. These transactions include:

    the exclusion of the Rising Star assets and liabilities that we are not acquiring in the Rising Star Acquisition;

    the Resolute Disposition;

    the Spanish Trail Acquisition;

    our corporate reorganization;

    the Contributions; and

    the ACTOIL NPI Repurchase.

        Our historical results are not necessarily indicative of future operating results. The selected combined financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, "Capitalization," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical combined financial statements of our

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predecessor and the unaudited pro forma combined financial statements of RSP Permian, Inc. included elsewhere in this prospectus.

 
  Our Predecessor   RSP Permian, Inc.
Pro Forma
 
 
  Six Months Ended
June 30,
  Year Ended
December 31,
 
 
  Six Months
Ended
June 30,
2013
   
 
 
  Year Ended
December 31,
2012
 
 
  2013   2012   2012   2011  
 
  (Unaudited)
   
   
  (Unaudited)
 
 
  (In thousands, except per share data)
 

Statement of Operations Data:

                                     

Revenues:

                                     

Oil sales

  $ 44,365   $ 44,675   $ 91,441   $ 56,772   $                $               

Natural gas sales

    2,562     1,596     4,284     7,217              

NGL sales(1)

    2,876     4,462     8,702                  
                           

Total revenues

  $ 49,803   $ 50,733   $ 104,427   $ 63,989   $                $               
                           

Operating expenses:

                                     

Lease operating expenses

  $ 7,456   $ 7,645   $ 15,290   $ 6,803   $     $    

Production, severance and ad valorem taxes

    2,419     2,508     5,139     3,101              

Depreciation, depletion and amortization

    22,234     13,923     48,803     16,612              

Exploration expense

                             

Asset retirement obligation accretion

    51     36     115     46              

Impairments

                2,241              

General and administrative expenses

    1,624     1,271     2,859     3,509              
                           

Total operating expenses

    33,784     25,383     72,206     32,312              
                           

(Gain) on sale of assets

    (6,045 )   (27 )   (6,734 )   (105,333 )            
                           

Operating income

  $ 22,064   $ 25,377   $ 38,955   $ 137,010   $                $               
                           

Other income (expense):

                                     

Other income

  $ 565   $ 505   $ 884   $ 163   $     $    

Gain (loss) on derivative instruments

    (735 )   5,269     (796 )   (1,979 )            

Interest expense

    (1,101 )   (1,373 )   (3,474 )   (3,472 )            
                           

Total other income (expense)

  $ (1,271 ) $ 4,401   $ (3,386 ) $ (5,288 ) $                $               
                           

Income before taxes

    20,793     29,778     35,569     131,722              

Income tax (expense) benefit

    (68 )   (41 )   339     (550 )            
                           

Net Income

  $ 20,725   $ 29,737   $ 35,908   $ 131,172   $     $    
                           

Per share data (unaudited):

                                     

Net earnings (loss) per common share:

                                     

Basic

                          $     $    

Diluted

                                     

Weighted average common shares outstanding:

                                     

Basic

                                     

Diluted

                                     

Pro forma C corporation data (unaudited)(2):

                                     

Net income (loss)

  $ 20,725         $ 35,908         $     $    

Pro forma for income taxes

    (7,461 )         (12,927 )                  
                               

Pro forma net income (loss)

  $ 13,264         $ 22,981         $     $    
                               

Cash Flow Data:

                                     

Net cash provided by operating activities

  $ 31,416   $ 27,470   $ 72,803   $ 26,243   $     $    

Net cash provided by (used in) investing activities

    27,234     (87,152 )   (113,220 )   83,846              

Net cash provided by (used in) financing activities

    (93,851 )   60,500     81,583     (105,155 )            

Other Financial Data:

                                     

Adjusted EBITDAX(3)

  $ 36,295   $ 37,644   $ 78,745   $ 48,698   $     $    
                           

(1)
In 2011, we did not track NGLs as a seperate product category; instead, NGL production and sales were included in our natural gas production and sales.

(2)
RSP Permian, L.L.C. was formed in October 2010, and did not conduct any material business operations until December 2010. RSP Permian, Inc. is a C-corp under the Code, and will be subject to income taxes. The Company computed a pro

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    forma income tax provision for the year ended December 31, 2012 and for the six months ended June 30, 2013, as if our predecessor was subject to income taxes since January 1, 2012, using an effective tax rate of 36%. For 2013 and 2012 comparative purposes, we have included pro forma financial data to give effect to income taxes assuming the earnings of our predecessor had been subject to federal and state income taxes as a C-corp since inception. The unaudited pro forma data is presented for informational purposes only and does not purport to project our results of operations for any future period or our financial position as of any future date. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences.

(3)
Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income, see "Prospectus Summary—Summary Historical and Pro Forma Combined Financial Data—Non-GAAP Financial Measure."

 
  Our Predecessor   RSP Permian, Inc.
Pro Forma
 
 
   
  Year Ended
December 31,
   
 
 
  As of June 30,
2013
  As of June 30,
2013
 
 
  2012   2011  
 
  (Unaudited)
   
   
  (Unaudited)
 
 
  (In thousands)
 

Balance Sheet Data:

                         

Cash and cash equivalents

  $ 16,031   $ 51,232   $ 10,066   $               

Other current assets

    20,871     31,124     27,362        
                   

Total current assets

    36,902     82,356     37,428        

Property, plant and equipment, net

    377,350     421,412     349,598        

Other long-term assets

    11,504     9,470     8,636        
                   

Total assets

  $ 425,756   $ 513,238   $ 395,662   $               
                   

Current liabilities

    15,001     28,165     27,916        

Long-term debt

    27,086     111,586     46,586        

Deferred revenue

    36,931     16,583            

Other long-term liabilities

    1,870     3,061     3,225        

Total members'/stockholders' equity              

    344,868     353,843     317,935        
                   

Total liabilities and members'/stockholders' equity

  $ 425,756   $ 513,238   $ 395,662   $               
                   

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following discussion and analysis should be read in conjunction with the "Selected Historical and Pro Forma Combined Financial Data" and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements," all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Our Predecessor and RSP Permian, Inc.

