RSP Permian, Inc. - FORM S-1/A

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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

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As filed with the Securities and Exchange Commission on December 13, 2013

Registration No. 333-192268

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

AMENDMENT NO. 1
to
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

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 December 13, 2013

PROSPECTUS

Shares

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 25.

	Per share	Total

Price to the public	$	$
Underwriting discounts and commissions(1)	$	$
Proceeds to us (before expenses)	$	$
Proceeds to the selling stockholders (before expenses)	$	$

(1): We refer you to "Underwriting" beginning on page 150 of this prospectus for additional information regarding underwriting compensation.

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		J.P. Morgan

Tudor, Pickering, Holt & Co.

Prospectus dated

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TABLE OF CONTENTS


PROSPECTUS SUMMARY			1
RISK FACTORS			25
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			50
USE OF PROCEEDS			52
DIVIDEND POLICY			53
CAPITALIZATION			54
DILUTION			56
SELECTED HISTORICAL AND PRO FORMA COMBINED FINANCIAL DATA			58
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			61
BUSINESS			85
MANAGEMENT			114
EXECUTIVE COMPENSATION			120
PRINCIPAL AND SELLING STOCKHOLDERS			128
RECENT AND FORMATION TRANSACTIONS			131
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			137
DESCRIPTION OF CAPITAL STOCK			141
SHARES ELIGIBLE FOR FUTURE SALE			144
MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS			146
UNDERWRITING			150
LEGAL MATTERS			156
EXPERTS			156
WHERE YOU CAN FIND MORE INFORMATION			156
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 and Formation Transactions" for more information regarding these contributions. These contributions and the other transactions described in "—Recent 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.

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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 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 80% 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 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 312 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		312		500		812

Total Target Horizontal and Vertical Locations						1,981	(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 1,981 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 1,981 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 $201.1 million. Our capital budget excludes acquisitions. As of September 30, 2013, we had spent approximately $130.8 million to drill and complete operated wells, $22.3 million for our participation in the drilling and completion of non-operated wells and $5.4 million on infrastructure. We currently estimate our 2014 capital budget for drilling, completion, recompletion and infrastructure will be approximately $361.5 million. We intend to allocate these expenditures approximately as follows:

•: $305.4 million for the drilling and completion of operated wells;
•: $45.3 million for our participation in the drilling and completion of non-operated wells;
•: 80% of our total drilling and completion expenditures to horizontal wells; and
•: $10.8 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 three months ended September 30, 2013, our average net daily production was 8,155 Boe/d (approximately 70% oil, 14% natural gas and 16% NGLs), of which 18% was from horizontal well production and 82% was from vertical well production. As of September 30, 2013, we produced from 16 horizontal and 328 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 as if they had taken place at the beginning of 2011.

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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 than our total surface acreage, 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.

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The following table provides summary information regarding our proved reserves as of June 30, 2013, and production for the three months ended September 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 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 (MMBbls)		Natural Gas (Bcf)		NGLs (MMBbls)		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		8,155(3	)		17.5

(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 three months ended September 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 70% oil, 14% 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 80% 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 November 1, 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

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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 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.

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•: 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.
•: 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 312 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

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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 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 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 three months ended September 30, 2013, average net daily production associated with the Spanish Trail Assets was approximately 1,097 Boe/d (approximately 71% oil, 12% natural gas and 17% 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 Collins and Wallace 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.

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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 (the "Verde Acquisition"). 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. This belief is based on detailed log analysis of four key well penetrations located within the acreage block as well as drill cuttings analysis from two of these wells to verify porosity, permeability and total organic carbon content. We believe the prospectivity of this acreage is further corroborated by the data provided from an additional 50 wells drilled by third parties on or within one mile of the acreage block that have penetrated sufficient depth to provide data on the Wolfcamp B zone. No 3-D seismic data has been acquired on this acreage as of this time.

This acreage currently contains no producing wells. However, 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 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, 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 three months ended September 30, 2013, RSP Permian, L.L.C.'s average net daily production was 4,476 Boe/d (approximately 70% oil, 14% natural gas and 16% NGLs).

Pursuant to the terms of a corporate reorganization that will be completed in connection with this offering, (i) the members of RSP Permian, L.L.C. will contribute all of their interests in RSP Permian, L.L.C. to RSP Permian Holdco, L.L.C., a to-be-formed entity that will be wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. will contribute all of its interests in RSP Permian, L.L.C. to RSP Permian, Inc. in exchange for shares of common stock of RSP Permian, Inc., and an assignment of RSP Permian, L.L.C.'s pro rata share of an escrow related to the Resolute Disposition (which escrow is described in Note 3 of the unaudited historical combined financial statements of RSP Permian, L.L.C. and Rising Star Energy Development Co., L.L.C.). 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

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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 three months ended September 30, 2013, the average net daily production associated with the Rising Star Assets was 213 Boe/d (approximately 65% oil, 16% natural gas and 19% 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 nine months ended September 30, 2013.

The Collins and Wallace Contributions. Collins, Wallace LP and a newly-formed entity, Collins & Wallace Holdings, LLC, that is owned equally by Collins and Wallace LP have each agreed to contribute to us certain working interests (collectively, the "Collins and Wallace 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 Collins and Wallace 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 three months ended September 30, 2013, the 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 2,369 Boe/d (approximately 69% oil, 15% natural gas and 16% NGLs).

The Pecos Contribution. In connection with this offering, Pecos Energy Partners, L.P. ("Pecos"), an entity owned by certain members of our management team, has agreed to contribute to us certain working interests (the "Pecos Assets") in certain acreage and wells in the Permian Basin in which RSP Permian, L.L.C. already has working interests (the "Pecos Contribution"). In exchange, Pecos will receive shares of RSP Permian, Inc. common stock. The Pecos Contribution will increase our working interests in approximately 650 gross acres and six producing wells. For the three months ended September 30, 2013, the average net daily production associated with the Pecos Assets was 8 Boe/d (approximately 78% oil and 22% natural gas).

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.

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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 "—Recent and Formation Transactions," "—Our Ownership and Organizational Structure" and "Principal and Selling Stockholders."

Our Ownership and Organizational Structure

Following the completion of the Transactions, 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.(4)
Ted Collins, Jr.
Wallace Family Partnership, LP
Collins & Wallace Holdings, LLC
Pecos Energy Partners, L.P.(5)
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 also own incentive units in RSP Permian Holdco, L.L.C. Please see "Executive Compensation—Outstanding Equity Awards at 2012 Fiscal Year-End" for information on the incentive units.
(4): Rising Star Energy Development Co., L.L.C. is wholly owned by Rising Star Energy Holdings, L.P. ("Rising Star LP"), which is managed by its general partner, Rising Star Energy GP, L.L.C. ("Rising Star GP"). Rising Star LP and Rising Star GP are each owned by Natural Gas Partners VIII, L.P. ("NGP VIII"), certain members of our management team and certain other persons.
(5): Pecos Energy Partners, L.P. is owned by certain members of our management team and is managed by its general partner, Pecos Operating Company, LLC, which is also owned by certain members of our management team.

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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 and Formation Transactions."

Ownership Structure After Giving Effect to the Transactions and this Offering

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 25 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.
•: 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.

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•: 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 will be used 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 25 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 September 30, 2013 and for the nine months ended September 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 nine months ended September 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 and Formation Transactions" (other than the Verde Acquisition and the Pecos Contribution, which are not included in our pro forma financial statements due to their insignificance to our combined financial results) had taken place on September 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 nine months ended September 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 Collins and Wallace 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 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.

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Among other things, those historical and unaudited pro forma combined financial statements include more detailed information regarding the basis of presentation for the following information.

	Our Predecessor												RSP Permian, Inc. Pro Forma

	Nine Months Ended September 30,						Year Ended December 31,						RSP Permian, Inc. Pro Forma
													Nine Months Ended September 30, 2013
														Year Ended December 31, 2012
	2013			2012			2012			2011				Year Ended December 31, 2012
	(Unaudited)												(Unaudited)
	(In thousands, except per share data)
Statement of Operations Data
Revenues:
Oil sales	$	77,504		$	69,539		$	91,441		$	56,772		$	$
Natural gas sales		3,962			2,441			4,284			7,217
NGL sales(1)		5,197			5,649			8,702			—

Total revenues	$	86,663		$	77,629		$	104,427		$	63,989		$	$

Operating expenses:
Lease operating expenses	$	10,470		$	9,253		$	15,290		$	6,803		$	$
Production and ad valorem taxes		5,923			5,294			5,139			3,101
Depreciation, depletion and amortization		41,113			21,458			48,803			16,612
Exploration expense		—			—			—			—
Asset retirement obligation accretion		83			54			115			46
Impairments		—			—			—			2,241
General and administrative expenses		2,672			1,743			2,859			3,509

Total operating expenses		60,261			37,802			72,206			32,312

(Gain) on sale of assets		(22,700	)		(27	)		(6,734	)		(105,333	)

Operating income	$	49,102		$	39,854		$	38,955		$	137,010		$	$

Other income (expense):
Other income	$	863		$	651		$	884		$	163		$	$
Gain (loss) on derivative instruments		(3,365	)		137			(796	)		(1,979	)
Interest expense		(1,770	)		(2,403	)		(3,474	)		(3,472	)

Total other income (expense)	$	(4,272	)	$	(1,615	)	$	(3,386	)	$	(5,288	)	$	$

Income before taxes		44,830			38,239			35,569			131,722
Income tax (expense) benefit		(68	)		364			339			(550	)

Net Income	$	44,762		$	38,603		$	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

	Nine Months Ended September 30,						Year Ended December 31,						RSP Permian, Inc. Pro Forma
													Nine Months Ended September 30, 2013
														Year Ended December 31, 2012
	2013			2012			2012			2011				Year Ended December 31, 2012
	(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)	$	44,762					$	35,908					$	$
Pro forma for income taxes		(16,114	)					(12,927	)

Pro forma net income (loss)	$	28,648					$	22,981					$	$

Cash Flow Data:
Net cash provided by operating activities	$	38,602		$	43,878		$	72,803		$	26,243		$	$
Net cash provided by (used in) investing activities		(80,187	)		(124,000	)		(113,220	)		83,846
Net cash provided by (used in) financing activities		8,249			80,000			81,583			(105,155	)
Other Financial Data:
Adjusted EBITDAX(3)	$	64,549		$	59,392		$	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 nine months ended September 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 September 30, 2013		Year Ended December 31,				As of September 30, 2013
	As of September 30, 2013		2012		2011		As of September 30, 2013
	(Unaudited)						(Unaudited)
	(In thousands)
Balance Sheet Data:
Cash and cash equivalents	$	17,896	$	51,232	$	10,066	$
Other current assets		44,163		31,124		27,362

Total current assets		62,059		82,356		37,428
Property, plant and equipment, net		481,091		421,412		349,598
Other long-term assets		16,803		9,470		8,636

Total assets	$	559,953	$	513,238	$	395,662	$

Current liabilities		22,428		28,165		27,916
Long-term debt		128,155		111,586		46,586
NPI payable		36,931		16,583		—
Other long-term liabilities		3,534		3,061		3,225
Total members'/stockholders' equity		368,905		353,843		317,935

Total liabilities and members'/stockholders' equity	$	559,953	$	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

	Nine Months Ended September 30,						Year Ended December 31,						RSP Permian, Inc. Pro Forma
													Nine Months Ended September 30, 2013
														Year Ended December 31, 2012
	2013			2012			2012			2011				Year Ended December 31, 2012
	(Unaudited)												(Unaudited)
	(In thousands)
Adjusted EBITDAX reconciliation to net income:
Net income	$	44,762		$	38,603		$	35,908		$	131,172		$	$
Interest expense		1,770			2,403			3,474			3,472
Income tax expense (benefit)		68			(364	)		(339	)		550
Depreciation, depletion and amortization		41,113			21,458			48,803			16,612
Exploration expense		—			—			—			—
(Gain) loss on derivative instruments		3,365			(137	)		796			1,979
Net cash receipts (payments) on settled derivative instruments		(542	)		(495	)		(474	)		(856	)
Premiums paid for put options that settled during the period(1)		(3,370	)		(2,103	)		(2,804	)		(1,185	)
Impairments		—			—			—			2,241
Non-cash equity based compensation		—			—			—			—
Asset retirement obligation accretion		83			54			115			46
(Gain) on sale of assets		(22,700	)		(27	)		(6,734	)		(105,333	)

Adjusted EBITDAX	$	64,549		$	59,392		$	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, as of the dates indicated, summary data with respect to our estimated pro forma net proved oil and natural gas reserves and pro forma operating data, 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(1)

	Nine Months Ended September 30, 2013		Year Ended December 31, 2012
	(Unaudited)
Production and operating data:
Net production volumes:
Oil (MBbls)		1,353		1,278
Natural gas (MMcf)		1,715		1,629
NGLs (MBbls)		305		313

Total (MBoe)		1,944		1,862

Average net daily production (Boe/d)		7,122		5,089
Average sales price before effects of hedges:(1)
Oil (per Bbl)	$	95.10	$	88.16
Natural gas (per Mcf)		3.33		2.65
NGLs (per Bbl)		27.85		33.72
Average price per Boe		73.50		68.46
Average sales price after effects of hedges:(1)
Oil (per Bbl)	$	95.22	$	88.42
Natural gas (per Mcf)		3.33		2.65
NGLs (per Bbl)		27.85		33.72
Average price per Boe		73.58		68.64
Average unit costs per Boe:
Lease operating expenses	$	8.66	$	10.11
Production and ad valorem taxes		4.47		3.37
Depreciation, depletion and amortization		37.69		37.65
General and administrative expenses(2)		1.32		1.44

(1): Does not include the results related to the Verde Acquisition or Pecos Contribution due to their lack of significance to our combined financial results.
(2): 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.
(3): 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 $361.5 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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•: 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.

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;

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•: 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 $140 million as of , 2013, with lender commitments of $500 million, and we expect the borrowing base will be increased to $ million after this offering. Our next scheduled borrowing base redetermination is expected to occur in May 2014.

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 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

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of approximately 1,745 MBbls 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 September 30, 2013, the estimated fair value of our commodity derivative contracts was a net liability of approximately $1.0 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 312 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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Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations. The Permian Basin has recently experienced severe winter weather and, as a result, our operating results for the three months ending December 31, 2013 may ultimately be adversely affected.

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.

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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.

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.

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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 nine months ended September 30, 2013, four purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (20%), Shell Trading (US) Company (41%), Enterprise Crude Oil LLC (12%) and Diamondback E&P LLC (11%). For the nine months ended September 30, 2013, MidMar Gas, LLC ("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.

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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.

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;

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•: pressure or lost circulation in formations;
•: equipment failure or accidents;
•: adverse weather conditions;
•: 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

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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.

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."

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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 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.

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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 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 and Formation Transactions—The Existing Investors" for more information regarding the Existing Investors and their ownership of our common stock. Furthermore, in connection with the closing of this offering, we expect to enter into a stockholders' agreement with RSP Permian Holdco, L.L.C., Collins, Wallace LP, Rising Star and Pecos. The stockholders' agreement is expected to provide each of RSP Permian Holdco, L.L.C., Collins and Wallace LP with the right to designate a certain number of nominees to our board of directors so long as each beneficially owns more than a certain percentage of the outstanding shares of our common stock. See "Certain Relationships and Related Party Transactions—Stockholders' Agreement." The existence of significant stockholders and the stockholders' agreement 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.

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

Our amended and restated certificate of incorporation will authorize 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.

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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 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 "Certain Relationships and Related Party Transactions—Registration Rights Agreement" and "Shares Eligible for Future Sale."

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.

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

Our amended and restated certificate of incorporation will authorize 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.

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 management's 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.

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

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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. The remaining net proceeds of $ million will be used 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 September 30, 2013:

•: on an actual basis for our predecessor;
•: on a pro forma basis to give effect to the transactions described under "Recent 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 September 30, 2013

	Actual(1)		Pro Forma	Pro Forma As Adjusted(2)
	(In thousands, except number of shares and par value)
Cash and cash equivalents	$	17,896	$	$
Long-term debt, including current maturities:
Revolving credit facility(3)		58,155
Term loan(4)		70,000

Total indebtedness	$	128,155	$	$

Members' equity		368,905
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		368,905

Total capitalization	$	497,060	$	$

(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.

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(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 (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 $140 million, the outstanding amount totaled $ million, and we were able to incur approximately $ million of indebtedness under our revolving credit facility. After the consummation of the Transactions and this offering, we expect the borrowing base will be increased to $ million, which would provide $ 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 September 30, 2013, after giving pro forma effect to the 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. 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 September 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 September 30, 2013 (after giving effect to 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 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 September 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
	Shares Acquired								Average Price Per Share
	Number	Percent			Amount	Percent			Average Price Per Share
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 September 30, 2013 and for the nine months ended September 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 nine months ended September 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 and Formation Transactions" (other than the Verde Acquisition and the Pecos Contribution, which are not included in our pro forma financial statements due to their insignificance to our combined financial results.) had taken place on September 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 nine months ended September 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 Collins and Wallace 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

	Nine Months Ended September 30,						Year Ended December 31,						RSP Permian, Inc. Pro Forma
													Nine Months Ended September 30, 2013
														Year Ended December 31, 2012
	2013			2012			2012			2011				Year Ended December 31, 2012
	(Unaudited)												(Unaudited)
	(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil sales	$	77,504		$	69,539		$	91,441		$	56,772		$	$
Natural gas sales		3,962			2,441			4,284			7,217
NGL sales(1)		5,197			5,649			8,702			—

Total revenues	$	86,663		$	77,629		$	104,427		$	63,989		$	$

Operating expenses:
Lease operating expenses	$	10,470		$	9,253		$	15,290		$	6,803		$	$
Production and ad valorem taxes		5,923			5,294			5,139			3,101
Depreciation, depletion and amortization		41,113			21,458			48,803			16,612
Exploration expense		—			—			—			—
Asset retirement obligation accretion		83			54			115			46
Impairments		—			—			—			2,241
General and administrative expenses		2,672			1,743			2,859			3,509

Total operating expenses		60,261			37,802			72,206			32,312

(Gain) on sale of assets		(22,700	)		(27	)		(6,734	)		(105,333	)

Operating income	$	49,102		$	39,854		$	38,955		$	137,010		$	$

Other income (expense):
Other income	$	863		$	651		$	884		$	163		$	$
Gain (loss) on derivative instruments		(3,365	)		137			(796	)		(1,979	)
Interest expense		(1,770	)		(2,403	)		(3,474	)		(3,472	)

Total other income (expense)	$	(4,272	)	$	(1,615	)	$	(3,386	)	$	(5,288	)	$	$

Income before taxes		44,830			38,239			35,569			131,722
Income tax (expense) benefit		(68	)		364			339			(550	)

Net Income	$	44,762		$	38,603		$	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)	$	44,762					$	35,908					$	$
Pro forma for income taxes		(16,114	)					(12,927	)

Pro forma net income (loss)	$	28,648					$	22,981					$	$

Cash Flow Data:
Net cash provided by operating activities	$	38,602		$	43,878		$	72,803		$	26,243		$	$
Net cash provided by (used in) investing activities		(80,187	)		(124,000	)		(113,220	)		83,846
Net cash provided by (used in) financing activities		8,249			80,000			81,583			(105,155	)
Other Financial Data:
Adjusted EBITDAX(3)	$	64,549		$	59,392		$	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 nine months ended September 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 September 30, 2013		Year Ended December 31,				As of September 30, 2013
	As of September 30, 2013		2012		2011		As of September 30, 2013
	(Unaudited)						(Unaudited)
	(In thousands)
Balance Sheet Data:
Cash and cash equivalents	$	17,896	$	51,232	$	10,066	$
Other current assets		44,163		31,124		27,362

Total current assets		62,059		82,356		37,428
Property, plant and equipment, net		481,091		421,412		349,598
Other long-term assets		16,803		9,470		8,636

Total assets	$	559,953	$	513,238	$	395,662	$

Current liabilities		22,428		28,165		27,916
Long-term debt		128,155		111,586		46,586
NPI payable		36,931		16,583		—
Other long-term liabilities		3,534		3,061		3,225
Total members'/stockholders' equity		368,905		353,843		317,935

Total liabilities and members'/stockholders' equity	$	559,953	$	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 nine months ended September 30, 2013. See "Recent 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 information of RSP Permian, Inc. consists of the financial results of our predecessor adjusted as if this offering, the application of proceeds therefrom as set forth in "Use of Proceeds" and the transactions listed below, which will have been completed or will be effected prior to, or in connection with, this offering, had taken place on January 1, 2012:

•: 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 Collins and Wallace Contributions; and
•: the ACTOIL NPI Repurchase.

For information on the transactions reflected in such pro forma combined financial or operating information, see "Recent 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 (giving effect to the Transactions), 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 nine months ended September 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 nine months ended September 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 nine months ended September 30, 2013 and 2012 and the years ended December 31, 2012 and 2011

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and our pro forma production volumes for the nine months ended September 30, 2013 and the year ended December 31, 2012.

	Our Predecessor									RSP Permian, Inc. Pro Forma

	For the Nine Months Ended September 30,				For the Years Ended December 31,
	For the Nine Months Ended September 30,				For the Years Ended December 31,					For the Nine Months Ended September 30, 2013		For the Year Ended December 31, 2012
	2013		2012		2012		2011			For the Nine Months Ended September 30, 2013		For the Year Ended December 31, 2012
Oil (MBbls)		820		758		1,040		618			1,353		1,278
Natural gas (MMcf)		1,188		1,102		1,576		971			1,715		1,629
NGLs (MBbls)		178		189		264		—	(1)		305		313

Total (MBoe)		1,196		1,131		1,567		780			1,944		1,862
Average net daily production (Boe/d)		4,381		4,126		4,281		2,137			7,122		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.

	Nine Months Ended September 30,						Year Ended December 31,

	2013			2012			2012			2011
Oil:
NYMEX WTI High	$	110.53		$	109.77		$	109.77		$	113.93
NYMEX WTI Low		86.68			77.69			77.69			75.67
Differential to Average NYMEX WTI		(3.67	)		(4.42	)		(6.23	)		(3.27	)
Natural Gas:
NYMEX Henry Hub High	$	4.41		$	3.32		$	3.90		$	4.85
NYMEX Henry Hub Low		3.11			1.91			1.91			2.99
Differential to Average NYMEX Henry Hub		(0.35	)		(0.36	)		(0.11	)		—	(1)
NGLs:
NGL Realized Price as a % of Average NYMEX WTI		30	%		31	%		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		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 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 and Ad Valorem Taxes. Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues from production sold at fixed rates established by federal,

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state or local taxing authorities. In general, the production 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, upon vesting, entitle the holders to a disproportionate share of future distributions to members after all of the members that have made capital contributions to RSP Permian Holdco, L.L.C. have received cumulative distributions in respect of their membership interests (including distributions made upon sales of shares of our common stock) equal to specified rates of return. These rates of return and the vesting schedule are described under "Executive Compensation—Outstanding Equity Awards at 2012 Fiscal Year-End." While these distributions will not involve any cash payment by us, we will recognize a non-cash compensation expense, which may be material, in the period such distributions are deemed probable. The consummation of the offering is not expected to result in any such 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.

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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.

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 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 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

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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 $361.5 million, including $305.4 million for the drilling and completion of operated wells, $45.3 million for our participation in the drilling and completion of non-operated wells and $10.8 million on infrastructure. Approximately 80% of our total drilling and completion expenditures is allocated to horizontal wells. Our 2014 capital budget represents an 80% increase over our $201.1 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

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 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:

	Nine Months Ended September 30,

	2013		2012		$ Change			% Change
	(Unaudited)
Revenues (in thousands, except percentages):
Oil sales	$	77,504	$	69,539	$	7,965			11	%
Natural gas sales		3,962		2,441		1,521			62	%
NGL sales		5,197		5,649		(452	)		(8	)%

Total revenues	$	86,663	$	77,629	$	9,034			12	%

Average sales prices:
Oil (per Bbl) (excluding impact of cash settled derivatives)	$	94.52	$	91.74	$	2.78			3	%
Oil (per Bbl) (after impact of cash settled derivatives)		94.72		91.60		3.12			3	%
Natural gas (per Mcf)		3.34		2.22		1.12			51	%
NGLs (per Bbl)		29.20		29.89		(0.69	)		(2	)%

Total (per Boe) (excluding impact of cash settled derivatives)	$	72.46	$	68.64	$	3.82			6	%
Total (per Boe) (after impact of cash settled derivatives)	$	72.60	$	68.57	$	4.03			6	%

Production:
Oil (MBbls)		820		758		62			8	%
Natural gas (MMcf)		1,188		1,102		86			8	%
NGLs (MBbls)		178		189		(11	)		(6	)%

Total (MBoe)		1,196		1,131		65			6	%

Average daily production volume:
Oil (Bbls/d)		3,004		2,766		238			9	%
Natural gas (Mcf/d)		4,352		4,022		330			8	%
NGLs (Bbls/d)		652		690		(38	)		(5	)%

Total (Boe/d)		4,381		4,126		255			6	%

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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 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.

	Nine Months Ended September 30,

	2013			2012
Average realized oil price ($/Bbl)	$	94.52		$	91.74
Average NYMEX ($/Bbl)		98.19			96.16
Differential to NYMEX		(3.67	)		(4.42	)
Average realized oil price to NYMEX percentage		96	%		95	%
Average realized natural gas price ($/Mcf)	$	3.34		$	2.22
Average NYMEX ($/Mcf)		3.69			2.58
Differential to NYMEX		(0.35	)		(0.36	)
Average realized natural gas price to NYMEX percentage		91	%		86	%
Average realized NGL price ($/Bbl)	$	29.20		$	29.89
Average NYMEX ($/Bbl)		98.19			96.16
Average realized NGL price to NYMEX percentage		30	%		31	%

Our average realized oil price as a percentage of the average NYMEX price increased to 96% for the first nine months of 2013 as compared to 95% for the first nine months of 2012. All of our oil contracts are impacted by the NYMEX differential, which was negative $3.67 per Bbl in the first nine months of 2013 as compared to negative $4.42 per Bbl in the first nine months of 2012. Our average realized natural gas price as a percentage of the average NYMEX price was 86% for the first nine months of 2012 and 91% for the first nine months of 2013.

Oil revenues increased 11% from $69.5 million for the nine months ended September 30, 2012 to $77.5 million for the nine months ended September 30, 2013 as a result of a $2.78 per Bbl increase in our average realized price for oil, compounded by an increase in oil production volumes of 62 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 nine months ended September 30, 2013 compared to 0% for the nine months ended September 30, 2012. This increase was partially offset by the partial sale of 80 producing wells to Resolute in March 2013, which accounted for 38% of total production for the nine months ended September 30, 2012 compared to 9% of total production for the nine months ended September 30, 2013.

Natural gas revenues increased 62% from $2.4 million for the nine months ended September 30, 2012 to $4.0 million for the nine months ended September 30, 2013 as a result of an increase in natural gas production volumes of 86 MMcf and a $1.12 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 8% from $5.6 million for nine months ended September 30, 2012 to $5.2 million for the nine months ended September 30, 2013 as a result of a $0.69 per Bbl decrease in our average realized NGL price. Our NGL production volumes were generally flat for the nine months ended September 30, 2012 compared to the nine months ended September 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:

	Nine Months Ended September 30,

	2013			2012			$ Change			% Change
	(Unaudited)
Operating expenses (in thousands, except percentages):
Lease operating expenses	$	10,470		$	9,253		$	1,217			13	%
Production and ad valorem taxes		5,923			5,294			629			12	%
Depreciation, depletion and amortization		41,113			21,458			19,655			92	%
Exploration expense		—			—			—			0	%
Asset retirement obligation accretion		83			54			29			54	%
General and administrative expenses		2,672			1,743			929			53	%

Total operating expenses before gain on sale of assets	$	60,261		$	37,802		$	22,459			59	%

(Gain) on sale of assets		(22,700	)		(27	)		(22,673	)		NM
Total operating expenses after gain on sale of assets		37,561			37,775			(214	)		(0.5	)%
Expenses per Boe:
Lease operating expenses	$	8.75		$	8.18			0.57			7	%
Production and ad valorem taxes		4.95			4.68			0.27			6	%
Depreciation, depletion and amortization		34.38			18.97			15.41			81	%
Exploration expense		—			—			—			0	%
Asset retirement obligation accretion		0.07			0.05			0.02			40	%
General and administrative expenses		2.23			1.54			0.69			45	%

Total operating expenses per Boe	$	50.38		$	33.42		$	16.96			51	%

Lease Operating Expenses. Lease operating expenses increased 13% from $9.3 million for the nine months ended September 30, 2012 to $10.5 million for the nine months ended September 30, 2013. This increase in our average lease operating expenses was attributable to increased drilling activity, which resulted in additional producing wells for the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012. Our lease operating expense was impacted by costs of gathering and transportation and increases in third party operated lease operating expense offset by 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.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 12% from $5.3 million for the nine months ended September 30, 2012 to $5.9 million for the nine months ended September 30, 2013 primarily as a result of higher wellhead revenues.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization ("DD&A") expense increased 92% from $21.5 million for the nine months ended September 30, 2012 to $41.1 million for the nine months ended September 30, 2013 due to an increase in production volumes and an increase in our per Boe DD&A rate. The DD&A rate increased 81% from $18.97 per Boe for the nine months ended September 30, 2012 to $34.38 per Boe for the nine months ended September 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, slightly offset by additional production volumes attributable to the additional drilling activity in 2013.

General and Administrative Expenses. General and administrative ("G&A") expenses increased 53% from $1.7 million for the nine months ended September 30, 2012 to $2.7 million for the nine months ended September 30, 2013 primarily due to increases in advisory fees associated with our

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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 nine months ended September 30, 2012 to a $22.7 million gain for the nine months ended September 30, 2013 as a result of the property sale to Resolute in March 2013. See "Recent and Formation Transactions—Recent Acquisitions and Dispositions—Resolute Disposition."

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

	Nine Months Ended September 30,

	2013			2012			$ Change			% Change
	(Unaudited)
Other income (expense) (in thousands, except percentages):
Other income	$	863		$	651		$	212			33	%
Gain (loss) on derivative instruments		(3,365	)		137			(3,502	)		NM
Interest expense		(1,770	)		(2,403	)		633			(26)	%

Total other income (expense)	$	(4,272	)	$	(1,615	)	$	(2,657	)		(165)	%

Other Income. Other income increased 33% from $0.7 million for the nine months ended September 30, 2012 to $0.9 million for the nine months ended September 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 nine months ended September 30, 2012, we recorded a $0.1 million derivative fair value gain as compared to $3.4 million loss in the nine months ended September 30, 2013. The change of our derivative fair value gain to a loss was a result of the decrease in the future commodity price outlook during the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012, which unfavorably impacted the fair values of our commodity derivative contracts.

Interest Expense. Interest expense decreased 26% from approximately $2.4 million for the nine months ended September 30, 2012 to $1.8 million for the nine months ended September 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.

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	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 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 and ad valorem taxes		3.28			3.98			(0.70	)		(18	)%
Depreciation, depletion and amortization		31.15			21.30			9.85			46	%
Exploration expense		—			—			—			0	%
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 and Ad Valorem Taxes. Production 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.

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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 and Formation Transactions—Recent Acquisitions and Dispositions—Resolute Disposition."

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 $201.1 million. As of September 30, 2013, we had spent approximately $130.8 million to drill and complete operated wells, $22.3 million for our participation in the drilling and completion of non-operated wells and $5.4 million on infrastructure. Our 2014 capital budget for drilling, completion, recompletion and infrastructure will be approximately $361.5 million. In 2014, we intend to allocate these expenditures approximately as follows:

•: $305.4 million for the drilling and completion of operated wells;
•: $45.3 million for our participation in the drilling and completion of non-operated wells;
•: 80% of our total drilling and completion expenditures to horizontal wells; and
•: $10.8 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

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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 , 2013, after giving effect to this offering (including the use of proceeds therefrom) and the Transactions we would have $ million available under our revolving credit facility. Our borrowing base under our revolving credit facility is $140 million as of , 2013, and we expect our borrowing base will be increased to $ million after this offering.

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 $39.6 million, $54.2 million and $9.5 million at September 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 $17.9 million, $51.2 million and $10.1 million at September 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)	$	—	$	—	$	111,585	$	—	$	—	$	—	$	111,585
Term loan(2)		—		—		—		—		—		—		—
Drilling rig commitments(3)		10,144		4,077		—		—		—		—		14,221
Office and equipment leases		264		191		14		—		—		—		469
Asset retirement obligations(4)		—		—		—		—		—		3,925		3,925

Total	$	10,408	$	4,268	$	111,599	$	—	$	—	$	3,925	$	130,200

(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

	Nine Months Ended September 30,						Year Ended December 31,
	2013			2012			2012			2011
	(Unaudited)
	(In thousands)
Net cash provided by operating activities	$	38,602		$	43,878		$	72,803		$	26,243
Net cash provided by (used in) investing activities		(80,187	)		(124,000	)		(113,220	)		83,846
Net cash provided by (used in) financing activities		8,249			80,000			81,583			(105,155	)

Net cash provided by operating activities was approximately $38.6 million and $43.9 million for the nine months ended September 30, 2013 and 2012, respectively. Revenues were substantially consistent for the nine months ended September 30, 2013 as compared to the nine months ended September 30,

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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 used in investing activities was approximately $(80.2) million and $(124.0) million for the nine months ended September 30, 2013 and 2012, respectively. The decrease in the amount of cash used in investing activities in the nine months ended September 30, 2013 compared to the nine months ended September 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 financing activities was approximately $8.2 million and $80.0 million for the nine months ended September 30, 2013 and 2012, respectively. For the nine months ended September 30, 2013, the decreased cash provided by financing activities was primarily the result of increased borrowings under long-term debt of $101.2 million offset by long-term debt repayments of $85.0 million and capital distributions of $30.0 million. For the nine months ended September 30, 2012, the cash provided by financing activities included $80.0 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 $140 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 a substantial portion of the outstanding borrowings under our revolving credit facility.

