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

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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on July 25, 2014

Registration No. 333-196388

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

Amendment No. 2
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 (IRS Employer Identification Number)

3141 Hood Street, Suite 500
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 500
Dallas, Texas 75219
(214) 252-2700
(Name, address, including zip code, and telephone number, including area code, of agent for service)


Copies to:
Douglas E. McWilliams Christopher G. Schmitt Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 Houston, Texas 77002		J. Michael Chambers David J. Miller Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002

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

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

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

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

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

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


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

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered¹	Proposed Maximum Offering Price per Share²	Proposed Maximum Aggregate Offering Price^1,2	Amount of Registration Fee³




Common Stock, par value $0.01 per share	17,250,000	$31.93	$550,792,500.00	$70,942.08

¹: Includes shares of common stock that may be sold to cover the exercise of an option to purchase additional shares granted to the underwriters.
²: Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(c) under the Securities Act of 1933, as amended, and based on a price of $31.93, which is the average of the high and low trading prices per share as reported by the New York Stock Exchange on July 22, 2014.
³: The Registrant previously paid $32,136.12 of this amount on May 30, 2014 upon the initial filing of this Registration Statement and an additional $14,240.26 of this amount on June 26, 2014 upon filing Amendment No. 1 to this Registration Statement. The balance is being paid herewith.

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 July 25, 2014

PROSPECTUS

15,000,000 Shares

RSP Permian, Inc.

Common Stock

We are offering 6,000,000 shares of our common stock, and the selling stockholders identified in this prospectus are offering 9,000,000 shares of our common stock. We will not receive any proceeds from the sale of any shares by the selling stockholders.

Our common stock is listed on the New York Stock Exchange under the symbol "RSPP." On July 23, 2014, the last sale price of our common stock as reported on the New York Stock Exchange was $32.20 per share.

We are an emerging growth company as that term is used in the Jumpstart Our Business Startups Act of 2012 and have elected to take advantage of certain reduced public company reporting requirements. Please see "Prospectus Summary—Emerging Growth Company."

Investing in our common stock involves risks. See "Risk Factors" beginning on page 26.

	Per share	Total

Price to the public	$	$
Underwriting discounts and commissions¹	$	$
Proceeds to us (before expenses)	$	$
Proceeds to the selling stockholders (before expenses)	$	$

¹: We refer you to "Underwriting" beginning on page 165 of this prospectus for additional information regarding underwriting compensation.

We and certain selling stockholders have granted the underwriters the option to purchase up to an additional 900,000 and 1,350,000 shares of common stock, respectively, on the same terms and conditions set forth below if the underwriters sell more than 15,000,000 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 , 2014 through the book-entry facilities of The Depository Trust Company.

Barclays

Prospectus dated , 2014

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TABLE OF CONTENTS


PROSPECTUS SUMMARY		1
RISK FACTORS		26
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		51
USE OF PROCEEDS		53
MARKET PRICE OF OUR COMMON STOCK		54
DIVIDEND POLICY		55
CAPITALIZATION		56
DILUTION		57
SELECTED HISTORICAL AND PRO FORMA COMBINED FINANCIAL DATA		59
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		63
BUSINESS		93
MANAGEMENT		122
EXECUTIVE COMPENSATION		129
PRINCIPAL AND SELLING STOCKHOLDERS		138
OUR IPO AND RELATED TRANSACTIONS		146
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		149
DESCRIPTION OF CAPITAL STOCK		154
SHARES ELIGIBLE FOR FUTURE SALE		159
MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS		161
UNDERWRITING		165
LEGAL MATTERS		171
EXPERTS		171
WHERE YOU CAN FIND MORE INFORMATION		171
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 or on behalf of us or to 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."

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

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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, unless otherwise indicated, assumes that the underwriters do not exercise their option to purchase additional shares of common stock.

In connection with RSP Permian, Inc.'s initial public offering (our "IPO"), which was completed in January 2014, and pursuant to the terms of a corporate reorganization, all of the interests in RSP Permian, L.L.C. were exchanged for shares of common stock of RSP Permian, Inc. Additionally, in connection with our IPO, certain owners of working interests and net profits interests in RSP Permian, L.L.C.'s oil and natural gas properties contributed all or substantially all of such interests to RSP Permian, Inc. in exchange for, among other things, shares of common stock of RSP Permian, Inc. See "—Our IPO and Related Transactions" for more information regarding these contributions. These contributions, our IPO and the other transactions described in "—Our IPO and Related 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, RSP Permian, L.L.C.

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 330 vertical Wolfberry wells and served as the operator of over 190 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. We recently drilled our first successful horizontal well targeting the Wolfcamp A formation on a dual-well pad with a second completion into the Wolfcamp B formation, without any communication between the zones.