        RSP Permian, Inc. was formed in September 2013 and does not have historical financial operating results. For purposes of this prospectus, our accounting predecessor reflects the combined results of RSP Permian, L.L.C. and Rising Star. RSP Permian, L.L.C. was formed in 2010 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves in the Permian Basin. In connection with this offering, pursuant to the terms of a corporate reorganization, all of the interests in RSP Permian, L.L.C. will be exchanged for shares of common stock of RSP Permian, Inc. Also in connection with this offering, Rising Star will contribute to RSP Permian, Inc. working interests in certain acreage and wells in which RSP Permian, L.L.C. already has working interests in exchange for shares of RSP Permian, Inc. common stock. These contributed assets represent substantially all of Rising Star's production and revenues for each of the year ended December 31, 2012 and the six months ended June 30, 2013. See "Recent Events and Formation Transactions—Corporate Formation Transactions—The Rising Star Acquisition" for more information regarding the acquisition of assets from Rising Star.

        The pro forma combined financial and operating information of RSP Permian, Inc. consists of the financial and operating results of our predecessor adjusted as if this offering, the application of proceeds therefrom as set forth in "Use of Proceeds" and certain transactions, which have been completed or will be effected prior to, or in connection with, this offering had taken place on January 1, 2012. These transactions include:

    the exclusion of the Rising Star assets and liabilities that we are not acquiring in the Rising Star Acquisition;

    the Resolute Disposition;

    the Spanish Trail Acquisition;

    our corporate reorganization;

    the Contributions; and

    the ACTOIL NPI Repurchase.

        For more information on these transactions, see "Recent Events and Formation Transactions."

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Overview

Our Properties

        The vast majority of our acreage is located on large, contiguous acreage blocks in the core of the Midland Basin, a sub-basin of the Permian Basin, primarily in the adjacent counties of Midland, Martin, Andrews, Dawson and Ector. As of June 30, 2013, on a pro forma basis, we had interests in 324 gross (219 net) producing wells across our properties. As of June 30, 2013, on a pro forma basis, we operate approximately 95% of our net acreage. As of June 30, 2013, on a pro forma basis, our total estimated proved reserves were approximately 52,164 MBoe (approximately 62% oil, 17% natural gas and 21% NGLs), of which approximately 38% were classified as proved developed reserves, including approximately 1% classified as proved developed nonproducing.

How We Evaluate Our Operations

        We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

    production volumes;

    realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts on our oil production;

    lease operating expenses; and

    Adjusted EBITDAX.

        See "—Sources of Revenues," "—Principal Components of Our Cost Structure," and "—Adjusted EBITDAX" for a discussion of these metrics.

Sources of Our Revenues

        Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the six months ended June 30, 2013 and the years ended December 31, 2012 and 2011, our revenues were derived 89%, 88% and 89%, respectively, from oil sales and 5%, 4% and 11%, respectively, from natural gas sales. Our revenues from NGL sales for the six months ended June 30, 2013 and the year ended December 31, 2012, were 6% and 8%, respectively. In 2011, we did not track NGLs as a separate product category; instead, NGL production and sales were included in our natural gas production and sales.

        Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

    Production Volumes

        The following table presents historical production volumes for our predecessor's properties for the six months ended June 30, 2013 and 2012 and the years ended December 31, 2012 and 2011 and our

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pro forma production volumes for the six months ended June 30, 2013 and the year ended December 31, 2012.

 
  Our Predecessor   RSP Permian, Inc.
Pro Forma
 
 
  For the Six
Months Ended
June 30,
  For the Years
Ended
December 31,
   
   
 
 
  For the Six
Months
Ended June 30,
2013
  For the Year
Ended
December 31,
2012
 
 
  2013   2012   2012   2011  

Oil (MBbls)

    511     486     1,040     618     826     1,278  

Natural gas (MMcf)

    807     631     1,576     971     1,098     1,629  

NGLs (MBbl)

    118     117     264     (1)   190     313  
                           

Total (MBoe)

    763     708     1,567     780     1,199     1,862  

Average net daily production (Boe/d)

    4,217     3,893     4,281     2,137     6,627     5,089  

(1)
In 2011, we did not track NGLs as a separate product category; instead, NGL production was included in our natural gas production.

        As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through increased drilling as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to borrow or raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read "Risk Factors—Risks Related to Our Business" for a discussion of these and other risks affecting our proved reserves and production.

    Realized Prices on the Sale of Oil, Natural Gas and NGLs

        The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the ability to transport crude oil to the Cushing, Oklahoma transport hub and the Gulf Coast refineries. Periodically, logistical and infrastructure constraints at the Cushing, Oklahoma transport hub have resulted in an oversupply of crude oil at Midland, Texas and thus lowered prices for Midland WTI. These lower prices adversely affected the prices we realized on oil sales and increased our differential to NYMEX WTI. However, several projects have recently been implemented and several more are underway, which have eased these transportation difficulties and which have reduced our differentials to NYMEX to historical norms.

        The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, liquids-rich natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas' proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds.

        The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the

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periods indicated. The differential varies, but our oil and natural gas normally sells at a discount to the NYMEX WTI and NYMEX Henry Hub price, respectively.

 
  Six Months Ended
June 30,
  Year Ended
December 31,
 
 
  2013   2012   2012   2011  

Oil:

                         

NYMEX WTI High

  $ 98.44   $ 109.77   $ 109.77   $ 113.93  

NYMEX WTI Low

    86.68     77.69     77.69     75.67  

Differential to Average NYMEX WTI

    (7.36 )   (6.24 )   (6.23 )   (3.27 )

Natural Gas:

                         

NYMEX Henry Hub High

  $ 4.41   $ 3.10   $ 3.90   $ 4.85  

NYMEX Henry Hub Low

    3.11     1.91     1.91     2.99  

Differential to Average NYMEX Henry Hub

    (0.59 )   0.10     (0.11 )   (1)

NGLs:

                         

NGL Realized Price as a % of Average NYMEX WTI

    26 %   39 %   35 %   (2)

(1)
In 2011, we did not track NGLs as a separate product category; instead, NGL production and sales were included in our natural gas production and sales. Therefore, the average differential of realized prices to NYMEX Henry Hub is a number that is not meaningful.
(2)
In 2011, we did not track NGLs as a separate product category; instead, NGL production and sales were included in our natural gas production and sales.