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. We expect the borrowing base will be increased to $ million after this offering. 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		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.

The fair value of our oil derivative contracts as of September 30, 2013 was a net liability of $1.0 million. For information regarding the terms of these hedges, see "—Overview—Sources of Our Revenues—Realized Prices on the Sale of Oil, Natural Gas and NGLs" above.

Counterparty and Customer Credit Risk

Our oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While our predecessor does not require our counterparties to our derivative contracts to

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post collateral, our predecessor does evaluate the credit standing of such counterparties as it deems appropriate. We plan to continue to evaluate the credit standings of our counterparties in a similar manner. The counterparties to our predecessor's derivative contracts currently in place have investment grade ratings.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of its oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rate Risk

At , 2013, our predecessor had $ million of debt outstanding, with an assumed weighted average interest rate of %. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the average interest rate, after giving effect to RSP Permian, L.L.C.'s existing interest rate derivative contracts, would be approximately $ million per year. The adjusted LIBOR rate applicable to our predecessor's term loan may not be lower than 1.0%.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our combined financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our combined financial statements.

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

Our oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method we capitalize, lease acquisition costs, all development costs and successful exploration costs.

Unproved properties. Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration costs. Exploration costs, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures and other geological and geophysical costs,

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amortization and impairment of unproved leasehold costs and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

Proved oil and natural gas properties. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil, gas and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells and service wells, including unsuccessful development wells, are capitalized.

Impairment

The capitalized costs of proved oil and natural gas properties are reviewed on a field level basis for impairment whenever events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. This review is completed at least annually. We estimate the expected future cash flows of our oil and natural gas properties and compare these future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the expected cash flows projected. We estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Unproved leasehold costs are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the statement of operations.

Depreciation, depletion and amortization

DD&A of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field basis based upon total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

Revenue recognition

We recognize oil, natural gas and NGL revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured (sales method). Oil and natural gas sold is not significantly different from our share of production.

Derivative financial instruments

We use derivative contracts to hedge the effects of fluctuations in the prices of oil. We record such derivative instruments as assets or liabilities in the statements of financial position (see Note 4 of the accompanying Notes to Combined Financial Statements for further information on fair value). Estimating the fair value of derivative financial instruments requires management to make estimates and judgments regarding volatility and counterparty credit risk.

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We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in other income (expense) in the period of the change.

Acquisitions

As part of our business strategy, we periodically pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Asset retirement obligations

We recognize as a liability an asset retirement obligation ("ARO") associated with the retirement of a tangible long-lived asset in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. We measure the fair value of the ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate.

Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Recently Issued Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (the "FASB") issued Accounting Standards Update ("ASU") 2011-04, "Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs." ASU 2011-04 amended ASC 820 to converge the fair value measurement guidance in GAAP and International Financial Reporting Standards. Certain of the amendments clarified the application of existing fair value measurement requirements, while other amendments changed a particular principle in ASC 820. In addition, ASU 2011-04 required additional fair value disclosures. The amendments were effective for annual periods beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on the predecessor's financial position, results of operations or liquidity.

The FASB issued ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities" in December 2011, and issued ASU 2013-01, "Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities" in January 2013. These ASUs create new disclosure requirements regarding the nature of an entity's rights of setoff and related arrangements associated with its derivative instruments, repurchase agreements and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements would be required, irrespective of whether the entity has elected to offset those instruments in the statement of financial position. These

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ASUs are effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs will not impact the predecessor's financial position, results of operations or liquidity.

Internal Controls and Procedures

We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC's rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until our first annual report subsequent to our ceasing to be an "emerging growth company" within the meaning of Section 2(a)(19) of the Securities Act.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended 2012 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

Currently, neither we nor our predecessor have off-balance sheet arrangements.

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BUSINESS

The following discussion 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. Unless otherwise indicated, all references to financial or operating data are on a pro forma basis giving effect to the offering, the use of proceeds therefrom and the Transactions.

The pro forma estimated proved reserve information for our properties as of June 30, 2013 contained in this prospectus is based on a reserve report relating to our properties prepared by Ryder Scott, our independent petroleum engineer.

Our Company

We were formed in October 2010 by our management team and an affiliate of 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 and Formation Transactions" for information regarding our acquisitions and other transactions since December 2010.

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	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		312		500		812

Total Target Horizontal and Vertical Locations						1,981	(4)

(1): Our total identified drilling locations include 338 locations associated with PUDs 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.

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(4): As of June 30, 2013, one, 79 and 113 of our 1,981 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 1,981 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 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.

•: $305.4 million for the drilling and completion of operated wells;
•: $45.3 million for our participation in the drilling and completion of non-operated wells;
•: 80% of our total drilling and completion expenditures to horizontal wells; and
•: $10.8 million for infrastructure.

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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 believe this acreage metric more accurately conveys our horizontal drilling opportunities in our target zones than our total surface acreage, 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."

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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, our independent reserve engineer. Of these reserves, approximately 38% were classified as PDP. 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 three months ended September 30, 2013. As estimated by Ryder Scott, our 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 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 (MMBbls)		Natural Gas (Bcf)		NGLs (MMBbls)		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		8,155(3	)		17.5

(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 three months ended September 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 70% oil, 14% 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 80% 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 November 1, 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.

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•: 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 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

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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 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.
•: 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. Other operators have drilled successful horizontal wells targeting the Wolfcamp A formation in close proximity to our properties. 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,

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our vertical Wolfberry play drilling plan included 312 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 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.

Our Properties

Our properties include working interests in approximately 42,428 surface acres located in the Permian Basin in the Texas counties of Midland, Martin, Andrews, Ector, Dawson and Upton. The following table summarizes our surface acreage by county as of June 30, 2013.



County:
Andrews	3,304	3,304
Ector	4,898	4,782
Martin	6,579	5,767
Midland	17,546	11,414
Dawson	9,464	8,092
Upton	637	574

Total	42,428	33,933

The Permian Basin consists of mature, legacy onshore oil and liquids-rich natural gas reservoirs that span approximately 86,000 square miles in West Texas and New Mexico. 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. It is composed of three sub basins, the Delaware Basin, the Central Basin Platform and the Midland Basin.

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The Midland Basin is characterized by an extensive operating history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators. The vast majority of our acreage is located on large, contiguous acreage blocks in the core of the Midland Basin, primarily in the contiguous Texas counties of Midland, Martin, Andrews, Dawson and Ector. We believe that our properties are prospective for oil and liquids-rich natural gas from multiple producing stratigraphic horizons, which we refer to as stacked pay zones.

Our contiguous acreage positions allow us to maximize our resource recovery on a per section basis and increase our returns. In addition, our contiguous acreage position allows us the flexibility to adjust our drilling and completion techniques, primarily the length of our horizontal laterals, in order to maximize our well results, drilling costs and returns. Our contiguous position and the flexibility it provides allow us to target multiple horizontal zones underneath our surface acreage, providing us with total Effective Horizontal Acreage of approximately 140,435 net acres in the Midland Basin. The following table provides a summary of our Effective Horizontal Acreage, which we believe more accurately conveys our horizontal drilling opportunities in our target zones.

	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		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."

The Midland Basin has been one of the most prolific oil-producing regions in Texas. The first commercial oil well drilled in the Midland Basin was completed in 1921, and the large resource potential of the Spraberry Trend was discovered in the 1940s. The Wolfcamp formation has a similarly long operating history, as drillers aiming for deeper conventional targets during the 1950s occasionally intersected carbonate formations and debris flows with good reservoir properties. Industry operators often refer to the combined Spraberry and Wolfcamp formations in terms of vertical development as the "Wolfberry" play, but recent advances in geologic understanding and production technology have highlighted the resource potential of the region's unconventional reservoirs, located in mudrock-dominated intervals that are productive after hydraulic-fracture stimulation. Technological advances in 3-D seismic imagery have demonstrated the larger geographic extent of the unconventional formations than originally estimated and, due to multiple stacked pay zones, significantly more oil in place as compared to other major U.S. shale oil plays.

In recent years, drilling activity in the Midland Basin has shown a trend towards horizontal development. As of January 2012, there were 20 horizontal rigs and approximately 260 vertical rigs operating in the Midland Basin. As of September 2013, there were 73 horizontal rigs and approximately

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170 vertical rigs operating within the same area. Our primary focus shifted in late 2012 to drilling higher rate of return horizontal wells targeting the Middle Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B and Wolfcamp D (Cline) formations. In addition, we believe our properties present additional horizontal drilling opportunities from several other stacked pay zones such as the Clearfork, Jo Mill, Dean, Strawn, Atoka, Mississippian and Devonian formations.

Ryder Scott, our independent petroleum engineering firm, has estimated that as of June 30, 2013, proved reserves net to our interest in our properties were approximately 52,164 MBoe, of which 38% were classified as PDP. The proved reserves are generally characterized as long-lived, with predictable production profiles.

Production Status. For the three months ended September 30, 2013, our average net daily production was 8,155 Boe/d (approximately 70% oil, 14% natural gas and 16% NGLs), of which 18% was from horizontal well production and 82% was from vertical well production. During 2012, our average net daily production was 5,089 Boe/d (approximately 69% oil, 14% natural gas and 17% NGLs), of which 1% was from horizontal well production and 99% was from vertical well production. As of September 30, 2013, we produced from 16 horizontal and 328 vertical wells and were the operator of approximately 95% of our net acreage.

Facilities. We strive to develop the necessary infrastructure to lower our costs and support our drilling schedule and production growth. We accomplish this goal through a combination of developing our own midstream assets as well as through contractual arrangements with third party service providers. Our facilities located on our properties are generally in close proximity to our well locations and include storage tank batteries, oil/gas/water separation equipment and pumping units.

In addition to standard well site surface equipment, we have invested our capital in building gathering lines and water infrastructure, including water pipelines, water source wells and water disposal wells. We have laid approximately 85 miles of oil, natural gas and water transport lines to support gathering and transportation activities on our properties. To secure adequate water supplies, we have drilled eight water source wells into the Santa Rosa formation in West Texas that complement our purchase of fresh water. A majority of the water used in our operations is sourced from the Santa Rosa formation, which is a brackish, non-potable water aquifer that is not used for human consumption or agricultural use but is of adequate quality for our hydraulic fracturing operations. We also have operated three saltwater disposal wells on our properties and we have an additional two saltwater disposal wells in the permitting process. We sold one of our water source wells and one of our saltwater disposal wells to Resolute as part of an asset disposition that occurred in part in December 2012 and in part in March 2013.

Recent and Future Activity. A total of 109 gross (69 net) wells were drilled on our acreage during 2012, and during the nine months ended September 30, 2013, 81 gross (43 net) wells were drilled on our acreage. For the remainder of 2013, we intend to drill and complete an additional six vertical Wolfberry wells, one horizontal Middle Spraberry well, two Lower Spraberry horizontal wells and one Wolfcamp B horizontal well. We expect our non-operated properties will undergo similar drilling and completion activities, with the exception of horizontal targets, which will be concentrated almost solely on the Wolfcamp B formation. We recently drilled our first multi-well pad (two well) layout. We expect these multi-well pads to increase our capital efficiency and intend to begin implementing multi-well pad drilling on a regular basis.

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we define identified drilling locations as locations specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant, such as easement restrictions and state and local regulations, are considered in determining such locations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Proved Reserves. Our pro forma proved reserve estimates as of June 30, 2013 were prepared by Ryder Scott, our independent petroleum engineers. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of the independent petroleum engineering firm's proved reserve report as of June 30, 2013 is included as an exhibit to the registration statement of which this prospectus forms a part. Our pro forma reserve report as of December 31, 2012 is an internally prepared reserve report.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to Ryder Scott for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Tamara Pollard, our Vice President of Planning and Reserves, is primarily responsible for overseeing the preparation of all of our reserve estimates. Ms. Pollard is a petroleum engineer with over 25 years of reservoir and operations experience, and our geoscience staff has an average of approximately 30 years of energy industry experience per person.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•: review and verification of historical production data, which data is based on actual production as reported by us;
•: preparation of reserve estimates by Ms. Pollard or under her direct supervision;
•: review by our Chief Executive Officer of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new PUDs additions;
•: direct reporting responsibilities by our Vice President of Planning and Reserves to our Chief Executive Officer; and
•: verification of property ownership by our land department.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is

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reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered." All of our proved reserves as of June 30, 2013 and December 31, 2012 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and PUDs for our properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

To estimate economically recoverable proved reserves and related future net cash flows, we, in the case of our internally prepared reserve report as of December 31, 2012, and Ryder Scott, in the case of the reserve report as of June 30, 2013, considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Summary of Pro Forma Oil and Natural Gas Reserves. The following table presents our estimated pro forma net proved oil and natural gas reserves, after giving effect to the Transactions as if the Transactions had occurred on January 1, 2012, as of June 30, 2013 and December 31, 2012, based on the proved reserve reports as of June 30, 2013 by Ryder Scott, our independent petroleum engineering firm, and based on our internally generated reserve reports as of December 31, 2012, in each case, prepared in accordance with the rules and regulations of the SEC. All of our proved reserves are located in the United States. A copy of the proved reserve report as June 30, 2013 prepared by Ryder Scott with respect to our properties is included as an exhibit to the registration statement of which this

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prospectus forms a part. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with this offering.



Proved developed reserves:
Oil (MBbls)	12,029	8,712
Natural gas (MMcf)	20,969	16,037
NGLs (MBbls)	4,040	3,074
Total (MBoe)	19,564	14,459
Proved undeveloped reserves:
Oil (MBbls)	20,451	18,726
Natural gas (MMcf)	30,605	29,044
NGLs (MBbls)	7,048	5,457
Total (MBoe)	32,600	29,024
Total proved reserves:
Oil (MBbls)	32,480	27,438
Natural gas (MMcf)	51,574	45,081
NGLs (MBbls)	11,088	8,531
Total (MBoe)	52,164	43,483

The changes from December 31, 2012 estimated proved reserves to June 30, 2013 estimated proved reserves reflect production during this period of approximately 1,285 MBoe, net negative revisions of approximately 2 MBoe and additions of approximately 9,968 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read "Risk Factors" appearing elsewhere in this prospectus.

Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in this prospectus and the proved reserve report as of June 30, 2013, which is included as an exhibit to the registration statement of which this prospectus forms a part.

Pro Forma PUDs

Year Ended December 31, 2012

As of December 31, 2012, our PUDs totaled 18,726 MBbls of oil, 29,044 MMcf of natural gas and 5,457 MBbls of NGLs, for a total of 29,024 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

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Changes in PUDs that occurred during 2012 were primarily due to:

•: additions of approximately 14,741 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position;
•: the conversion of approximately 4,965 MBoe attributable to PUDs into proved developed reserves; and
•: negative revisions of approximately 37,361 MBoe in PUDs were due to a combination of adjustments in working interest, performance revisions and a reduction in PUD reserves that resulted from our strategic decision to not include 20-acre PUD locations in our reserves in favor of focusing our capital expenditures on horizontal locations and, to a lesser extent, on 40-acre vertical locations.

During the twelve months ended December 31, 2012, we spent $93.1 million to convert PUDs to proved developed reserves and $79.1 million to convert non-proved reserves to proved developed reserves.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.

As of December 31, 2012, 1% of our total proved reserves were classified as proved developed non-producing.

Six Months Ended June 30, 2013

As of June 30, 2013, our PUDs totaled 20,451 MBbls of oil, 30,605 MMcf of natural gas and 7,048 MBbls of NGLs, for a total of 32,600 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during the first six months of 2013 were primarily due to:

•: additions of approximately 7,528 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position; and
•: the conversion of approximately 3,952 MBoe attributable to PUDs into proved developed reserves.

During the six months ended June 30, 2013, we spent $77.0 million to convert PUDs to proved developed reserves and $35.3 million to convert non-proved reserves to proved developed reserves.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.

As of June 30, 2013, 1% of our total proved reserves were classified as proved developed non-producing.

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Oil and Natural Gas Production Prices and Costs

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:

	Predecessor									Pro Forma(1)

	For the Nine Months Ended September 30,				For the Years Ended December 31,
										Nine Months Ended September 30, 2013
												Year Ended December 31, 2012
	2013		2012		2012		2011					Year Ended December 31, 2012
Production data:
Oil (MBbls)		820		758		1,040		618			1,353		1,278
Natural gas (MMcf)		1,188		1,102		1,576		971			1,715		1,629
NGLs (MBbls)		178		189		264		—	(2)		305		313

Total (MBoe)		1,196		1,131		1,567		780			1,944		1,862

Average prices before effects of hedges(3)(4):
Oil (per Bbl)	$	94.52	$	91.74	$	87.92	$	91.84		$	95.10	$	88.16
Natural gas (per Mcf)		3.34		2.22		2.72		7.44			3.33		2.67
NGLs (per Bbl)(2)		29.20		29.89		32.94		—			27.85		33.72

Total (per Boe)	$	72.46	$	68.64	$	66.65	$	82.05		$	73.50	$	68.46

Average realized prices after effects of hedges(3)(4):
Oil (per Bbl)	$	94.72	$	91.60	$	88.25	$	91.66		$	95.22	$	88.42
Natural gas (per Mcf)		3.34		2.22		2.72		7.44			3.33		2.65
NGLs (per Bbl)(2)		29.20		29.89		32.94		—			27.85		33.72

Total (per Boe)	$	72.60	$	68.57	$	66.86	$	81.90		$	73.58	$	68.64

Average costs (per Boe):
Lease operating expenses	$	8.75	$	8.18	$	9.76	$	8.72		$	8.66	$	10.11
Production taxes		4.95		4.68		3.28		3.98			4.47		3.37
DD&A		34.38		18.97		31.15		21.30			37.69		37.65
Asset retirement obligation accretion		0.07		0.05		0.07		0.06			0.08		0.09
General and administrative expenses(5)		2.23		1.54		1.82		4.50			1.32		1.44

Total	$	50.38	$	33.42	$	46.01	$	38.50		$	52.21	$	52.65

(1): Does not include the results related to the Verde Acquisition or Pecos Contribution due to their lack of significance to our combined financial results.
(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.
(3): Average prices shown in the table reflect prices both before and after the effects of our realized commodity derivative transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions.
(4): Average realized prices for oil are net of transportation costs. Average realized prices for natural gas do not include transportation costs; instead, transportation costs related to our gas production and sales are included in our lease operating expenses. No transportation costs are associated with NGL production and sales.
(5): 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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Pro Forma Productive Wells

As of September 30, 2013, on a pro forma basis, we owned an average 67% working interest in 344 gross productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

Pro Forma Developed and Undeveloped Acreage

The following table sets forth information as of June 30, 2013 relating to our leasehold acreage:

	Developed acreage(1)				Undeveloped acreage(2)				Total acreage

	Gross(3)		Net(4)		Gross(3)		Net(4)		Gross(3)		Net(4)
Midland Basin		12,960		8,777		29,468		25,156		42,428		33,933

(1): Developed acres are acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease.
(2): Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
(3): A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(4): A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage, as of June 30, 2013, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

	Remaining 2013				2014				2015				2016				2017

	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Midland Basin		19		1		2,419		2,102		4,595		4,029		4,358		3,597		0		0

Pro Forma Drilling Results

The table below sets forth the results of our drilling activities for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.

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Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

	For the Nine Months Ended September 30,								For the Year Ended December 31,

	2013				2012				2012				2011
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive(1)		—		—		1.0		0.4		1.0		0.4		—		—
Dry		—		—		—		—		—		—		—		—

Total Exploratory		—		—		1.0		0.4		1.0		0.4		—		—

Development Wells:
Productive(1)		81.0		42.9		68.0		47.3		108.0		68.8		80.0		61.8
Dry		—		—		—		—		—		—		—		—

Total Development		81.0		42.9		68.0		47.3		108.0		68.8		80.0		61.8

Total Wells:
Productive(1)		81.0		42.9		69.0		47.6		109.0		69.2		80.0		61.8
Dry		—		—		—		—		—		—		—		—

Total		81.0		42.9		69.0		47.6		109.0		69.2		80.0		61.8

(1): Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.

Operations

General

We are the operator of approximately 95% of our net acreage. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties

Marketing and Customers

We market the majority of the oil and natural gas production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our natural gas production to purchasers at market prices. We sell all of our natural gas under contracts with terms of greater than twelve months and all of our oil under contracts with terms of twelve months or less, excluding a five year oil purchase agreement with Shell Trading (US) Company ("Shell Trading").

We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the nine months ended September 30, 2013, four purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (20%), Shell Trading (US) Company (41%), Enterprise Crude Oil LLC (12%) and Diamondback E&P LLC (11%). For the nine months ended September 30, 2013, MidMar 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%). However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major

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purchasers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Transportation

During the initial development of our fields, we consider all gathering and delivery infrastructure in the areas of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm or by pipeline. Our natural gas is generally transported from the wellhead to the purchaser's pipeline interconnection point through our gathering system.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination

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and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 18.75% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 81.25%.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such

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laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Texas, which regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Transportation of Oil

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

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Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC's NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC's policy statement on price reporting.

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Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC's determinations as to the classification of facilities is done on a case by case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act ("CEA"), and regulations promulgated thereunder by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Regulation of Environmental and Occupational Safety and Health Matters

Our oil and natural gas exploration and production operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity

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commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste Handling

CERCLA, also known as the "Superfund" law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The RCRA and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA's less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous

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substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in connection with on-site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. We are currently undertaking a review of recently acquired oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.

The primary federal law related specifically to oil spill liability is the OPA, which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of "responsible party" who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly

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comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, on August 16, 2012, the EPA published final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and NESHAP programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: (i) wildcat (exploratory) and delineation gas wells; (ii) low reservoir pressure non-wildcat and non-delineation gas wells; and (iii) all "other" fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the "other" wells must use reduced emission completions, also known as "green completions," with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012, and from pneumatic controllers and storage vessels, effective October 15, 2013. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules in 2013 that are likely responsive to some of these requests. For example, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels, and on August 5, 2013, the EPA issued a press release announcing that it had finalized the proposed amendment, and we anticipate that this rulemaking will be made effective by the EPA publication in the Federal Register in the very near future. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

Regulation of GHG Emissions

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish 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.

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Hydraulic Fracturing Activities

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 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 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. Specifically, the FRAC Act has been introduced in each Congress since 2008 to accomplish these purposes, and on May 9, 2013, the FRAC Act was again re-introduced. If such legislation were to pass, it could result in substantial compliance costs and could negatively impact our ability to conduct hydraulic fracturing activities.

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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 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.

ESA and Migratory Birds

The ESA and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species' habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or

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endangered under the ESA may exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency's 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted 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 an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2012, nor do we anticipate that such expenditures will be material in 2013.

OSHA

We are subject to the requirements of the OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

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Employees

As of December 1, 2013, we had 35 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition.

Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers' compensation claims and employment related disputes. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

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MANAGEMENT

The following table sets forth the names, ages and titles of our directors, director nominees and executive officers.

Name		Position

Michael Grimm	59	Chairman of the Board of Directors
Steven Gray	54	Director and Chief Executive Officer
David Albin	54	Director
Scott McNeill	42	Director and Chief Financial Officer
Joseph B. Armes	51	Director Nominee
Ted Collins, Jr.	74	Director Nominee
Matthew S. Ramsey	58	Director Nominee
Michael W. Wallace	49	Director Nominee
Zane Arrott	55	Chief Operating Officer
Tamara Pollard	52	Vice President of Planning and Reserves
Erik B. Daugbjerg	44	Vice President of Oil & Gas Marketing/Business Development
William Huck	58	Vice President, Operations

Michael Grimm, Chairman of the Board, co-founded RSP Permian, L.L.C. in 2010 and has served as our Chairman of the Board since our formation. Prior to being named our Chairman of the Board, Mr. Grimm served as RSP Permian, L.L.C.'s Co-Chief Executive Officer. From 2006 to present, Mr. Grimm has served as President and Chief Executive Officer of Rising Star, and from 1995 to 2006, Mr. Grimm served as President and Chief Executive Officer of Rising Star Energy, L.L.C., which he co-founded in 1995. From 1990 to 1994, Mr. Grimm served as Vice President of Worldwide Exploration and Land for Placid Oil Company. Prior to that, Mr. Grimm was employed for 13 years in the land and exploration department for Amoco Production Company in Houston, New Orleans and Chicago. Mr. Grimm has more than 35 years of experience in the oil and natural gas industry and currently serves as a Director for Rising Star, Rising Star Petroleum, L.L.C. and Energy Transfer Partners, L.P. He has a B.B.A. from the University of Texas at Austin.

Mr. Grimm has significant experience as a chief executive of oil and natural gas exploration and production companies and broad knowledge of the oil and natural gas industry. We believe his background and skill set will enable Mr. Grimm to provide our board of directors with executive counsel on a full range of business, strategic and professional matters.

Steven Gray, Director and Chief Executive Officer, co-founded RSP Permian, L.L.C. in 2010. He has served as our Chief Executive Officer and as a member of our board of directors since our formation and has served RSP Permian, L.L.C. as Co-Chief Executive Officer since its inception in 2010. In 2007, Mr. Gray co-founded Pecos with Messrs. Daugbjerg and Huck. In 2000, Mr. Gray co-founded Pecos Production Company, an NGP-backed oil and natural gas exploration and production company that operated in the Permian Basin until it was sold in 2005 to Chesapeake Energy Corporation. Mr. Gray continues to serve as a manager of Pecos Operating Company, LLC, Pecos's general partner. From 1993 to 2000, Mr. Gray was a Co-Founder, President and Chief Operating Officer of Vista Energy Resources, an NGP-backed oil and natural gas exploration and production company. Prior to forming Vista, Mr. Gray was employed for 11 years as a petroleum engineer with Bettis, Boyle, and Stovall, Inc. and Texas Oil & Gas Corp. He received a B.S. in Petroleum Engineering from Texas Tech University and has more than 30 years of experience in the oil and natural gas industry.

Mr. Gray has significant experience as a chief executive officer and chief operating officer of oil and natural gas exploration and production companies and broad knowledge of the oil and natural gas industry. We believe his background and skill set will enable Mr. Gray to provide our board of directors with executive counsel on a full range of business, strategic and professional matters.

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David Albin, Director, has served as a member of our board of directors since our formation. Mr. Albin is a co-founder and managing partner of NGP and has served in that or similar capacities since 1988. He also serves as a director of NGP Capital Resources Company. Prior to his participation as a founding member and managing partner of NGP, Mr. Albin was a partner in the $600 million Bass Investment Limited Partnership, and prior to joining Bass Investment Limited Partnership, he was a member of the oil and natural gas group in the investment banking division of Goldman, Sachs & Co. From 2004 through the second quarter of 2012, Mr. Albin served as a director of Energy Transfer Partners, LP and LE GP, LLC, the general partner of Energy Transfer Equity, L.P., and continues to serve on the board of numerous other private companies. Mr. Albin received a B.S. in Physics in 1981 and an M.B.A. in 1985 from Stanford University.

Mr. Albin has significant experience with energy companies and investments and broad knowledge of the oil and natural gas industry as well as significant expertise in finance. We believe his background and skill set make Mr. Albin well-suited to serve as a member of our board of directors.

Scott McNeill, Director and Chief Financial Officer, has served as our Chief Financial Officer since our formation and as a member of our board of directors since December 2013. Mr. McNeill has served RSP Permian, L.L.C. as Chief Financial Officer since April 2013. Prior to joining the company, Mr. McNeill served as a Managing Director in the energy investment banking group of Raymond James. Mr. McNeill spent 15 years as an investment banker advising a wide spectrum of companies operating in the exploration and production, midstream, and energy service and equipment segments of the energy industry. Mr. McNeill is licensed as a Certified Public Accountant. He earned a B.B.A from Baylor University and an M.B.A from the University of Texas at Austin.

Mr. McNeill has significant experience with energy companies and investments and broad knowledge of the oil and natural gas industry as well as significant expertise in finance. We believe his background and skill set make Mr. McNeill well-suited to serve as a member of our board of directors.

Joseph B. Armes, Director Nominee, will be appointed to our board of directors shortly after the consummation of this offering. Since June 2013, Mr. Armes has served as President, Chief Executive Officer and a member of the board of directors of Capital Southwest Corporation, a publicly-traded investment company. Since 2010, Mr. Armes served as President and Chief Executive Officer of JBA Investment Partners, a family investment vehicle. From 2005 to 2010, Mr. Armes served as Chief Operating Officer of Hicks Holdings, LLC. Prior to 2005, Mr. Armes served as Executive Vice President and General Counsel and later as Chief Financial Officer of Hicks Sports Group, LLC, as Executive Vice President and General Counsel of Suiza Foods Corporation (now Dean Foods Company) and Vice President and General Counsel of The Morningstar Group Inc. In addition, from 2007 to 2009, Mr. Armes served as a director of Hicks Acquisition Co. I, a publicly-traded acquisition company. Mr. Armes received a B.B.A. in Finance, an M.B.A. from Baylor University and a J.D. from Southern Methodist University.

Mr. Armes has significant experience as an executive officer and director in a variety of public companies and an extensive background in strategic investing. We believe his background and skill set make Mr. Armes well-suited to serve as a member of our board of directors.

Ted Collins, Jr., Director Nominee, will be appointed to our board of directors shortly after the consummation of this offering. Mr. Collins has been an independent oil and gas producer since 2000. He served as Chairman and Chief Executive Officer of Patriot Resources Partners, LLC from 2007 to 2010 and as President of Collins & Ware Inc. from 1988 to 2000, when its assets were sold to Apache Corporation. From 1982 to 1988, Mr. Collins was President of the predecessors of EOG Resources, and HNG Oil Company, HNG Internorth Exploration Co. and Enron Oil and Gas Company. From 1969 to 1982, Mr. Collins served as Executive Vice President of American Quasar Petroleum Company. Since 2011, Mr. Collins has served as a director of Oasis Petroleum, Inc. and as a member of its audit committee and nominating and governance committee. In addition, Mr. Collins has served as a director

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of the general partner of Energy Transfer Partners, L.P. since 2004 and as a director of CLL Global Research Foundation since 2009. Mr. Collins is also the chairman of the board of managers of Coronado Midstream, LLC (formerly named MidMar Gas, LLC). Mr. Collins is a past President of the Permian Basin Petroleum Association, the Permian Basin Landmen's Association, the Petroleum Club of Midland and has served as Chairman of the Midland Wildcat Committee since 1984. Mr. Collins received a B.S. in Geological Engineering from the University of Oklahoma.

Mr. Collins has significant experience as an independent operator and as an executive officer in various positions and a director of oil and gas companies and has broad knowledge of the oil and gas industry. We believe his background and skill set will enable Mr. Collins to provide our board of directors with executive counsel on a full range of business, strategic and professional matters.

Matthew S. Ramsey, Director Nominee, will be appointed to our board of directors shortly after the consummation of this offering. Since 2000, Mr. Ramsey has served RPM Exploration, Ltd., a private oil and gas exploration limited partnership generating and drilling 3-D seismic prospects on the Gulf Coast of Texas, as President and a member of the board of directors of its general partner, Ramsey, Pawelek & Maloy, Inc. Currently, Mr. Ramsey also serves as President of Ramsey Energy Management, LLC, the general partner of Ramsey Energy Partners, I, Ltd., a private oil and gas partnership; President of Dollarhide Management, LLC, the general partner of Deerwood Investments, Ltd., a private oil and gas partnership; President of Gateshead Oil, LLC, a private oil and gas partnership; and Manager of MSR Energy, LLC, the general partner of Shafter Lake Energy Partners, Ltd., a private oil and gas partnership. Previously, Mr. Ramsey served as President of DDD Energy, Inc. from 2001 until its sale in 2002; President, Chief Executive Officer and a member of the board of directors of OEC Compression Corporation, a publicly-traded oil field service company, from 1996 to 2000; and Vice President of Nuevo Energy Company, an independent energy company, from 1991 to 1996. Additionally, from 1990 to 1996, he was employed by Torch Energy Advisors, Inc., a company providing management and operations services to energy companies, where he last served as Executive Vice President. Since July 2012, Mr. Ramsey has served as a member of the board of director of LE GP, LLC, the general partner of Energy Transfer Equity, L.P., and as a member of its audit and compensation committees. From March 2012 to July 2012, Mr. Ramsey served as a member of the board of directors of Southern Union Company. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate of the Harvard Business School Advanced Management Program.

Mr. Ramsey has significant experience as an executive officer and director in a variety of oil and gas companies and has broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Ramsey well-suited to serve as a member of our board of directors.