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horizontal zones on our properties, primarily from multi-well, multi-zone pads to increase our capital efficiency. We expect the remainder of our horizontal wells to be drilled in 2014 on multi-well pads that target multiple horizons on our properties. Currently, all four of our horizontal rigs are drilling from multi-well, multi-zone pads.

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, the combination of horizontal and vertical drilling enables us to hold our acreage through our continuous development program.

We are currently operating four horizontal rigs and two vertical rigs. We expect to add a fifth horizontal rig during the fourth quarter of 2014 and a sixth horizontal rig during the first quarter of 2015. We expect that approximately 75% 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 960 MBbls/d from over 80,000 wells during 2013, production from the Permian Basin represented 50% 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 "—Our IPO and Related 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 June 30, 2014, we had identified 1,572 horizontal drilling locations on our acreage based on approximately 750 to 1,050 foot spacing between wells in the same horizontal zone. Additionally, based on our evaluation of applicable geologic and engineering data, as of June 30, 2014, we had 280 identified vertical drilling locations on 40-acre spacing and an additional 645 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.

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through horizontal downspacing and 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 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 Locations¹

	Target Horizontal Locations²
	Short Laterals³		Long Laterals³		Total
Target Horizontal Zones⁴:
Middle Spraberry		117		295		412
Lower Spraberry		112		289		401
Wolfcamp A		77		149		226
Wolfcamp B		82		199		281
Wolfcamp D (Cline)		77		175		252


Total Target Horizontal Locations		465		1,107		1,572

	Vertical Locations

	40-acre		20-acre		Total
Vertical Locations		280		645		925


Total Target Horizontal and Vertical Locations						2,497	⁵

¹: Our total identified drilling locations include 313 locations associated with proved undeveloped reserves as of December 31, 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 approximately 750 to 1,050 foot spacing between wells in the same horizontal zone.
³: We define short laterals as horizontal lateral lengths ranging from approximately 4,500 to 5,500 feet and long laterals as horizontal lateral lengths ranging from approximately 6,500 to 10,000 feet. The average lateral length of our target horizontal locations is approximately 6,700 feet.
⁴: In addition to these target horizontal zones, we believe we have the potential to increase our multi-year drilling inventory through horizontal downspacing and with additional horizontal locations in the Clearfork, Jo Mill, Dean, Strawn, Atoka, Mississippian and Devonian formations.
⁵: As of June 30, 2014, seven and 103 of our 2,497 total target horizontal and vertical locations are associated with acreage that will expire in 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.

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Based on our current drilling schedule, we do not expect the acreage associated with any of our 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 December 31, 2013, none of our 313 locations associated with proved undeveloped reserves is associated with acreage that will expire prior to scheduled drilling.

During 2013, we spent approximately $216 million of capital, which included $170 million to drill and complete operated wells, $37 million for our participation in the drilling and completion of non-operated wells and $9 million on infrastructure. Our 2014 capital budget for drilling, completion, recompletion and infrastructure is approximately $425 million. Our capital budget excludes acquisitions. We intend to allocate our 2014 capital budget approximately as follows:

•: $360 million, or 85%, for the drilling and completion of operated wells;
•: $40 million, or 9%, for our participation in the drilling and completion of non-operated wells; and
•: $25 million, or 6%, for infrastructure.

As of March 31, 2014, we have spent approximately $57 million to drill and complete operated wells, $7 million for our participation in the drilling and completion of non-operated wells and $2 million on 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, NGLs and natural gas; 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 March 31, 2014, our average net daily production was 9,339 Boe/d (approximately 71% oil, 17% NGLs and 12% natural gas), of which 32% was from horizontal well production and 68% was from vertical well production. As of March 31, 2014, we produced from 35 horizontal and 501 vertical wells and were the operator of approximately 94% of our net acreage.

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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.

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 55,355 gross (40,086 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 Acreage¹

	Gross		Net
Target Horizontal Zones:
Middle Spraberry		53,306		38,370
Lower Spraberry		54,064		39,053
Wolfcamp A		34,255		21,645
Wolfcamp B		47,644		33,125
Wolfcamp D (Cline)		39,917		26,890


Total Effective Horizontal Acreage		229,186		159,083

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

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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 December 31, 2013, our estimated proved oil and natural gas reserves were 53,883 MBoe based on a reserve report prepared by Ryder Scott Company, L.P. ("Ryder Scott"), our independent reserve engineer. Of these reserves, approximately 40% were classified as proved developed producing ("PDP"). Proved undeveloped reserves ("PUDs") included in this estimate are from 290 vertical well locations and 23 horizontal well locations. As of December 31, 2013, these proved reserves were approximately 65% oil, 19% NGLs and 16% natural gas.