        In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2012, the NYMEX WTI prompt month oil price ranged from a high of $109.77 per Bbl to a low of $77.69 per Bbl, while the NYMEX Henry Hub prompt month natural gas price ranged from a high of $3.90 per MMBtu to a low of $1.91 per MMBtu.

        Due to the inherent volatility in oil prices, we have historically used commodity derivative instruments, such as collars, swaps and puts, to hedge price risk associated with a significant portion of our anticipated oil production. We have not historically hedged our natural gas production as it generally represents a small overall percentage of our total revenue. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil prices and may partially limit our potential gains from future increases in prices. None of our instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge a portion of our physical production in order to protect our returns. Our revolving credit facility limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production volume. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our derivatives contract prices are higher than market prices.

        We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our production.

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        Our open positions as of September 30, 2013 were as follows:

Description & Production Period
  Volume (Bbls)   Weighted
Average
Floor price
($/Bbl)(1)
  Weighted
Average
Ceiling price
($/Bbl)(1)
  Weighted
Average
Swap price
($/Bbl)(1)
 

Crude Oil Swaps:

                         

October 2013 - December 2014

    150,000           $ 96.40  

October 2013 - December 2015

    270,000             92.60  

Crude Oil Collars:

                         

October 2013

    2,000   $ 90.00   $ 106.92      

October 2013 - December 2013

    84,000     80.25     101.12      

October 2013 - December 2014

    195,000     90.00     113.37      

January 2014 - September 2014

    9,000     85.00     113.04      

January 2014 - December 2014

    228,000     85.00     107.84      

January 2014 - December 2015

    600,000     85.00     95.00      

January 2015 - December 2015

    72,000     80.00     93.25      

Crude Oil Puts:

                         

October 2013 - December 2013

    135,000   $ 75.00          

(1)
The oil derivative contracts are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude.

Principal Components of Our Cost Structure

        Lease Operating Expenses.    Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production, severance or ad valorem taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expenses in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production related activities such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production.

        We monitor our operations to ensure that we are incurring lease operating expenses at an acceptable level. For example, we monitor our lease operating expenses per Boe to determine if any wells or properties should be shut in, recompleted or sold. This unit rate also allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers. Although we strive to reduce our lease operating expenses, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of properties. For example, we may increase field level expenditures to optimize our operations, incurring higher expenses in one quarter relative to another or we may acquire or dispose of properties that have different lease operating expenses per Boe. These initiatives would influence our overall operating cost and could cause fluctuations when comparing lease operating expenses on a period to period basis.

        Production, Severance and Ad Valorem Taxes.    Production and severance taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues from production sold at fixed

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rates established by federal, state or local taxing authorities. In general, the production and severance taxes we pay correlate to the changes in oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions.

        Depreciation, Depletion and Amortization.    Depreciation, depletion and amortization ("DD&A") is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method. Please read "—Critical Accounting Policies and Estimates—Successful Efforts Method of Accounting for Oil and Natural Gas Activities" for further discussion.

        Impairment Expense.    We review our proved properties and unproved leasehold costs for impairment whenever events and changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Please read "—Critical Accounting Policies and Estimates—Impairment" for further discussion.

        General and Administrative Expenses.    These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services and legal compliance. Certain of our employees hold incentive units in RSP Permian Holdco, L.L.C. that may entitle the holders to a portion of the proceeds to be received by the owners of RSP Permian Holdco, L.L.C. upon sales of shares of our common stock. Any payments with respect to these units will only occur if and when the owners of RSP Permian Holdco, L.L.C. achieve certain minimum return hurdles on their investment through the sale of their shares of our common stock. While these proceeds will not involve any cash payment by us, we will recognize a non-cash compensation expense, which may be material, in the period such payment is deemed probable. The consummation of the offering is not expected to result in any such payments or distributions.

        Gain (Loss) on Derivative Instruments.    We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil. None of our derivative contracts are designated as hedges for accounting purposes. Consequently, our derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. The amount of future gain or loss recognized on derivative instruments is dependent upon future oil prices, which will affect the value of the contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

        Interest Expense.    We finance a portion of our working capital requirements and capital expenditures with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We also have a term loan outstanding that was used to partially fund our recent acquisition of the Spanish Trail Assets. We reflect interest paid to the lenders under our revolving credit facility and term loan in interest expense.

Adjusted EBITDAX

        We define Adjusted EBITDAX as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and premiums paid on put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation, asset retirement obligation accretion expense, gains and losses from the sale of assets and other non-cash operating items.

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        Management believes Adjusted EBITDAX is useful because it allows it 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 from net income in arriving at Adjusted EBITDAX 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 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 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 may not be comparable to other similarly titled measures of other companies. For further discussion, please read "Prospectus Summary—Summary Historical and Pro Forma Combined Financial Data—Non-GAAP Financial Measure."

Factors Affecting the Comparability of Our Pro Forma Results of Operations to the Historical Results of Operations of Our Predecessor

        Our pro forma results of operations and our future results of operations may not be comparable to the historical results of operations of our predecessor for the periods presented, primarily for the reasons described below:

Recent Events and Formation Transactions

        The historical results of operations are based on the financial statements of our accounting predecessor, which reflects the combined results of RSP Permian, L.L.C. and Rising Star, prior to the corporate reorganization and the Transactions described under "Recent Events and Formation Transactions," which will increase the scope of our operations.

Public Company Expenses

        Upon completion of this offering, we expect to incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, increased scope of our operations as a result of recent activities and costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations.