Michael W. Wallace, Director Nominee, will be appointed to our board of directors shortly after the consummation of this offering. Since 2011 Mr. Wallace has been a partner and manager of Wallace Family Partnership, LP, which holds non-operated working interests in oil and gas leases, midstream assets and other investments. Since 2009, Mr. Wallace has also served as the President, director and manager of High Sky Partners LLC, a Midland, Texas-based oil and gas company with operations in the Spraberry Trend of the Permian Basin. From 2007 to 2011, Mr. Wallace was a member and Executive Vice President of Production for Patriot Resource Partners LLC. In 2004, Mr. Wallace founded Flying W Resources, LLC, an independent oil and gas production company. In addition, Mr. Wallace served in a variety of technical and managerial roles within Conoco Inc. and ConocoPhillips Company from 2001 to 2004. Prior to joining Conoco Inc., Mr. Wallace served in a variety of roles within Burlington Resources Inc. Mr. Wallace received a B.S. in Petroleum Engineering from Texas Tech University and is a member of the Society of Petroleum Engineers.

Mr. Wallace has significant experience as an independent operator and as an executive officer in various positions of oil and gas companies and has broad knowledge of the oil and gas industry. We

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believe his background and skill set will enable Mr. Wallace to provide our board of directors with executive counsel on a full range of business, strategic and professional matters.

Zane Arrott, Chief Operating Officer, has served as our Chief Operating Officer since our formation and has served RSP Permian, L.L.C. in such capacity since its inception in 2010. Since 1995, Mr. Arrott has served as the Chief Operating Officer for Rising Star and continues to serve on the boards of Rising Star and Rising Star Petroleum, L.L.C. From 1982 to 1995, Mr. Arrott held several positions with Placid Oil Company and was elevated to General Manager of its Canadian Division in 1988. Mr. Arrott has more than 32 years of experience in the oil and natural gas industry and extensive experience with reservoir engineering, production engineering, project economic forecasting and reserve acquisitions. He has a B.S. in Petroleum Engineering from Texas Tech University.

Tamara Pollard, Vice President of Planning and Reserves, has served as our Vice President of Planning and Reserves since our formation and has served RSP Permian, L.L.C. in such capacity since its inception in 2010. Since 1998, Ms. Pollard has held several positions with Rising Star Energy, L.L.C., most recently as Vice President of Financial Planning and Reserves, Secretary and Treasurer. From 1995 to 1998, Ms. Pollard was employed by Lovegrove & Associates and Oryx Energy. From 1985 to 1995, Ms. Pollard held several positions at Placid Oil Company and worked as a reservoir engineer until 1992 when she was elevated to Manager of Planning and Business Development. She has over 25 years of oil and gas experience and has as B.S. in Petroleum Engineering from the University of Tulsa and an M.B.A. from the University of Texas at Arlington.

Erik B. Daugbjerg, Vice President of Oil & Gas Marketing/Business Development, has served as our Vice President of Oil & Gas Marketing/Business Development since our formation and has served RSP Permian, L.L.C. in such capacity since its inception in 2010. In 2007 Mr. Daugbjerg co-founded Pecos with Messrs. Gray and Huck, and he continues to serve as a manager of Pecos Operating Company, LLC, Pecos's general partner. Mr. Daugbjerg served as President of Pecos River Operating Company, an exploration and production company with operations in southeast New Mexico, from 2000 until is sale in 2005. From 1997 to 2000, Mr. Daugbjerg served as Vice President of Producer Services for Highland Energy Company. From 1992 to 1996, he served in various roles with Hadson Corporation, an oil and natural gas marketing and midstream company with operations in the Permian Basin. Mr. Daugbjerg has more than 20 years of experience in the energy industry and has a B.B.A. from Southern Methodist University.

William Huck, Vice President, Operations, co-founded RSP Permian, L.L.C. in 2010. He has served as our Vice President, Operations since our formation and served RSP Permian, L.L.C. in such capacity since its inception. In 2007, Mr. Huck co-founded Pecos with Messrs. Daugbjerg and Gray, and he continues to serve as a manager of Pecos Operating Company, LLC, Pecos's general partner. Mr. Huck co-founded Pecos Production Company in 2000 and served as its Vice President—Production until it was sold to Chesapeake Energy Corporation in 2005. In addition, he serves as President of Huck Engineering, Inc. From 1998 to 2000, Mr. Huck served as an Operating Manager for Collins & Ware, Inc., an oil and natural gas production company in Midland, Texas. From 1994 to 1998, Mr. Huck operated an independent engineering consulting firm, Huck Engineering, Inc. Mr. Huck has more than 30 years of oil and natural gas experience and has a B.S. in Petroleum Engineering from Marietta College.

There are no family relationships among any of our directors or executive officers.

Board of Directors

Our board of directors currently consists of four members, Michael Grimm, Steven Gray, David Albin and Scott McNeill. Four director nominees, Joseph B. Armes, Ted Collins, Jr., Matthew S. Ramsey and Michael W. Wallace, will be appointed to our board of directors shortly after the consummation of this offering.

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In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board of directors' ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board of the directors to fulfill their duties. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.

In connection with this offering, we will enter into a stockholders' agreement with RSP Permian Holdco, L.L.C., Collins, Wallace LP, Rising Star and Pecos. The stockholders' agreement is expected to provide each of RSP Permian Holdco, L.L.C., Collins and Wallace LP with the right to designate a certain number of nominees to our board of directors, so long as each beneficially owns more than a certain percentage of the outstanding shares of our common stock.

Committees of the Board of Directors

Upon the conclusion of this offering, we intend to have an audit committee, a compensation committee and a nominating and corporate governance committee of our board of directors, and may have such other committees as the board of directors shall determine from time to time. We anticipate that each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

We will establish an audit committee prior to the completion of this offering. Rules implemented by the NYSE and the SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to transitional relief during the one-year period following the completion of this offering. We anticipate that following completion of this offering, our audit committee will initially consist of at least one director who will be independent under the rules of the SEC. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors. SEC rules also require that a public company disclose whether or not its audit committee has an "audit committee financial expert" as a member. An "audit committee financial expert" is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. We anticipate that at least one of our independent directors will satisfy the definition of "audit committee financial expert."

This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. We expect to adopt an audit committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Compensation Committee

We will establish a compensation committee prior to completion of this offering. We anticipate that the compensation committee will consist of at least one director who will be "independent" under the rules of the SEC. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee will also administer our incentive compensation and benefit plans. We expect to adopt a compensation committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

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Nominating and Corporate Governance Committee

We will establish a nominating and corporate governance committee shortly after completion of this offering. We anticipate that the nominating and corporate governance committee will consist of at least one director who will be "independent" under the rules of the SEC. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors; develop and oversee our internal corporate governance processes; and maintain a management succession plan. We expect to adopt a nominating and corporate governance committee charter defining the committee's primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or compensation committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

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EXECUTIVE COMPENSATION

Named Executive Officers

We are currently considered an emerging growth company for purposes of the SEC's executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures. Further, our reporting obligations extend only to the individuals serving as our chief executive officers, and our two other most highly compensated executive officers. For fiscal year 2012, our named executive officers were:

Name		Principal Position

Michael Grimm		Chief Executive Officer
Steven Gray		Chief Executive Officer
Zane Arrott		Chief Operating Officer
Tamara Pollard		Vice President of Planning and Reserves
William Huck		Vice President, Operations

Messrs. Grimm and Gray served as co-Chief Executive Officers during the 2012 fiscal year. Messrs. Arrott and Huck and Ms. Pollard were paid the same amount of compensation for the 2012 year, thus we have disclosed three rather than two individuals. Following the end of the 2012 fiscal year we hired Mr. Scott McNeill as our Chief Financial Officer. Due to the timing of his employment he is not considered a named executive officer for the 2012 year, although we expect that he will be a named executive officer for the current 2013 fiscal year.

2012 Summary Compensation Table

The following table summarizes, with respect to our named executive officers, information relating to the compensation earned for services rendered in all capacities during the fiscal years ended December 31, 2012.

Name and Principal Position

Michael Grimm (Chief Executive Officer)	2012	225,000	225,000
Steven Gray (Chief Executive Officer)	2012	225,000	225,000
Zane Arrott (Chief Operating Officer)	2012	225,000	225,000
Tamara Pollard (Vice President of Planning and Reserves)	2012	225,000	225,000
William Huck (Vice President, Operations)	2012	225,000	225,000

*: None of the named executive officers received compensation other than base salary during the 2012 fiscal year.

Outstanding Equity Awards at 2012 Fiscal Year-End

The awards reported here reflect the incentive units, or profits interest awards, that each named executive officer held as of December 31, 2012. Prior to this offering the incentive units were profits interests, rather than capital interests, in us. In connection with this offering, the profits interest awards will become incentive units, or profits interest awards, in RSP Permian Holdco, L.L.C., although the

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terms and conditions of the profits interest awards will remain substantially similar to the terms applicable to the profits interest awards prior to the offering, including the retention of existing vesting schedules. Where terms will be modified following this offering, they have been described in the narrative below. Until each of the transactions that are necessary to effect this offering have occurred, however, the incentive units will be based upon distributions to RSP Permian, L.L.C.'s members rather than the members of RSP Permian Holdco, L.L.C., thus the majority of the section below will refer to the terms and conditions of the profits interest awards as they exist as of the date of this filing. However, following this offering, the profits interest awards held by the named executive officers described below will not relate directly to our securities, and we will not be financially or otherwise responsible for distributions or settlements relating to such profits interest awards.

Name

Michael Grimm
Tier I Units	0	133,333	N/A	N/A
Tier II Units	133,333	0	N/A	N/A
Tier III Units	133,333	0	N/A	N/A
Tier IV Units	133,333	0	N/A	N/A
Steven Gray(2)
Tier I Units	0	180,000	N/A	N/A
Tier II Units	180,000	0	N/A	N/A
Tier III Units	180,000	0	N/A	N/A
Tier IV Units	180,000	0	N/A	N/A
Zane Arrott
Tier I Units	0	133,333	N/A	N/A
Tier II Units	133,333	0	N/A	N/A
Tier III Units	133,333	0	N/A	N/A
Tier IV Units	133,333	0	N/A	N/A
Tamara Pollard
Tier I Units	0	128,333	N/A	N/A
Tier II Units	128,333	0	N/A	N/A
Tier III Units	128,333	0	N/A	N/A
Tier IV Units	128,333	0	N/A	N/A
William Huck
Tier I Units	0	140,000	N/A	N/A
Tier II Units	140,000	0	N/A	N/A
Tier III Units	140,000	0	N/A	N/A
Tier IV Units	140,000	0	N/A	N/A

(1): Despite the fact that profits interests such as the incentive units do not require the payment of an exercise price, we believe that these profits interest awards are economically similar to stock options due to the fact that they have no value for tax purposes at grant and will obtain value only as the price of the underlying security rises, and as such, are required to be reported in this table as an "Option" award. The profits interest awards are divided into four tiers each of which has a separate distributions threshold and vesting schedule. Awards reflected as "Unexercisable" are incentive units that have not yet vested. The Tier II, Tier III and Tier IV units in the

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"Unexercisable" column will not become vested until such time as the distributions threshold for that Tier has been satisfied. Awards reflected as "Exercisable" are profits interest awards that have vested, but have not yet been settled. For a description of how and when the profits interest awards could become vested and when such awards could begin to receive payments, see the discussion below.

(2): Each of the incentive units reported in the table above for Mr. Gray have been irrevocably transferred, without value, to a family trust maintained solely for the benefit of Mr. Gray's children. He is not deemed to have beneficial ownership over any of the incentive units reported in the table, but they are reported above due to the fact that the grant of the awards were considered to be compensatory awards to Mr. Gray at the time of grant.

Narrative to the Outstanding Equity Awards Table

We granted profits interest awards to each of the named executive officers in order to provide them with the ability to benefit from the growth in our operations and business. The profits interest awards are divided into four tiers. A potential payout for each tier will occur only after a specified level of cumulative cash distributions has been received by members that have made capital contributions to us, as further described below. Tier I units are designed to vest in three equal annual installments and the Tier I units granted to our named executive officers became fully time-vested on October 18, 2013. Tier II units, Tier III units and Tier IV units will each vest only upon the payment threshold established for that tier (described below). The difference between a vested and unvested unit is that once a unit is vested, in the event that an executive's employment terminates other than for Cause or due to a voluntary termination by such executive, the executive may retain all vested profits interest awards as non-voting interests. All profits interest awards that have not vested according to their original vesting schedule at the time an executive's employment is terminated for any reason will be forfeited without payment. If we terminate an executive for Cause (as defined below), or the executive voluntarily terminates his or her employment, all vested profits interest awards will also be forfeited at the time of the termination. If distributions are made with respect to a tier of these profits interest awards, both vested and unvested units will receive the distributions and the holder of such units would be entitled to keep any such distributions regardless of whether the units were subsequently forfeited. In the event that this offering is consummated, the following changes will be made to the terms of the profits interest awards:

•: the profits interest awards will be an interest and an obligation of RSP Permian Holdco, L.L.C. and not of RSP Permian, L.L.C. or the issuer;
•: if an executive's employment is terminated due to a death or Disability (as defined below), the executive (or his or her estate) may retain all vested profits interest awards as non-voting interests;
•: the board of managers of RSP Permian Holdco, L.L.C. will have the ability, but not obligation, to waive the forfeiture of vested profits interest awards if an executive voluntarily terminates his or her employment; and
•: the distribution thresholds for each tier of profits interest awards, and the distributions in which such awards will be entitled to a share of following the time the applicable distribution threshold has been met, will be based on all distributions to the members of equity interests in RSP Permian Holdco, L.L.C., and not only on cash distributions as is the case while the awards are an obligation of RSP Permian, L.L.C., plus all cash distributions made to the members of equity interests in RSP Permian, L.L.C. prior to the offering.

The Tier I units will be entitled to 15% of future distributions to members only after all of the members that have made capital contributions to RSP Permian, L.L.C. (or after this offering, to RSP Permian Holdco, L.L.C.) shall have received cumulative distributions in respect of their membership

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interests equal to their cumulative capital contributions multiplied by 1.10ⁿ, where "n" is equal to a weighted average capital contribution factor determined as of the dates of the distributions. The Tier II units will be entitled to 5% of future distributions to members only after all of the members that have made capital contributions to RSP Permian, L.L.C. (or after this offering, to RSP Permian Holdco, L.L.C.) shall have received cumulative distributions in respect of their membership interests equal to two times their cumulative capital contributions. Tier III units will be entitled to 5% of future distributions to members only after all of the members that have made capital contributions to RSP Permian, L.L.C. (or after this offering, to RSP Permian Holdco, L.L.C.) shall have received cumulative distributions in respect of their membership interests equal to three times their cumulative capital contributions. The Tier IV units will be entitled to 5% of future distributions to members only after all of the members that have made capital contributions to RSP Permian, L.L.C. (or after this offering, to RSP Permian Holdco, L.L.C.) shall have received cumulative distributions in respect of their membership interests equal to four times their cumulative capital contributions. In the event this offering is consummated, distribution thresholds will not be modified as part of the transactions that are necessary to effect this offering in the limited liability company agreement of RSP Permian Holdco, L.L.C., although references to "members" in the definition above shall refer to members of RSP Permian Holdco, L.L.C. rather than our members.

As used in the paragraph above, a "capital contribution" to RSP Permian, L.L.C. generally means, for any member thereof, the dollar amount of any cash and the fair market value of any property contributed to RSP Permian, L.L.C. In the event this offering is consummated, a "capital contribution" to RSP Permian Holdco, L.L.C. generally will mean, for any member thereof, the aggregate of (i) the dollar amount of any cash and the fair market value of any property contributed to the capital of RSP Permian, L.L.C. by the member prior to this offering, and (ii) other than the interests in RSP Permian, L.L.C. that will be contributed to RSP Permian, Inc. in connection with our corporate reorganization (as further described in "Recent and Formation Transactions—Corporate Formation Transactions—Corporate Reorganization"), the dollar amount of any cash and the fair market value of any property contributed by the member to RSP Permian Holdco, L.L.C.

A termination for "Cause" will generally occur upon the individual's (i) conviction of, or plea of nolo contendere to, any felony or crime causing substantial harm to us or our affiliates or involving acts of theft, fraud, embezzlement, moral turpitude or similar conduct; (ii) repeated intoxication by alcohol or drugs during the performance of the individual's duties in a manner that materially and adversely affects the individual's performance of such duties; (iii) malfeasance in the conduct of the individual's duties; (iv) violation of any voting or transfer restriction agreement or a confidentiality and noncompete agreement that the individual has executed with us; and (v) failure to perform the duties of the individual's service relationship with us or our affiliates, or failure to follow or comply with the reasonable and lawful written directives of our board of managers or the board of an affiliate, as applicable. In the event this offering is consummated, the definition of "Cause" will not be modified as part of the transactions that are necessary to effectuate this offering in the limited liability company agreement of RSP Permian Holdco, L.L.C., although now references to "us" in the definition above shall now refer to RSP Permian Holdco, L.L.C.

A "Disability" will be defined in the limited liability company agreement of RSP Permian Holdco, L.L.C. as (i) the individual's inability to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than 12 months; or (ii) the individual's receipt of income replacement benefits for a period of not less than three months under the accident and health plans maintained by RSP Permian Holdco, L.L.C. or its affiliates, by reason of the individual's medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months.

As of the date of this filing, no tier of the profits interest awards has received a payout.

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Because we will not be a party to the RSP Permian Holdco, L.L.C. limited liability company agreement after the offering, we cannot assure you that the terms of the profits interest units will not change in the future.

Employment, Severance or Change in Control Agreements

We historically have not maintained any employment, severance or change in control agreements with any of our named executive officers. In addition, none of the named executive officers are entitled to any payments or other benefits in connection with a termination of their employment or a change in control.

Compensation of Directors

We did not award any compensation to our non-employee individual directors during 2012. Going forward, our board of directors believes that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance of our company. Our board of directors also believes that the compensation package for our non-employee directors should require a significant portion of the total compensation package to be equity-based to align the interest of these directors with our stockholders.

We are reviewing the non-employee compensation package paid by our peer group and are considering a non-employee director compensation program.

Directors who are also our employees will not receive any additional compensation for their service on our board of directors.

We expect that each director will be reimbursed for: (i) travel and miscellaneous expenses to attend meetings and activities of our board of directors or its committees; (ii) travel and miscellaneous expenses related to such director's participation in general education and orientation program for directors; and (iii) travel and miscellaneous expenses for each director's spouse who accompanies a director to attend meetings and activities of our board of directors or any of our committees.

Compensation Following This Offering

IPO Bonuses

We expect to provide certain employees with discretionary bonuses in connection with this offering. While we have not made final decisions regarding the amounts or the recipients of the bonuses, we expect that the bonuses will be designed with a retention element, so that the bonuses will be paid out or vest over a period of two years rather than a full payment at the time of the completion of this offering.

2013 Long Term Incentive Plan

We intend to adopt the RSP Permian, Inc. 2013 Long Term Incentive Plan (the "LTIP") for the employees, consultants and the directors of our company and its affiliates who perform services for us. The description of the LTIP set forth below is a summary of the material features of the plan. This summary is qualified in its entirety by reference to the LTIP, a copy of which has been filed as an exhibit to this registration statement. The purpose of the LTIP is to provide a means to attract and retain individuals to serve as our directors, employees and consultants who will provide services to us by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common stock. At this time we have not made any final decisions regarding whether LITP awards will be given to any individual in connection with this offering.

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The LTIP will provide for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws ("incentive options"); (ii) stock options that do not qualify as incentive stock options ("nonstatutory options," and together with incentive options, "options"); (iii) restricted stock awards ("restricted stock awards"); (iv) phantom stock awards ("phantom stock awards"); (v) restricted stock units ("restricted stock units" or "RSUs"); (vi) bonus stock ("bonus stock awards"); (vii) performance awards ("performance awards"); and (viii) annual incentive awards ("annual incentive awards") (collectively referred to as "awards").

Administration

The compensation committee of our board of directors will administer the LTIP pursuant to its terms and all applicable state, federal or other rules or laws, except in the event that our board of directors chooses to take action under the LTIP. The LTIP administrator will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common stock), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the exercise terms of an option, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. The LTIP administrator shall be limited in its administration of the LTIP only in the event that a performance award or annual incentive award intended to comply with section 162(m) of the Code requires the compensation committee to be composed solely of "outside" directors at a time when not all directors are considered "outside" directors for purposes of section 162(m) of the Code; at such time any director that is not qualified to grant or administer such an award will recuse himself from the compensation committee's actions with regard to that award.

Securities to be Offered

The maximum aggregate number of shares of common stock that may be issued pursuant to any and all awards under the LTIP shall not exceed shares, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or the expiration of awards, as provided under the LTIP.

If common stock subject to any award is not issued or transferred, or ceases to be issuable or transferable for any reason, including (but not exclusively) because shares are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common stock or is otherwise terminated without a delivery of shares, those shares of common stock will again be available for issue, transfer or exercise pursuant to awards under the LTIP to the extent allowable by law.

Options—We may grant options to eligible persons including: (i) incentive options (only to our employees or those of our subsidiaries) which comply with section 422 of the Code; and (ii) nonstatutory options. The exercise price of each option granted under the LTIP will be stated in the option agreement and may vary; however, the exercise price for an option must not be less than the fair market value per share of common stock as of the date of grant (or 110% of the fair market value for certain incentive options), nor may the option be re-priced without the prior approval of our stockholders. Options may be exercised as the compensation committee determines, but not later than ten years from the date of grant. The compensation committee will determine the methods and form of payment for the exercise price of an option (including, in the discretion of the compensation committee, payment in common stock, other awards or other property) and the methods and forms in which common stock will be delivered to a participant.

Stock appreciation rights ("SARs") may be awarded in connection with an option (or as SARs that stand alone, as discussed below). SARs awarded in connection with an option will entitle the holder, upon exercise, to surrender the related option or portion thereof relating to the number of shares for

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which the SAR is exercised. The surrendered option or portion thereof will then cease to be exercisable. Such SAR is exercisable or transferable only to the extent that the related option is exercisable or transferable.

SARs—A SAR is the right to receive a share of common stock, or an amount equal to the excess of the fair market value of one share of the common stock on the date of exercise over the grant price of the SAR, as determined by the compensation committee. The exercise price of a share of common stock subject to the SAR shall be determined by the compensation committee, but in no event shall that exercise price be less than the fair market value of the common stock on the date of grant. The compensation committee will have the discretion to determine other terms and conditions of a SAR award.

Restricted stock awards—A restricted stock award is a grant of shares of common stock subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the compensation committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the compensation committee. Except as otherwise provided under the terms of the LTIP or an award agreement, the holder of a restricted stock award will have rights as a stockholder, including the right to vote the common stock subject to the restricted stock award or to receive dividends on the common stock subject to the restricted stock award during the restriction period. The compensation committee shall provide, in the restricted stock award agreement, whether the restricted stock will be forfeited and reacquired by us upon certain terminations of employment. Unless otherwise determined by the compensation committee, common stock distributed in connection with a stock split or stock dividend, and other property distributed as a dividend, will be subject to restrictions and a risk of forfeiture to the same extent as the restricted stock award with respect to which such common stock or other property has been distributed.

Phantom stock awards—Phantom stock awards are rights to receive common stock, cash, or a combination of both at the end of a specified period. The compensation committee may subject phantom stock awards to restrictions (which may include a risk of forfeiture) to be specified in the phantom stock award agreement that may lapse at such times determined by the compensation committee. Phantom stock awards may be satisfied by delivery of common stock, cash equal to the fair market value of the specified number of shares of common stock covered by the phantom stock award, or any combination thereof determined by the compensation committee at the date of grant or thereafter. Except as otherwise provided by the compensation committee in the phantom stock award agreement or otherwise, phantom stock awards subject to forfeiture restrictions may be forfeited upon termination of a participant's employment prior to the end of the specified period. Cash dividend equivalents may be paid during or after the vesting period with respect to a phantom stock award, as determined by the compensation committee.

Restricted stock units—RSUs are rights to receive common stock, cash, or a combination of both at the end of a specified period. The compensation committee may subject RSUs to restrictions (which may include a risk of forfeiture) to be specified in the RSU award agreement, and those restrictions may lapse at such times determined by the compensation committee. Restricted stock units may be settled by delivery of common stock, cash equal to the fair market value of the specified number of shares of common stock covered by the RSUs, or any combination thereof determined by the compensation committee at the date of grant or thereafter. Dividend equivalents on the specified number of shares of common stock covered by RSUs may be paid on a current, deferred or contingent basis, as determined by the compensation committee on or following the date of grant.

Bonus stock awards—The compensation committee will be authorized to grant common stock as a bonus stock award. The compensation committee will determine any terms and conditions applicable to grants of common stock, including performance criteria, if any, associated with a bonus stock award.

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Performance awards and annual incentive awards—The compensation committee may designate that certain awards granted under the LTIP constitute "performance" awards. A performance award is any award the grant, exercise or settlement of which is subject to one or more performance standards. An annual incentive award is an award based on a performance period of the fiscal year, and is also conditioned on one or more performance standards. One or more of the following business criteria for the company, on a consolidated basis, and/or for specified subsidiaries, may be used by the compensation committee in establishing performance goals for such performance awards or annual incentive awards that are intended to meet the "performance-based compensation" criteria of section 162(m) of the Code: (i) earnings per share; (ii) increase in revenues; (iii) increase in cash flow; (iv) increase in cash flow from operations; (v) increase in cash flow return; (vi) return on net assets; (vii) return on assets; (viii) return on investment; (ix) return on capital; (x) return on equity; (xi) economic value added; (xii) operating margin; (xiii) contribution margin; (xiv) net income; (xv) net income per share; (xvi) pretax earnings; (xvii) pretax operating earnings after interest expense and before incentives, service fees and extraordinary or special items; (xviii) pretax earnings before interest, depreciation and amortization; (xix) total stockholder return; (xx) debt reduction; (xxi) market share; (xxii) change in the fair market value of the common stock; (xxiii) operating income; or (xxiv) sales. The compensation committee may exclude the impact of any of the following events or occurrences which the compensation committee determines should appropriately be excluded: (i) asset write-downs; (ii) litigation, claims, judgments or settlements; (iii) the effect of changes in tax law or other such laws or regulations affecting reported results; (iv) accruals for reorganization and restructuring programs; (v) any extraordinary, unusual or nonrecurring items as described in the Accounting Standards Codification Topic 225, as the same may be amended or superseded from time to time; (vi) any change in accounting principles as defined in the Accounting Standards Codification Topic 250, as the same may be amended or superseded from time to time; (vii) any loss from a discontinued operation as described in the Accounting Standards Codification Topic 360, as the same may be amended or superseded from time to time; (viii) goodwill impairment charges; (ix) operating results for any business acquired during the calendar year; (x) third party expenses associated with any acquisition by us or any subsidiary; and (xi) to the extent set forth with reasonable particularity in connection with the establishment of performance goals, any other extraordinary events or occurrences identified by the compensation committee. The compensation committee may also use any of the above goals determined on an absolute or relative basis or as compared to the performance of a published or special index deemed applicable by the compensation committee including, but not limited to, the Standard & Poor's 500 stock index or a group of comparable companies.

Performance awards or annual incentive awards granted to eligible persons who are deemed by the compensation committee to be "covered employees" pursuant to section 162(m) of the Code shall be administered in accordance with the rules and regulations issued under section 162(m) of the Code. The compensation committee may also impose individual performance criteria on the awards, which, if required for compliance with section 162(m) of the Code, will be approved by our stockholders.

Tax withholding. At our discretion, subject to conditions that the compensation committee may impose, a participant's minimum statutory tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of shares of common stock issuable pursuant to the award based on the fair market value of the shares.

Merger, recapitalization or change in control. If any change is made to our capitalization, such as a stock split, stock combination, stock dividend, exchange of shares or other recapitalization, merger or otherwise, which results in an increase or decrease in the number of outstanding shares of common stock, appropriate adjustments will be made by the compensation committee in the shares subject to an award under the LTIP. We will also have the discretion to make certain adjustments to awards in the event of a change in control, such as accelerating the exercisability of options or SARs, requiring the surrender of an award, with or without consideration, or making any other adjustment or modification to the award we feel is appropriate in light of the specific transaction.

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PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth the beneficial ownership of our common stock that, upon the consummation of this offering and the Transactions, will be owned by:

•: each of the selling stockholders;
•: each person known to us to beneficially own more than 5% of any class of our outstanding common stock;
•: each member of our board of directors;
•: each of our named executive officer; and
•: all of our directors and executive officers as a group.

All information with respect to beneficial ownership has been furnished by the respective 5% or more stockholders, selling stockholders, directors or named executive officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o RSP Permian, Inc., 3141 Hood Street, Suite 701, Dallas, Texas 75219.

To the extent that the underwriters sell more than shares of common stock, the underwriters have the option to purchase up to an additional shares from the selling stockholders.

				Shares Beneficially Owned After this Offering (Assuming No Exercise of the Underwriters' Option to Purchase Additional Shares)		Shares Beneficially Owned After this Offering (Assuming the Underwriters' Option to Purchase Additional Shares is Exercised in Full)

	Shares Beneficially Owned Before this Offering
	Shares Beneficially Owned Before this Offering		Shares Offered Hereby
Name of Beneficial Owner(1)	Number	Percentage	Shares Offered Hereby	Number	Percentage	Number	Percentage
Selling Stockholders and Other 5% Stockholders:
RSP Permian Holdco, L.L.C.(2)
Rising Star Energy Development Co., L.L.C.(3)
Ted Collins, Jr.
Wallace Family Partnership, LP(4)
Collins & Wallace Holdings, LLC(5)
Pecos Energy Partners, L.P.
ACTOIL, LLC(7)
Directors and Executive Officers:
Michael Grimm
Steven Gray
David Albin
Scott McNeill
Zane Arrott
Tamara Pollard
Erik B. Daugbjerg
William Huck
Directors and executive officers as a group (8 persons)

*: Less than 1%.

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(1): The amounts and percentages of common stock beneficially owned are reported on the bases of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person's ownership percentage, but not for purposes of computing any other person's percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated shares of common stock, except to the extent this power may be shared with a spouse.
(2): RSP Permian Holdco, L.L.C. is owned by Production Opportunities (an entity owned by Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P. (collectively "NGP IX")), certain members of our management team and certain of our employees. Certain members of our management team and certain of our employees also own incentive units in RSP Permian Holdco, L.L.C. Please see "Executive Compensation—Outstanding Equity Awards at 2012 Fiscal Year-End" for more information on the incentive units. NGP IX may be deemed to share voting and dispositive power over the reported securities and may also be deemed to be the beneficial owner of these securities. NGP IX disclaims beneficial ownership of the reported securities in excess of such entity's respective pecuniary interest in the securities. GFW IX, L.L.C. and G.F.W. Energy IX, L.P. may be deemed to beneficially own the common stock owned by NGP IX by virtue of GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the sole general partner of NGP IX). David Albin, one of our directors, may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition of, those securities by virtue of his shared control of GFW IX, L.L.C. Mr. Albin does not own directly any shares of our common stock.
(3): Rising Star Energy Development Co., L.L.C. is wholly owned by Rising Star LP, which is managed by its general partner, Rising Star GP. Rising Star LP and Rising Star GP are each owned by NGP VIII, certain members of our management team and certain other persons. NGP VIII may be deemed to have voting and dispositive power over the reported securities and may also be deemed to be the beneficial owner of these securities. NGP VIII disclaims beneficial ownership of the reported securities in excess of its pecuniary interest in the securities.
(4): Wallace Family Partnership, LP is a family-owned entity owned by Michael W. Wallace and certain members of Mr. Wallace's family. The general partner of Wallace Family Partnership, LP is Michael Wallace Management, LLC ("Wallace Management"). Wallace Management is controlled by Mr. Wallace. Because of the foregoing relationships, each of Wallace Management and Mr. Wallace may be deemed to have voting and dispositive power over the reported securities and may also be deemed to be the beneficial owner of these securities. Each of Wallace Management and Mr. Wallace disclaim beneficial ownership of the reported securities in excess of its or his pecuniary interest in the securities.
(5): Collins & Wallace Holdings, LLC is owned equally by Ted Collins, Jr. and Wallace Family Partnership, LP. Mr. Collins is the Chief Executive Officer and the manager of Collins & Wallace Holdings, LLC. Mr. Collins may be deemed to have voting or dispositive power over the reported securities and may also be deemed to be the beneficial owner of these securities. In addition, due to its 50% ownership interest in Collins & Wallace Holdings, LLC, Wallace Family Partnership, LP may be deemed to have voting or dispositive power over the reported securities. As described in

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note (4) above, through their relationship with Wallace Family Partnership, LP, each of Wallace Management and Mr. Wallace may be deemed to have voting and dispositive power over the reported securities and may also be deemed to be the beneficial owner of these securities. Each of Wallace Management and Mr. Wallace disclaim beneficial ownership of the reported securities in excess of its or his pecuniary interest in the securities.

(6): Steven Gray, Erik B. Daugbjerg and William Huck each own one-third of the outstanding partnership interests of Pecos, directly and through their membership interests in Pecos Operating Company, LLC, a Texas limited liability company and the general partner of Pecos. Messrs. Gray, Daugbjerg and Huck may be deemed to share the power to vote, or to direct the vote, and to dispose of, or to direct the disposition of, those securities by virtue of their shared control of Pecos and Pecos Operating Company, LLC. Each of Messrs. Gray, Daugbjerg and Huck disclaim beneficial ownership of the reported securities in excess of his respective pecuniary interest in the securities. Pecos Operating Company, LLC may be deemed to have voting and dispositive power over the reported securities and may also be deemed to be the beneficial owner of these securities. Pecos Operating Company, LLC disclaims beneficial ownership of the reported securities in excess of its pecuniary interest in the securities.
(7): ACTOIL, LLC is a wholly owned subsidiary of TIAA Oil and Gas Investments, LLC, its sole member. TIAA Oil and Gas Investments, LLC is a wholly owned subsidiary of Teachers Insurance and Annuity Association of America, its sole member. Because of the foregoing relationships, each of ACTOIL, LLC, TIAA Oil and Gas Investments, LLC and Teachers Insurance and Annuity Association of America may be deemed to have voting and dispositive power over the reported securities and may also be deemed to be the beneficial owner of these securities. Each of ACTOIL, LLC, TIAA Oil and Gas Investments, LLC and Teachers Insurance and Annuity Association of America disclaim beneficial ownership of the reported securities in excess of its pecuniary interest in the securities.