The following table provides summary information regarding our proved reserves as of December 31, 2013, and production for the three months ended March 31, 2014. As estimated by Ryder Scott, our estimated ultimate recoveries ("EURs") from our PUD horizontal drilling locations as of December 31, 2013 average 524 MBoe (approximately 70% oil, 16% NGLs and 14% natural gas) for our Wolfcamp B wells, which have an average assumed lateral length of approximately 6,000 feet, 652 MBoe (approximately 65% oil, 19% NGLs and 16% natural gas) for our Lower Spraberry wells, which have an average assumed lateral length of approximately 6,400 feet, and 428 MBoe (approximately 65% oil, 18% NGLs and 17% natural gas) for our Middle Spraberry wells, which have an average assumed lateral length of approximately 5,000 feet.

	Estimated Total Proved Reserves

	Oil (MMBbls)		Natural Gas (Bcf)		NGLs (MMBbls)		Total (MMBoe)		% Oil		% Liquids¹		% Developed		Average Net Production (Boe/d)		R/P Ratio (Years)²
Midland Basin		34.9		52.7		10.2		53.9		65		84		40		9,339³		15.8

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 March 31, 2014. 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 71% oil, 17% NGLs and 12% natural gas.

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 four horizontal drilling rigs focused on the Wolfcamp B and Lower Spraberry target zones and two vertical rigs targeting the Wolfberry play. We expect to add a fifth horizontal rig during the fourth quarter of 2014 and a sixth horizontal rig during the first quarter of 2015.
•: Apply horizontal drilling technology in multiple pay zones to increase production. In 2014, we plan to spend approximately 75% 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

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June 30, 2014, we had drilled or were currently drilling 36 horizontal wells as the operator and had participated in 39 additional horizontal wells as a non-operator. Of these 75 total horizontal wells, 49 are Wolfcamp B wells, three are Wolfcamp A wells, two are Wolfcamp D (Cline) wells, six are Middle Spraberry wells, 14 are Lower Spraberry wells and one is a Clearfork well.

•: Strengthen hydrocarbon recovery from vertical drilling and increased well density drilling. We believe our vertical drilling program complements our horizontal drilling program and generates attractive returns on invested capital. We also believe increased well density drilling opportunities exist across our acreage base for both our horizontal and vertical drilling programs. We closely monitor industry trends with respect to higher well density drilling, which could increase the recovery factor per section and provide additional attractive opportunities for capital deployment.
•: Pursue strategic acquisition opportunities with oil-weighted resource potential. We have made, and intend to continue to make, opportunistic acquisitions of acreage in the Permian Basin that have substantial oil-weighted resource potential from which we believe we can achieve attractive returns on invested capital. We evaluate acquisition opportunities on a variety of criteria, including expected rate of return, location, resource potential and the presence of multiple pay zones where we can utilize our horizontal drilling experience. We intend to grow our position around and within our concentrated acreage position in the Midland Basin through leasing activity and acquisitions.
•: Maintain a high degree of operational control in order to continuously improve operating and cost efficiencies. We seek operational control of our properties in order to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by continuous improvement of our drilling techniques, completion methodologies and reservoir evaluation processes. We expect the remainder of our 2014 horizontal development program to be drilled from multi-well, multi-zone pads to increase our capital efficiency. 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 87 miles of oil, natural gas and water transport lines to support gathering and transportation activities on our properties, operate ten water source wells drilled into the Santa Rosa formation in West Texas, operate four saltwater disposal wells on our properties, and have an additional saltwater disposal well in the completion 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.

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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 more than 800% 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 December 31, 2013, our estimated net proved reserves were comprised of approximately 65% oil, 19% NGLs and 16% natural gas. In the current commodity price environment, our oil and liquids-rich asset base provides attractive rates of return.
•: Contiguous acreage position with high degree of operational control. The vast majority of our acreage is located on contiguous blocks in what we believe to be the core of the Midland Basin. We believe this large, contiguous acreage position allows us to optimize our horizontal and vertical development programs to maximize our resource recovery on a per 640-acre 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 and use of multi-well, multi-zone pads, in order to optimize our well results, drilling costs and returns. As the operator of approximately 94% 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 June 30, 2014, we had identified 1,572 horizontal drilling locations on our acreage based on approximately 750 to 1,050 foot spacing between wells in the same horizontal zone. 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 1,572 identified horizontal drilling locations, 412 are in the Middle Spraberry horizon, 401 are in the Lower Spraberry horizon, 226 are in the Wolfcamp A horizon, 281 are in the Wolfcamp B horizon and 252 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