Income Taxes

        Our predecessor was not subject to federal income taxes. Accordingly, the financial data attributable to our predecessor contain no provision for federal income taxes because the tax liability with respect to our taxable income was passed through to our predecessor's members. Our predecessor was subject to State of Texas franchise taxes at less than 1% of modified pre-tax earnings. At the closing of this offering, we will be taxed as a C-corp under the Code and subject to income taxes at a blended statutory rate of 36% of pretax earnings.

Increased Drilling Activity

        Our board of directors has approved a capital budget for 2014 of $             million, including $             million for the drilling and completion of operated wells, of which approximately            % is

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allocated to horizontal wells, $         million for our participation in the drilling and completion of non-operated wells and $         million on infrastructure. This represents a    % increase over our $220.0 million 2013 capital budget. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results.

Predecessor Results of Operations

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

        Oil, Natural Gas, and NGL Sales Revenues.    The following table provides the components of our revenues for the periods indicated, as well as each period's respective average prices and production volumes:

 
  Six Months Ended
June 30,
   
   
 
 
  2013   2012   $ Change   % Change  
 
  (Unaudited)
   
   
 

Revenues (in thousands, except percentages):

                         

Oil sales

  $ 44,365   $ 44,675   $ (310 )   (1 )%

Natural gas sales

    2,562     1,596     966     61 %

NGL sales

    2,876     4,462     (1,586 )   (36 )%
                   

Total sales revenues

  $ 49,803   $ 50,733   $ (930 )   (2 )%
                   

Average sales prices:

                         

Oil (per Bbl) (excluding impact of cash settled derivatives)

  $ 86.90   $ 91.91   $ (5.01 )   (5 )%

Oil (per Bbl) (after impact of cash settled derivatives)

    87.07     91.18     (4.11 )   (5 )%

Natural gas (per Mcf)

    3.17     2.53     0.64     25 %

NGLs (per Bbl)

    24.32     38.08     (13.76 )   (36 )%
                   

Total (per Boe) (excluding impact of cash settled derivatives)

  $ 65.24   $ 71.61   $ (6.37 )   (9 )%

Total (per Boe) (after impact of cash settled derivatives)

  $ 65.36   $ 71.11   $ (5.75 )   (8 )%
                   

Production:

                         

Oil (MBbls)

    511     486     25     5 %

Natural gas (MMcf)

    807     631     176     28 %

NGLs (MBbls)

    118     117     1     1 %
                   

Total (MBoe)

    763     708     55     8 %
                   

Average daily production volume:

                         

Oil (Bbls/d)

    2,820     2,671     149     6 %

Natural gas (Mcf/d)

    4,461     3,468     993     29 %

NGLs (Bbls/d)

    653     644     9     1 %
                   

Total (Boe/d)

    4,217     3,893     325     8 %
                   

        The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price and the relationship between our average realized natural gas price as a

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percentage of the average NYMEX price for the years indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

 
  Six Months Ended
June 30,
 
 
  2013   2012  

Average realized oil price ($/Bbl)

  $ 86.90   $ 91.91  

Average NYMEX ($/Bbl)

    94.26     98.15  

Differential to NYMEX

    (7.36 )   (6.24 )

Average realized oil price to NYMEX percentage

    92 %   94 %

Average realized natural gas price ($/Mcf)

 
$

3.17
 
$

2.53
 

Average NYMEX ($/Mcf)

    3.76     2.43  

Differential to NYMEX

    (0.59 )   0.10  

Average realized natural gas price to NYMEX percentage

    84 %   104 %

Average realized NGL price ($/Bbl)

 
$

24.32
 
$

38.08
 

Average NYMEX ($/Bbl)

    94.26     98.15  

Average realized NGL price to NYMEX percentage

    26 %   39 %

        Our average realized oil price as a percentage of the average NYMEX price decreased to 92% for the first half of 2013 as compared to 94% for the first half of 2012. All of our oil contracts are impacted by the NYMEX differential, which was negative $7.36 per Bbl in the first half of 2013 as compared to negative $6.24 per Bbl in the first half of 2012. Our average realized natural gas price as a percentage of the average NYMEX price decreased from 104% for the first half of 2012 to 84% for the first half of 2013.

        Oil revenues decreased 1% from $44.7 million for the six months ended June 30, 2012 to $44.4 million for the six months ended June 30, 2013 as a result of a $5.01 per Bbl decrease in our average realized price for oil offset by an increase in oil production volumes of 25 MBbls. Our higher oil production was a result of increased production from our horizontal drilling program. Our production from our horizontal drilling program accounted for 9% of our total production for the six months ended June 30, 2013 compared to 0% for the six months ended June 30, 2012. This increase was partially offset by the partial sale of 80 producing wells to Resolute in March 2013, which accounted for 39% of total production for the six months ended June 30, 2012 compared to 15% of total production for the six months ended June 30, 2013.

        Natural gas revenues increased 61% from $1.6 million for the six months ended June 30, 2012 to $2.6 million for the six months ended June 30, 2013 as a result of an increase in natural gas production volumes of 176 MMcf and a $0.64 per Mcf increase in our average realized natural gas price. Our increase in natural gas production was a result of increased production from our horizontal drilling program offset by the partial sale of producing wells to Resolute in March 2013.

        NGL revenues decreased 36% from $4.5 million for six months ended June 30, 2012 to $2.8 million for the six months ended June 30, 2013 as a result of a $13.76 per Bbl decrease in our average realized NGL price. Our NGL production volumes were generally flat for the six months ended June 30, 2012 compared to the six months ended June 30, 2013. NGL production volumes were flat as a result of increased production from our horizontal drilling program that was offset by an equivalent amount from the partial sale of producing wells to Resolute in March 2013. Our lower average realized NGL price was primarily due to increased supplies of NGLs produced from NGL-rich shales in the Permian Basin and other basins, which has resulted in a decrease in prices received for NGLs.