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RECENT 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 for approximately $214 million.

Spanish Trail Acquisition

On September 10, 2013, we completed the Spanish Trail Acquisition. 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 below under "—Corporate Formation Transactions," the Spanish Trail Acquisition increased our working interests in 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 three months ended September 30, 2013, average net daily production associated with the Spanish Trail Assets was approximately 1,097 Boe/d (approximately 71% oil, 12% natural gas and 17% 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, Collins and 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 and 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 Collins and Wallace 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 an 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 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. This belief is based on detailed log analysis of four key well penetrations located within the acreage block as well as drill cuttings analysis from two of these wells to verify porosity, permeability and total organic carbon content. We believe the prospectivity of this acreage is further corroborated by an additional 50 wells located on or within one mile of the acreage block that have penetrated sufficient depth to provide data on the Wolfcamp B zone. No 3-D seismic data has been acquired on this acreage as of this time.

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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, 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 three months ended September 30, 2013, RSP Permian, L.L.C.'s average net daily production was 4,476 Boe/d (approximately 70% oil, 14% natural gas and 16% NGLs).

Pursuant to the terms of a corporate reorganization that will be completed in connection with this offering, (i) the members of RSP Permian, L.L.C. will contribute all of their interests in RSP Permian, L.L.C. to RSP Permian Holdco, L.L.C., a to-be-formed entity that will be wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. will contribute all of its interests in RSP Permian, L.L.C. to RSP Permian, Inc. in exchange for shares of common stock of RSP Permian, Inc. and an assignment of RSP Permian, L.L.C.'s pro rata share of an escrow related to the Resolute Disposition (which escrow is described in Note 3 of the unaudited historical combined financial statements of RSP Permian, L.L.C. and Rising Star). 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 complete 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 three months ended September 30, 2013, the average net daily production associated with the Rising Star Assets was 213 Boe/d (approximately 65% oil, 16% natural gas and 19% 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 nine months ended September 30, 2013.

The Collins and Wallace Contributions

Collins, Wallace LP and Collins & Wallace Holdings, LLC have each agreed to contribute to us certain working interests 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 Collins and Wallace Contributions will occur in connection with this offering.

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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 three months ended September 30, 2013, the 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 2,369 Boe/d (approximately 69% oil, 15% natural gas and 16% NGLs).

The Pecos Contribution

In connection with this offering, Pecos, an entity owned by certain members of our management team, has agreed to contribute to us certain working interests in certain acreage and wells in the Permian Basin in which RSP Permian, L.L.C. already has working interests. In exchange, Pecos will receive shares of RSP Permian, Inc. common stock. The Pecos Contribution will increase our working interests in approximately 650 gross acres and six producing wells. For the three months ended September 30, 2013, the average net daily production associated with the Pecos Assets was 8 Boe/d (approximately 78% oil and 22% natural gas).

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 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.

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The Existing Investors

Following the completion of the Transactions, our 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.(4)
Ted Collins, Jr.
Wallace Family Partnership, LP
Collins & Wallace Holdings, LLC
Pecos Energy Partners, L.P.(5)
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 (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 also own incentive units in RSP Permian Holdco, L.L.C. Please see "Executive Compensation—Outstanding Equity Awards at 2012 Fiscal Year-End" for more information on the incentive units.
(4): Rising Star Energy Development Co., L.L.C. is wholly owned by Rising Star LP, which is managed by its general partner, Rising Star GP. Rising Star LP and Rising Star GP are each owned by NGP VIII, certain members of our management team and certain other persons.
(5): Pecos Energy Partners, L.P. is owned by certain members of our management team and is managed by its general partner, Pecos Operating Company, LLC, which is also owned by certain members of our management team.

The allocation of the shares of our common stock to be owned by the Existing Investors will be dependent on the equity valuation of our company as determined by the initial public offering price of this offering. While the total number of shares that will be owned by the Existing Investors will not change based on the initial public offering price, a $1.00 increase in the assumed initial public

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offering price of $ per share would cause the allocation of shares among the Existing Investors to consist of the following:

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

RSP Permian Holdco, L.L.C.(2)
Rising Star Energy Development Co., L.L.C.(3)
Ted Collins, Jr.
Wallace Family Partnership, LP
Collins & Wallace Holdings, LLC
Pecos Energy Partners, L.P.(4)
ACTOIL, LLC

Total

(1): Assumes no exercise of the underwriters' option to purchase additional shares of our common stock.
(2): RSP Permian Holdco, L.L.C. is owned by 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 also own incentive units in RSP Permian Holdco, L.L.C. Please see "Executive Compensation—Outstanding Equity Awards at 2012 Fiscal Year-End" for more information on the incentive units.
(3): Rising Star Energy Development Co., L.L.C. is wholly owned by Rising Star LP, which is managed by its general partner, Rising Star GP. Rising Star LP and Rising Star GP are each owned by NGP VIII, certain members of our management team and certain other persons.
(4): Pecos Energy Partners, L.P. is owned by certain members of our management team and is managed by its general partner, Pecos Operating Company, LLC, which is also owned by certain members of our management team.

Likewise, a $1.00 decrease in the assumed initial public offering price of $ per share would cause the allocation of shares among the Existing Investors to consist of the following:

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

RSP Permian Holdco, L.L.C.(2)
Rising Star Energy Development Co., L.L.C.(3)
Ted Collins, Jr.
Wallace Family Partnership, LP
Collins & Wallace Holdings, LLC
Pecos Energy Partners, L.P.(4)
ACTOIL, LLC

Total

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

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(2): RSP Permian Holdco, L.L.C. is owned by 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 also own incentive units in RSP Permian Holdco, L.L.C. Please see "Executive Compensation—Outstanding Equity Awards at 2012 Fiscal Year-End" for more information on the incentive units.
(3): Rising Star Energy Development Co., L.L.C. is wholly owned by Rising Star LP, which is managed by its general partner, Rising Star GP. Rising Star LP and Rising Star GP are each owned by NGP VIII, certain members of our management team and certain other persons.
(4): Pecos Energy Partners, L.P. is owned by certain members of our management team and is managed by its general partner, Pecos Operating Company, LLC, which is also owned by certain members of our management team.

For more information on the ownership of our common stock by our principal and selling stockholders, see "Principal and Selling Stockholders."

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Historical Transactions with Affiliates

Resolute Disposition

As more fully described under "Recent and Formation Transactions—Recent Acquisitions and Dispositions—Resolute Disposition," we sold all of our working interests in certain Permian Basin assets to Resolute for $214 million in a transaction that closed in part in December 2012 and in part in March 2013. An affiliate of NGP, Natural Gas Partners VII, L.P. ("NGP VII"), and an affiliated co-investment fund ("NGP VII Co-Invest") collectively own less than 5% of the total issued and outstanding shares of the publicly-traded holding company of Resolute, Resolute Energy Corporation ("Resolute Parent"). Assuming full exercise of all warrants held by an entity owned by NGP VII and NGP VII Co-Invest, however, NGP VII and NGP VII Co-Invest would collectively own 10.7% of Resolute Parent. NGP is also entitled to designate one member of Resolute Parent's board of directors.

Rising Star Acquisition

As described under "Recent and Formation Transactions—Corporate Formation Transactions—The Rising Star Acquisition," we will acquire from Rising Star working interests in certain acreage and wells in the Permian Basin in exchange for shares of RSP Permian, Inc. common stock. Prior to this offering, an affiliate of NGP, Natural Gas Partners VIII, L.P., owns over 90% of the membership interests in the general partner of Rising Star and over 80% of the membership interests of the sole owner of Rising Star, Rising Star Energy Holdings, L.P. Certain members of our management team, Michael Grimm, Zane Arrott and Tamara Pollard, are officers of Rising Star. Mr. Grimm, Mr. Arrott, Ms. Pollard and Ted Collins, Jr., who will be appointed to our board of directors shortly after the consummation of this offering, own 3%, 3%, 2% and 4% of the membership interest in Rising Star Energy Holdings, L.P. Following the completion of the Transactions but immediately prior to the completion of this offering, Rising Star will own approximately % of RSP Permian, Inc.'s common stock. See "Recent and Formation Transactions—The Existing Investors" for more information regarding Rising Star's ownership of RSP Permian, Inc.'s common stock.

Corporate Reorganization

As described in "Recent and Formation Transactions," in connection with this offering, (i) the members of RSP Permian, L.L.C. will contribute all of their interests in RSP Permian, L.L.C. to RSP Permian Holdco, L.L.C., a to-be-formed entity that will be wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. will contribute all of its interests in RSP Permian, L.L.C. to RSP Permian, Inc. in exchange for shares of common stock of RSP Permian, Inc. and an assignment of RSP Permian, L.L.C.'s pro rata share of an escrow related to the Resolute Disposition (which escrow is described in Note 3 of the unaudited historical combined financial statements of RSP Permian, L.L.C. and Rising Star). RSP Permian Holdco, L.L.C. is owned by Production Opportunities, an entity affiliated with NGP, certain members of our management team and certain of our employees.

The Collins and Wallace Contributions

In exchange for common units, Mr. Collins, Wallace LP and Collins & Wallace Holdings, LLC will each contribute to us working interests in certain of RSP Permian, L.L.C.'s existing properties in exchange for shares of RSP Permian, Inc. common stock. See "Recent and Formation Transactions—Corporate Formation Transactions—The Collins and Wallace Contributions" for more information regarding the Collins and Wallace Contributions. Wallace LP is a family-owned entity owned by Michael W. Wallace and certain members of Mr. Wallace's family. The general partner of Wallace LP is Michael Wallace Management, LLC, which is controlled by Mr. Wallace. Collins & Wallace Holdings, LLC is owned equally by Mr. Collins and Wallace LP. Mr. Collins is the manager of Collins & Wallace Holdings, LLC.

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Messrs. Collins and Wallace will be appointed to our board of directors shortly after the consummation of this offering and will own approximately % and % of RSP Permian, Inc.'s common stock, respectively, following the completion of the Transactions but immediately prior to the completion of this offering. See "Recent and Formation Transactions—The Existing Investors" for more information regarding Mr. Collins', Wallace LP's and Collins & Wallace Holdings, LLC's ownership of RSP Permian, Inc.'s common stock.

Pecos Contribution

As described under "Recent and Formation Transactions," we will acquire from Pecos, an entity owned by certain members of our management team, working interests in certain acreage and wells in the Permian Basin in exchange for shares of RSP Permian, Inc. common stock. Steven Gray, Erik B. Daugbjerg and William Huck, each a member of our management team, each owns one-third of the outstanding partnership interests of Pecos, directly and through their membership interests in Pecos Operating Company, LLC, the general partner of Pecos. In addition, each of Messrs. Gray, Daugbjerg and Huck serve as managers of the general partner of Pecos. In connection with the Pecos Contribution, Pecos will receive shares of RSP Permian, Inc. common stock with an approximate value of $ , of which $ , $ and $ is attributable to the interests held by Messrs. Gray, Daugbjerg and Huck, respectively.

MidMar

We are party to a gas purchase agreement, dated March 1, 2009, as amended, with MidMar (which was renamed Coronado Midstream, LLC in September 2013), an entity that owns a natural gas gathering system and processing plant in the Permian Basin. Under this agreement, MidMar is obligated to purchase from us, and we are obligated to sell to MidMar, all of the natural gas conforming to certain quality specifications produced from certain of our Permian Basin acreage.

Messrs. Collins and Wallace own approximately 9.8% and 9.8% of the ownership interests in MidMar, and the remaining interests in MidMar are owned by unaffiliated third parties. Mr. Collins is the chairman of the board of managers of MidMar. For the years ended December 31, 2011 and 2012 and for the nine months ended September 30, 2013, MidMar accounted for 9%, 11% and 9% of our revenue, respectively.

Messrs. Collins and Wallace will be appointed to our board of directors shortly after the consummation of this offering and will own approximately % and % of RSP Permian, Inc.'s common stock, respectively, following the consummation of the Transactions but immediately prior to the consummation of this offering. See "Recent and Formation Transactions—The Existing Investors" for more information regarding Mr. Collins', Wallace LP's and Collins & Wallace Holdings, LLC's ownership of RSP Permian, Inc.'s common stock.

Operating Overheard Reimbursements

In connection with the operation of certain oil and natural gas properties, pursuant to joint operating agreements, the Company charges Mr. Collins and Wallace LP for administrative overhead (commonly referred to as the Council of Petroleum Accountants Society (COPAS) fees). Such overhead recoveries from Mr. Collins and Wallace LP each totaled $0.3 million during the year ended December 31, 2012. Wallace LP is a family-owned entity owned by Mr. Wallace and certain members of Mr. Wallace's family. The general partner of Wallace LP is Michael Wallace Management, LLC, which is controlled by Mr. Wallace.

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completion of this offering. See "Recent and Formation Transactions—The Existing Investors" for more information regarding Mr. Collins' and Wallace LP's ownership of RSP Permian, Inc.'s common stock.

Registration Rights Agreement

In connection with the closing of this offering, we expect to enter into a registration rights agreement with RSP Permian Holdco, L.L.C., Collins, Wallace LP, ACTOIL, Rising Star and Pecos. The registration rights agreement is expected to provide for customary rights for RSP Permian Holdco, L.L.C., Collins, Wallace LP and ACTOIL (and their respective permitted transferees) to demand that we register the sale of their shares of common stock, including in an underwritten offering. Rising Star and Pecos (and their respective permitted transferees) may, in certain circumstances, participate in such registration. In addition, we expect that the agreement will grant RSP Permian Holdco, L.L.C., Collins, Wallace LP, ACTOIL, Rising Star and Pecos customary rights to participate in certain registrations and underwritten offerings of our common stock that we may conduct. We expect that we will be required to bear the expenses associated with any registration or offering of shares of our common stock held by the holders of our common stock with registration rights under our the registration rights agreement, other than underwriting discounts, selling commissions and stock transfer taxes and fees and disbursements of counsel for any such holders.

Stockholders' Agreement

In connection with the closing of this offering, we will enter into a stockholders' agreement with RSP Permian Holdco, L.L.C., Collins, Wallace LP, Rising Star and Pecos. The stockholders' agreement will provide each of RSP Permian Holdco, L.L.C., Collins and Wallace LP with the right to designate a certain number of nominees to our board of directors, subject to the following:

•: RSP Permian Holdco, L.L.C. will have the right to designate two nominees to our board of directors, provided that such number of nominees shall be reduced to one and zero if RSP Permian Holdco, L.L.C. and its affiliates collectively own less than 15% and 5%, respectively, of the outstanding shares of our common stock;
•: Collins will have the right to designate one nominee to our board of directors, provided that such number of nominees shall be reduced to zero if Collins and his affiliates collectively own less than 5% of the outstanding shares of our common stock, and provided further that Collins and his affiliates shall be deemed to beneficially own only the number of shares that is proportional to their ownership of Collins & Wallace Holdings, LLC; and
•: Wallace LP will have the right to designate one nominee to our board of directors, provided that such number of nominees shall be reduced to zero if Wallace LP and its affiliates collectively own less than 5% of the outstanding shares of our common stock, and provided further that Wallace LP and its affiliates shall be deemed to beneficially own only the number of shares that is proportional to their ownership of Collins & Wallace Holdings, LLC.

The stockholders' agreement will also require the stockholders party thereto to take all necessary actions, including voting their shares of our common stock, to cause the election of the nominees designated by RSP Permian Holdco, L.L.C., Collins and Wallace LP.

Procedures for Approval of Related Party Transactions

Prior to the closing of this offering, we have not maintained a policy for approval of Related Party Transactions. A "Related Party Transaction" is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds

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$120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A "Related Person" means:

•: any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;
•: any person who is known by us to be the beneficial owner of more than 5% of our common stock;
•: any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and
•: any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

We anticipate that our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that our audit committee will review all material facts of all Related Party Transactions.

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DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering, the authorized capital stock of RSP Permian, Inc. will consist of shares of common stock, $0.01 par value per share, of which shares will be issued and outstanding, and shares of preferred stock, $ par value per share, of which no shares will be issued and outstanding.

The following summary of the capital stock and amended and restated certificate of incorporation and amended and restated bylaws of RSP Permian, Inc. does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our amended and restated certificate of incorporation and amended and restated bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.

Common Stock

Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of common stock are not entitled to vote on any amendment to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to our amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the Delaware General Corporation Law (the "DGCL"). Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably in proportion to the shares of common stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable.

The holders of common stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to common stock. In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets in proportion to the shares of common stock held by them that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock, if any.

Preferred Stock

Our amended and restated certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $ per share, covering up to an aggregate of shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

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Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law

Some provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

Section 203 of the DGCL prohibits a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

•: the transaction is approved by the board of directors before the date the interested stockholder attained that status;
•: upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or
•: on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

We may elect to not be subject to the provisions of Section 203 of the DGCL.

Our Amended and Restated Certificate of Incorporation and Our Amended and Restated Bylaws

Provisions of our amended and restated certificate of incorporation and our amended and restated bylaws, which will become effective upon the closing of this offering, may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests. Therefore, these provisions could adversely affect the price of our common stock.

Limitation of Liability and Indemnification Matters

Our amended and restated certificate of incorporation will limit the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

•: for any breach of their duty of loyalty to us or our stockholders;

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•: for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;
•: for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or
•: for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our amended and restated bylaws will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated bylaws also will permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person's actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision that will be in our amended and restated certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Registration Rights

For a description of registration rights with respect to our common stock, see the information under the heading "Certain Relationships and Related Party Transactions—Registration Rights Agreement."

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is .

Listing

We intend to apply to list our common stock on the NYSE under the symbol "RSPP."

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. Future sales of our common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our common stock prevailing from time to time. As described below, only a limited number of shares will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price of our common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

Upon the closing of this offering, we will have outstanding an aggregate of shares of common stock. Of these shares, all of the shares of common stock to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our "affiliates" as such term is defined in Rule 144 under the Securities Act. All remaining shares of common stock held by existing stockholders will be deemed "restricted securities" as such term is defined under Rule 144. The restricted securities were issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our common stock (excluding the shares to be sold in this offering) that will be available for sale in the public market are as follows:

•: no shares will be eligible for sale on the date of this prospectus or prior to 180 days after the date of this prospectus;
•: shares will be eligible for sale upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus (subject to extension) and when permitted under Rule 144 or Rule 701; and
•: shares will be eligible for sale, upon exercise of vested options, upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus (subject to extension).

Lock-up Agreements

We, all of our directors and executive officers, certain of our stockholders and the selling stockholders have agreed or will agree that, subject to certain exceptions and under certain conditions, for a period of 180 days after the date of this prospectus, we and they will not, without the prior written consent of Barclays Capital Inc., dispose of or hedge any shares or any securities convertible into or exchangeable for shares of our capital stock. See "Underwriting—Lock-Up Agreements" for a description of these lock-up provisions.

Rule 144

In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least sixth months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted

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securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least nine months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Rule 701

In general, under Rule 701 under the Securities Act, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register shares issuable under our equity incentive plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.

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

The following is a summary of the material U.S. federal income tax and, to a limited extent, estate tax, consequences related to the purchase, ownership and disposition of our common stock by a non-U.S. holder (as defined below), that holds our common stock as a "capital asset" (generally property held for investment). This summary is based on the provisions of the Code, U.S. Treasury regulations and administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service ("IRS") with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.

This summary does not address all aspects of U.S. federal income or estate taxation that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal gift tax laws, any state, local or foreign tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as (without limitation):

•: banks, insurance companies or other financial institutions;
•: tax-exempt or governmental organizations;
•: dealers in securities or foreign currencies;
•: traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;
•: persons subject to the alternative minimum tax;
•: partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein;
•: persons deemed to sell our common stock under the constructive sale provisions of the Code;
•: persons that acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;
•: certain former citizens or long-term residents of the United States;
•: real estate investment trusts or regulated investment companies; and
•: persons that hold our common stock as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction.

PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISOR WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE TAX LAWS TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR COMMON STOCK ARISING UNDER THE U.S. FEDERAL GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.

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Non-U.S. Holder Defined

For purposes of this discussion, a "non-U.S. holder" is a beneficial owner of our common stock that is not for U.S. federal income tax purposes any of the following:

•: an individual who is a citizen or resident of the United States;
•: a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;
•: an estate the income of which is subject to U.S. federal income tax regardless of its source; or
•: a trust (i) whose administration is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person.

If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner and upon the activities of the partnership. Accordingly, we urge partners in partnerships (including entities treated as partnerships for U.S. federal income tax purposes) considering the purchase of our common stock to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership and disposition of our common stock by such partnership.

Distributions

As described in the section entitled "Dividend Policy," we do not plan to make any distributions on our common stock for the foreseeable future. However, if we do make distributions of cash or property on our common stock, those payments will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the non-U.S. holder's tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See "—Gain on Disposition of Common Stock." Any distribution made to a non-U.S. holder on our common stock generally will be subject to U.S. withholding tax at a rate of 30% of the gross amount of the distribution unless an applicable income tax treaty provides for a lower rate. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide the withholding agent with an IRS Form W-8BEN (or other appropriate form) certifying qualification for the reduced rate.

Dividends paid to a non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if the non-U.S. holder satisfies certain certification requirements by providing the withholding agent a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a foreign corporation, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items).

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Gain on Disposition of Common Stock

A non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

•: the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met;
•: the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or
•: our common stock constitutes a U.S. real property interest by reason of our status as a United States real property holding corporation ("USRPHC") for U.S. federal income tax purposes.

A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.

A non-U.S. holder whose gain is described in the second bullet point above generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items) which will include such gain.

Generally, a corporation is a USRPHC if the fair market value of its U.S. real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our common stock is considered to be regularly traded on an established securities market, only a non-U.S. holder that actually or constructively owns or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder's holding period for the common stock, more than 5% of our common stock will be taxable on gain recognized on the disposition of our common stock as a result of our status as a USRPHC. If our common stock were not considered to be regularly traded on an established securities market, all non-U.S. holders generally would be subject to U.S. federal income tax on a taxable disposition of our common stock, and a 10% withholding tax would apply to the gross proceeds from the sale of our common stock by such non-U.S. holders.

Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our common stock.

U.S. Federal Estate Tax

Our common stock beneficially owned or treated as owned by an individual who is not a citizen or resident of the United States (as defined for U.S. federal estate tax purposes) at the time of death generally will be includable in the decedent's gross estate for U.S. federal estate tax purposes and thus may be subject to U.S. federal estate tax, unless an applicable estate tax treaty provides otherwise.

Backup Withholding and Information Reporting

Any dividends paid to a non-U.S. holder must be reported annually to the IRS and to the non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Payments of dividends to a non-U.S.

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holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or other appropriate version of IRS Form W-8.

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or other appropriate version of IRS Form W-8 and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our common stock effected outside the United States by a foreign office of a broker. However, unless such broker has documentary evidence in its records that the holder is a non-U.S. holder and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our common stock effected outside the United States by such a broker if it has certain relationships within the United States.

Backup withholding is not an additional tax. Rather, the U.S. income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Additional Withholding Requirements

Sections 1471 through 1474 of the Code, and the Treasury regulations and administrative guidance issued thereunder, impose a 30% withholding tax on any dividends on our common stock and on the gross proceeds from a disposition of our common stock in each case if paid to a "foreign financial institution" or a "non-financial foreign entity" (each as defined in the Code) (including, in some cases, when such foreign financial institution or entity is acting as an intermediary), unless: (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are foreign entities with U.S. owners); (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any "substantial United States owners" (as defined in the Code) or provides the withholding agent with a certification identifying the direct and indirect substantial United States owners of the entity; or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes.

Payments subject to withholding tax under this law generally include dividends paid on common stock of a U.S. corporation after June 30, 2014, and gross proceeds from sales or other dispositions of such common stock after December 31, 2016. Non-U.S. holders are encouraged to consult their tax advisors regarding the possible implications of these withholding rules.

THE FOREGOING DISCUSSION IS FOR GENERAL INFORMATION ONLY AND SHOULD NOT BE VIEWED AS TAX ADVICE. INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL GIFT TAX LAWS AND ANY STATE, LOCAL OR FOREIGN TAX LAWS AND TAX TREATIES.

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UNDERWRITING

Barclays Capital Inc. and J.P. Morgan Securities LLC are acting as the representatives of the underwriters named below, and Barclays Capital Inc., J.P. Morgan Securities LLC and Tudor, Pickering, Holt & Co. Securities, Inc. are acting as joint bookrunning managers for this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us and the selling stockholders the respective number of shares of common stock shown opposite its name below:

Underwriters		Number of Shares

Barclays Capital Inc.
J.P. Morgan Securities LLC
Tudor, Pickering, Holt & Co. Securities, Inc.

Total

The underwriting agreement provides that the underwriters' obligation to purchase shares of common stock depends on the satisfaction of the conditions contained in the underwriting agreement, including:

•: the obligation to purchase all of the shares of common stock offered hereby (other than those shares of common stock covered by their option to purchase additional shares as described below), if any of the shares are purchased;
•: the representations and warranties made by us and the selling stockholders to the underwriters are true;
•: there is no material change in our business or the financial markets; and
•: we and the selling stockholders deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we and the selling stockholders will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us and the selling stockholders for the shares.

	Us		Selling Stockholders

	No Exercise	Full Exercise	No Exercise	Full Exercise
Per Share	$	$	$	$

Total	$	$	$	$

The representative has advised us that the underwriters propose to offer the shares of common stock directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per share. After this offering, the representative may change the offering price and other selling terms. Sales of the shares of common stock made outside of the United States may be made by affiliates of the underwriters.

The expenses of this offering that are payable by us and the selling stockholders are estimated to be approximately $ (excluding underwriting discounts and commissions). We have agreed to pay expenses incurred by the selling stockholders in connection with this offering, other than the

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underwriting discounts and commissions. We have also agreed to reimburse the underwriters for certain of their expenses in an amount up to $ .

Option to Purchase Additional Shares

The selling stockholders have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of shares from the selling stockholders at the public offering price less underwriting discounts and commissions. This option may be exercised to the extent the underwriters sell more than shares in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter's percentage underwriting commitment in this offering as indicated in the table at the beginning of this Underwriting section.

Lock-Up Agreements

We, all of our directors and executive officers, certain of our stockholders and the selling stockholders have agreed or will agree that, for a period of 180 days after the date of this prospectus, we and they will not directly or indirectly, without the prior written consent of Barclays Capital Inc., (i) offer for sale, sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of our common stock (including, without limitation, shares of our common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and shares of our common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for shares of our common stock (other than the stock and shares issued pursuant to employee benefit plans, qualified stock option plans or other employee compensation plans existing on the date of this prospectus or pursuant to currently outstanding options, warrants or rights not issued under one of those plans), or sell or grant options, rights or warrants with respect to any shares of our common stock or securities convertible into or exchangeable for shares of our common stock (other than the grant of options pursuant to option plans existing on the date of this prospectus); (ii) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of shares of our common stock, whether any such transaction described in clause (i) or (ii) above is to be settled by delivery of common stock or other securities, in cash or otherwise; (iii) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of our common stock or securities convertible, exercisable or exchangeable into shares of our common stock or any of our other securities (other than any registration statement on Form S-8); or (iv) publicly disclose the intention to do any of the foregoing.

Barclays Capital Inc., in its sole discretion, may release the shares of our common stock and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release shares of our common stock and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder's reasons for requesting the release, the number of shares of common stock and other securities for which the release is being requested and market conditions at the time. At least three business days before the effectiveness of any release or waiver of any of the restrictions described above with respect to an officer or director of ours, Barclays Capital Inc. will notify us of the impending release or waiver and we have agreed to announce the impending release or waiver by press release through a major news service at least two business days before the effective date of the release or waiver, except where the release or waiver is effected solely to permit a transfer of common stock that is not for consideration and where the transferee has agreed in writing to be bound by the same terms as the lock-up agreements described above to the extent and for the duration that such terms remain in effect at the time of transfer.

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Directed Share Program

At our request, 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. Any executive officer, director or director nominee purchasing shares of common stock as part of the directed share program will be subject to the 180-day lock-up restriction as described above in "—Lock-Up Agreements." 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. Any reserved shares of our common stock that are not so purchased will be offered by the underwriters to the general public on the same terms as the other shares of our common stock offered by this prospectus. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with sales of the reserved shares.

Offering Price Determination

Prior to this offering, there has been no public market for our common stock. The initial public offering price was negotiated between the representative and us. In determining the initial public offering price of our common stock, the representative considered:

•: the history and prospects for the industry in which we compete;
•: our financial information;
•: the ability of our management and our business potential and earning prospects;
•: the prevailing securities markets at the time of this offering; and
•: the recent market prices of, and the demand for, publicly traded shares of generally comparable companies.

Indemnification

We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representative may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of our common stock, in accordance with Regulation M under the Exchange Act:

•: Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
•: A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in this offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by either exercising their option to purchase additional shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will

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consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in this offering.

•: Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions.
•: Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common stock. In addition, neither we nor any of the underwriters make any representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Listing on the New York Stock Exchange

We intend to apply to list our common stock on the NYSE under the symbol "RSPP."

Stamp Taxes

If you purchase shares of common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Other Relationships

The underwriters and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for us and our affiliates, for which they received or may in the future receive customary fees and expenses. An affiliate of Barclays Capital Inc. is a limited partner in G.F.W. Energy IX, L.P., which is the general partner of Natural Gas Partners IX, L.P., one of the entities that owns Production Opportunities, which in turn owns RSP Permian Holdco, L.L.C., one of the selling stockholders in this offering. In addition, an affiliate of Barclays Capital Inc. is a limited partner in G.F.W. Energy VIII, L.P., which is the general partner of NGP VIII, one of the entities that owns Rising Star LP and Rising Star GP, which entities wholly own and manage, respectively, Rising Star, one of the selling stockholders in this offering.

In the ordinary course of their various business activities, the underwriters and certain of their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of ours or our affiliates. The underwriters and certain of their affiliates

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may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations. Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Selling Restrictions

This prospectus does not constitute an offer to sell to, or a solicitation of an offer to buy from, anyone in any country or jurisdiction (i) in which such an offer or solicitation is not authorized; (ii) in which any person making such offer or solicitation is not qualified to do so; or (iii) in which any such offer or solicitation would otherwise be unlawful. No action has been taken that would, or is intended to, permit a public offer of the shares of our common stock or possession or distribution of this prospectus or any other offering or publicity material relating to the shares of our common stock in any country or jurisdiction (other than the United States) where any such action for that purpose is required. Accordingly, each underwriter has undertaken that it will not, directly or indirectly, offer or sell any shares of our common stock or have in its possession, distribute or publish any prospectus, form of application, advertisement or other document or information in any country or jurisdiction except under circumstances that will, to the best of its knowledge and belief, result in compliance with any applicable laws and regulations and all offers and sales of shares of our common stock by it will be made on the same terms.

European Economic Area

In relation to each Member State of the European Economic Area that has implemented the Prospectus Directive (each, a "Relevant Member State"), an offer to the public of any common stock that are the subject of the offering contemplated herein may not be made in that Relevant Member State, except that an offer to the public in that Relevant Member State of any common stock may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:

•: to legal entities that are qualified investors as defined under the Prospectus Directive;
•: by the underwriters to fewer than 100, or, if the Relevant Member State has implemented the relevant provisions of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the representative of the underwriters for any such offer; or
•: in any other circumstances falling within Article 3(2) of the Prospectus Directive,

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provided that no such offer of common stock shall result in a requirement for us, the selling stockholders or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive.

Each person in a Relevant Member State who receives any communication in respect of, or who acquires any common stock under, the offers contemplated here in this prospectus will be deemed to have represented, warranted and agreed to and with each underwriter, the selling stockholders and us that:

•: it is a qualified investor as defined under the Prospectus Directive; and
•: in the case of any common stock acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (i) the common stock acquired by it in this offering have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than qualified investors, as that term is defined in the Prospectus Directive, or in the circumstances in which the prior consent of the representative of the underwriters has been given to the offer or resale or (ii) where common stock have been acquired by it on behalf of persons in any Relevant Member State other than qualified investors, the offer of such common stock to it is not treated under the Prospectus Directive as having been made to such persons.

For the purposes of this representation and the provision above, the expression an "offer of common stock to the public" in relation to any common stock in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any common stock to be offered so as to enable an investor to decide to purchase or subscribe for the common stock, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State, the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in each Relevant Member State and the expression "2010 PD Amending Directive" means Directive 2010/73/EU.

United Kingdom

This prospectus has only been communicated or caused to have been communicated and will only be communicated or caused to be communicated as an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act of 2000 (the "FSMA")) as received in connection with the issue or sale of the common stock in circumstances in which Section 21(1) of the FSMA does not apply to us. All applicable provisions of the FSMA will be complied with in respect to anything done in relation to the common stock in, from or otherwise involving the United Kingdom.