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our development program in 2010, we have participated in the drilling of over 330 vertical Wolfberry wells across our concentrated leasehold position. As of June 30, 2014, our vertical Wolfberry play drilling plan included 280 identified drilling locations based on 40-acre spacing and an additional 645 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. None of the members of our senior management are selling any shares in this offering.
•: Financial flexibility to fund expansion. We have a conservative balance sheet, which allows 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. As of July 23, 2014, we had $170.0 million of borrowings and $0.6 million of letters of credit outstanding under our revolving credit facility, providing $204.4 million of available borrowing capacity. After giving effect to this offering and the use of proceeds therefrom, we expect to have no borrowings and $0.6 million of letters of credit outstanding, and $374.4 million of borrowing capacity, under our revolving credit facility. 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 IPO and Related Transactions

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 subsequently contributed to us in connection with our IPO, 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").

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 Collins & Wallace Holdings, LLC, a newly-formed entity that contributed these acquired assets for shares of RSP Permian, Inc.'s common stock, as described in

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"—Corporate Formation Transactions—The Collins and Wallace Contributions." The exercise of the preferential purchase rights reduced our effective 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.

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 contributed 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 (8,092 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 a total of approximately 276 gross horizontal drilling locations on this acreage and additional contiguous acreage acquired in Dawson County during 2014 (see "—Recent Events—Acquisitions"), of which 92 are located in the Wolfcamp B zone, 92 are located in the Middle Spraberry zone and 92 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.

Our IPO

On January 23, 2014, we completed our IPO, selling 23 million shares of our common stock at $19.50 per share to the public. Of the 23 million shares sold to the public, 9.2 million shares were issued and sold by the Company and 13.8 million shares were sold by selling stockholders. Immediately following the closing of our IPO, common stock held by public holders represented approximately 32% of our outstanding common stock.

The net proceeds to us from our IPO were approximately $163 million. These proceeds were used to fully repay our $70 million term loan, reduce outstanding borrowings under our revolving credit facility, make cash payments as partial consideration for certain working interests in oil and natural gas properties contributed to us in conjunction with our IPO (which contributions are discussed below under "—Corporate Formation Transactions"), pay cash bonuses to certain of our employees, and fund a portion of our capital expenditure plan. We did not receive any proceeds from the sale of shares by the selling stockholders in our IPO.

In connection with our IPO, we entered into several transactions that changed the structure and scope of the Company. See "—Corporate Formation Transactions."

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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.

Pursuant to the terms of a corporate reorganization that was completed in connection with our IPO (i) the members of RSP Permian, L.L.C. contributed all of their interests in RSP Permian, L.L.C. to RSP Permian Holdco, L.L.C., a newly-formed entity wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. contributed all of its interests in RSP Permian, L.L.C. to RSP Permian, Inc. in exchange for approximately 28.5 million shares of common stock of RSP Permian, Inc., an assignment of RSP Permian, L.L.C.'s pro rata share of an escrow related to the Resolute Disposition and the right to receive approximately $27.7 million in cash. As a result of the reorganization, RSP Permian, L.L.C. became a wholly owned subsidiary of RSP Permian, Inc.

The Rising Star Acquisition. In connection with our IPO, we acquired from Rising Star Energy Development Co., L.L.C. ("Rising Star") working interests (the "Rising Star Assets") in certain acreage and wells in the Permian Basin in which RSP Permian, L.L.C. already had working interests (the "Rising Star Acquisition"). In exchange, Rising Star received approximately 1.8 million shares of RSP Permian, Inc.'s common stock and the right to receive approximately $1.7 million in cash. The Rising Star Acquisition increased our average working interest in approximately 3,250 gross acres and 36 gross producing wells in the Permian Basin. The Rising Star Assets represented substantially all of Rising Star's production and revenues for the year ended December 31, 2013.

The Collins and Wallace Contributions. Collins, Wallace LP and Collins & Wallace Holdings, LLC, a newly-formed entity that is owned equally by Collins and Wallace LP, contributed 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, (i) Collins received approximately 9.9 million shares of RSP Permian, Inc.'s common stock and the right to receive approximately $1.6 million in cash, (ii) Wallace LP received approximately 10.0 million shares of RSP Permian, Inc.'s common stock and the right to receive approximately $0.6 million in cash, and (iii) Collins & Wallace Holdings, LLC received approximately 2.2 million shares of RSP Permian, Inc.'s common stock. The Collins and Wallace Contributions occurred in connection with our IPO.

These contributed working interests consisted 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.

The Pecos Contribution. In connection with our IPO, Pecos Energy Partners, L.P. ("Pecos"), an entity owned by certain members of our management team, contributed 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 had working interests (the "Pecos Contribution"). In exchange, Pecos received approximately 0.1 million shares of RSP Permian, Inc.'s common stock.