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        Operating Expenses.    The following table summarizes our expenses for the periods indicated:

 
  Six Months Ended
June 30,
   
   
 
 
  2013   2012   $ Change   % Change  
 
  (Unaudited)
   
   
 

Operating expenses (in thousands, except percentages):

                         

Lease operating expenses

  $ 7,456   $ 7,645   $ (189 )   (2 )%

Production, severance and ad valorem taxes

    2,419     2,508     (89 )   (4 )%

Depreciation, depletion and amortization

    22,234     13,923     8,311     60 %

Exploration expense

                0 %

Asset retirement obligation accretion

    51     36     15     42 %

General and administrative expenses

    1,624     1,271     353     28 %
                   

Total operating expenses before gain on sale of assets

  $ 33,784   $ 25,383   $ 8,401     33 %
                   

(Gain) on sale of assets

    (6,045 )   (27 )   (6,018 )   NM  

Total operating expenses after gain on sale of assets

    27,739     25,356     2,383     9 %

Expenses per Boe:

                         

Lease operating expenses

  $ 9.77   $ 10.79     (1.02 )   (9 )%

Production, severance and ad valorem taxes

    3.17     3.54     (0.37 )   (10 )%

Depreciation, depletion and amortization

    29.13     19.65     9.48     48 %

Asset retirement obligation accretion

    0.07     0.05     0.02     40 %

General and administrative expenses

    2.13     1.79     0.34     19 %
                   

Total operating expenses per Boe

  $ 44.27   $ 35.82   $ 8.45     24 %
                   

        Lease Operating Expenses.    Lease operating expenses decreased 2% from $7.7 million for the six months ended June 30, 2012 to $7.5 million for the six months ended June 30, 2013. This decrease in our average lease operating expenses was attributable to savings achieved through 2013 infrastructure projects that have resulted in efficiencies in our field operations and, in particular, putting additional oil volumes on pipeline compared to trucking. These savings more than offset our increase in production from new wells completed during the period.

        Production, Severance and Ad Valorem Taxes.    Production, severance and ad valorem taxes decreased 4% from $2.5 million for the six months ended June 30, 2012 to $2.4 million for the six months ended June 30, 2013 primarily as a result of lower wellhead revenues.

        Depreciation, Depletion and Amortization.    Depreciation, depletion and amortization ("DD&A") expense increased 60% from $13.9 million for the six months ended June 30, 2012 to $22.2 million for the six months ended June 30, 2013 due to an increase in production volumes and an increase in our per Boe DD&A rate. The DD&A rate increased 48% from $19.65 per Boe for the six months ended June 30, 2012 to $29.13 per Boe for the six months ended June 30, 2013 partially as a result of the property sale to Resolute in March 2013 and the resulting decrease in our reserves relative to our carrying costs offset by additional production volumes attributable to the additional drilling activity in 2013.

        General and Administrative Expenses.    General and administrative ("G&A") expenses increased 28% from $1.3 million for the six months ended June 30, 2012 to $1.6 million for the six months ended June 30, 2013 primarily due to increases in advisory fees associated with our property sale to Resolute in March 2013 and increases in compensation expense associated with additions to personnel.

        Gain on Sale of Assets.    Gain on sale of assets increased from a $27 thousand gain for the six months ended June 30, 2012 to a $6.0 million gain for the six months ended June 30, 2013 as a result of the property sale to Resolute in March 2013. See "Recent Events and Formation Transactions—Recent Acquisitions and Dispositions—Resolute Disposition."

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        Other Income and Expenses.    The following table summarizes our other income and expenses for the periods indicated:

 
  Six Months Ended
June 30,
   
   
 
 
  2013   2012   $ Change   % Change  
 
  (Unaudited)
   
   
 

Other income (expense) (in thousands, except percentages):

                         

Other income

  $ 565   $ 505   $ 60     12 %

Gain (loss) on derivative instruments

    (735 )   5,269     (6,004 )   (114) %

Interest expense

    (1,101 )   (1,373 )   272     (20) %
                   

Total other income (expense)

  $ (1,271 ) $ 4,401   $ (5,672 )   (129) %
                   

        Other Income.    Other income increased 12% from $0.5 million for the six months ended June 30, 2012 to $0.6 million for the six months ended June 30, 2013 primarily due to an increase in income related to water we sourced and sold to other working interest partners for use in completion activities.

        Gain (loss) on Derivative Instruments.    During the six months ended June 30, 2012, we recorded a $5.3 million derivative fair value gain as compared to $0.7 million loss in the six months ended June 30, 2013. The change of our derivative fair value loss to a gain was a result of the decrease in the future commodity price outlook during the six months ended June 30, 2013 as compared to the six months ended June 30, 2012, which favorably impacted the fair values of our commodity derivative contracts.

        Interest Expense.    Interest expense decreased 20% from approximately $1.4 million for the six months ended June 30, 2012 to $1.1 million for the six months ended June 30, 2013 as a result of a decrease in the amount outstanding under our revolving credit facility and change in interest rates on our indebtedness.

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Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

        Oil, Natural Gas, and NGL Sales Revenues.    The following table provides the components of our revenues for the years indicated, as well as each year's respective average prices and production volumes:

 
  Year Ended
December 31,
   
   
 
 
  2012   2011   $ Change   % Change  

Revenues (in thousands, except percentages):

                         

Oil sales

  $ 91,441   $ 56,772   $ 34,669     61 %

Natural gas sales(1)

    4,284     7,217     NM     NM  

NGL sales(1)

    8,702         NM     NM  
                   

Total revenues

  $ 104,427   $ 63,989   $ 40,438     63 %
                   

Average sales prices:

                         

Oil (per Bbl) (excluding impact of cash settled derivatives)

  $ 87.92   $ 91.84   $ (3.92 )   (4 )%

Oil (per Bbl) (after impact of cash settled derivatives)

    88.25     91.66     (3.41 )   (4 )%

Natural gas (per Mcf)(1)

    2.72     7.44     NM     NM  

NGLs (per Bbl)(1)

    32.94         NM     NM  
                   

Total (per Boe) (excluding impact of cash settled derivatives)

  $ 66.65   $ 82.05   $ (15.40 ) $ (19 )%

Total (per Boe) (after impact of cash settled derivatives)

  $ 66.86   $ 81.90   $ (15.04 ) $ (18 )%
                   

Production:

                         

Oil (MBbls)

    1,040     618     422     68 %

Natural gas (MMcf)(1)

    1,576     971     NM     NM  

NGLs (MBbls)(1)

    264         NM     NM  
                   

Total (MBoe)

    1,567     780     786     101 %
                   

Average daily production volumes:

                         

Oil (Bbls/d)

    2,842     1,694     1,148     68 %

Natural gas (Mcf/d)(1)

    4,305     2,659     NM     NM  

NGLs (Bbls/d)(1)

    722         NM     NM  
                   

Total (Boe/d)

    4,281     2,137     2,144     100 %
                   

(1)
In 2011, we did not track NGLs as a separate product category; instead, NGL production and sales were included in our natural gas production and sales. Therefore, a comparison of revenues, sales prices and production of natural gas and NGLs between 2011 and 2012 is not meaningful.