Notice to Residents of Canada

Our common stock may be sold only to purchasers purchasing as principal that are both "accredited investors" as defined in National Instrument 45-106 Prospectus and Registration Exemptions and "permitted clients" as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of our common stock must be made in accordance with an exemption from the prospectus requirements and in compliance with the registration requirements of applicable securities laws.

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LEGAL MATTERS

The validity of our common stock offered by this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. The validity of the shares of common stock offered by this prospectus will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The audited combined financial statements of RSP Permian, L.L.C. and Rising Star Energy Development Co., L.L.C. included in this prospectus and elsewhere in the registration statement, have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accounting firm, upon the authority of said firm as experts in accounting and auditing in giving said report.

The audited statements of revenues and direct operating expenses of the Spanish Trail Assets included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon authority of said firm as experts in accounting and auditing in giving said report.

The audited statements of revenues and direct operating expenses of the Contributed Properties included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing in giving said report.

The audited balance sheet of RSP Permian, Inc. included in this prospectus and elsewhere in the registration statement has been so included in reliance upon the report of Grant Thornton LLP, independent registered public accounting firm, upon the authority of said firm as experts in accounting and auditing in giving said report.

Estimates of our oil and natural gas reserves and related future net cash flows related to our properties as of June 30, 2013 included elsewhere in this prospectus were based upon reserve reports prepared by independent petroleum engineers, Ryder Scott Company, L.P. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC's website is www.sec.gov.

As a result of this offering, we will become subject to full information requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.

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INDEX TO FINANCIAL STATEMENTS

		Page

RSP PERMIAN, INC.
Unaudited Pro Forma Combined Financial Statements
Introduction		F-2
Unaudited pro forma combined balance sheet as of September 30, 2013		F-5
Unaudited pro forma combined statement of operations for the year ended December 31, 2012		F-6
Unaudited pro forma combined statement of operations for the nine months ended September 30, 2013		F-7
Notes to unaudited pro forma combined financial data		F-8
Historical Balance Sheet:
Report of independent registered public accounting firm		F-18
Balance sheet as of September 30, 2013		F-19
Notes to balance sheet		F-20
RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C. (PREDECESSOR)
Unaudited Historical Combined Financial Statements
Unaudited combined balance sheet as of September 30, 2013		F-21
Unaudited combined statements of operations for the nine months ended September 30, 2013 and 2012		F-22
Unaudited combined statements of changes in members' equity for the nine months ended September 30, 2013		F-23
Unaudited combined statements of cash flows for the nine months ended September 30, 2013 and 2012		F-24
Notes to unaudited combined financial statements		F-25
Historical Combined Financial Statements
Report of independent registered public accounting firm		F-43
Combined balance sheets as of December 31, 2012 and 2011		F-44
Combined statements of operations for the years ended December 31, 2012 and 2011		F-45
Combined statement of changes in members' equity for the years ended December 31, 2012 and 2011		F-46
Combined statements of cash flows for the years ended December 31, 2012 and 2011		F-47
Notes to combined financial statements		F-48
Spanish Trail Assets Financial Statements
Report of independent certified public accountants		F-71
Statements of revenues and direct operating expenses for the years ended December 31, 2012 and 2011 and for the six months ended June 30, 2013 and 2012 (unaudited)		F-72
Notes to statements of revenues and direct operating expenses		F-73
The Contributed Properties Financial Statements
Report of independent certified public accountants		F-77
Statements of revenues and direct operating expenses for the years ended December 31, 2012 and 2011 and for the nine months ended September 30, 2013 and 2012 (unaudited)		F-78
Notes to statements of revenues and direct operating expenses		F-79

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RSP PERMIAN, INC.

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Introduction

RSP Permian, Inc. (the "Company") is a newly-formed Delaware corporation formed by RSP Permian, L.L.C. ("RSP") to engage in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. The following unaudited pro forma combined financial statements of the Company reflect the combined historical results of RSP and Rising Star Energy Development Co., L.L.C. ("Rising Star" and, together with RSP, the "Predecessor"), on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on September 30, 2013 for pro forma balance sheet purposes and on January 1, 2012 for pro forma statements of operations purposes:

•: the exclusion by Rising Star of certain assets and liabilities (the "Rising Star Excluded Assets") that are not being conveyed to the Company;
•: the Resolute Disposition;
•: the Spanish Trail Acquisition;
•: the Corporate Reorganization;
•: the Collins and Wallace Contributions;
•: the ACTOIL NPI Repurchase; and
•: the initial public offering of shares of common stock and the use of the net proceeds therefrom as described in "Use of Proceeds" (the "Offering").

The Resolute Disposition. In a transaction that closed in part in December 2012 and in part in March 2013, RSP sold all of its working interests in approximately 2,600 net acres and 81 producing wells in the Permian Basin to a third party (the "Resolute Disposition") for approximately $214 million.

The Spanish Trail Acquisition. On September 10, 2013, RSP acquired certain working interests in oil and natural gas properties located in the Permian Basin from Summit Petroleum, LLC and EGL Resources, Inc. (the "Spanish Trail Acquisition"). The Spanish Trail Acquisition involved the acquisition of additional working interests in oil and natural gas properties located in the Permian Basin, referred to as the Spanish Trail Assets, in which RSP already owned a non-working interest prior to such acquisition.

The Corporate Reorganization. Pursuant to the terms of a corporate reorganization (the "Corporate Reorganization") that will be completed in connection with the Offering, (i) the members of RSP will contribute all of their interests in RSP to RSP Permian Holdco, L.L.C., a to-be-formed entity that will be wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. will contribute all of its interests in RSP to the Company in exchange for shares of the Company's common stock and an assignment of RSP Permian, L.L.C.'s pro rata share of an escrow related to the Resolute Disposition (which escrow is described in Note 3 of the unaudited historical combined financial statements of RSP Permian, L.L.C. and Rising Star). As a result of the Corporate Reorganization, RSP will become a wholly owned subsidiary of the Company.

The Collins and Wallace Contributions. In connection with the Offering, Ted Collins, Jr., Wallace Family Partnership, LP and Collins & Wallace Holdings, LLC will each contribute to the Company certain working interests (collectively, the "Collins and Wallace Contributions") in certain oil and natural gas properties owned by RSP in exchange for shares of the Company's common stock.

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RSP PERMIAN, INC.

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

The ACTOIL NPI Repurchase. ACTOIL, LLC ("ACTOIL") owns a 25% net profits interest ("NPI") on substantially all of the oil and natural gas properties owned by RSP. In connection with the Offering, ACTOIL will contribute 100% of its NPI to the Company in exchange for new shares of the Company's common stock (the "ACTOIL NPI Repurchase").

The Offering. For purposes of the unaudited pro forma combined financial statements, the Offering is defined as the planned issuance and sale to the public of million shares of common stock of the Company as contemplated by this prospectus and the application by the Company of the net proceeds from such issuance as described in "Use of Proceeds." The net proceeds from the sale of the common stock are expected to be $ million (based on an assumed initial public offering price of $ , the midpoint of the range set forth on the cover of this prospectus), net of underwriting discounts and structuring fees of $ million and other offering-related costs of $ million.

The unaudited pro forma combined balance sheet of the Company is based on the unaudited historical combined balance sheet of the Predecessor as of September 30, 2013 and includes pro forma adjustments to give effect to the Spanish Trail Acquisition, the Contributions, the ACTOIL NPI Repurchase and the Offering, as if they had occurred on September 30, 2013.

The unaudited pro forma combined statements of operations of the Company are based on: (i) the unaudited historical combined statements of operations of the Predecessor for the nine months ended September 30, 2013 and the audited historical combined statement of operations of the Predecessor for the year ended December 31, 2012, each period having been adjusted to give effect to the Resolute Disposition, the Spanish Trail Acquisition, the Collins and Wallace Contributions, the ACTOIL NPI Repurchase, and the Offering as if they occurred on January 1, 2012; (ii) the historical statements of revenues and direct operating expenses, as included elsewhere in this prospectus, of certain oil and natural gas properties from the Spanish Trail Acquisition and the Collins and Wallace Contributions; and (iii) the historical accounting records of the Predecessor.

The unaudited pro forma combined financial statements have been prepared on the basis that the Company will be subject to subchapter C of the Internal Revenue Code of 1986, as amended, and as a result, will become taxable as a corporation and subject to U.S. federal and state income taxes at the entity level. The unaudited pro forma combined financial statements should be read in conjunction with the notes thereto and with the audited historical combined financial statements and related notes of the Predecessor, as well as the other historical statements of revenues and direct operating expenses, included elsewhere in this prospectus.

The pro forma data presented reflect events directly attributable to the described transactions and certain assumptions that the Company believes are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated below or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses associated with being a public company. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial statements.

The unaudited pro forma combined financial statements and related notes are presented for illustrative purposes only. If the Offering and other transactions contemplated herein had occurred in

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RSP PERMIAN, INC.

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

the past, the Company's operating results might have been materially different from those presented in the unaudited pro forma financial statements. The unaudited pro forma combined financial statements should not be relied upon as an indication of operating results that the Company would have achieved if the Offering and other transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma financial statements of operations and should not be relied on as an indication of the future results the Company will have after the completion of the Offering and the other transactions contemplated by these unaudited pro forma combined financial statements.

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RSP PERMIAN, INC.

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

SEPTEMBER 30, 2013

				(a)			(b)

	Predecessor Historical			Rising Star Excluded Assets			Formation Related Adjustments	Pro Forma
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,896		$	(2,864	)	$	$
Restricted short-term investment		—
Accounts receivable		22,504			(290	)
Accounts receivable, related party		5,670
Escrow receivable		15,986
Derivative instruments		3

Total current assets		62,059			(3,154	)

PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and natural gas properties, successful efforts method:		556,958			(2,602	)
Accumulated depletion		(80,377	)		1,679

Total property, plant and equipment, net		476,581			(923	)
Other property and equipment, net		4,510			—

Total property, plant and equipment		481,091			(923	)

NONCURRENT ASSETS:
Derivative instruments		832
Restricted cash		150
Other assets		15,821			(3,004	)

Total noncurrent assets		16,803			(3,004	)

TOTAL ASSETS	$	559,953		$	(7,081	)	$	$

LIABILITIES AND MEMBERS'/STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	13,601		$	(17	)	$	$
Accrued expenses		7,954
Interest payable		237
Derivative instruments		636

Total current liabilities		22,428			(17	)
LONG-TERM LIABILITIES:
Asset retirement obligations		2,376			(29	)
Derivative instruments		1,158
Term loan		70,000
Revolving credit facility		58,155			(2,000	)
NPI payable		36,931
Deferred tax liability		—

Total long-term liabilities		168,620			(2,029	)

Total liabilities		191,048			(2,046	)
EQUITY:
Preferred stock		—			—
Common stock
Additional paid-in capital
Members' equity		368,905			(5,055	)
Accumulated deficit
TOTAL MEMBERS'/STOCKHOLDERS' EQUITY:		368,905			(5,055	)

TOTAL LIABILITIES AND MEMBERS'/STOCKHOLDERS' EQUITY	$	559,953		$	(7,081	)	$	$

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

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RSP PERMIAN, INC.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2012

	Predecessor Historical			Rising Star Excluded Assets			Dispositions			Spanish Trail Acquisition				Formation Related Adjustments	Pro Forma

	(In thousands, except per share data)
				(c)			(d)			(e)				(h)
REVENUES
Oil sales	$	91,441		$	(410	)	$	(32,892	)	$	24,115			$	$
Natural gas sales		4,284			(235	)		(1,472	)		662
NGL sales		8,702			(8	)		(3,469	)		2,152

Total revenues	$	104,427		$	(653	)	$	(37,833	)	$	26,929			$	$
OPERATING EXPENSES
Lease operating expenses		15,290			(115	)		(4,322	)		2,828
Production and ad valorem taxes		5,139			(24	)		(1,864	)		1,304
Depreciation, depletion and amortization		48,803			(168	)		(16,481	)		11,115		(f)
Asset retirement obligation accretion		115			(3	)		—			16
General and administrative expenses		2,859			(182	)		—			—

Total operating expenses		72,206			(492	)		(22,667	)		15,263

(Gain) on sale of assets		(6,734	)		—			6,734			—
Operating income (loss)		38,955			(161	)		(21,900	)		11,666

OTHER INCOME (EXPENSE)
Other income		884			(35	)		—			—
Gain (loss) on derivative instruments		(796	)		—			—			—
Interest expense		(3,474	)		92			—			(5,547	)	(g)

Total other income (expense)		(3,386	)		57			—			(5,547	)

INCOME (LOSS) BEFORE TAXES		35,569			(104	)		(21,900	)		6,119
Income tax benefit (expense)		339			—			219			(61	)

NET INCOME (LOSS)	$	35,908		$	(104	)	$	(21,681	)	$	6,058			$	$

Pro forma net income															$

Pro forma income tax expense
Pro forma net income															$	(i)
Net income (loss) per common share
Basic															$
Diluted															$
Weighted average common shares outstanding
Basic															$
Diluted															$

The accompanying notes are an integral part of these unaudited pro forma
combined financial statements.

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RSP PERMIAN, INC.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2013

	Predecessor Historical			Rising Star Excluded Assets			Dispositions			Spanish Trail Acquisition				Formation Related Adjustments	Pro Forma

	(In thousands, except per share data)
				(a)			(d)			(e)				(h)
REVENUES
Oil sales	$	77,504		$	(232	)	$	(5,801	)	$	20,052			$	$
Natural gas sales		3,962			(183	)		(353	)		672
NGL sales		5,197			(61	)		(501	)		1,288

Total revenues	$	86,663		$	(476	)	$	(6,655	)	$	22,012			$	$
OPERATING EXPENSES
Lease operating expenses		10,470			(73	)		(694	)		2,639
Production and ad valorem taxes		5,923			(13	)		(326	)		1,061
Depreciation, depletion and amortization		41,113			(133	)		—			3,159		(f)
Asset retirement obligation accretion		83			(2	)		—			18
General and administrative expenses		2,672			(113	)		—			—

Total operating expenses		60,261			(334	)		(1,020	)		6,877

(Gain) on sale of assets		(22,700	)		—			22,700
Operating income (loss)		49,102			(142	)		(28,335	)		15,135

OTHER INCOME (EXPENSE)
Other income		863			—			—			—
Gain (loss) on derivative instruments		(3,365	)		—			—			—
Interest expense		(1,770	)		(95	)		—			(4,160	)	(g)

Total other income (expense)		(4,272	)		(95	)		—			(4,160	)

INCOME (LOSS) BEFORE TAXES		44,830			(237	)		(28,335	)		10,975
Income tax (expense) benefit		(68	)		—			283			(110	)

NET INCOME (LOSS)	$	44,762		$	(237	)	$	(28,052	)	$	10,865			$	$

Pro forma net income															$
Pro forma income tax expense

Pro forma net income															$	(i)
Net income (loss) per common share
Basic															$
Diluted															$
Weighted average common shares outstanding
Basic															$
Diluted															$

F-7

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

1. Basis of Presentation

The historical financial information is derived from the combined financial statements of RSP Permian, L.L.C. ("RSP") and Rising Star Energy Development Co., L.L.C. ("Rising Star" and, together with RSP, the "Predecessor") included elsewhere in this prospectus. For purposes of the unaudited pro forma combined balance sheet, it is assumed that the transactions had taken place on September 30, 2013. For purposes of the unaudited pro forma combined statements of operations, it is assumed all transactions had taken place on January 1, 2012.

The unaudited pro forma combined financial statements give effect to the following:

•: The retention by Rising Star of certain oil and natural gas interests and other assets, liabilities and operations not sold or contributed to RSP Permian, Inc. (the "Company");
•: The dispositions to a third party, which was consummated in part in December 2012 and part in March 2013, of working interests in certain oil and natural gas properties (the "Resolute Disposition");
•: The acquisition in September 2013 of working interests in certain oil and natural gas properties and related assets (the "Spanish Trail Acquisition") from Summit Petroleum, LLC ("Summit") and EGL Resources, Inc. ("EGL");
•: The contributions by Ted Collins, Jr. ("Collins"), Wallace Family Partnership, LP ("Wallace LP") and Collins & Wallace Holdings, LLC of certain non-operated working interests in oil and natural gas properties owned by RSP (collectively, the "Collins and Wallace Contributions") in exchange for shares of the Company's common stock;
•: The contribution by ACTOIL, LLC ("ACTOIL") of a 25% net profits interest ("NPI") in substantially all of the oil and natural gas properties owned by RSP, in exchange for shares of common stock of the Company in connection with the Offering (the "ACTOIL NPI Repurchase"); and
•: The issuance by the Company of million common shares in the Offering and the use of the net proceeds therefrom as described in "Use of Proceeds."

In connection with the Offering, all of the member interests of the Predecessor will be transferred to a newly-formed Delaware corporation (the Company) in a transaction that is tax free to each transferor of property to the extent stock is received by such transferor in the exchange. Treated as an acquisition of assets for tax purposes, the Company will take a tax basis in each asset equal to the tax basis of the property in the hands of the transferor immediately prior to the exchange, increased by any gain recognized on the exchange by any transferor. This exchange constitutes a change in tax status with respect to the Predecessor assets, requiring the Company to record a $112.4 million charge at closing against income from continuing operations in an amount equal to the tax effect (at 36%, including state tax) of the excess of the carrying value of the Company's assets for financial reporting purposes over their respective tax bases immediately after the exchange. Any difference between the book basis and tax basis of the properties related to the Collins and Wallace Contributions and the ACTOIL NPI Repurchase will be recognized in purchase accounting, and the corresponding effects will be recorded in the financial statements as an increase in the basis of the properties.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

2. Pro Forma Adjustments

We made the following adjustments in the preparation of the unaudited pro forma combined balance sheet:

(a) Adjustments to reflect assets and liabilities that will be retained by Rising Star, and thus will not be contributed to the Company.

(b) Adjustments reflect the total effect of the Collins and Wallace Contributions, the ACTOIL NPI Repurchase, the Offering and Reorganization on the pro forma combined balance sheet, as follows:

	Collins and Wallace Contributions	ACTOIL NPI Repurchase	Corporate Reorganization		Offering		Formation Related Adjustments

	(1)	(2)
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	$	$		$	(4)	$
Escrow Receivable
						(5)

Total current assets
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and natural gas properties, successful efforts method:
NONCURRENT ASSETS
Deferred Tax Assets
Other assets						(5)

TOTAL ASSETS	$	$	$		$		$

LIABILITIES AND MEMBERS'/STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
LONG-TERM LIABILITIES:
Asset retirement obligations
Term loan
Revolving credit facility						(5)
Deferred tax liability				(3)
NPI payable

Total long-term liabilities

Total liabilities
EQUITY
Preferred stock
Common stock
Additional paid-in capital						(4)
Member's capital
Accumulated deficit

TOTAL MEMBERS'/STOCKHOLDERS' EQUITY:						(5)
				(3)		(5)

TOTAL LIABILITIES AND MEMBERS'/STOCKHOLDERS' EQUITY	$	$	$		$		$

(1): Adjustments to reflect the Collins and Wallace Contributions in exchange for shares of common stock of the Company.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

2. Pro Forma Adjustments (Continued)

Collins holds non-operated working interest in substantially all of the oil and natural gas properties owned by RSP (the "Collins Assets"). In addition, Wallace LP holds non-operated working interest in substantially all of the oil and natural gas properties owned by RSP (the "Wallace Assets"). As of the consummation of the Spanish Trail Acquisition, Collins & Wallace Holdings, LLC holds non-operated working interests in substantially all of the Spanish Trail properties (the "C/W Holdings Assets"). The C/W Holdings Assets together with the Collins Assets and the Wallace Assets constitute the "Contributed Assets."

The pro forma adjustment to the Company's oil and natural gas properties reflects the approximate combined % of the Company that will be held by Collins, Wallace LP and Collins & Wallace Holdings, LLC upon completion of the Offering, as follows (in thousands):


Equity value of the Offering (based on an assumed offering price of $ per share of common stock (the midpoint of the price range set forth on the cover of this prospectus))		$
Combined ownership % of Collins, Wallace LP and Collins & Wallace Holdings, LLC

Pro forma adjustment to members'/stockholders' equity		$
Asset retirement obligation/asset

Pro forma adjustment to oil and natural gas properties		$

A $1.00 increase in the assumed initial public offering price of $ per share would result in the following (in thousands):


Equity value of the Offering		$
Combined ownership % of Collins, Wallace LP and Collins & Wallace Holdings, LLC

Pro forma adjustment to stockholders' equity		$
Asset retirement obligation/asset

Pro forma adjustment to oil and natural gas properties

A: $1.00 decrease in the assumed initial public offering price of $ per share would result in the following (in thousands):


Equity value of the Offering		$
Combined ownership % of Collins, Wallace LP and Collins & Wallace Holdings, LLC

Pro forma adjustment to stockholders' equity		$
Asset retirement obligation/asset

Pro forma adjustment to oil and natural gas properties		$

(2): Adjustments to reflect the ACTOIL NPI Repurchase in exchange for common shares of the Company, which is expected to occur in connection with the Offering.

The Predecessor's sale of properties to Resolute in December 2012 and March 2013 resulted in ACTOIL earning cash proceeds through their NPI in the properties sold. ACTOIL chose to have those proceeds applied to their NPI Account cumulative deficit balance, rather than receiving cash. As such, the Predecessor applied the NPI proceeds dollar for dollar to reduce the NPI deficit balance and recorded the amount as a long-term NPI payable on its balance sheet. This amount will be eliminated upon ACTOIL contributing its NPI in exchange for common shares upon completion of the Offering.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

2. Pro Forma Adjustments (Continued)

The pro forma adjustment to the Company's oil and natural gas properties reflects the approximate % of the Company that will be held by ACTOIL upon completion of the Offering, as follows (in thousands):


Equity value of the Offering (based on an assumed offering price of $ per share of common stock (the midpoint of the price range set forth on the cover of this prospectus))		$
Ownership % of ACTOIL

Pro forma adjustment to members'/stockholders' equity		$
Elimination of NPI payable
Asset retirement obligation/asset

Pro forma adjustment to oil and natural gas properties		$

A $1.00 increase in the assumed initial public offering price of $ per share would result in the following (in thousands):


Equity value of the Offering		$
Combined ownership % of ACTOIL

Pro forma adjustment to stockholders' equity		$
Elimination of NPI payable
Asset retirement obligation/asset

Pro forma adjustment to oil and natural gas properties		$

A $1.00 decrease in the assumed initial public offering price of $ per share would result in the following (in thousands):


Equity value of the Offering		$
Combined ownership % of ACTOIL

Pro forma adjustment to stockholders' equity		$
Elimination of NPI payable
Asset retirement obligation/asset

Pro forma adjustment to oil and natural gas properties		$

(3): Adjustments to reflect the estimated change in long-term deferred tax liabilities for temporary differences between the historical cost basis and tax basis of the Company's assets and liabilities as the result of its change in tax status to a subchapter C corporation. A corresponding charge to earnings has not been reflected in the unaudited pro forma combined statements of operations as the charge is considered non-recurring.
(4): Adjustments to reflect the estimated gross proceeds of $ million from the issuance and sale of million shares of common stock at an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this), net of estimated underwriting discounts and commissions of $ million, in the aggregate, and additional estimated expenses related to the Offering of approximately $ million.

The following table provides a reconciliation of the pro forma cash expected to be received upon consummation of the Offering and the net proceeds from the Offering as disclosed throughout this prospectus (in thousands):


Gross proceeds from the Offering		$
Estimated underwriting discounts and commissions
Additional estimated Offering expenses

Pro forma cash received from the Offering		$

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

2. Pro Forma Adjustments (Continued)

(5): Adjustments to reflect using $ million of the $ million in net proceeds from the Offering to repay indebtedness previously incurred in connection with the acquisition of the Spanish Trail Assets by the Predecessor. The unamortized deferred financing costs of $ million related to the Term Loan would be realized as an expense upon paying off those obligations.

For further discussion on the application of the net proceeds from the Offering, please read "Use of Proceeds."

The Company made the following adjustments and assumptions in the preparation of the unaudited pro forma combined statements of operations:

(c) Adjustments to reflect the revenues and expenses of certain oil and natural gas properties that will be retained by Rising Star, and thus, will not be contributed to the Company. The adjustment applied to the historical basis of each account was based on specific identification of assets and related operations that were not contributed.

(d) Adjustments to reflect the reduction in revenues, expenses and other income pertaining to certain oil and natural gas properties sold to Resolute in December 2012 and March 2013. The adjustment applied to the historical basis of each account was based on specific identification of the assets and operations sold to Resolute.

(e) Unless otherwise noted, adjustments represent the historical statements of revenues and direct operating expenses as included elsewhere in this prospectus, relating to the Spanish Trail Assets. The Spanish Trail Acquisition includes assets acquired by RSP, Collins, Wallace LP and Collins & Wallace Holdings, LLC.

(f) Adjustments to reflect additional depreciation, depletion and amortization expense that would have been recorded with respect to the Spanish Trail Assets, had such transaction occurred on January 1, 2012.

(g) Adjustments to reflect the increase in interest expense on borrowings by RSP, with respect to the Spanish Trail Acquisition, of $20.4 million under the Revolving Credit Facility and $70 million under the Term Loan. A ¹/8% change in the interest rate would change pro forma interest expense by $0.03 million for the year ended December 31, 2012 and $0.02 million for the nine months ended September 30, 2013.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

2. Pro Forma Adjustments (Continued)

(h) Adjustments to reflect the total effect of the Collins and Wallace Contributions, ACTOIL NPI Repurchase and the Offering and the Corporate Reorganization on the pro forma combined statements of operations, as follows:

	For the Twelve Months Ended December 31, 2012

	Collins and Wallace Contributions			ACTOIL NPI Repurchase			Formation Related Adjustments
	(1)
	(In thousands)
REVENUES
Oil sales	$	30,377		$			$
Natural gas sales		1,074
NGL sales		3,188

Total revenues		34,639			—
OPERATING EXPENSES
Lease operating expenses		5,139
Production and ad valorem taxes		1,724
Depreciation, depletion and amortization		17,857	(2)		8,995	(2)
Asset retirement obligation accretion		34

Total operating expenses		24,754			8,995

Operating income (loss)		9,885			(8,995	)
OTHER INCOME (EXPENSE)
Interest expense

INCOME (LOSS) BEFORE TAXES		9,885			(8,995	)
Income tax (expense) benefit		(99)	(3)		90	(3)

NET INCOME (LOSS)	$	9,786		$	(8,905	)	$

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

2. Pro Forma Adjustments (Continued)

	For the Nine Months Ended September 30, 2013

	Collins and Wallace Contributions			ACTOIL NPI Repurchase			Formation Related Adjustments
	(1)
	(In thousands)
REVENUES
Oil sales	$	37,159		$			$
Natural gas sales		1,612
NGL sales		2,576

Total revenues		41,347			—
OPERATING EXPENSES
Lease operating expenses		4,504
Production and ad valorem taxes		2,046
Depreciation, depletion, and amortization		19,711	(2)		9,423	(2)
Asset retirement obligation accretion		47

Total operating expenses		26,308			9,423

Operating income		15,039			(9,423	)
OTHER INCOME (EXPENSE)
Interest expense

INCOME (LOSS) BEFORE TAXES		15,039			(9,423	)
Income tax (expense) benefit		(150)	(3)		94	(3)

NET INCOME (LOSS)	$	14,889		$	(9,329	)	$

(1): Unless otherwise noted, adjustments represent the historical statements of revenues and direct operating expenses, as included elsewhere in this prospectus, of certain oil and natural gas properties acquired through the Collins and Wallace Contributions in connection with the Offering. These adjustments do not include the Spanish Trail Assets acquired by RSP, Collins, Wallace LP and Collins & Wallace Holdings, LLC.
(2): Adjustments reflect additional depreciation, depletion and amortization expense that would have been recorded with respect to the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, had such transactions occurred on January 1, 2012.
(3): Adjustments reflect the application of a 1% Texas franchise tax (commonly referred to as the margin tax) on all properties acquired on a pro forma basis.

(i) Reflects the estimated incremental income tax provision associated with the Company's historical results of operations and pro forma adjustments assuming the Company's earnings had been subject to federal income tax as a subchapter C corporation using an effective tax rate of approximately 36%. This rate is inclusive of federal and state income taxes.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

3. Supplemental Disclosure of Oil and Natural Gas Operations

Net Proved Oil and Natural Gas Reserves

The historical pro forma supplemental oil and natural gas disclosure is derived from the combined financial statements of the Predecessor included elsewhere in this prospectus and reserve reports prepared internally by the Predecessor's management and not by independent third party petroleum consultants. The unaudited pro forma combined supplemental oil and natural gas disclosures of the Company reflect the combined historical results of RSP and Rising Star, on a pro forma basis to give effect to the transactions, described above, as if they had occurred on December 31, 2012 for pro forma supplemental oil and natural gas disclosure purposes.

In accordance with SEC regulations, reserves at December 31, 2012 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.

An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, is as follows for the year ended December 31, 2012:

	Year Ended December 31, 2012

	Predecessor Historical			Rising Star Excluded Assets			Resolute Disposition			Spanish Trail Acquisition			Collins and Wallace Contributions			RSP Permian, Inc.
Proved developed and undeveloped reserves:
Beginning of year		48,774			(55	)		(7,603	)		4,400			18,513			64,029
Revisions of previous estimates		(24,608	)		(5	)		1,834			(1,901	)		(14,859	)		(39,539	)
Extensions, discoveries and other additions		10,001			—			(2,420	)		4,418			8,856			20,855
Divestiture of minerals in place		—			—			—			—			—			—
Production		(1,567	)		15			586			(383	)		(513	)		(1,862	)

End of year		32,600			(45	)		(7,603	)		6,534			11,997			43,483

Proved developed reserves:
Beginning of year		10,854			(55	)		(4,522	)		2,562			3,554			12,393
End of year		12,427			(45	)		(4,532	)		2,854			3,754			14,459
Proved undeveloped reserves:
Beginning of year		37,920			—			(3,081	)		1,838			14,959			51,636
End of year		20,173			—			(3,072	)		3,680			8,243			29,024

The table above includes changes in estimated quantities of oil and natural gas reserves shown in MBbl equivalents ("MBoe") at a rate of six MMcf per one MBbl.

For the year ended December 31, 2012, RSP Permian, Inc.'s pro forma negative revision of 39,539 MBoe of previous estimated quantities is primarily due to a change in development strategy to replace 20-acre proved vertical well locations with non-proved horizontal well locations. In addition, in 2012, RSP Permian, Inc. switched to the recognition of three stream instead of two stream sales volumes, which resulted in a negative revision of natural gas reserves and a positive revision of NGL reserves. Extensions, discoveries and other additions of 20,855 MBoe during the year ended December 31, 2012,

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

3. Supplemental Disclosure of Oil and Natural Gas Operations (Continued)

result primarily from the drilling of new wells during the year and from new unproved undeveloped locations added during the year.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2012 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2012:

	Predecessor Historical			Rising Star Excluded Assets			Resolute Disposition			Spanish Trail Acquisition			Collins and Wallace Contributions			RSP Permian, Inc.

	(In thousands)
Future cash inflows	$	2,210,325		$	(3,379	)	$	(544,086	)	$	436,690		$	802,351		$	2,901,901
Future production costs		(655,720	)		1,611			146,463			(128,166	)		(242,365	)		(878,177	)
Future development costs		(362,876	)		82			61,996			(67,253	)		(149,173	)		(517,224	)
Future income tax expenses		(389,312	)		607			39,299			(54,298	)		(147,893	)		(551,597	)

Future net cash flows		802,417			(1,079	)		(296,328	)		186,973			262,920			954,903
10% discount for estimated timing of cash flows		(503,906	)		378			408,013			(113,700	)		(172,771	)		(605,356	)

Standardized measure of discounted future net cash flows	$	298,511		$	(701	)	$	(111,685	)	$	73,273		$	90,149		$	349,547

It is not intended that the Financial Accounting Standards Board's ("FASB") standardized measure of discounted future net cash flows represent the fair market value of the Predecessor's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS (Continued)

3. Supplemental Disclosure of Oil and Natural Gas Operations (Continued)

Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	Predecessor Historical			Rising Star Excluded Assets			Resolute Disposition			Spanish Trail Acquisition			Collins and Wallace Contributions			RSP Permian, Inc.

	(In thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	854,424		$	(1,780	)	$	(151,440	)	$	92,430		$	308,564		$	1,102,198
Changes in the year resulting from:
Sales, less production costs		(84,647	)		514			470			(22,798	)		(27,776	)		(134,237	)
Revisions of previous quantity estimates		(438,394	)		(162	)		32,129			(39,936	)		(247,662	)		(694,025	)
Extensions, discoveries and other additions		84,149			—			(37,245	)		48,685			109,311			204,900
Net change in prices and production costs		(133,485	)		527			(15,437	)		(15,361	)		(25,381	)		(189,137	)
Changes in estimated future development costs		38,096			38			61,335			3,575			2,306			105,350
Previously estimated development costs incurred during the period		108,367			—			(44,392	)		2,595			13,809			80,379
Accretion of discount		85,442			(178	)		—			9,243			30,856			125,363
Net change in income taxes		(389,312	)		607			39,299			(54,298	)		(147,893	)		(551,597	)
Timing differences and other		173,871			(267	)		3,596			49,138			74,015			300,353

Standardized measure of discounted future net cash flows, end of year	$	298,511		$	(701	)	$	(111,685	)	$	73,273		$	90,149		$	349,547

Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholder
RSP Permian, Inc.