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 "—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.

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

In connection with our IPO, ACTOIL contributed both 25% NPIs to us (the "ACTOIL NPI Repurchase") in exchange for approximately 10.8 million shares of RSP Permian, Inc.'s common stock.

Recent Events

Acquisitions

During the first quarter of 2014, we acquired additional acreage that we believe is prospective for horizontal development located in Martin, Glasscock and Dawson counties in Texas for an aggregate purchase price of approximately $79 million in three separate transactions, with approximately $69 million recorded as proved oil and natural gas properties. These transactions were financed with borrowings under our revolving credit facility. These transactions are described in further detail below:

•: In Martin County, we acquired a 17.5% non-operated working interest in producing properties located between our operated leasehold positions. The properties include 6,451 gross (1,125 net) acres, and net production, on a two-stream basis, averaged approximately 500 Boe/d (76% oil) for the month of March 2014 from 147 vertical wells. The operator of these properties has indicated it has identified 196 horizontal drilling locations in six target intervals, including the Middle Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B, Wolfcamp D (Cline) and Clearfork formations.
•: In Glasscock County, we acquired a 100% operated working interest in 961 acres of undeveloped leasehold. We have identified 28 horizontal locations on these properties in the Middle Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B and Wolfcamp D (Cline) formations.
•: In Dawson County, we acquired 3,766 gross (3,230 net) undeveloped acres in the same area as the assets acquired in the Verde Acquisition, bringing our total acreage in Dawson County to 13,389 gross (11,481 net) acres. We have identified approximately 61 additional net horizontal locations in the Middle Spraberry, Lower Spraberry and Wolfcamp A/B formations.

On July 25, 2014 we announced our entry into definitive agreements in separate transactions with multiple sellers to acquire certain undeveloped acreage and oil and natural gas producing properties located in Glasscock County (the "Pending Glasscock Acquisitions") for an approximate aggregate price of $259 million in cash, the substantial majority of which was to acquire undeveloped acreage. We will operate 100% of, and have approximately an 87% average working interest in, the properties to be acquired. The Pending Glasscock Acquisitions are expected to close in late August 2014 and are subject to the completion of customary due diligence, closing conditions and purchase price adjustments. We intend to use the net proceeds from this offering to fully repay amounts drawn under our revolving credit facility and expect to reborrow amounts under our revolving credit facility to fund a portion of the Pending Glasscock Acquisition. Please read "Use of Proceeds." In addition, following the closing of the Pending Glasscock Acquisition, we will evaluate the potential issuance of senior notes.

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on our internal reserve estimates, the properties contain net proved reserves of approximately 22 MBoe (approximately 9% developed). The foregoing information regarding the assets to be acquired in the Pending Glasscock Acquisitions is based solely on our internal evaluation and interpretation of reserve and other information provided to us by the sellers of those assets in the course of our due diligence with respect to the Pending Glasscock Acquisitions and has not been independently verified or estimated by our independent petroleum engineers or any other party.

The properties to be acquired are currently being developed with one vertical rig. We plan to keep operating this vertical rig on the acquired properties during the remainder of 2014 and 2015 and intend to initiate a horizontal drilling program in 2015 on the acquired properties. We believe the properties are prospective for horizontal drilling in the Company's target horizons, including the Lower Spraberry, Wolfcamp A, Wolfcamp B and Wolfcamp D (Cline) formations. In addition, we believe that additional horizontal drilling opportunities in several other stacked pay zones may be present on the properties.

RSP Permian Holdco, L.L.C.'s Distribution of RSP Permian, Inc. Common Stock

In connection with and immediately prior to this offering, RSP Permian Holdco, L.L.C. will distribute 10,235,712 shares of our common stock to its members (assuming a public offering price per common share of $32.20, which is the last sale price of our common stock as reported on the New York Stock Exchange (the "NYSE") on July 23, 2014). In the event the underwriters exercise their option to purchase additional shares in full, RSP Permian Holdco, L.L.C. will make an additional distribution of 1,697,594 shares of our common stock to its members (assuming a public offering price per common share of $32.20). The number of shares to be distributed is based, in part, on the public offering price of the common stock offered in this offering. A $1.00 increase or decrease in the assumed public offering price of $32.20 per share would cause the number of shares of our common stock to be distributed by RSP Permian Holdco, L.L.C. to increase or decrease, respectively, by less than 1%. Certain of those members, Michael G. Cook, Erik B. Daugbjerg, David Groves, William Huck, William Christopher Krusz, Robert Lemmon, Steve Smith and Leslyn Wallace, will sell all or a portion of the shares of our common stock distributed to them to the underwriters in this offering. One of RSP Permian Holdco, L.L.C.'s members, Production Opportunities II, L.P. ("Production Opportunities"), will immediately distribute the shares of our common stock distributed to it by RSP Permian Holdco, L.L.C. to its partners, including Natural Gas Partners IX, L.P., which will sell all such shares to the underwriters in this offering. None of the members of our senior management are selling any shares in this offering. See "Principal and Selling Stockholders" for more information. Prior to such distribution, RSP Permian Holdco, L.L.C. holds 16,285,481 shares, or 22.3%, of our common stock, and after such distribution and immediately following completion of this offering, RSP Permian Holdco, L.L.C. will hold 6,049,769 shares, or 7.7%, of our common stock, assuming no exercise of the underwriters' option to purchase additional shares of our common stock and 4,352,175 shares, or 5.5%, of our common stock, assuming full exercise of the underwriters' option to purchase additional shares of our common stock.