        The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price and the relationship between our average realized natural gas price as a

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percentage of the average NYMEX price for the years indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

 
  Year Ended
December 31,
 
 
  2012   2011  

Average realized oil price ($/Bbl)

  $ 87.92   $ 91.84  

Average NYMEX ($/Bbl)

    94.15     95.11  

Differential to NYMEX

    (6.23 )   (3.27 )

Average realized oil price to NYMEX percentage

    93 %   97 %

Average realized natural gas price ($/Mcf)(1)

 
$

2.72
 
$

7.44
 

Average NYMEX ($/Mcf)

    2.83     4.03  

Differential to NYMEX

    (0.11 )   (1)

Average realized natural gas price to NYMEX percentage

    96 %   (1)

Average realized NGL price ($/Bbl)

 
$

32.94
   

(1)

Average NYMEX ($/Bbl)

    94.15   $ 95.11  

Average realized NGL price to NYMEX percentage

    35 %   (1)

(1)
In 2011, we did not track NGLs as a separate product category; instead, NGL production and sales were included in our natural gas production and sales. Therefore, the average differential of realized prices to NYMEX Henry Hub is a number that is not meaningful.

        Oil revenues increased 61% from $56.8 million in 2011 to $91.4 million in 2012 as a result of an increase in oil production volumes of 422 MBbls offset by a decrease in average oil prices of $3.92 per barrel. Of the overall change in oil sales, increases in oil production volumes accounted for a positive change of $38.8 million while decreases in oil prices accounted for a negative change of $4.1 million.

        Natural gas revenues decreased from $7.2 million in 2011 to $4.3 million in 2012. During 2011, we did not track our NGL volumes as a separate product category and included NGL revenues in natural gas sales. As such, a comparison of natural gas or NGL revenues in 2011 to 2012 is not meaningful.

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        Operating Expenses.    The following table summarizes our expenses for the periods indicated:

 
  Year Ended
December 31,
   
   
 
 
  2012   2011   $ Change   % Change  

Operating expenses (in thousands, except percentages):

                         

Lease operating expenses

  $ 15,290   $ 6,803   $ 8,487     125 %

Production, severance and ad valorem taxes

    5,139     3,101     2,038     66 %

Depreciation, depletion and amortization

    48,803     16,612     32,191     194 %

Exploration expense

                0 %

Asset retirement obligation accretion

    115     46     69     150 %

Impairments

        2,241     (2,241 )   (100 )%

General and administrative expenses

    2,859     3,509     (650 )   (19 )%
                   

Total operating expenses before gain on sale

  $ 72,206   $ 32,312   $ 39,894     123 %
                   

(Gain) on sale of assets

    (6,734 )   (105,333 )   98,599     (94 )%

Total operating expenses after gain on sale

  $ 65,472   $ (73,021 ) $ 138,493     190 %

Average unit costs per Boe:

                         

Lease operating expenses

  $ 9.76   $ 8.72   $ 1.04     12 %

Production, severance and ad valorem taxes

    3.28     3.98     (0.70 )   (18 )%

Depreciation, depletion and amortization

    31.15     21.30     9.85     46 %

Asset retirement obligation accretion

    0.07     0.06     0.01     17 %

Impairments

        2.87     (2.87 )   (100 )%

General and administrative expenses

    1.82     4.50     (2.68 )   (60 )%
                   

Total operating expenses per Boe

  $ 46.08   $ 41.43   $ 4.65     11 %
                   

        Lease Operating Expenses.    Lease operating expenses increased 125% from $6.8 million in 2011 to $15.3 million in 2012. This increase was primarily due to an increase in the number of operated wells due to continued drilling activity. On a per Boe basis, lease operating expense increased $1.04 per Boe to $9.76 per Boe. This increase was attributable to increases in costs for repairs and maintenance for 139 new wells added; pumpers, contract welding and administrative expense increases; gathering expensed increases; and fuel and power expense increases.

        Production, Severance and Ad Valorem Taxes.    Production, severance and ad valorem taxes increased 66% from $3.1 million in 2011 to $5.1 million in 2012 as a result of higher wellhead revenues, which exclude the effects of commodity derivative contracts resulting from increased production from our drilling activity and an increase in the number of wells brought on production in 2012.

        Depreciation, Depletion and Amortization.    DD&A expense increased 194% from $16.6 million in 2011 to $48.8 million in 2012 primarily due to an increase in production volumes by adding 139 new wells along with an increase in our asset base subject to amortization as a result of our drilling activity in 2012 and 2011. The DD&A rate per Boe increased 46% from $21.30 per Boe to $31.15 per Boe in 2012 as a result of additional drilling activity in 2012.

        Impairment Expense.    Impairment expense in 2011 was attributable to the annual assessed fair value of oil and natural gas properties being less than the recorded net book value.

        General and Administrative Expenses.    G&A expenses decreased 19% from $3.5 million in 2011 to $2.9 million in 2012. The decrease of $0.7 million is primarily a result of an increase in compensation expenses and advisory services offset by an increase in COPAS overhead reimbursement credits due to increased drilling activity.

        Gain on Sale of Assets.    Gain on sale of assets decreased 94% from $105.3 million gain in 2011 to $6.7 million gain in 2012 as a result of the sale in 2011 of a 25% net profits interest to ACTOIL in substantially all of our oil and natural gas properties at the time, which resulted in a larger gain as compared to the sale to Resolute in 2012. See "Recent Events and Formation Transactions—Recent Acquisitions and Dispositions—Resolute Disposition."