We have audited the accompanying balance sheet of RSP Permian, Inc. (a Delaware corporation) (the "Company") as of September 30, 2013. This financial statement is the responsibility of the Company's management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of RSP Permian, Inc. as of September 30, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Dallas, Texas

October 7, 2013

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RSP PERMIAN, INC.

BALANCE SHEET

	September 30, 2013

Assets
Receivable from stockholder	$	10

Total assets	$	10

Stockholders' equity
Common stock, $0.01 par value; authorized 1,000,000 shares; 1,000 issued and outstanding	$	10

Total stockholders' equity	$	10

See the accompanying notes to the balance sheet.

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RSP PERMIAN, INC.

NOTES TO BALANCE SHEET

1. Nature of Operations

RSP Permian, Inc. (the "Company") was formed on September 30, 2013, pursuant to the laws of the State of Delaware to become a holding company for RSP Permian, L.L.C.

2. Summary of Significant Accounting Policies

Basis of Presentation

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). Separate statements of operations, statements of changes in stockholder's equity and statements of cash flows have not been presented because the Company has had no business transactions or activities to date.

3. Subsequent Events

We are not aware of any events that have occurred subsequent to September 30, 2013 that would require recognition or disclosure in this financial statement.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

COMBINED BALANCE SHEETS

(Unaudited)

	September 30, 2013			December 31, 2012

	(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	17,896		$	51,232
Restricted short-term investment		—			1,031
Accounts receivable		22,504			21,614
Accounts receivable, related party		5,670			4,232
Escrow receivable		15,986			3,135
Derivative instruments		3			1,112

Total current assets		62,059			82,356
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and natural gas properties, successful efforts method		556,958			476,816
Accumulated depletion		(80,377	)		(60,489	)

Total property, plant and equipment, net		476,581			416,327
Other property and equipment, net		4,510			5,085

Total property, plant and equipment		481,091			421,412
NONCURRENT ASSETS
Derivative instruments		832			2,325
Restricted cash		150			150
Other assets		15,821			6,995

Total noncurrent assets		16,803			9,470

TOTAL ASSETS	$	559,953		$	513,238

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	13,601		$	23,437
Accrued expenses		7,954			3,249
Interest payable		237			252
Derivative instruments		636			1,227

Total current liabilities		22,428			28,165
LONG-TERM LIABILITIES
Asset retirement obligations		2,376			2,716
Derivative instruments		1,158			345
Term loan		70,000			—
Revolving credit facility		58,155			111,586
NPI payable		36,931			16,583

Total long-term liabilities		168,620			131,230

Total liabilities		191,048			159,395
MEMBERS' EQUITY		368,905			353,843

TOTAL LIABILITIES AND MEMBERS' EQUITY	$	559,953		$	513,238

The accompanying notes are an integral part of these combined financial statements.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

COMBINED STATEMENTS OF OPERATIONS

(Unaudited)

	Nine Months Ended September 30,

	2013			2012
	(In thousands, except per share data)
REVENUES
Oil sales	$	77,504		$	69,539
Natural gas sales		3,962			2,441
NGL sales		5,197			5,649

Total revenues		86,663			77,629
OPERATING EXPENSES
Lease operating expenses	$	10,470		$	9,253
Production and ad valorem taxes		5,923			5,294
Depreciation, depletion and amortization		41,113			21,458
Asset retirement obligation accretion		83			54
General and administrative expenses		2,672			1,743

Total operating expenses		60,261			37,802

(Gain) on sale of assets		(22,700	)		(27	)

OPERATING INCOME	$	49,102		$	39,854

OTHER INCOME (EXPENSE)
Other income	$	863		$	651
Gain (loss) on derivative instruments		(3,365	)		137
Interest expense		(1,770	)		(2,403	)

Total other (expense) income		(4,272	)		(1,615	)

INCOME BEFORE TAXES		44,830			38,239
INCOME TAX (EXPENSE) BENEFIT		(68	)		364

NET INCOME	$	44,762		$	38,603

PRO FORMA INFORMATION (UNAUDITED):
Net income	$	44,762
Pro forma provision for income taxes		(16,114	)

Pro forma net income	$	28,648

Pro forma income per common share
Basic	$
Diluted	$
Weighted average pro forma shares outstanding
Basic	$
Diluted	$

The accompanying notes are an integral part of these combined financial statements.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

COMBINED STATEMENT OF CHANGES IN MEMBERS' EQUITY

(Unaudited)

	RSP			Rising Star		Total Members' Equity

	(In thousands)
BALANCE AT DECEMBER 31, 2012	$	334,965		$	18,878	$	353,843
Distribution		(30,000	)		—		(30,000	)
Contribution		300			—		300
Net income		42,955			1,807		44,762

BALANCE AT SEPTEMBER 30, 2013	$	348,220		$	20,685	$	368,905

The accompanying notes are an integral part of these combined financial statements.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

COMBINED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,

	2013			2012
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	44,762		$	38,603
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and depreciation		39,540			21,133
Abandoned equipment and intangibles		45			—
Accretion of asset retirement obligations		83			54
Amortization of loan fees		1,579			325
Equity in earnings of investment		(13	)		18
(Gain) on sale of assets		(22,700	)		(27	)
(Gain) loss on derivative instruments		3,365			(137	)
Net cash (payments) on settled derivatives		(542	)		(495	)
Changes in operating assets and liabilities:
Accounts receivable and accounts receivable from related parties		(11,994	)		(7,272	)
Other assets		(10,389	)		(877	)
Interest payable		(15	)		303
Accounts payable		(9,825	)		(10,602	)
Accrued expenses		4,706			2,852

Net cash provided by operating activities	$	38,602		$	43,878

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of assets	$	115,339		$	27
Increase in equity investment		—			(1,038	)
Purchase of other property and equipment		57			(1,060	)
Purchase of oil and natural gas properties		(195,583	)		(121,929	)

Net cash provided by (used in) investing activities	$	(80,187	)	$	(124,000	)

CASH FLOWS FROM FINANCING ACTIVITIES
Capital contributions	$	300		$	—
Distributions		(30,000	)		—
Borrowings under long-term debt		101,569			80,000
Restricted short-term investment		1,031			—
Payments on long-term debt		(85,000	)		—
NPI payable		20,349			—

Net cash provided by financing activities	$	8,249		$	80,000

NET CHANGE IN CASH	$	(33,336	)	$	(122	)

CASH AT BEGINNING OF PERIOD	$	51,232		$	10,066

CASH AT END OF PERIOD	$	17,896		$	9,944

SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	$	1,677		$	2,100

The accompanying notes are an integral part of these combined financial statements.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

RSP Permian, L.L.C., a Delaware limited liability company ("RSP"), was formed on October 18, 2010 by its management team and an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds ("NGP"). RSP is engaged in the acquisition, development and operation of oil and natural gas properties. On December 15, 2010, primary operations commenced through a significant acquisition of oil and natural gas leases and corresponding interests on acreage located in the Permian Basin in and around Midland, Texas. Over 90% of RSP's outstanding equity is indirectly owned by Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P. (collectively, "NGP IX").

Rising Star Energy Development Co., L.L.C., a Texas limited liability company ("Rising Star"), was formed on April 30, 2006 and is engaged primarily in the acquisition, development and operation of oil and natural gas properties. Rising Star is wholly owned by Rising Star Energy Holdings Company, L.P. ("Rising Star LP"), which is managed by its general partner, Rising Star Energy GP, L.L.C. ("Rising Star GP"). Natural Gas Partners VIII, L.P. ("NGP VIII") owns over 90% of the membership interests in Rising Star GP and over 80% of the limited partnership interests in Rising Star LP. Rising Star LP's sole material assets are its interests in Rising Star and its interests in Rising Star Energy Operating Co., L.L.C., which has not conducted any operations for the past several years.

All power and authority to control the core functions of RSP and Rising Star (collectively, the "Predecessor") are controlled by NGP VIII and NGP IX, respectively. Through the delegation of authority of the general partners of NGP VIII and NGP IX to NGP Energy Capital Management, L.L.C. ("NGP ECM"), all power and authority of the respective fund limited partnership in effectuating its core investment, management and divestment function is controlled by NGP ECM. The results of RSP and Rising Star have been combined for all periods presented.

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP").

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Predecessor's combined financial statements requires the Predecessor's management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively. Significant assumptions are required in the valuation of proved oil and natural gas reserves which may affect the amount at which oil and natural gas properties are recorded. Estimation of asset retirement obligations ("AROs"), valuation of derivative instruments and the fair value of incentive unit compensation also require significant assumptions. It is possible these estimates could be revised at future dates and these revisions could be material. Depletion of oil and natural gas properties are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price estimates.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Cash and Cash Equivalents

The Predecessor considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents.

Derivative and Other Financial Instruments

The Predecessor uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil. In addition, the Predecessor enters into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates. These transactions are in the form of collars, swaps and puts.

The Predecessor reports the fair value of derivatives on the combined balance sheets in derivative instrument assets and derivative instrument liabilities as either current or noncurrent. The Predecessor determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The Predecessor reports these amounts on a gross basis by contract.

The Predecessor's derivatives instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the combined statement of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.

Accounts Receivable

Accounts receivable, which are primarily from the sale of oil, natural gas and natural gas liquids ("NGLs"), are accrued based on estimates of the sales and prices the Predecessor believes it will receive. The Predecessor routinely reviews outstanding balances, assesses the financial strength of its customers, and records a reserve for amounts not expected to be fully recovered. The Predecessor has not provided an allowance for doubtful accounts based on management's expectations that all receivables will be fully collected. The need for an allowance is determined based upon reviews of individual accounts, historical losses, existing economic conditions and other pertinent factors. No bad debt expense was recorded for the nine months ended September 30, 2013 or the nine months ended September 30, 2012.

Transactions with Related Parties

Wallace Family Partnership, LP ("Wallace LP") has a non-operating working interest in approximately 20% of the oil and natural gas assets the Predecessor operates. Leslyn Wallace is a limited partner of Wallace LP and an employee of RSP. The carrying amount of the receivable from Wallace LP as of September 30, 2013 and December 31, 2012 was approximately $5.7 million and $4.0 million, respectively. The Predecessor does not consider the accounts receivable from Wallace LP to be uncollectible.

Oil and Natural Gas Properties

The Predecessor uses the successful efforts method of accounting for its oil and natural gas exploration and production activities. Costs incurred by the Predecessor related to the acquisition of oil and natural gas properties and the cost of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when determined to be unsuccessful.

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Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The Predecessor capitalizes interest on expenditures while activities are in progress to bring the assets to their intended use for significant exploration and development projects that last more than six months. The Predecessor did not capitalize any interest in 2013 and 2012 as no projects lasted more than six months. Costs incurred to maintain wells and related equipment, lease and well operating costs and other exploration costs are charged to expense as incurred. Gains and losses arising from sales of properties are generally included in other income and expenses. Unproved properties are assessed periodically for possible impairment.

Capitalized acquisition costs attributable to proved oil and natural gas properties are depleted on a field basis based on proved reserves using the unit-of-production method. Capitalized exploration well costs and development costs, including AROs, are depleted on a field basis, based on proved developed reserves. Depletion expense for oil and natural gas producing property was $39.1 million and $20.8 million for the nine months ended September 30, 2013 and 2012, respectively, and is included in depreciation, depletion and amortization in the accompanying combined statements of operations. The Predecessor's oil and natural gas properties as of September 30, 2013 and December 31, 2012 consisted of the following:

	September 30, 2013			December 31, 2012

	(In thousands)
Proved oil and natural gas properties	$	531,201		$	447,369
Unproved oil and natural gas properties		25,757			29,447
Less: accumulated depletion		(80,377	)		(60,489	)

	$	476,581		$	416,327

In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of September 30, 2013 and December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

Capitalized costs are evaluated for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. To determine if a depletable unit (field) is impaired, the Predecessor compares the carrying value of the depletable unit to the undiscounted future net cash flows by applying estimates of future oil and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon reservoir engineers' estimates of proved reserves.

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Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

determination of the depletable units' estimated reserves, future net cash flows and fair value. No impairment of proved property was recorded for the nine months ended September 30, 2013 and 2012.

Natural gas volumes are converted to barrels of oil equivalent ("Boe") at the rate of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas.

Other Property and Equipment

Other capital assets include service wells, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition, and are depreciated using straight-line methods based on expected lives of the individual assets or group of assets ranging from 5 to 39 years. Depreciation expense related to such assets for the nine months ended September 30, 2013 and 2012 was $0.4 million and $0.3 million, respectively, and is included in depreciation, depletion and amortization in the combined statement of operations.

Restricted Cash

Restricted cash as of September 30, 2013 and December 31, 2012 consisted of a certificate of deposit that matures in 2014.

Deferred Loan Costs

Deferred loan costs are stated at cost, net of amortization, which is computed using the straight-line method over the life of the loan which is reflective of the effective interest rate method. Deferred loan costs of $1.3 million and $1.5 million as of September 30, 2013 and December 31, 2012, respectively, net of accumulated amortization, are included in other assets in the accompanying combined balance sheets. Amortization expense of $1.6 million and $0.3 million was recorded for the nine months ended September 30, 2013 and 2012, respectively, and is included in depreciation, depletion and amortization in the combined statement of operations.

Asset Retirement Obligation

The Predecessor records AROs related to the retirement of long lived assets at the time a legal obligation is incurred and the liability can be reasonably estimated. AROs are recorded as long-term liabilities with a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

The Predecessor estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future down-hole plugging, dismantlement and removal of production equipment and facilities and the restoration and reclamation of a field's surface to a condition similar to that existing before oil and natural gas extraction began.

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Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.

After recording these amounts, the ARO is accreted to its future estimated value using the same assumed credit adjusted rate and the associated capitalized costs are depreciated on a unit-of-production basis.

The ARO consisted of the following for the periods indicated:

	Nine Months Ended September 30, 2013			Year Ended December 31, 2012

	(In thousands)
Asset retirement obligation at beginning of period	$	2,716		$	1,114
Liabilities acquired		—			—
Liabilities incurred		474			1,474
Liabilities settled		(897	)		—
Revision of estimate		—			13
Accretion expense		83			115

Asset retirement obligation at end of period	$	2,376		$	2,716

Revenue Recognition

Oil, natural gas and NGL revenue is recognized when the product is sold to a purchaser, delivery has occurred, evidence of an arrangement exists, pricing is fixed and determinable and collectability of the revenue is reasonably assured. Oil and natural gas imbalances result when sales differ from the seller's net revenue interest in the particular property's reserves. An imbalance receivable or liability is recognized only to the extent that the Predecessor has an imbalance on a specific property greater than the expected remaining proved reserves. As of September 30, 2013 and December 31, 2012, the Predecessor had no significant asset or liability recorded for oil and natural gas imbalances.

Income Taxes

RSP and Rising Star are organized as Delaware limited liability companies and are treated as flow-through entities for federal income tax purposes. As a result, the net taxable income of the Predecessor and any related tax credits are passed through to the members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, no federal tax provision has been recorded in the financial statements of the Predecessor.

However, the Predecessor's operations are located in Texas and are subject to an entity-level tax, the Texas franchise tax, at a statutory rate of up to 1% of income that is apportioned to Texas.

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Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

threshold. The Predecessor's policy is to reflect interest and penalties related to uncertain tax positions as part of its income tax expense, when and if they become applicable.

Unaudited Pro Forma Income Taxes

These financial statements have been prepared in anticipation of a proposed initial public offering (the "Offering") of the common stock of its parent entity. In connection with the Offering, all interests in RSP will be contributed to a newly formed Delaware corporation, which will be treated as a taxable C corporation and thus will be subject to federal and state income taxes. Accordingly, a pro forma income tax provision has been disclosed as if the Predecessor was a taxable corporation for all periods presented. The Predecessor has computed pro forma tax expense using a 36% blended corporate level federal and state tax rate. The effective tax rate includes a corporate level state income tax rate with consideration to apportioned income for each state of operation. If the Predecessor had affected the change in tax status on September 30, 2013, the Predecessor would have recognized a deferred tax liability of approximately $112.4 million related to the tax basis of its long-lived assets being less than its book basis in those assets.

Segment Reporting

The Predecessor operates in only one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

Concentrations of Credit Risk

Cash equivalents

The Predecessor's cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts receivable

The following table summarizes concentration of receivables, net of allowances, by product or service as of the following dates:

	September 30, 2013		December 31, 2012

	(In thousands)
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	8,500	$	9,673
Joint interest owners		13,788		11,935
Other		216		6

Total	$	22,504	$	21,614

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the Permian Basin. As a general policy, collateral is not required for receivables, but customers' financial condition and credit worthiness are evaluated regularly.

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Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Derivative assets and liabilities

The Predecessor has a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors.

During 2013, the Predecessor did not incur any significant losses due to counterparty bankruptcy filings. The Predecessor assesses its credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. The Predecessor offsets its credit exposure to each counterparty with amounts the Predecessor owes the counterparty under derivative contracts.

New Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-04, "Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs." ASU 2011-04 amended ASC 820 to converge the fair value measurement guidance in U.S. GAAP and International Financial Reporting Standards. Certain of the amendments clarified the application of existing fair value measurement requirements, while other amendments changed a particular principle in ASC 820. In addition, ASU 2011-04 required additional fair value disclosures. The amendments were effective for annual periods beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on the Predecessor's financial position, results of operations or liquidity.

In December 2011, the FASB issued ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities," and in January 2013 issued ASU 2013-01, "Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities." These ASUs create new disclosure requirements regarding the nature of an entity's rights of setoff and related arrangements associated with its derivative instruments, repurchase agreements and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements would be required, irrespective of whether the entity has elected to offset those instruments in the statement of financial position. These ASUs are effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs will not impact the Predecessor's financial position, results of operations or liquidity.

NOTE 3—SALE OF OIL AND NATURAL GAS PROPERTY INTERESTS

Effective October 1, 2012, RSP, ACTOIL, LLC ("ACTOIL"), and other minority non-operating working interest owners entered into a Purchase, Sale, and Option Agreement ("PSA") to sell an undivided 32.35% interest in certain assets for an aggregate purchase price of $110.0 million to Resolute Natural Resources Southwest LLC ("Resolute"). The Predecessor's share of the purchase price was $69.0 million and was recorded as a reduction to the basis of the underlying oil and natural gas properties. To the extent that the proceeds received exceeded the cost basis of the oil and natural gas properties, the Predecessor recorded a gain on the sale. In addition, RSP sold Resolute an option (the "Option") for $5.0 million, $2.4 million of which is the Predecessor's share. The Option allows Resolute the option to acquire the remaining 67.65% interest in these certain assets. The Option is non-refundable and only entitles Resolute to a limited time period during which they can exercise a right to acquire the remaining interest in these certain assets, and therefore the Option fee was

F-31

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 3—SALE OF OIL AND NATURAL GAS PROPERTY INTERESTS (Continued)

included in the consideration transferred in computing the gain on disposition of the assets described above. The Predecessor recorded a gain in connection with the sale of the 32.35% interest in these assets and option fee in the amount of $6.7 million.

The PSA contained customary closing conditions and a $5.0 million title and environmental escrow and an $11.0 million indemnity escrow which were held back from the initial purchase price to provide for these contingencies. Amounts held in escrow for potential indemnity matters have not been considered in the computation of the gain in connection with the sale of these certain assets because the Predecessor cannot reasonably estimate the potential outcome of any such matters as of September 30, 2013. RSP's share of the indemnity escrow was $16.0 million.

In March 2013, Resolute exercised the right to acquire the 67.65% remaining interest in these assets from RSP, ACTOIL and other working interest owners for an additional purchase price of approximately $230.0 million. RSP's share of the purchase price was $144.2 million. There was an additional $23.0 million indemnity escrow that was withheld from the purchase price and excluded from the computation of gain on disposition of the assets. RSP's share of the indemnity escrow was $10.8 million.

Spanish Trail Acquisition

On September 10, 2013, RSP acquired additional working interests in certain of its 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 RSP in connection with the Offering, the Spanish Trail Acquisition increased RSP's working interests in approximately 5,400 gross acres and 70 gross producing wells (the "Spanish Trail Assets").

The aggregate purchase price for the Spanish Trail Assets agreed to by RSP 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 and Wallace Holdings, LLC, and will contribute these acquired assets, along with other non-operated working interests in substantially all of RSP's assets, for shares of RSP Permian, Inc.'s common stock. The exercise of the preferential purchase rights reduced RSP's purchase price from $155 million to $121 million. RSP allocated the net

F-32

Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 3—SALE OF OIL AND NATURAL GAS PROPERTY INTERESTS (Continued)

purchase price to the oil and natural gas properties acquired and asset retirement obligation assumed as follows:

(In thousands)



Net purchase price	$	120,521
NPI sale to ACTOIL	$	(30,131	)

Oil and natural gas properties acquired	$	90,390
Asset retirement obligation assumed	$	469

Oil and natural gas properties	$	90,859

The Spanish Trail Acquisition was funded with a $70 million term loan, borrowings under RSP's revolving credit facility (described below in Note 5) and the issuance of an NPI (described below in Note 6).

NOTE 4—DERIVATIVE INSTRUMENTS

Crude Oil Derivative Instruments

The Predecessor uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its crude oil production. These include over-the-counter (OTC) swaps, put options and collars with the underlying contract and settlement pricings based on NYMEX West Texas Intermediate (WTI). The derivative instruments are recorded at fair value on the balance sheet and any gains and losses are recognized in current period earnings.

Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Predecessor pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Predecessor an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Predecessor receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Predecessor pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.

F-33

Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

The following table summarizes open positions as of September 30, 2013, and represents, as of such date, derivatives in place through December 31, 2015, on annual production volumes:

	Year 2013		Year 2014		Year 2015

Swaps:
Notional volume (Bbl)		60,000		240,000		120,000
Weighted average price ($/Bbl)	$	94.50	$	94.50	$	92.60
Puts:
Notional volume (Bbl)		135,000		—		—
Weighted average price ($/Bbl)	$	75.00	$	—	$	—
Collars:
Notional volume (Bbl)		125,000		693,000		372,000
Weighted average floor price ($/Bbl)	$	83.45	$	86.13	$	84.03
Weighted average ceiling price ($/Bbl)	$	105.04	$	103.59	$	94.66

Interest Rate Derivative Instruments

The Predecessor's use of variable rate debt directly exposes it to interest rate risk. The Predecessor's policy is to manage interest rate risk through the use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposure when appropriate. These derivatives are used for cash flow purposes and are not for speculative purposes. These derivatives involve the exchange of amounts based on variable interest rates and amounts based on a fixed interest rate over the life of the agreement without an exchange of the notional amount upon which payments are based. The interest rate differential to be received or paid on the swaps is recognized over the lives of the swaps as an adjustment to interest expense.

In December 2010, as part of the credit agreement more fully described in Note 5, the Predecessor entered into two interest rate swap agreements with effective dates of March 2011 and expiration dates of December 2013, to fix the interest rate of a portion of the floating variable interest. The total notional amount of the two instruments is $65 million. As of September 30, 2013, the weighted average effective fixed interest rate on the Predecessor's interest rate swaps was approximately 1.46%.

Fair Values and Gains (Losses)

The following table presents the fair value of derivative instruments. The Predecessor's derivatives are presented as separate line items in its combined balance sheets as current and noncurrent derivative instrument assets and liabilities. Derivative instruments are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivative instruments classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect

F-34

Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

the netting of asset and liability positions permitted under the terms of the Predecessor's master netting arrangements.

	Assets				Liabilities

	September 30, 2013		December 31, 2012		September 30, 2013			December 31, 2012
	(In thousands)
Derivative Instruments:
Current amounts
Crude oil contracts	$	3	$	1,112	$	(427	)	$	(417	)
Interest rate contracts		—		—		(209	)		(810	)
Noncurrent amounts
Crude oil contracts		832		2,325		(1,158	)		(345	)
Interest rate contracts		—		—		—			—

Total derivative instruments	$	835	$	3,437	$	(1,794	)	$	(1,572	)

Gains and losses on derivatives are reported in the combined statements of operations.

The following represents the Predecessor's reported gains and losses on derivative instruments for the periods presented:

	For the nine months ended September 30,

	2013			2012
	(In thousands)
Gain (loss) on derivative instruments:
Crude oil derivative instruments		(3,342	)		519
Interest rate derivative instruments		(23	)		(382	)

Total	$	(3,365	)	$	137

F-35

Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

Offsetting of derivative assets and liabilities

The following table presents the Predecessor's gross and net derivative assets and liabilities.

	Gross Amount Presented on Balance Sheet			Netting Adjustments(a)			Net Amount

	(In thousands)
September 30, 2013
Derivative assets with right of offset or master netting agreements	$	835		$	(352	)	$	483
Derivative liabilities with right of offset or master netting agreements	$	(1,794	)	$	352			(1,442	)
December 31, 2012
Derivative assets with right of offset or master netting agreements	$	3,437		$	(1,373	)	$	2,064
Derivative liabilities with right of offset or master netting agreements	$	(1,572	)	$	1,373		$	(199	)

(a): With all of the Predecessor's financial trading counterparties, the Predecessor has agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

Credit Risk related Contingent Features in Derivatives

None of the Company's derivative instruments contains credit-risk related contingent features. No amounts of collateral were posted by the Predecessor related to net liability positions as of September 30, 2013.

NOTE 5—CREDIT AGREEMENT

In December 2010, RSP entered into a credit agreement (the "Agreement") with two participating banks (the "Lenders") for the acquisition of producing and nonproducing oil and natural gas interests in the Permian Basin. The Agreement consists of a revolving credit facility (the "Revolving Credit Facility") and a term loan (the "Term Loan") (collectively, the "Commitments").

RSP's obligations under the Commitments are secured by the first lien on all of RSP's oil and natural gas properties. In 2011, the Agreement was syndicated and the Lenders increased to six participating banks.

As a condition to the Commitments, RSP was required to enter into certain derivative instruments for crude oil to hedge not less than fifty percent of the anticipated projected production from proved, developed, producing oil and natural gas properties. In addition, RSP entered into interest rate swap agreements with the Lenders. Derivative instruments are more fully described at Note 4.

F-36

Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 5—CREDIT AGREEMENT (Continued)

The Agreement contains various restrictive covenants and compliance requirements which include:

•: maintenance of certain financial ratios, including: (i) commencing March 31, 2011 maintenance of a working capital ratio; (ii) commencing June 30, 2011 maintenance of a leverage ratio; and (iii) commencing June 30, 2011 maintenance of a minimum interest coverage ratio;
•: restrictions on selling, assigning farm-out and conveying oil and natural gas interests;
•: limits on the incurrence of additional indebtedness and certain types of liens; and
•: restrictions on the payment of cash dividends, except as described in the Agreement.

At September 30, 2013, RSP was in compliance with all of the covenants under the Agreement.

On June 1, 2011, an amendment to the credit agreement was entered into by the parties which revised the maturity date of letters of credit available to be issued per the credit agreement.

Revolving Credit Facility

As of September 30, 2013 and December 31, 2012, the Revolving Credit Facility had an outstanding balance of approximately $58.2 million and $111.6 million with a maturity date of December 15, 2015. RSP's borrowing base was $125 million, with scheduled semi-annually redeterminations commencing June 1, 2013 and December 1, 2013. RSP may elect borrowings under the Revolving Credit Facility to be either a) Eurodollar Revolving Credit Loans ("Eurodollar") or b) ABR Revolving Credit loans ("ABR").

Borrowings elected as Eurodollar bear interest based on a 1, 2 or 3-month LIBOR Rate (Libor) plus an applicable margin ranging from 1.50% to 2.25%, based upon the percentage of borrowing base utilized, plus a facility fee of 0.50% charged on the borrowing base amount. Borrowings elected as ABR bear interest at the Prime Rate (3.25% as of December 31, 2012) plus 0.50% to 1.25%, based upon the percentage of borrowing base utilized, plus a facility fee of 0.50% charged on the borrowing base amount.

RSP also has available a Swing Line Loan ("Swing Line") with the Administrative Agent of the Agreement, whereby the Predecessor may borrow up to $5 million. The Swing Line is a sub-line under the Revolving Credit Facility and the Administrative Agent may require the Lenders to fund borrowings under the Revolving Credit Facility to fund outstanding balances of the Swing Line. The Swing Line bears interest at the ABR rate and matures on December 15, 2015. The Predecessor has not borrowed any funds under the Swing Line as of September 30, 2013.

Amended and Restated Credit Agreement

As of September 10, 2013, RSP amended and restated its credit agreement, dated December 15, 2010, which includes a revolving credit facility and a term loan as described above. The borrowing base under RSP's amended and restated credit agreement is $140 million as of September 30, 2013, with lender commitments of $500 million. The maturity date of the revolving credit facility is September 10, 2017 while the term loan matures on April 1, 2016. As of September 30, 2013, the revolving credit facility has a margin of 1.25% to 2.00% plus LIBOR, plus a facility fee of 0.50% charged on the borrowing base amount, while the term loan has a margin of 5.5% plus LIBOR (floor of 1%), or 6.5%.

F-37

Table of Contents

RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 6—NET PROFITS INTEREST

In July 2011, RSP entered into a $175.0 million financing agreement to convey a 25% net profits interest ("NPI") to ACTOIL. The NPI conveys 25% of the oil and natural gas sales less associated direct capital expenditures and lease operating expenses from substantially all the oil and natural gas properties held by RSP effective January 1, 2011. RSP maintains a separate net profits account ("NPI Account") maintained on a cash basis, as defined in the agreement governing the NPI.

The calculation to determine if amounts are to be distributed to ACTOIL for its interest is determined on a quarterly basis by RSP. ACTOIL does not fund its proportionate share of direct capital expenditures or lease operating expenses as the expenses are funded by the Predecessor and reimbursed through the NPI calculation. When the cumulative oil and natural gas sales, net of associated direct capital expenditures and lease operating expenses attributable to the NPI is a negative number, then the distribution is zero for such calendar quarter and such cumulative negative amount is carried forward. When the cumulative NPI calculation becomes a positive number at the end of a calendar quarter, a distribution will be made to ACTOIL for its share of net profits. If the NPI Account has a deficit balance at the end of a calendar quarter, ACTOIL incurs interest charged by RSP on the cumulative deficit balance at varying annual rates depending on the amount of the deficit balance. This interest is added to the cumulative deficit balance.

As of September 30, 2013, the NPI Account had a cumulative deficit balance of approximately $7.7 million. The deficit balance attributable to the NPI Account is not recorded in the Predecessor's balance sheet at September 30, 2013, because ACTOIL is not obligated to pay such balance. As such time that the NPI computation reflects a net positive balance at the end of a quarter, the positive balance will be reflected as a payable to ACTOIL in the balance sheet and a distribution to ACTOIL will be reflected in the combined statement of operations for that quarter.

In December 2012, RSP, ACTOIL, and other minority non-operating working interest owners sold an undivided 32.35% interest in certain assets for an aggregate purchase price of $110.0 million to Resolute. In addition, RSP sold Resolute the Option for $5.0 million as described in Note 3. ACTOIL's share of the proceeds, after escrowed items and adjustments, was approximately $15.8 million. ACTOIL used these proceeds, along with subsequent escrow releases, to reduce the cumulative deficit balance of the NPI Account. The proceeds were applied dollar for dollar to reduce the NPI deficit balance as of the date of the sale and recorded as a long-term NPI payable.

As described in Note 3, in March 2013, Resolute exercised the right to acquire the 67.65% remaining interest in these assets from RSP, ACTOIL and other working interest owners for an additional purchase price before adjustments of $230.0 million. ACTOIL's share of the proceeds, after escrowed items and adjustments, was approximately $31.8 million. ACTOIL used $21.1 million of these proceeds to first reduce the cumulative deficit balance of the NPI Account to zero. The Predecessor recorded the $21.1 million proceeds as a long-term NPI payable in the accompanying balance sheet. The remaining proceeds of $10.7 million were distributed to ACTOIL.

NOTE 7—MAJOR CUSTOMERS AND SUPPLIERS

Dependence on major customers

The Predecessor believes, due to the competitive nature of goods and services supporting the oil and natural gas industry, plus access to several marketing alternatives, the Predecessor is not

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 7—MAJOR CUSTOMERS AND SUPPLIERS (Continued)

significantly dependent on any single purchaser. The following purchasers accounted for 10% or greater of total revenues for the periods indicated:

	Percentage of Total Revenues for the Nine Months Ended September 30,

Purchaser	2013			2012
MidMar Gas, LLC		9	%		10	%
Plains Marketing, L.P.		20	%		79	%
Shell Trading Company		41	%		—
Diamondback E&P LLC		11	%		—
Enterprise Crude Oil LLC		12	%		—

Management believes that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Predecessor can establish such relationships or that those relationships will result in an increased number of purchasers. Although the Predecessor is exposed to a concentration of credit risk, management believes that all of the Predecessor's purchasers are credit worthy.