Summary Preliminary Financial Results and Production Data for the Second Quarter of 2014

Summary Preliminary Financial Results for the Three Months Ended June 30, 2014

Our management has prepared the summary preliminary financial results below based on the most current information available to management. Our normal closing and financial reporting processes with respect to the summary preliminary financial results for the three months ended June 30, 2014 have not been fully completed. As a result, our actual financial results could be different from these summary preliminary financial results, and any differences could be material. Our independent certified public accountants have not performed review procedures with respect to the summary preliminary financial results provided below, nor have they expressed any opinion or provided any other form of assurance on the these summary preliminary financial results. The summary preliminary financial results below have been prepared on a basis consistent with our unaudited consolidated financial statements for the three months ended March 31, 2014. This summary is not intended to be a comprehensive

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statement of our unaudited financial results for the three months ended June 30, 2014. The results of operations for an interim period, including the summary preliminary financial results provided below, may not give a true indication of the results to be expected for a full year or any future period.

For the three months ended June 30, 2014, we expect that our net income will be in the range of $7.8 million to $8.3 million and Adjusted EBITDAX will be in the range of $51.0 million to $53.7 million. As set out in the following table, for the three months ended June 30, 2014, we expect that our pro forma net income will be in the range of $8.6 million to $9.1 million and pro forma Adjusted EBITDAX will be in the range of $51.0 million to $53.7 million. For a definition of Adjusted EBITDAX, see "—Non-GAAP Financial Measure" below. The following table shows the reconciliation of net income to Adjusted EBITDAX on an actual basis and a pro forma basis for the three months ended June 30, 2014.

	RSP Permian, Inc.						RSP Permian, Inc. Pro Forma

	Low Estimate			High Estimate			Low Estimate			High Estimate
	(In thousands)
Adjusted EBITDAX reconciliation to net income:
Net income		7,815			8,226			8,621			9,075
Interest expense		1,085			1,142			1,085			1,142
Income tax expense (benefit)(1)		4,701			4,948			4,852			5,106
Depreciation, depletion and amortization		20,647			21,734			20,647			21,734
Exploration expense		1,171			1,233			1,171			1,233
Non-cash loss on derivatives		15,160			15,958			15,160			15,958
Net cash payments on settled derivatives		(1,441	)		(1,517	)		(1,441	)		(1,517	)
Non-cash equity based compensation(2)		1,582			1,665			625			658
Other (income)/expense		323			340			323			340


Adjusted EBITDAX(3)		51,043			53,729			51,043			53,729

(1): Pro forma income tax expense (benefit) is adjusted for a normalized effective tax rate.
(2): Pro forma non-cash equity based compensation excludes non-cash equity compensation associated with IPO bonuses and incentive units owned by certain management members.
(3): For a definition of Adjusted EBITDAX, see "—Non-GAAP Financial Measure" below.

Summary Production Results for the Three Months Ended June 30, 2014

On July 17, 2014, we reported that our average net daily production for the second quarter of 2014 was 10,714 Boe/d, representing a 15% increase over pro forma average net daily production for the three months ended March 31, 2014, which was 9,339 Boe/d.



Production Data:
Oil (MBbls)	687	594
NGLs (MBbls)	169	143
Natural gas (MMcf)	712	621


Total (Mboe)	975	841


Average net daily production (Boe/d)	10,714	9,339

(1): Represents our predecessor's production volumes for the first 22 days of the three months ended March 31, 2014 plus RSP Permian, Inc.'s volumes for the remainder of the period and does not

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include the production volumes related to the Verde Acquisition or Pecos Contribution for periods prior to the consummation of such transactions due to their lack of significance to our combined results.