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        Other Income and Expenses.    The following table summarizes our other income and expenses for the periods indicated:

 
  Year Ended
December 31,
   
   
 
 
  2012   2011   $ Change   % Change  

Other income (expense) (in thousands, except percentages):

                         

Other income

  $ 884   $ 163   $ 721     442 %

Gain (loss) on derivative instruments

    (796 )   (1,979 )   1,183     60 %

Interest expense

    (3,474 )   (3,472 )   (2 )   0 %
                   

Total other income (expense)

  $ (3,386 ) $ (5,288 ) $ 1,902     36 %
                   

        Other Income.    Other income increased 442% from $0.2 million in 2011 to $0.9 million in 2012 as a result of income related to disposing of saltwater from third parties totaling $0.1 million in 2011 compared to $0.8 million in 2012.

        Gain (Loss) on Derivative Instruments.    During 2011, we recognized a $2.0 million loss compared to a $0.8 million loss in 2012 on derivative instruments. The change was a result of a decrease in the future commodity price outlook during 2012 as compared to 2011.

        Interest Expense.    The increase in interest expense is a result of an increase in the interest rate on our indebtedness offset by a decrease in the amount outstanding under our revolving credit facility.

Capital Requirements and Sources of Liquidity

        Historically, our predecessor's primary sources of liquidity have been capital contributions from their equity sponsor, borrowings under RSP Permian, L.L.C.'s credit facility, term loan borrowings, proceeds from asset dispositions, proceeds from the issuance of net profits interests and cash flows from operations. To date, our predecessor's primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties.

        Our 2013 capital budget for drilling, completion, recompletion and infrastructure is approximately $220.0 million. As of June 30, 2013, we had spent approximately $94.7 million to drill and complete operated wells, $17.6 million for our participation in the drilling and completion of non-operated wells and $4.1 million on infrastructure. Our 2014 capital budget for drilling, completion, recompletion and infrastructure will be approximately $             million. In 2014, we intend to allocate these expenditures approximately as follows:

    $             million for the drilling and completion of operated wells;

    $             million for our participation in the drilling and completion of non-operated wells; and

    $             million for infrastructure.

        Because we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures are largely discretionary. We could choose to defer a portion of these planned 2014 capital expenditures depending on a variety of factors, including the success of our drilling activities; prevailing and anticipated prices for oil, natural gas and NGLs; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the level of participation by other working interest owners.

        We intend to use a portion of the net proceeds from this offering to fully repay our term loan and a substantial portion of the outstanding borrowings under our revolving credit facility. As of                    

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, 2013, after giving effect to this offering (including the use of proceeds therefrom) and the Transactions, our borrowing base would be $             million, and we would have $             million available under our revolving credit facility.

        Based upon current oil and natural gas price expectations for 2014, following the closing of this offering and the consummation of the Transactions, we believe that our cash flow from operations and additional borrowings under our revolving credit facility will provide us with sufficient liquidity to execute our current capital program.

        However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other needed capital will be available on acceptable terms or at all. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.

Working Capital

        Our working capital, which we define as current assets minus current liabilities, totaled $21.9 million, $54.2 million and $9.5 million at June 30, 2013, December 31, 2012 and December 31, 2011, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $16.0 million, $51.2 million and $10.1 million at June 30, 2013, December 31, 2012 and December 31, 2011, respectively. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our credit agreement after application of the estimated net proceeds from this offering, as described under "Use of Proceeds," will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

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Contractual Obligations

        A summary of our predecessor's contractual obligations as of December 31, 2012 is provided in the following table.

 
  Our Predecessor  
 
  Payments Due by Period
For the Year Ended December 31,
 
 
  2013   2014   2015   2016   2017   Thereafter   Total  
 
  (In thousands)
 

Revolving credit facility(1)

  $   $ 2,000   $ 25,086   $   $   $   $ 27,086  

Term loan(2)

                70,000             70,000  

Drilling rig commitments(3)

    10,127     4,077                     14,204  

Office and equipment leases

    264     191     14                 469  

Asset retirement obligations(4)

                        3,925     3,925  
                               

Total

  $ 10,391   $ 6,268   $ 25,100   $ 70,000   $   $ 3,925   $ 115,684  
                               

(1)
This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on RSP Permian, L.L.C.'s revolving credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2)
We intend to use a portion of the net proceeds from this offering to fully repay our $70 million term loan. Please see "Use of Proceeds."

(3)
The values in the table represent the gross amounts that our predecessor is committed to pay.

(4)
Amounts represent estimates of our predecessor's future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.

Cash Flows

        The following table summarizes our cash flows for the periods indicated:

 
  Our Predecessor  
 
  Six Months Ended
June 30,
  Year Ended
December 31,
 
 
  2013   2012   2012   2011  
 
  (Unaudited)
   
   
 
 
  (In thousands)
 

Net cash provided by operating activities

  $ 31,416   $ 27,470   $ 72,803   $ 26,243  

Net cash provided by (used in) investing activities

    27,234     (87,152 )   (113,220 )   83,846  

Net cash provided by (used in) financing activities

    (93,851 )   60,500     81,583     (105,155 )

        Net cash provided by operating activities was approximately $31.4 million and $27.5 million for the six months ended June 30, 2013 and 2012, respectively. Revenues were substantially consistent for the

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six months ended June 30, 2013 as compared to the six months ended June 30, 2012, and therefore our net cash provided by operating activities were consistent during that same period.

        Net cash provided by operating activities was approximately $72.8 million and $26.2 million for the years ended December 31, 2012 and 2011. Revenues increased for the year ended December 31, 2012 as compared to the year ended December 31, 2011, primarily as a result of increased production, and therefore our net cash provided by operating activities increased during that same period. Cash provided by operating activities is impacted by the prices received for oil and natural gas sales and levels of production volumes.