NOTE 8—FAIR VALUE MEASUREMENTS

The Predecessor accounts for its commodity and interest rate derivative instruments at fair value. The fair value of derivative financial instruments is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

The Predecessor has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Assets and liabilities recorded at fair value on the combined balance sheets are categorized based on the inputs to the valuation techniques as follows:

•: Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
•: Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument can be

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 8—FAIR VALUE MEASUREMENTS (Continued)

derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

•: Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Fair value measurement on a recurring basis

The following table presents, by level within the fair value hierarchy, the Predecessor's assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the combined balance sheets for cash and cash equivalents approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

	Level 1		Level 2			Level 3		Total fair value

	(In thousands)
As of September 30, 2013:
Crude oil derivative instruments	$	—	$	(750	)	$	—	$	(750	)
Interest rate derivative instruments		—		(209	)		—		(209	)

Total	$	—	$	(959	)	$	—	$	(959	)

	Level 1		Level 2			Level 3		Total fair Value

As of December 31, 2012
Crude oil derivative instruments	$	—	$	2,675		$	—	$	2,675
Interest rate derivative instruments		—		(810	)		—		(810	)

Total	$	—	$	1,865		$	—	$	1,865

Significant level 2 assumptions used to measure the fair value of the crude oil derivative instruments include current market and contractual crude oil prices, volatility factors, appropriate risk adjusted discount rates as well as other relevant data. Significant level 2 assumptions used to measure the fair value of the interest rate derivative instruments include the interest rate curves, appropriate risk adjusted discount rates and other relevant data.

Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers between Level 1, Level 2 or Level 3 during the nine months ended September 30, 2013.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 8—FAIR VALUE MEASUREMENTS (Continued)

Nonfinancial assets and liabilities

Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a nonrecurring Level 3 measurement.

The Predecessor reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

NOTE 9—MEMBERS' EQUITY

RSP's operations are governed by the provisions of a limited liability company agreement (the "RSP LLC Agreement"). As of September 30, 2013, the members of RSP had contributed $185.1 million to RSP. There are no current outstanding equity commitments of the members. Allocations of net income and loss are allocated to the members based on a hypothetical liquidation.

Limitations of Member's liabilities

Pursuant to the RSP LLC Agreement (and as is customary for limited liability companies), the liability of the members is limited to their contributed capital.

Incentive Units

As part of the RSP LLC Agreement, certain incentive units are available to be issued to management and employees of RSP, consisting of Tier I, Tier I A, Tier II, Tier III and Tier IV units. The incentive units are intended to be compensation for services rendered to RSP. All incentive units, whether vested or not, are forfeited if payouts are not achieved by a specified date. Substantially all of the incentive unit grants were issued to members of management on October 18, 2010. The original terms of the incentive units are as follows. Tier I and Tier I A incentive units vest ratably over three years, but are subject to forfeiture if payout is not achieved. Tier I and Tier I A payout is realized upon the return of members' invested capital and a specified rate of return. Tier II, III and IV incentive units vest only upon the achievement of certain payout thresholds for each such Tier and each Tier of the incentive units is subject to forfeiture if the applicable required payouts are not achieved.

In addition, vested and unvested units will be forfeited if an incentive unit holder's employment is terminated for cause or if the unitholder voluntarily terminates his or her employment.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 9—MEMBERS' EQUITY (Continued)

The achievement of these payout conditions is a performance condition that requires the Predecessor to assess, at each reporting period, the probability that an event of payout for any Tier of incentive units will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. At the grant dates and subsequent reporting periods, the Predecessor did not deem as probable that payouts would be achieved for any Tier of incentive units.

NOTE 10—COMMITMENTS AND CONTINGENCIES

Legal Matters

In the ordinary course of business, the Predecessor may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Predecessor's financial position, results of operations or cash flows.

Environmental Matters

The Predecessor is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Predecessor to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed as incurred. The Predecessor has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

The Predecessor accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.

Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At September 30, 2013, the Predecessor had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Leases

During 2011, RSP entered into a month-to-month operating lease agreement and a long-term operating lease agreement for office space.

Rent expense for the nine months ended September 30, 2013 and 2012 was $0.2 million and $0.2 million, respectively.

NOTE 11—SUBSEQUENT EVENTS

The Predecessor has evaluated subsequent events through the date that these financial statements were available to be issued. Except as described above, the Predecessor determined there were no additional events that required disclosure or recognition in these financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Managers
RSP Permian, L.L.C. and
Rising Star Energy Development Co., L.L.C.

We have audited the accompanying combined balance sheets of RSP Permian, L.L.C. and Rising Star Energy Development Co., L.L.C. (collectively, the "Predecessor") as of December 31, 2012 and 2011, and the related combined statements of operations, members' equity, and cash flows for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Predecessor's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Predecessor is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Predecessor's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of RSP Permian, L.L.C. and Rising Star Energy Development Co., L.L.C. as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Dallas, Texas
October 7, 2013 (except for the effects of the reclassification described in Note 1, as to which the date is November 12, 2013)

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

COMBINED BALANCE SHEETS

	As of December 31,

	2012			2011
	(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	51,232		$	10,066
Restricted short-term investment		1,031			1,028
Accounts receivable		21,614			20,838
Accounts receivable, related party		4,232			4,236
Escrow receivable		3,135			—
Derivative instruments		1,112			1,260

Total current assets	$	82,356		$	37,428
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and natural gas properties, successful efforts method	$	476,816		$	370,215
Accumulated depletion		(60,489	)		(23,585	)

Total property, plant and equipment, net		416,327			346,630
Other property and equipment, net		5,085			2,968

Total property, plant and equipment	$	421,412		$	349,598

NONCURRENT ASSETS
Derivative instruments	$	2,325		$	4,337
Restricted cash		150			150
Other assets		6,995			4,149

Total noncurrent assets		9,470			8,636

TOTAL ASSETS	$	513,238		$	395,662

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	23,437		$	25,159
Accrued expenses		3,249			1,267
Interest payable		252			190
Derivative instruments		1,227			1,300

Total current liabilities		28,165			27,916
LONG-TERM LIABILITIES
Asset retirement obligations		2,716			1,114
Derivative instruments		345			2,111
Revolving credit facility		111,586			46,586
NPI payable		16,583			—

Total long-term liabilities		131,230			49,811

Total liabilities		159,395			77,727
MEMBERS' EQUITY		353,843			317,935

TOTAL LIABILITIES AND MEMBERS' EQUITY	$	513,238		$	395,662

The accompanying notes are an integral part of these combined financial statements.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

COMBINED STATEMENTS OF OPERATIONS

	For the year ended December 31,

	2012			2011
	(In thousands, except per share data)
REVENUES
Oil sales	$	91,441		$	56,772
Natural gas sales		4,284			7,217
NGL sales		8,702			—

Total revenues		104,427			63,989
OPERATING EXPENSES
Lease operating expenses		15,290			6,803
Production and ad valorem taxes		5,139			3,101
Depreciation, depletion and amortization		48,803			16,612
Asset retirement obligation accretion		115			46
Impairments		—			2,241
General and administrative expenses		2,859			3,509

Total operating expenses		72,206			32,312

(Gain) on sale of assets		(6,734	)		(105,333	)

OPERATING INCOME	$	38,955		$	137,010

OTHER INCOME (EXPENSE)
Other income	$	884		$	163
(Loss) on derivative instruments		(796	)		(1,979	)
Interest expense		(3,474	)		(3,472	)

Total other income (expense)		(3,386	)		(5,288	)

INCOME BEFORE TAXES		35,569			131,722
INCOME TAX BENEFIT (EXPENSE)		339			(550	)

NET INCOME	$	35,908		$	131,172

PRO FORMA INFORMATION (UNAUDITED)
Net income	$	35,908
Pro forma provision for income taxes		(12,927	)

Pro forma net income	$	22,981

Pro forma income per common share
Basic	$
Diluted	$
Weighted average pro forma shares outstanding
Basic	$
Diluted	$

The accompanying notes are an integral part of these combined financial statements.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

COMBINED STATEMENT OF CHANGES IN MEMBERS' EQUITY

	RSP		Rising Star		Total Members' Equity

	(In thousands)
BALANCE AT JANUARY 1, 2011	$	178,104	$	8,659	$	186,763
Net income		122,400		8,772		131,172

BALANCE AT DECEMBER 31, 2011		300,504		17,431		317,935
Net income		34,461		1,447		35,908

BALANCE AT DECEMBER 31, 2012	$	334,965	$	18,878	$	353,843

The accompanying notes are an integral part of these combined financial statements.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

COMBINED STATEMENTS OF CASH FLOWS

	For the year ended December 31,

	2012			2011
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	35,908		$	131,172
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and depreciation		48,347			16,246
Abandoned equipment and intangibles		135			131
Impairment		—			2,241
Accretion of asset retirement obligations		115			46
Bad debt expense		—			65
Amortization of loan fees		456			366
Equity in earnings of investment		(11	)		(55	)
Gain on certificate of deposit		(3	)		(3	)
(Gain) on sale of assets		(6,734	)		(105,333	)
Loss on derivative instruments		796			1,979
Net cash (payments) on settled derivatives		(474	)		(856	)
Changes in operating assets and liabilities:
Accounts receivable and accounts receivable from related parties		(3,907	)		(22,719	)
Other assets		(2,148	)		(624	)
Interest payable		63			23
Accounts payable		(1,722	)		2,298
Accrued expenses		1,982			1,266

Net cash provided by operating activities	$	72,803		$	26,243

CASH FLOWS FROM INVESTING ACTIVITIES
Payment of premium for put options	$	—		$	(2,588	)
Restricted cash		—			(150	)
Proceeds from sale of assets		63,196			182,640
Increase in equity investment		(1,146	)		—
Additions to other property and equipment		(1,287	)		(402	)
Additions to oil and natural gas properties		(173,983	)		(95,654	)

Net cash provided by (used in) investing activities	$	(113,220	)	$	83,846

CASH FLOWS FROM FINANCING ACTIVITIES
Payment of debt issuance costs	$	—		$	(241	)
Borrowings under long-term debt		90,000			55,086
Payments on long-term debt		(25,000	)		(160,000	)
NPI payable		16,583			—

Net cash provided by financing activities		81,583			(105,155	)

NET CHANGE IN CASH		41,166			4,934

CASH AT BEGINNING OF YEAR		10,066			5,132

CASH AT END OF YEAR	$	51,232		$	10,066

SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	$	3,420		$	3,293

NON-CASH INVESTING ACTIVITIES
Assets purchased included in accounts payable and accrued expenses	$	21,416		$	20,099

Asset retirement obligation assumed through acquisition of oil and natural gas properties	$	—		$	(694	)

The accompanying notes are an integral part of these combined financial statements.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

RSP Permian, L.L.C., a Delaware limited liability company ("RSP"), was formed on October 18, 2010 by its management team and an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds ("NGP"). The Company is engaged in the acquisition, development and operation of oil and natural gas properties. On December 15, 2010 primary operations commenced through a significant acquisition of oil and natural gas leases and corresponding interests on acreage located in the Permian Basin in and around Midland, Texas. Over 90% of RSP's outstanding equity is indirectly owned by Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P. (collectively, "NGP IX").

Rising Star Energy Development Co., L.L.C. , a Texas limited liability company ("Rising Star"), was formed on April 30, 2006 and is engaged primarily in the acquisition, development and operation of oil and natural gas properties. Rising Star is wholly owned by Rising Star Energy Holdings Company, L.P. ("Rising Star LP"), which is managed by its general partner, Rising Star Energy GP, L.L.C. ("Rising Star GP"). Natural Gas Partners VIII, L.P. ("NGP VIII") owns over 90% of the membership interests in Rising Star GP and over 80% of the limited partnership interests in Rising Star LP. Rising Star LP's sole material assets are its interests in Rising Star and its interests in Rising Star Energy Operating Co., L.L.C., which has not conducted any operations for the past several years.

As all power and authority to control the core functions of RSP and Rising Star (collectively, the "Predecessor") are controlled by NGP VIII and NGP IX, respectively, the acquisition has been accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests. Through the delegation of authority of the general partners of NGP VIII and NGP IX to NGP Energy Capital Management, L.L.C. ("NGP ECM"), all power and authority of the respective fund limited partnership in effectuating its core investment, management and divestment function is controlled by NGP ECM. The results of RSP and Rising Star have been combined for all periods in which common control existed for financial reporting purposes.

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP").

Reclassification of Gain on Sale of Assets

The Company has reclassified the gain on sale of assets recorded for the years ending December 31, 2012 and 2011 from a component of other income (expense) to be a component of operating income. There was no effect on net income for either year presented. The effects of this reclassification on operating income and other income (expense) are described below:

	December 31, 2012

	(In Thousands)
	As Previously Reported		Adjustment			As Adjusted
Operating income	$	32,221	$	6,734		$	38,955
Other income (expense)		3,348		(6,734	)		(3,386	)
Net income	$	—	$	—		$	—

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION (Continued)

	December 31, 2011

	(In Thousands)
	As Previously Reported		Adjustment			As Adjusted
Operating income	$	31,677	$	105,333		$	137,010
Other income (expense)		100,045		(105,333	)		(5,288	)
Net income	$	—	$	—		$	—

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the combined financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively. Significant assumptions are required in the valuation of proved oil and natural gas reserves which may affect the amount at which oil and natural gas properties are recorded. Estimation of asset retirement obligations ("AROs"), valuation of derivative instruments and the fair value of incentive unit compensation also require significant assumptions. It is possible these estimates could be revised at future dates and these revisions could be material. Depletion of oil and natural gas properties are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price estimates.

Cash and Cash Equivalents

The Predecessor considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents.

Derivative and Other Financial Instruments

The Predecessor's derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the combined

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

statement of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Net premiums paid for put options are included in cash flows from investing activities.

Accounts Receivable

Accounts receivable, which are primarily from the sale of oil, natural gas, and natural gas liquids ("NGLs"), are accrued based on estimates of the sales and prices the Predecessor believes it will receive. The Predecessor routinely reviews outstanding balances, assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. The Predecessor has not provided an allowance for doubtful accounts based on management's expectations that all receivables at year-end will be fully collected. The need for an allowance is determined based upon reviews of individual accounts, historical losses, existing economic conditions and other pertinent factors.

Transactions with Related Parties

Wallace Family Partnership, LP ("Wallace LP") has a non-operated working interest in substantially all the oil and natural gas assets the Predecessor operates. Leslyn Wallace is a limited partner of Wallace LP and an employee of RSP. The carrying amount of the receivable from Wallace LP was approximately $4.2 million at both December 31, 2012 and 2011. The Predecessor does not consider the accounts receivable from Wallace LP to be uncollectible.

Oil and Natural Gas Properties

The Predecessor capitalizes interest on expenditures while activities are in progress to bring the assets to their intended use for significant exploration and development projects that last more than six months. The Predecessor did not capitalize any interest in 2011 and 2012 as no projects lasted more than six months. Costs incurred to maintain wells and related equipment, lease and well operating costs and other exploration costs are charged to expense as incurred. Gains and losses arising from sales of properties are generally included as income. Unproved properties are assessed periodically for possible impairment.

Capitalized acquisition costs attributable to proved oil and natural gas properties are depleted on a field basis based on proved reserves using the unit-of-production method. Capitalized exploration well costs and development costs, including AROs, are depleted on a field basis, based on proved developed reserves. Depletion expense for oil and natural gas producing property was $48.0 million and $16.0 million for the years ended December 31, 2012 and 2011, respectively, and is included in depreciation, depletion and amortization in the accompanying Combined Statements of Operations.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The Predecessor's oil and natural gas properties as of December 31, 2012 and 2011 consisted of the following:

	2012			2011

	(In thousands)
Proved oil and natural gas properties	$	447,369		$	338,220
Unproved oil and natural gas properties		29,447			31,995
Less: accumulated depletion		(60,489	)		(23,585	)

	$	416,327		$	346,630

In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of December 31, 2012 and 2011, there were no costs capitalized in connection with exploratory wells in progress.

For a property determined to be impaired, an impairment loss equal to the difference between the property's carrying value and estimated fair value is recognized. Fair value, on a field basis, is estimated to be the present value of the aforementioned expected future net cash flows. Unproved properties are assessed periodically to determine whether they have been impaired. An impairment allowance is provided on an unproved property when the Predecessor determines that the property will not be developed. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units' estimated reserves, future net cash flows and fair value. In 2011, the Predecessor recognized impairment losses of $2.2 million related to oil and natural gas properties, which were impaired to fair value using Level 3 fair-value inputs. No impairment of proved property was recorded for the years ended December 31, 2012.

Other Property and Equipment

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

of the individual assets or group of assets ranging from 5 to 39 years. Depreciation expense related to such assets for the years ended December 31, 2012 and 2011 was $0.3 million and $0.2 million, respectively, and is included in depreciation, depletion and amortization in the accompanying combined statement of operations.

Restricted Cash

Restricted cash as of December 31, 2012 and 2011 consisted of a certificate of deposit.

Deferred Loan Costs

Deferred loan costs are stated at cost, net of amortization, which is computed using the straight-line method over the life of the loan which is reflective of the effective interest rate method. Deferred loan costs of $1.5 million as of December 31, 2012 and 2011, respectively, net of accumulated amortization, are included in other assets in the accompanying combined balance sheets. Amortization expense of $0.5 million and $0.4 million was recorded for the year ended December 31, 2012 and 2011, respectively, and is included in depreciation, depletion and amortization in the accompanying combined statements of operations.

Asset Retirement Obligation

The Predecessor estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future down-hole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of a field's surface to a condition similar to that existing before oil and natural gas extraction began.

In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The ARO consisted of the following for the periods indicated:

	Year Ended December 31,

	2012		2011
	(In thousands)
Asset retirement obligation at beginning of period	$	1,114	$	289
Liabilities acquired		—		356
Liabilities incurred		1,474		396
Liabilities settled		—		—
Revision of estimate		13		27
Accretion expense		115		46

Asset retirement obligation at end of period	$	2,716	$	1,114

Revenue Recognition

Oil, natural gas and NGL revenue is recognized when the product is sold to a purchaser, delivery has occurred, written evidence of an arrangement exists, pricing is fixed and determinable and collectability of the revenue is reasonably assured. Oil, natural gas and NGL imbalances result when sales differ from the seller's net revenue interest in the particular property's reserves. An imbalance receivable or liability is recognized only to the extent that the Predecessor has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2012 and 2011, the Predecessor had no significant asset or liability recorded for oil, natural gas or NGL imbalances. 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.

Income Taxes

However, the Predecessor's operations located in Texas are subject to an entity-level tax, the Texas franchise tax, at a statutory rate of up to 1% of income that is apportioned to Texas.

The Predecessor evaluates the tax positions taken or expected to be taken in the course of preparing its tax returns and disallows the recognition of tax positions not deemed to meet a "more-likely-than-not" threshold of being sustained by the applicable tax authority. The Predecessor's management does not believe that any tax positions included in its tax returns would not meet this threshold. The Predecessor's policy is to reflect interest and penalties related to uncertain tax positions as part of its income tax expense, when and if they become applicable.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Unaudited Pro Forma Income Taxes

These financial statements have been prepared in anticipation of a proposed initial public offering (the "Offering") of the common stock of the Predecessor's parent entity. In connection with the Offering, all of the interests in the Predecessor will be contributed to a newly formed Delaware corporation which will be treated as a taxable C corporation and thus will be subject to federal and state income taxes. Accordingly, a pro forma income tax provision has been disclosed as if the Predecessor was a taxable corporation for all periods presented. The Predecessor has computed pro forma tax expense using a 36% blended corporate level federal and state tax rate.

Segment Reporting

Concentrations of Credit Risk

Cash equivalents

The Predecessor's cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts receivable

The following table summarizes concentration of receivables, net of allowances, by product or service as of the following dates:

	December 31, 2012		December 31, 2011

	(In thousands)
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	9,673	$	7,444
Joint interest owners		11,935		13,394
Other		6		—

Total	$	21,614	$	20,838

Oil and natural gas customers include pipelines, distribution companies, producers, natural gas marketers and industrial users primarily located in the Permian Basin. As a general policy, collateral is not required for receivables, but customers' financial condition and credit worthiness are evaluated regularly.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Derivative assets and liabilities

During the year ended December 31, 2012 and 2011, the Predecessor did not incur any significant losses due to counterparty bankruptcy filings. The Predecessor assesses its credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. The Predecessor offsets its credit exposure to each counterparty with amounts it owes the counterparty under derivative contracts.

New Accounting Pronouncements

The FASB issued ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities" in December 2011, and issued ASU 2013-01, "Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities" in January 2013. These ASUs create new disclosure requirements regarding the nature of an entity's rights of setoff and related arrangements associated with its derivative instruments, repurchase agreements and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements would be required, irrespective of whether the entity has elected to offset those instruments in the statement of financial position. These ASUs are effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs will not impact the Predecessor's financial position, results of operations or liquidity.

NOTE 3—SALE OF OIL AND NATURAL GAS PROPERTY INTERESTS

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 3—SALE OF OIL AND NATURAL GAS PROPERTY INTERESTS (Continued)

right to acquire the remaining interest in these certain assets, and therefore the Option fee was included in the consideration transferred in computing the gain on disposition of the assets described above. The Predecessor recorded a gain in connection with the sale of the 32.35% interest in these assets and option fee in the amount of $6.7 million.

NOTE 4—DERIVATIVE INSTRUMENTS

Crude Oil Derivative Instruments

The Predecessor uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its crude oil production. These include over-the-counter ("OTC") put options and collars with the underlying contract and settlement pricings based on NYMEX West Texas Intermediate ("WTI"). The derivative instruments are recorded at fair value on the combined balance sheets and any gains and losses are recognized in current period earnings.

Each put transaction has an established floor price. The Predecessor pays the counterparty a premium in order to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Predecessor an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires. Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Predecessor receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Predecessor pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.

The following table summarizes open positions as of December 31, 2012, and represents, as of such date, derivatives in place through December 31, 2015:

	Year 2013		Year 2014		Year 2015

Puts:
Notional volume (Bbl)		540,000		—		—
Weighted average price ($/Bbl)	$	75.00	$	—	$	—
Collars:
Notional volume (Bbl)		537,000		393,000		72,000
Weighted average floor price ($/Bbl)	$	83.67	$	86.98	$	80.00
Weighted average ceiling price ($/Bbl)	$	104.53	$	110.16	$	93.25

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

Interest Rate Derivative Instruments

In December 2010, as part of the credit agreement more fully described in Note 6, the Predecessor entered into two interest rate swap agreements with effective dates of March 31, 2011 and expiration dates of December 31, 2013, to fix the interest rate of a portion of the floating variable interest. The total notional amount of the two instruments is $65 million. As of December 31, 2012, the weighted average effective interest rate on the Predecessor interest rate swaps was approximately 1.46%.

Fair Values and Gains (Losses)

The following table presents the fair value of derivative instruments. The Predecessor derivatives are presented as separate line items in its combined balance sheets as current and noncurrent derivative instrument assets and liabilities. Derivative instruments are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivative instruments classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of the Predecessor's master netting arrangements.

	Assets				Liabilities

	December 31, 2012		December 31, 2011		December 31, 2012			December 31, 2011
	(In thousands)
Derivative Instruments:
Current amounts
Crude oil contracts	$	1,112	$	1,260	$	(417	)	$	(1,300	)
Interest rate contracts		—		—		(810	)		—
Noncurrent amounts
Crude oil contracts		2,325		4,337		(345	)		(879	)
Interest rate contracts		—		—		—			(1,232	)

Total derivative instruments	$	3,437	$	5,597	$	(1,572	)	$	(3,411	)

Gains and losses on derivatives are reported in the combined statements of operations.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

The following represents the Predecessor's reported gains and losses on derivative instruments for the periods presented:

	For the year ended December 31,

	2012			2011
	(In thousands)
(Loss) on derivative instruments
Crude oil derivative instruments	$	(408	)	$	(545	)
Interest rate derivative instruments		(388	)		(1,434	)

Total	$	(796	)	$	(1,979	)

Offsetting of derivative assets and liabilities

The following table presents the Predecessor's gross and net derivative assets and liabilities.

	Gross Amount Presented on Balance Sheet			Netting Adjustments(a)			Net Amount

	(In thousands)
December 31, 2012
Derivative instrument assets with right of offset or master netting agreements	$	3,437		$	(1,373	)	$	2,064
Derivative instrument liabilities with right of offset or master netting agreements	$	(1,572	)	$	1,373		$	(199	)
December 31, 2011
Derivative instrument assets with right of offset or master netting agreements	$	5,597		$	(774	)	$	4,823
Derivative instrument liabilities with right of offset or master netting agreements	$	(3,411	)	$	774		$	(2,637	)

(a): With all of the Predecessor's financial trading counterparties, the Predecessor has agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

Credit Risk related Contingent Features in Derivatives

NOTE 5—CREDIT AGREEMENT

In December 2010, RSP entered into a credit agreement (the "Agreement") with two participating banks (the "Lenders") for the acquisition of producing and nonproducing oil and natural gas interests

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 5—CREDIT AGREEMENT (Continued)

in the Permian Basin. The Agreement consists of a revolving credit facility (the "Revolving Credit Facility") and a term loan (the "Term Loan") (collectively, the "Commitments").

The Agreement contains various restrictive covenants and compliance requirements which include:

•: maintenance of certain financial ratios, including: (i) commencing March 31, 2011 maintenance of a working capital ratio; (ii) commencing June 30, 2011 maintenance of a leverage ratio; and (iii) commencing June 30, 2011 maintenance of a minimum interest coverage ratio;
•: restrictions on selling, assigning farm-out and conveying oil and natural gas interests;
•: limits on the incurrence of additional indebtedness and certain types of liens; and
•: restrictions on the payment of cash dividends, except as described in the Agreement.

On June 1, 2011, an amendment to the credit agreement was entered into by the parties which revised the maturity date of letters of credit available to be issued per the credit agreement. At December 31, 2012, the Predecessor was in compliance with all of the covenants under the Agreement.

Revolving Credit Facility

As of December 31, 2012 and 2011, the Revolving Credit Facility had an outstanding balance of approximately $111.6 million and $46.6 million, respectively, with a maturity date of December 15, 2015. The Predecessor's borrowing base was $125 million, with scheduled semi-annually redeterminations commencing June 1, 2013 and December 1, 2013. The Predecessor may elect borrowings under the Revolving Credit Facility to be either a) Eurodollar Revolving Credit Loans ("Eurodollar") or b) ABR Revolving Credit loans ("ABR").

Borrowings elected as Eurodollar bear interest based on a 1, 2 or 3-month LIBOR Rate ("Libor") plus an applicable margin ranging from 1.50% to 2.25%, based upon the percentage of borrowing base utilized, plus a facility fee of 0.50% charged on the borrowing base amount. Borrowings elected as ABR bear interest at the Prime Rate (3.25% as of December 31, 2012) plus 0.50% to 1.25%, based upon the percentage of borrowing base utilized, plus a facility fee of 0.50% charged on the borrowing base amount.

The Predecessor also had available a Swing Line Loan ("Swing Line") with the Administrative Agent of the Agreement, whereby the Predecessor may borrow up to $5 million. The Swing Line is a sub-line under the Revolving Credit Facility and the Administrative Agent may require the Lenders to fund borrowings under the Revolving Credit Facility to fund outstanding balances of the Swing Line. The Swing Line bears interest at the ABR rate and matures on December 15, 2015. The Predecessor has not borrowed any funds under the Swing Line as of December 31, 2012.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 6—NET PROFITS INTEREST

In July 2011, RSP entered into a $175.0 million financing agreement to convey a 25% net profits interest ("NPI") to ACTOIL. The NPI conveys 25% of the oil and natural gas sales less associated direct capital expenditures and lease operating expenses from substantially all the oil and natural gas properties held by RSP effective January 1, 2011. RSP maintains a separate net profits interest account ("NPI Account") maintained on a cash basis, as defined in the agreement governing the NPI. The associated property cost and depletion was removed from the basis of the assets and the associated gain on the sale was approximately $98.5 million.

The calculation to determine if amounts are to be distributed to ACTOIL for its interest is determined on a quarterly basis by RSP. ACTOIL does not fund its proportionate share of direct capital expenditures or lease operating expenses as the expenses are funded by the Predecessor and reimbursed through the NPI calculation. When the cumulative oil and natural gas sales, net of associated direct capital expenditures and lease operating expenses attributable to the NPI is a negative number, then the distribution is zero for such calendar quarter and such cumulative negative amount is carried forward. When the cumulative NPI calculation becomes a positive number at the end of a calendar quarter, a distribution will be made to ACTOIL for its share of net profits. If the NPI Account has a deficit balance at the end of a calendar quarter, ACTOIL incurs interest to RSP on the cumulative deficit balance at varying annual rates depending on the amount of the deficit balance. This interest is added to the cumulative deficit balance.

As of December 31, 2012, the NPI Account had a cumulative deficit balance of approximately $19.3 million. The deficit balance attributable to the NPI Account is not recorded in the Predecessor's balance sheet at December 31, 2012, because ACTOIL is not obligated to pay such balance. As such time that the NPI computation reflects a net positive balance at the end of a quarter, the positive balance will be reflected as a payable to ACTOIL in the balance sheet and a distribution to ACTOIL will be reflected in the combined statement of operations for that quarter.

In December 2012, RSP, ACTOIL, and other minority non-operating working interest owners sold an undivided 32.35% interest in certain assets for an aggregate purchase price of $110.0 million to Resolute. In addition, RSP sold Resolute the Option for $5.0 million as described in Note 3. ACTOIL's share of the proceeds, after escrowed items, was approximately $15.8 million. ACTOIL used these proceeds, along with subsequent escrow releases, to reduce the cumulative deficit balance of the NPI Account. The proceeds were applied dollar for dollar to reduce the NPI deficit balance as of the date of the sale and recorded as a long-term NPI payable.

NOTE 7—MAJOR CUSTOMERS AND SUPPLIERS

Dependence on major customers

The Predecessor believes, due to the competitive nature of goods and services supporting the oil and natural gas industry, plus access to several marketing alternatives, the Predecessor is not significantly dependent on any single purchaser. The following purchasers accounted for 10% or greater

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 7—MAJOR CUSTOMERS AND SUPPLIERS (Continued)

of the sales of production for the periods indicated and the corresponding outstanding accounts receivable balance as of the dates indicated:

	Percentage of Total Revenues for the Year Ended December 31,

Purchaser	2012			2011
MidMar Gas LLC		11	%		9	%
Plains Marketing, L.P.		76	%		78	%

NOTE 8—FAIR VALUE MEASUREMENTS

Assets and liabilities recorded at fair value on the audited combined balance sheets are categorized based on the inputs to the valuation techniques as follows:

•: Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
•: Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 8—FAIR VALUE MEASUREMENTS (Continued)

•: Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Fair value measurement on a recurring basis

	Level 1		Level 2			Level 3		Total fair value

	(In thousands)
As of December 31, 2012:
Crude oil derivative instruments	$	—	$	2,675		$	—	$	2,675
Interest rate derivative instruments		—		(810	)		—		(810	)

Total	$	—	$	1,865		$	—	$	1,865

	Level 1		Level 2			Level 3		Total fair value

As of December 31, 2011:
Crude oil derivative instruments	$	—	$	3,418		$	—	$	3,418
Interest rate derivative instruments		—		(1,232	)		—		(1,232	)

Total	$	—	$	2,186		$	—	$	2,186

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 8—FAIR VALUE MEASUREMENTS (Continued)

Nonfinancial assets and liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company's estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company's AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company's ARO represent a nonrecurring Level 3 measurement.

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. During 2011, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily to downward reserve revisions or drilling of marginal or uneconomic wells. As a result, the Company recorded an impairment charge of $2.2 million on December 31, 2011. These charges are included in Impairment of oil and natural gas properties in the combined statement of operations. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

NOTE 9—MEMBERS' EQUITY

RSP's operations are governed by the provisions of a limited liability company agreement (the "RSP LLC Agreement"). As of December 31, 2012 and 2011, the members of RSP had contributed $184.8 million and $184.8 million, respectively, to RSP. There are no current outstanding equity commitments of the members. Allocations of net income and loss are allocated to the members based on a hypothetical liquidation.

Limitations of Member's liabilities

Pursuant to the RSP LLC Agreement (and as is customary for limited liability companies), the liability of the members is limited to their contributed capital.

Incentive Units

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 9—MEMBERS' EQUITY (Continued)

incentive units vest only upon the achievement of certain payout thresholds for each such Tier and each Tier of the incentive units is subject to forfeiture if the applicable required payouts are not achieved.

In addition, vested and unvested units will be forfeited if an incentive unit holder's employment is terminated for cause or if the unitholder voluntarily terminates his or her employment.

The achievement of these payout conditions is a performance condition that requires the Predecessor to assess, at each reporting period, the probability that an event of payout will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. At the grant dates and subsequent reporting periods, the Predecessor did not deem as probable that such payouts would be achieved.

NOTE 10—COMMITMENTS AND CONTINGENCIES

Legal Matters

Environmental Matters

Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At December 31, 2012 and 2011, the Predecessor had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 10—COMMITMENTS AND CONTINGENCIES (Continued)

Leases

During 2011, RSP entered into a month-to-month operating lease agreement and a long-term operating lease agreement for office space. The estimated future minimum lease payments under the long term operating lease agreement as of December 31, 2012 was as follows:


2013	$	157,397
2014		162,488
2015		13,576

Rent expense for the year ended December 31, 2012 and 2011 was $0.2 million and $0.2 million.