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 26 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.
•: 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 four largest stockholders, RSP Permian Holdco, L.L.C., Collins, Wallace LP and ACTOIL (collectively, our "Principal Investors"), collectively hold approximately 66% of our common stock prior to this offering, and their interests may conflict with yours. After this offering, assuming no exercise of the underwriters' option to purchase additional shares of our common stock, our Principal Investors will collectively hold approximately 47.6% of our common stock.

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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, we are not required to comply with certain requirements that are applicable to other public companies that are not emerging growth companies. For example, as an emerging growth company, 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;
•: 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 disclosures 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.

We intend to take advantage of these reporting exemptions until we are no longer an emerging growth company. 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" under the rules promulgated under the Securities Exchange Act of 1934, as amended (the "Exchange Act");
•: 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 IPO.

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 500, Dallas, Texas 75219, and our telephone number at that address is (214) 252-2700. Our website address is www.rsppermian.com. Our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the "SEC") are 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		6,000,000 shares (or 6,900,000 shares, if the underwriters exercise in full their option to purchase additional shares).
Shares of common stock offered by the selling stockholders		9,000,000 shares (or 10,350,000 shares, if the underwriters exercise in full their option to purchase additional shares).
Option to purchase additional shares		We and certain selling stockholders have granted the underwriters an option to purchase up to an additional 900,000 or 1,350,000 shares of our common stock, respectively, to the extent the underwriters sell more than 15,000,000 shares of common stock in this offering.
Shares of common stock to be outstanding after this offering¹		78,963,951 shares or 79,863,951 shares (if the underwriters' option to purchase additional shares is exercised in full).
Use of proceeds		We estimate that, after deducting underwriting discounts and commissions and estimated offering expenses payable by us, we will receive approximately $185.6 million of net proceeds from this offering, or $213.6 million if the underwriters exercise their option to purchase additional shares in full, based on an assumed public offering price of $32.20 (which is the last reported sale price of our common stock on the NYSE on July 23, 2014). We intend to use the net proceeds from this offering to fully repay amounts drawn under our revolving credit facility and for general corporate purposes. We may at any time reborrow amounts repaid under our revolving credit facility, and we expect to do so to fund a portion of the Pending Glasscock Acquisitions. We will not receive any of the proceeds from the sale of the shares of common stock by the selling stockholders. Please read "Use of Proceeds."
Dividend policy		We do not currently pay, and do not anticipate paying in the future, 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."
Risk factors		You should carefully read and consider the information set forth under the heading "Risk Factors" beginning on page 26 and all other information set forth in this prospectus before deciding to invest in our common stock.
Listing and trading symbol		"RSPP."

¹: Includes 463,951 shares of restricted stock that have been awarded to our directors and certain of our employees and consultants, which are deemed non-dilutive under the two-class method associated with participating equity securities and therefore do not increase the diluted share count for financial reporting purposes.

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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.

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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. Except with respect to the summary historical financial data as of and for the three months ended March 31, 2014, 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, and summary unaudited pro forma combined financial data of RSP Permian, Inc. for the periods and as of the dates indicated. Summary historical financial data as of March 31, 2014 shows summary historical financial data of RSP Permian, Inc., and summary historical financial data for the three months ended March 31, 2014 includes 22 days of our predecessor's historical financial data plus RSP Permian, Inc.'s historical financial data for the remainder of the quarter. 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 December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 were derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The summary historical combined financial data of our predecessor as of December 31, 2011 was derived from the audited historical financial statements of our predecessor not included in this prospectus. The summary historical interim financial data of our predecessor for the three months ended March 31, 2013 were derived from the unaudited interim consolidated financial statements of our predecessor included elsewhere in this prospectus; the summary historical interim financial data of RSP Permian, Inc. for the three months ended March 31, 2014 were derived from the unaudited interim consolidated financial statements of our predecessor (for the first 22 days of such period) and of RSP Permian, Inc. (for the remainder of such period); and the summary historical interim financial data of RSP Permian, Inc. as of March 31, 2014 were derived from the unaudited interim consolidated financial statements of RSP Permian, Inc. included elsewhere in this prospectus.