        Net cash provided by (used in) investing activities was approximately $27.2 million and $(87.2) million for the six months ended June 30, 2013 and 2012, respectively. The increase in the amount of cash provided by investing activities in the six months ended June 30, 2013 compared to the six months ended June 30, 2012 is due to $115.3 million received from the sale of properties to Resolute in March 2013.

        Net cash provided by (used in) investing activities was approximately $(113.2) million and $83.8 million for the years ended December 31, 2012 and 2011, respectively. The increased amount of cash used in investing activities in the year ended December 31, 2012 was due to $174.0 million spent on drilling and development of our properties in 2012 partially offset by $63.2 million of proceeds from the sale of properties to Resolute compared to $95.7 million spent on drilling and developing our properties in 2011, offset by $175 million of proceeds from the sale of a 25% net profits interest to ACTOIL in substantially all of our oil and natural gas properties at the time.

        Net cash provided by (used in) financing activities was approximately $(93.9) million and $60.5 million for the six months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013, the increased cash used in financing activities was primarily the result of a $85.0 million repayment of long-term debt and $30.0 million of capital distributions to members. For the six months ended June 30, 2012, the cash provided by financing activities included $60.5 million in borrowings.

        Net cash provided by (used in) financing activities was approximately $81.6 million and $(105.2) million for the years ended December 31, 2012 and 2011, respectively. For 2012, the increased cash provided by financing activities included $90.0 million of borrowings offset by debt repayments of $25.0 million. For 2011, the cash used in financing activities primarily related to debt repayments of $160.0 million offset by $55.1 million in borrowings.

Our Revolving Credit Facility

        On September 10, 2013, RSP Permian, L.L.C. entered into a credit agreement with Comerica Bank, as administrative agent, and a syndicate of lenders with revolving credit facility with commitments of $500 million, subject to a borrowing base of $             million as of                    , 2013, and a sublimit for letters of credit of $10 million, as well as a term loan in an aggregate principal amount of $70 million. We intend to use a portion of the net proceeds from this offering to fully repay our $70 million term loan and any remaining net proceeds to reduce amounts drawn under our revolving credit facility. After giving effect to the Transactions, this offering and the use of proceeds from this offering, we expect our revolving credit facility's borrowing base will be $             million, providing $             million of available borrowing capacity.

        The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semiannually each May and November and depends on the volumes of our proved oil and natural gas reserves and estimated cash flows from these reserves and our commodity hedge positions. The next redetermination is scheduled to occur in November 2013. As of                     , 2013, we had $             million of borrowings and $             million of letters of credit outstanding under our revolving credit facility. Our revolving credit facility matures September 10, 2017.

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        Our revolving credit facility is secured by liens on substantially all of our properties and guarantees from our subsidiaries other than any subsidiary that we have designated as an unrestricted subsidiary. Our revolving credit facility contains restrictive covenants that may limit our ability to, among other things:

    incur additional indebtedness;

    make loans to others;

    make investments;

    enter into mergers;

    make or declare dividends;

    enter into commodity hedges exceeding a specified percentage or our expected production;

    enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness;

    incur liens;

    sell assets; and

    engage in certain other transactions without the prior consent of the lenders.

        Our revolving credit facility also requires us to maintain the following three financial ratios:

    a working capital ratio, which is the ratio of our consolidated current assets (includes unused commitments under our revolving credit facility and excludes restricted cash and derivative assets) to our consolidated current liabilities (excluding the current portion of long-term debt under the credit facility and derivative liabilities), of not less than 1.0 to 1.0 as of September 30, 2013 and at the end of each fiscal quarter thereafter;

    a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as defined in our revolving credit facility) to consolidated interest expense, of not less than 3.0 to 1.0 as of September 30, 2013; and

    a leverage ratio, which is the ratio of the sum of all our debt to the consolidated EBITDAX (as defined in our revolving credit facility) for the four fiscal quarters then ended, of not greater than 4.0 to 1.0.

        We were in compliance with such covenants and ratios as of September 30, 2013.

        Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing in Eurodollars or at the adjusted base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to the quotient of: (i) the LIBOR Rate; divided by (ii) a percentage equal to 100% minus the maximum rate on such date at which the Administrative Agent is required to maintain reserves on "Eurocurrency Liabilities" as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 125 to 200 basis points, depending on the percentage of our borrowing base utilized. Adjusted base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank's reference rate; (ii) the federal funds effective rate plus 100 basis points; and (iii) the adjusted LIBOR rate plus 100 basis points, plus an applicable margin ranging from 25 to 100 basis points, depending on the percentage of our borrowing base utilized, plus a facility fee of 0.50% charged on the borrowing base amount. As of                    , 2013, borrowings and letters of credit outstanding under our revolving credit facility had a weighted average interest rate of            %. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

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Quantitative and Qualitative Disclosure About Market Risk

        We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

        Our revenues are subject to market risk and are dependent on the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. Our realized prices are primarily driven by the prevailing prices for oil and the prevailing spot prices for natural gas and NGLs. Our predecessor has used, and we expect to continue to use derivative contracts to reduce our exposure to the changes in the prices of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. We do not use these instruments to engage in trading activities, and we do not speculate on commodity prices.

        Our open positions as of September 30, 2013 were as follows:

Description & Production Period
  Volume (Bbls)   Weighted
Average
Floor price
($/Bbl)(1)
  Weighted
Average
Ceiling price
($/Bbl)(1)
  Weighted
Average
Swap price
($/Bbl)(1)
 

Crude Oil Swaps:

                         

October 2013 - December 2014

    150,000           $ 96.40  

October 2013 - December 2015

    270,000             92.60  

Crude Oil Collars:

                         

October 2013

    2,000   $ 90.00   $ 106.92      

October 2013 - December 2013

    84,000     80.25     101.12      

October 2013 - December 2014

    195,000     90.00     113.37      

January 2014 - September 2014

    9,000     85.00     113.04      

January 2014 - December 2014

    228,000     85.00     107.84      

January 2014 - December 2015

    600,000     85.00     95.00      

January 2015 - December 2015

    72,000     80.00     93.25      

Crude Oil Puts:

                         

October 2013 - December 2013

    135,000   $ 75.00