NOTE 11—SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED)

Costs incurred in oil and natural gas property acquisition, exploration and development

Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the years ended December 31:

	2012		2011

	(In thousands)
Property acquisition costs:
Proved	$	—	$	—
Unproved		—		—
Exploration		—		—
Development costs		173,983		95,654

Total costs incurred	$	173,983	$	95,654

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below for the years ended December 31:

	2012		2011

	(In thousands)
Capitalized Costs
Proved	$	447,369	$	338,220
Unproved		29,447		31,995

	$	476,816	$	370,215
Less accumulated depreciation, depletion, amortization and impairment		60,489		23,585

Net capitalized costs	$	416,327	$	346,630

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 11—SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED) (Continued)

Results of oil and natural gas producing activities

The results of operations of oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below for the years ended December 31:

	2012			2011

	(In thousands)
Revenues:
Oil and natural gas sales	$	104,427		$	63,989
Production costs:
Lease operating expenses		15,290			6,803
Production and ad valorem taxes		5,139			3,101

	$	83,998		$	54,085
Other costs:
Depreciation, depletion, amortization and impairment	$	48,803		$	16,612
Income tax expense (benefit)		(339	)		550

Results of operations	$	35,534		$	36,923

Net Proved Oil and Natural Gas Reserves (Unaudited)

The Predecessor's proved oil and natural gas reserves as of December 31, 2012 and 2011 were prepared internally by management and not by independent third party petroleum consultants. In accordance with the new SEC regulations, reserves at December 31, 2012 and 2011 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 11—SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED) (Continued)

An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, for the years ended December 31, 2012 and 2011 is as follows:

	Year Ended December 31, 2012

	Natural Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		92,416			33,371			—			48,774
Revisions of previous estimates		(57,872	)		(15,353	)		391			(24,608	)
Extensions, discoveries and other additions		7,724			3,885			4,829			10,001
Purchases of minerals in place		—			—			—			—
Production		(1,576	)		(1,040	)		(264	)		(1,567	)

End of year		40,692			20,863			4,956			32,600

Proved developed reserves:
Beginning of year		19,825			7,550			—			10,854
End of year		17,847			7,730			1,723			12,427
Proved undeveloped reserves:
Beginning of year		72,591			25,821			—			37,920
End of year		22,845			13,133			3,233			20,173

	Year Ended December 31, 2011

	Natural Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)		MBoe
Proved developed and undeveloped reserves:
Beginning of year		80,969			39,173			—		52,668
Revisions of previous estimates		8,487			(6,708	)		—		(5,294	)
Extensions, discoveries and other additions		3,931			1,524			—		2,180
Purchases of minerals in place		—			—			—		—
Production		(971	)		(618	)		—		(780	)

End of year		92,416			33,371			—		48,774

Proved developed reserves:
Beginning of year		9,197			4,656			—		6,189
End of year		19,825			7,550			—		10,854
Proved undeveloped reserves:
Beginning of year		71,772			34,517			—		46,479
End of year		72,591			25,821			—		37,920

The tables above include changes in estimated quantities of oil and natural gas reserves shown in MBbl equivalents ("MBoe") at a rate of six MMcf per one MBbl.

For the year ended December 31, 2012, the Predecessor's negative revision of 24,608 MBoe of previous estimated quantities is primarily due to a change in development strategy to replace 20-acre

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 11—SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED) (Continued)

proved vertical well locations with non-proved horizontal well locations. In addition, in 2012, the Predecessor switched to the recognition of three stream instead of two stream sales volumes, which resulted in a negative revision of natural gas reserves and a positive revision of NGL reserves. Extensions, discoveries and other additions of 10,001 MBoe during the year ended December 31, 2012, result primarily from the drilling of new wells during the year and from new proved undeveloped locations added during the year.

For the year ended December 31, 2011, the Predecessor's negative revision of previous estimated quantities is composed of a 5,294 MBoe revision due to the write off of un-economic wells based on past performance. Extensions, discoveries and other additions of 2,180 MBoe during the year ended December 31, 2011, consisted of drilling of new wells during the year and from new proved undeveloped locations added during the year, which increased the Predecessor's proved reserves.

Standardized Measure of Discounted Future Net Cash Flows—(Unaudited)

The estimates of future cash flows and future production and development costs as of December 31, 2012 and 2011 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31:

	2012			2011

	(In thousands)
Future cash inflows	$	2,210,325		$	3,825,056
Future production costs		(655,720	)		(759,190	)
Future development costs		(362,876	)		(505,710	)
Future income tax expenses(1)		—			—

Future net cash flows		1,191,729			2,560,156
10% discount for estimated timing of cash flows		(737,556	)		(1,705,732	)

Standardized measure of discounted future net cash flows	$	454,173		$	854,424

(1): Future net cash flows do not include the effects of income taxes on future revenues because the Predecessor was a limited liability company not subject to entity-level income taxation as of December 31, 2012 and December 31, 2011. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 11—SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED) (Continued)

Predecessor's equity holders. Following the Corporate Reorganization, the Company will be a subchapter C corporation subject to U.S. federal and state income taxes. If the Predecessor had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2012 and December 31, 2011 would have been $155,662 and $289,022, respectively. The unaudited standardized measure at December 31, 2012 and December 31, 2011 would have been $298,511 and $565,402, respectively.

In the foregoing determination of future cash inflows, sales prices used for gas and oil for December 31, 2012 and 2011 were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.

It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Predecessor's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	2012			2011

	(In thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	854,424		$	660,480
Changes in the year resulting from:		—			—
Sales, less production costs		(84,647	)		(54,270	)
Revisions of previous quantity estimates		(438,394	)		(73,222	)
Extensions, discoveries and other additions		84,149			32,525
Net change in prices and production costs		(133,485	)		118,588
Changes in estimated future development costs		38,096			(1,514	)
Previously estimated development costs incurred during the period		108,367			76,086
Purchases of minerals in place		—			—
Accretion of discount		85,442			66,048
Net change in income taxes		—			—
Timing differences and other		(59,779	)		29,703

Standardized measure of discounted future net cash flows, end of year	$	454,173		$	854,424

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RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C.
(PREDECESSOR)

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 11—SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED) (Continued)

NOTE 12—SUBSEQUENT EVENTS

Effective March 22, 2013, RSP completed the sale of the remaining working interest in certain assets, as described in Note 2. The aggregate purchase price for the remaining working interest was approximately $230.0 million for RSP and other working interest owners. The sale is subject to customary purchase price adjustments and closing conditions. RSP's share of the purchase price was $144.2 million.

Additionally, RSP Predecessor used cash proceeds from the asset sale to reduce the revolving credit facility balance. RSP's borrowing base was reduced to $95.0 million until the June 1, 2013 redetermination.

Spanish Trail Acquisition

On September 10, 2013, RSP acquired certain working interests in oil and natural gas properties located in the Permian Basin from Summit Petroleum, LLC ("Summit") and EGL Resources, Inc. ("EGL") (the "Spanish Trail Acquisition"). The Spanish Trail Acquisition involved the acquisition by RSP of additional working interests in oil and natural gas properties located in the Permian Basin, referred to as the Spanish Trail properties, in which RSP already owned a working interest prior to the acquisition.

Credit Agreement Amendment

As of September 10, 2013, RSP amended and restated the December 15, 2010 credit agreement which includes a revolving credit facility and a term loan. The borrowing base under RSP's amended and restated credit facility is $140 million. The maturity date of the revolving credit facility is September 10, 2017 while the term loan matures on April 1, 2016. As of September 30, 2013, the revolving credit facility has a margin of 1.25% to 2.00% plus LIBOR plus a facility fee of 0.50% charged on the borrowing base amount, while the term loan has a margin of 5.5% plus LIBOR (floor of 1%), or 6.5%.

The Predecessor has evaluated subsequent events through the date that these financial statements were available to be issued on October 7, 2013. Except as described above, the Predecessor determined there were no additional events that required disclosure or recognition in these financial statements.

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REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Board of Managers
RSP Permian, L.L.C.

We have audited the accompanying Statements of Revenues and Direct Operating Expenses of working and revenue interests in certain oil and gas properties (the "Statements") located in the Spanish Trail (the "Spanish Trail Assets") acquired by RSP Permian, L.L.C. (the "Company"), for the years ended December 31, 2012 and 2011, and the related notes to the Statements.

Management's responsibility for the Statements

Management is responsible for the preparation and fair presentation of the Statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of Statements that are free from material misstatement, whether due to fraud or error.

Auditor's responsibility

Our responsibility is to express an opinion on these Statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the Statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the Statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Spanish Trail Assets as described in Note 1 for the years ended December 31, 2012 and 2011, in accordance with accounting principles generally accepted in the United States of America.

Emphasis of matter

As described in Note 1, the accompanying Statements are prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to be a complete presentation of the Spanish Trail Assets' revenues and expenses. Our opinion is not modified with respect to this matter.

/s/ GRANT THORNTON LLP

Dallas, Texas

October 7, 2013

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SPANISH TRAIL ASSETS

STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011 AND
FOR THE SIX MONTHS ENDED JUNE 30, 2013 AND 2012

	Six Months Ended June 30,				For Years Ended December 31,

	2013		2012		2012		2011
	(Unaudited)
	(In thousands)
Operating revenues	$	13,780	$	14,075	$	26,929	$	23,277
Direct operating expenses		2,368		1,604		4,132		3,600

Revenues in excess of direct operating expenses	$	11,412	$	12,471	$	22,797	$	19,677

See notes to statements of operating revenues and direct operating expenses.

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SPANISH TRAIL ASSETS

NOTES TO STATEMENTS OF OPERATING REVENUES AND
DIRECT OPERATING EXPENSES

NOTE 1—BASIS OF PRESENTATION

The accompanying statements present the revenues and direct operating expenses of working and revenue interests of certain oil and natural gas properties located in the Permian Basin of West Texas (the "Spanish Trail Assets") acquired by RSP Permian, L.L.C. ("RSP") (the "Spanish Trail Acquisition") for the years ended December 31, 2012 and 2011 and the six months ended June 30, 2013 and 2012.

The Spanish Trail Acquisition which closed on September 10, 2013, involved RSP acquiring additional working interests in certain oil and natural gas properties in the Permian Basin in which it already owned interests in prior to the acquisition.

The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting. Such amounts may not be representative of future operations. The statements do not include depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America ("U.S. GAAP") are not presented as such information is not readily available on an individual property basis. Accordingly, the historical statements of revenues and direct operating expenses of the Spanish Trail Assets are presented in lieu of the financial statements required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the financial statements, in conformity with U.S. GAAP, requires the management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. It is possible these estimates could be revised at future dates and these revisions could be material.

Concentration of Credit Risk

Arrangements for crude oil and condensate, natural gas and NGL sales are evidenced by signed contracts with determinable market prices and revenues are recorded when production is delivered. A significant majority of the purchasers of these products have investment grade credit ratings and there have been no material credit losses.

Revenue Recognition

Oil and natural gas revenue is recognized when the product is sold to a purchaser, delivery has occurred, written evidence of an arrangement exists, pricing is fixed and determinable and collectability of the revenue is reasonably assured. Oil and natural gas imbalances result when sales differ from the seller's net revenue interest in the particular property's reserves. As of June 30, 2013, RSP had no significant asset or liability recorded for oil and natural gas imbalances.

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SPANISH TRAIL ASSETS

NOTES TO STATEMENTS OF OPERATING REVENUES AND
DIRECT OPERATING EXPENSES (Continued)

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)

All information set forth herein relating to the proved reserves as of December 31, 2012 and 2011, including the estimated future net cash flows and present values, from that date, is taken or derived from the records of RSP Permian, L.L.C. These estimates were based upon review of historical production data and other geological, economic, ownership and engineering data provided and related to the reserves. No reports on these reserves have been filed with any federal agency. In accordance with the Securities and Exchange Commission's guidelines, estimates of proved reserves and the future net revenues from which present values are derived are based on an unweighted 12-month average of the first-day-of-the- month price for the period, held constant throughout the life of the properties. Operating costs, development costs, and certain production-related taxes, which are based on current information and held constant, were deducted in arriving at estimated future net revenues.

	Year Ended December 31, 2012

	Natural Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		7,414			3,165			—			4,400
Revisions of previous estimates		(4,202	)		(1,201	)		—			(1,901	)
Extensions, discoveries and other additions		3,857			2,476			1,299			4,418
Purchases of minerals in place		—			—			—			—
Production		(278	)		(270	)		(66	)		(383	)

End of year		6,791			4,170			1,233			6,534

Proved developed reserves:
Beginning of year		4,278			1,849			—			2,562
End of year		3,053			1,792			554			2,854
Proved undeveloped reserves:
Beginning of year		3,136			1,316			—			1,838
End of year		3,738			2,378			679			3,680

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SPANISH TRAIL ASSETS

NOTES TO STATEMENTS OF OPERATING REVENUES AND
DIRECT OPERATING EXPENSES (Continued)

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Continued)

	Year Ended December 31, 2011

	Natural Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)		MBoe
Proved developed and undeveloped reserves:
Beginning of year		8,014			3,846			—		5,181
Revisions of previous estimates		(1,136	)		(813	)		—		(1,002	)
Extensions, discoveries and other additions		834			354			—		493
Purchases of minerals in place		—			—			—		—
Production		(298	)		(222	)		—		(272	)

End of year		7,414			3,165			—		4,400

Proved developed reserves:
Beginning of year		3,795			1,778			—		2,410
End of year		4,278			1,849			—		2,562
Proved undeveloped reserves:
Beginning of year		4,219			2,068			—		2,771
End of year		3,136			1,316			—		1,838

For the year ended December 31, 2012, the Spanish Trail Assets' negative revision of 1,901 MBoe of previously estimated quantities is primarily due to a change in development strategy to replace 20-acre proved vertical well locations with non-proved horizontal well locations.

Standardized measure of discounted future net cash flows relating to proved reserves (dollars in thousands):

	2012			2011

	(In thousands)
Future cash inflows	$	436,690		$	351,658
Future production costs		(128,166	)		(81,579	)
Future development costs		(67,253	)		(30,224	)
Future income tax expenses		—			—

Future net cash flows		241,271			239,855
10% annual discount for estimated timing of cash flows		(146,067	)		(147,425	)

Standardized measure of discounted future net cash flows	$	95,204		$	92,430

Future cash inflows are computed by applying a 12-month average commodity price adjusted for location and quality differentials for 2012 and 2011 to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of derivative instruments. Average sales price per commodity follows:

Petroleum Product	2012		2011

Natural gas per Mcf	$	2.23	$	7.72
Crude oil per Bbl		90.71		93.04
NGLs per Bbl		35.16		—

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SPANISH TRAIL ASSETS

NOTES TO STATEMENTS OF OPERATING REVENUES AND
DIRECT OPERATING EXPENSES (Continued)

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Continued)

The following reconciles the change in the standardized measure of discounted future net cash flows:

	2012			2011

	(In thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	92,430		$	100,791

Changes from:
Sales, less production costs		(22,798	)		(19,677	)
Revisions of previous quantity estimates		(39,936	)		(19,497	)
Net change in prices and production costs		(15,361	)		13,161
Extensions, discoveries and other additions		48,685			7,327
Change in estimated future development costs		3,575			(4,863	)
Previously estimated development costs incurred during the period		2,595			12,557
Purchases of minerals in place		—			—
Accretion or discount		9,243			10,079
Net change in income taxes		—			—
Timing differences and other		16,771			(7,448	)

Standardized measure of discounted future net cash flows, end of year	$	95,204		$	92,430

NOTE 4—SUBSEQUENT EVENTS

We are not aware of any events that have occurred subsequent to June 30, 2013 but before October 7, 2013, the date the financial statements were available to be issued, that require recognition or disclosure in these financial statements.

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REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Board of Managers
RSP Permian, L.L.C.

We have audited the accompanying Statements of Revenues and Direct Operating Expenses of working and revenue interests in certain oil and gas properties (the "Statements") located in the Permian Basin (the "Contributed Properties") to be acquired by RSP Permian, Inc. (the "Company"), for the years ended December 31, 2012 and 2011, and the related notes to the Statements.

Management's responsibility for the Statements

Auditor's responsibility

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Contributed Properties as described in Note 1 for the years ended December 31, 2012 and 2011, in accordance with accounting principles generally accepted in the United States of America.

Emphasis of matter

As described in Note 1, the accompanying Statements are prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to be a complete presentation of the Contributed Properties' revenues and expenses. Our opinion is not modified with respect to this matter.

/s/ GRANT THORNTON LLP

Dallas, Texas

October 7, 2013

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CONTRIBUTED PROPERTIES

STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011 AND
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2013 AND 2012

	Nine Months Ended September 30,				For Years Ended December 31,

	2013		2012		2012		2011
	(Unaudited)
	(In thousands)
Operating revenues	$	41,347	$	25,515	$	34,639	$	21,254
Direct operating expenses		6,550		4,662		6,863		3,514

Revenues in excess of direct operating expenses	$	34,797	$	20,853	$	27,776	$	17,740

See notes to statements of operating revenues and direct operating expenses.

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CONTRIBUTED PROPERTIES

NOTES TO STATEMENTS OF OPERATING REVENUES AND
DIRECT OPERATING EXPENSES

NOTE 1—BASIS OF PRESENTATION

The accompanying statements present the revenues and direct operating expenses of working and revenue interests of certain oil and natural gas properties located in the Permian Basin of West Texas (the "Contributed Properties") contributed by Ted Collins Jr. ("Collins") and Wallace Family Partnership ("Wallace LP") to RSP Permian, Inc. immediately prior to the closing of RSP Permian, Inc.'s initial public offering for the years ended December 31, 2012 and 2011 and for the nine months ended September 30, 2013.

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America ("U.S. GAAP") are not presented as such information is not readily available on an individual property basis. Accordingly, the historical statements of revenues and direct operating expenses of the Contributed Properties are presented in lieu of the financial statements required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the financial statements, in conformity with U.S. GAAP, requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. It is possible these estimates could be revised at future dates and these revisions could be material.

Concentration of Credit Risk

Arrangements for crude oil and condensate, NGLs and natural gas sales are evidenced by signed contracts with determinable market prices and revenues are recorded when production is delivered. A significant majority of the purchasers of these products have investment grade credit ratings and there have been no material credit losses.

Revenue Recognition

Oil and natural gas revenue is recognized when the product is sold to a purchaser, delivery has occurred, written evidence of an arrangement exists, pricing is fixed and determinable and collectability of the revenue is reasonably assured. Oil and natural gas imbalances result when sales differ from the seller's net revenue interest in the particular property's reserves. As of September 30, 2013, the Company had no significant asset or liability recorded for oil and natural gas imbalances.

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)

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CONTRIBUTED PROPERTIES

NOTES TO STATEMENTS OF OPERATING REVENUES AND
DIRECT OPERATING EXPENSES (Continued)

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Continued)

production data and other geological, economic, ownership and engineering data provided and related to the reserves. No reports on these reserves have been filed with any federal agency. In accordance with the SEC's guidelines, estimates of proved reserves and the future net revenues from which present values are derived are based on an unweighted 12-month average of the first-day-of-the-month price for the period, held constant throughout the life of the properties. Operating costs, development costs and certain production-related taxes, which are based on current information and held constant, were deducted in arriving at estimated future net revenues.

	Year Ended December 31, 2012

	Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		35,550			12,588			—			18,513
Revisions of previous estimates		(30,755	)		(9,733	)		—			(14,859	)
Extensions, discoveries and other additions		8,030			5,081			2,436			8,856
Purchases of minerals in place		—			—			—			—
Production		(442	)		(346	)		(94	)		(513	)

End of year		12,383			7,590			2,342			11,997

Proved developed reserves:
Beginning of year		6,443			2,480			—			3,554
End of year		4,168			2,253			806			3,754
Proved undeveloped reserves:
Beginning of year		29,107			10,108			—			14,959
End of year		8,215			5,337			1,536			8,243

	Year Ended December 31, 2011

	Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		29,425			14,272			—			19,176
Revisions of previous estimates		5,529			(1,856	)		2			(933	)
Extensions, discoveries and other additions		888			377			—			525
Purchases of minerals in place		—			—			—			—
Production		(292	)		(205	)		(2	)		(255	)

End of year		35,550			12,588			—			18,513

Proved developed reserves:
Beginning of year		3,239			1,571			—			2,111
End of year		6,443			2,480			—			3,554
Proved undeveloped reserves:
Beginning of year		26,186			12,701			—			17,065
End of year		29,107			10,108			—			14,959

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CONTRIBUTED PROPERTIES

NOTES TO STATEMENTS OF OPERATING REVENUES AND
DIRECT OPERATING EXPENSES (Continued)

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Continued)

For the year ended December 31, 2012, the Contributed Properties' negative revision of 14,859 MBoe of previously estimated quantities is primarily due to a change in development strategy to replace 20-acre proved vertical well locations with non-proved horizontal well locations.

Standardized measure of discounted future net cash flows relating to proved reserves (dollars in thousands):

	2012			2011

	(In thousands)
Future cash inflows	$	802,351		$	1,452,926
Future production costs		(242,365	)		(288,150	)
Future development costs		(149,173	)		(201,060	)
Future income tax expenses		—			—

Future net cash flows		410,813			963,716
10% annual discount for estimated timing of cash flows		(262,738	)		(655,152	)

Standardized measure of discounted future net cash flows	$	148,075		$	308,564

Petroleum Product	2012		2011

Natural gas per Mcf	$	2.24	$	7.93
Crude oil per Bbl		91.06		93.04
NGLs per Bbl		35.16		—

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CONTRIBUTED PROPERTIES

NOTES TO STATEMENTS OF OPERATING REVENUES AND
DIRECT OPERATING EXPENSES (Continued)

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Continued)

The following reconciles the change in the standardized measure of discounted future net cash flows:

	2012			2011

	(In thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	308,564		$	229,345

Changes from:
Sales, less production costs		(27,776	)		(17,740	)
Revisions of previous quantity estimates		(247,662	)		(11,154	)
Extensions, discoveries and other additions		109,311			6,042
Net change in prices and production costs		(25,381	)		45,096
Changes in estimated future development costs		2,306			(3,909	)
Previously estimated development costs incurred during the period		13,809			25,783
Purchases of minerals in place		—			—
Accretion or discount		30,856			22,935
Net change in income taxes		—			—
Timing differences and other		(15,952	)		12,166

Standardized measure of discounted future net cash flows, end of year	$	148,075		$	308,564

NOTE 4—SUBSEQUENT EVENTS

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ANNEX A
GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

"Analogous Reservoir." Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

"API Gravity." A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.

"Basin." A large natural depression on the earth's surface in which sediments generally brought by water accumulate.

"Bbl." One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.

"Bbl/d." One Bbl per day.

"Bcf." One billion cubic feet of natural gas.

"Bcfe." One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas.

"Boe." One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

"Boe/d." One Boe per day.

"Btu." One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

"Completion." The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

"Delineation." The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

"Developed acreage." The number of acres that are allocated or assignable to productive wells or wells capable of production.

"Development Project." A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

"Development well." A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

"Differential." An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

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"Downspacing." Additional wells drilled between known producing wells to better exploit the reservoir.

"Dry natural gas." A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

"Dry hole" or "Dry well." A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

"Economically Producible." The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

"Estimated Ultimate Recovery" or "EUR." Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

"Exploitation." A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

"Exploratory well." A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

"Field." An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

"Formation." A layer of rock which has distinct characteristics that differs from nearby rock.

"Gross acres" or "gross wells." The total acres or wells, as the case may be, in which a working interest is owned.

"Horizontal drilling." A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

"MBbl." One thousand barrels of crude oil, condensate or NGLs.

"MBbls/d." One thousand Bbls per day.

"MBoe." One thousand Boe.

"Mcf." One thousand cubic feet of natural gas.

"Mcf/d." One Mcf per day.

"MMBbl." One million barrels of crude oil, condensate or NGLs.

"MMBtu." One million British thermal units.

"MMcf." One million cubic feet of natural gas.

"Net acres." The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

"Net Production." Production that is owned by us less royalties and production due others.

"Net Revenue Interest." A working interest owner's gross working interest in production less the royalty, overriding royalty, production payment and NPIs.

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"NGLs." Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

"NYMEX." The New York Mercantile Exchange.

"Offset operator." Any entity that has an active lease on an adjoining property for oil, natural gas or NGLs purposes.

"Operator." The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease. Play: A geographic area with hydrocarbon potential.

"Productive well." A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

"Prospect." A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

"Proved Developed Reserves." Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

"Proved reserves." The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

"Proved undeveloped reserves" or "PUDs." Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having PUDs only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

"Realized Price." The cash market price less all expected quality, transportation and demand adjustments.

"Recompletion." The completion for production of an existing wellbore in another formation from that which the well has been previously completed

"Reserve Life." A measure of the productive life of an oil and natural gas property for a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year end by production for that year.

"Reliable Technology." Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

"Reserves." Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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"Reserve Life." A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are based on annualized fourth quarter production and are adjusted, if necessary, to reflect property acquisitions and dispositions.

"Reservoir." A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

"Resources." Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

"Spacing." The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

"Spot Market Price." The cash market price without reduction for expected quality, transportation and demand adjustments.

"Standardized measure." Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

"Success Rate." The percentage of wells drilled which produce hydrocarbons in commercial quantities.

"Undeveloped acreage." Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

"Unit." The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

"Wellbore." The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

"Working interest." The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

"Workover." Operations on a producing well to restore or increase production.

"WTI." West Texas Intermediate.

The terms "analogous reservoir," "development project," "development well," "economically producible," "estimated ultimate recovery," "exploratory well," "proved developed reserves," "proved reserves," "proved undeveloped reserves," "reliable technology," "reserves" and "resources" are defined by the SEC.

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Shares

RSP Permian, Inc.

Common Stock

Prospectus

Barclays

J.P. Morgan

Tudor, Pickering, Holt & Co.

Until , all dealers that buy, sell or trade our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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Part II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts and commissions) payable by us in connection with the registration of the common stock offered hereby. With the exception of the SEC registration fee and the FINRA filing fee, the amounts set forth below are estimates.


SEC registration fee	$	59,248
FINRA filing fee		60,500
NYSE listing fee		*
Accounting fees and expenses		*
Legal fees and expenses		*
Printing and engraving expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*

Total	$		*

*: To be provided by amendment

Item 14. Indemnification of Directors and Officers

Section 145 of the DGCL provides that a corporation may indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise), against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. A similar standard is applicable in the case of derivative actions (i.e., actions by or in the right of the corporation), except that indemnification extends only to expenses, including attorneys' fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation.

Our amended and restated certificate of incorporation and amended and restated bylaws will contain provisions that limit the liability of our directors and officers for monetary damages to the fullest extent permitted by the DGCL. Consequently, our directors will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except liability:

•: for any breach of the director's duty of loyalty to our company or our stockholders;
•: for any act or omission not in good faith or that involve intentional misconduct or knowing violation of law;
•: under Section 174 of the DGCL regarding unlawful dividends and stock purchases; or
•: for any transaction from which the director derived an improper personal benefit.

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Any amendment to, or repeal of, these provisions will not eliminate or reduce the effect of these provisions in respect of any act, omission or claim that occurred or arose prior to that amendment or repeal. If the DGCL is amended to provide for further limitations on the personal liability of directors or officers of corporations, then the personal liability of our directors and officers will be further limited to the fullest extent permitted by the DGCL.

In addition, we intend to enter into indemnification agreements with our current directors and officers containing provisions that are in some respects broader than the specific indemnification provisions contained in the DGCL. These indemnification agreements will require us, among other things, to indemnify our directors against certain liabilities that may arise by reason of their status or service as directors and to advance their expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and officers.

We intend to maintain liability insurance policies that indemnify our directors and officers against various liabilities, including certain liabilities under arising under the Securities Act and the Exchange Act, that may be incurred by them in their capacity as such.

The proposed form of Underwriting Agreement filed as Exhibit 1.1 to this registration statement provides for indemnification of our directors and officers by the underwriters against certain liabilities arising under the Securities Act or otherwise in connection with this offering.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Item 15. Recent Sales of Unregistered Securities

In connection with this offering, 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), we will issue: (i) shares of our common stock to Rising Star in connection with the Rising Star Acquisition; (ii) , and shares of our common stock to Collins, Wallace LP and Collins & Wallace Holdings, LLC, respectively, in connection with the Collins and Wallace Contributions; (iii) shares to Pecos in connection with the Pecos Contribution; and (iv) shares to ACTOIL in connection with the ACTOIL NPI Repurchase. See "Recent and Formation Transactions—The Existing Investors" for the impact a change in the initial public offering price will have on the relative ownership of our common stock by the Rising Star, Collins, Wallace LP, Collins & Wallace Holdings, LLC, Pecos and ACTOIL.

The shares of our common stock described in this Item 15 will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(2) of the Securities Act as sales by an issuer not involving any public offering.

Item 16. Exhibits and Financial Statement Schedules

(a) Exhibits

Exhibit number		Description

1.1	*	Form of Underwriting Agreement
3.1	*	Form of Amended and Restated Certificate of Incorporation of RSP Permian, Inc.
3.2	*	Form of Amended and Restated Bylaws of RSP Permian, Inc.

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Exhibit number		Description

4.1	*	Form of Common Stock Certificate
4.2		Form of Stockholders' Agreement among RSP Permian, Inc., RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace Family Partnership, LP, Rising Star Energy Development Co., L.L.C. and Pecos Energy Partners, L.P.
4.3	*	Form of Registration Rights Agreement among RSP Permian, Inc., RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace Family Partnership, LP, ACTOIL, LLC, Rising Star Energy Development Co., L.L.C. and Pecos Energy Partners, L.P.
5.1	*	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
10.1	**	Amended and Restated Credit Agreement, dated September 10, 2013, by and between RSP Permian, L.L.C., as borrower, Comerica Bank, as administrative agent, and the lenders party thereto
10.2	*	Form of RSP Permian, Inc. 2014 Long-Term Incentive Plan
10.3	*	Form of Indemnification Agreement between RSP Permian, Inc. and each of the directors and officers thereof
10.4	*	Form of Contribution Agreement
21.1	**	Subsidiaries of RSP Permian, Inc.
23.1		Consent of Grant Thornton LLP
23.2		Consent of Grant Thornton LLP
23.3		Consent of Grant Thornton LLP
23.4		Consent of Grant Thornton LLP
23.5	**	Consent of Ryder Scott Company, L.P.
23.6	*	Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto)
23.7	**	Consent of Director Nominee
23.8	**	Consent of Director Nominee
23.9	**	Consent of Director Nominee
23.10		Consent of Director Nominee
24.1	**	Power of Attorney (included on the signature page of this Registration Statement)
99.1	**	Ryder Scott Company, L.P., Summary of Reserves at June 30, 2013
99.2	**	Ryder Scott Company, L.P., Summary of Reserves at June 30, 2013
99.3	**	Ryder Scott Company, L.P., Summary of Reserves at June 30, 2013
99.4	**	Ryder Scott Company, L.P., Summary of Reserves at June 30, 2013

*: To be filed by amendment.
**: Previously filed.

(b) Financial Statement Schedules. Financial statement schedules are omitted because the required information is not applicable, not required or included in the financial statements or the notes thereto included in the prospectus that forms a part of this registration statement.

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Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this Amendment No. 1 to the registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, State of Texas, on December 13, 2013.


		RSP PERMIAN, INC.
		By:		/s/ SCOTT MCNEILL Scott McNeill Chief Financial Officer and Director

Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons on December 13, 2013 in the capacities indicated.

Signature		Title


* Michael Grimm		Chairman of the Board
* Steven Gray		Chief Executive Officer and Director (Principal Executive Officer)
/s/ SCOTT MCNEILL Scott McNeill		Chief Financial Officer and Director (Principal Financial Officer and Principal Accounting Officer)
* David Albin		Director
*By:	/s/ SCOTT MCNEILL Scott McNeill Attorney-in-Fact

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INDEX TO EXHIBITS

Exhibit number		Description

1.1	*	Form of Underwriting Agreement
3.1	*	Form of Amended and Restated Certificate of Incorporation of RSP Permian, Inc.
3.2	*	Form of Amended and Restated Bylaws of RSP Permian, Inc.
4.1	*	Form of Common Stock Certificate
4.2		Form of Stockholders' Agreement among RSP Permian, Inc., RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace Family Partnership, LP, Rising Star Energy Development Co., L.L.C. and Pecos Energy Partners, L.P.
4.3	*	Form of Registration Rights Agreement among RSP Permian, Inc., RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace Family Partnership, LP, ACTOIL, LLC, Rising Star Energy Development Co., L.L.C. and Pecos Energy Partners, L.P.
5.1	*	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
10.1	**	Amended and Restated Credit Agreement, dated September 10, 2013, by and between RSP Permian, L.L.C., as borrower, Comerica Bank, as administrative agent, and the lenders party thereto
10.2	*	Form of RSP Permian, Inc. 2014 Long-Term Incentive Plan
10.3	*	Form of Indemnification Agreement between RSP Permian, Inc. and each of the directors and officers thereof
10.4	*	Form of Contribution Agreement
21.1	**	Subsidiaries of RSP Permian, Inc.
23.1		Consent of Grant Thornton LLP
23.2		Consent of Grant Thornton LLP
23.3		Consent of Grant Thornton LLP
23.4		Consent of Grant Thornton LLP
23.5	**	Consent of Ryder Scott Company, L.P.
23.6	*	Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto)
23.7	**	Consent of Director Nominee
23.8	**	Consent of Director Nominee
23.9	**	Consent of Director Nominee
23.10		Consent of Director Nominee
24.1	**	Power of Attorney (included on the signature page of this Registration Statement)
99.1	**	Ryder Scott Company, L.P., Summary of Reserves at June 30, 2013
99.2	**	Ryder Scott Company, L.P., Summary of Reserves at June 30, 2013
99.3	**	Ryder Scott Company, L.P., Summary of Reserves at June 30, 2013

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Exhibit number		Description

99.4	**	Ryder Scott Company, L.P., Summary of Reserves at June 30, 2013

*: To be filed by amendment.
**: Previously filed.

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RSP Permian, Inc. - FORM S-1/A - December 13, 2013

Attached files

RSP Permian, Inc. Reports