The summary unaudited pro forma combined financial data of RSP Permian, Inc. for the three months ended March 31, 2014 and for the year ended December 31, 2013 were derived from the unaudited pro forma combined financial statements included elsewhere in this prospectus. The pro forma combined financial data assumes that our IPO and the transactions that were effected prior to, or in connection with, our IPO and described under "—Our IPO and Related 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 January 1, 2013. These transactions include:

•: the exclusion of the Rising Star assets and liabilities that we did not acquire 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," "Our IPO and Related Transactions," the historical combined financial statements of our predecessor, our historical financial

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

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

	RSP Permian, Inc.¹			Our Predecessor			Our Predecessor									RSP Permian, Inc. Pro Forma

	Three Months Ended March 31,															Three Months Ended March 31, 2014
							Year Ended December 31,
							Year Ended December 31,												Year Ended December 31, 2013
	2014			2013			2013			2012			2011						Year Ended December 31, 2013
	(Unaudited)															(Unaudited)
	(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil sales	$	51,471		$	21,923		$	110,345		$	91,441		$	56,772		$	55,930		$	177,415
NGL sales²		4,081			1,567			7,314			8,702			—			4,417			11,644
Natural gas sales		2,206			1,165			5,383			4,284			7,217			2,397			7,647


Total revenues	$	57,758		$	24,655		$	123,042		$	104,427		$	63,989		$	62,744		$	196,706


Operating expenses:
Lease operating expenses³	$	7,063		$	3,355		$	14,113		$	12,693		$	5,521		$	7,757		$	22,667
Production and ad valorem taxes		3,876			1,636			8,326			7,575			4,192			4,127			13,236
Depreciation, depletion and amortization		16,361			10,202			47,158			48,803			16,612			19,994			80,487
Asset retirement obligation accretion		29			25			121			115			46			38			199
Exploration expense³		756			63			551			161			191			756			551
Impairments		—			—			—			—			2,241			—			—
General and administrative expenses		17,016			555			3,852			2,859			3,509			2,064			3,716


Total operating expenses		45,101			15,836			74,121			72,206			32,312			34,736			120,856


(Gain) on sale of assets		—			(6,129	)		(22,700	)		(6,734	)		(105,333	)		—			—


Operating income	$	12,657		$	14,948		$	71,621		$	38,955		$	137,010		$	28,008		$	75,850


Other income (expense):
Other income	$	310		$	199		$	1,202		$	884		$	163		$	310		$	1,202
Loss on derivative instruments		(4,153	)		(1,657	)		(2,607	)		(796	)		(1,979	)		(4,153	)		(2,607	)
Interest expense		(1,131	)		(624	)		(5,216	)		(3,474	)		(3,472	)		(1,131	)		(10,890	)


Total other expense	$	(4,974	)	$	(2,082	)	$	(6,621	)	$	(3,386	)	$	(5,288	)	$	(4,974	)	$	(12,295	)


Income before taxes		7,683			12,866			65,000			35,569			131,722			23,033			63,555
Income tax (expense) benefit		(135,213	)		—			(2,262	)		339			(550	)		(8,292	)		(22,717	)


Net income (loss)	$	(127,530	)	$	12,866		$	62,738		$	35,908		$	131,172		$	14,741		$	40,838




Per share data:
Net earnings (loss) per common share:
Basic and diluted⁴	$	(2.03	)													$	0.20		$	0.56
Weighted average common shares outstanding:
Basic and diluted⁴		62,904															72,500			72,500
Pro forma C corporation data (unaudited)⁵:
Net income (loss)	$	(127,530	)				$	62,738		$	35,908
Pro forma for income taxes		132,524						(22,586	)		(12,927	)


Pro forma net income (loss)	$	4,994					$	40,152		$	22,981

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	RSP Permian, Inc.¹			Our Predecessor			Our Predecessor									RSP Permian, Inc. Pro Forma

	Three Months Ended March 31,															Three Months Ended March 31, 2014
							Year Ended December 31,
							Year Ended December 31,											Year Ended December 31, 2013
	2014			2013			2013			2012			2011					Year Ended December 31, 2013
	(Unaudited)															(Unaudited)
	(In thousands, except per share data)
Cash Flow Data:
Net cash provided by operating activities	$	31,001		$	14,585		$	73,345		$	72,803		$	26,243
Net cash provided by (used in) investing activities		(178,824	)		58,357			(119,591	)		(113,220	)		83,846
Net cash provided by (used in) financing activities		145,326			(94,456	)		8,248			81,583			(105,155	)
Other Financial Data:
Adjusted EBITDAX⁶	$	41,438		$	18,373		$	91,371		$	78,022		$	48,726		$	48,709	$	151,707

¹: Represents our predecessor's historical financial data for the first 22 days of the quarter plus RSP Permian, Inc.'s historical financial data for the remainder of the quarter.
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: Prior to 2014, exploration expense was included in lease operating expenses on our statement of operations. We have included exploration expense as a separate line item outside of lease operating expense for the 2013, 2012 and 2011 periods to conform to current period presentation.
⁴: The 421,999 outstanding shares of restricted stock outstanding as of March 31, 2014 are deemed non-dilutive under the two-class method associated with participating equity securities and therefore do not increase the diluted share count for financial reporting purposes.
⁵: 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 is subject to federal and State of Texas income taxes. The Company computed a pro forma income tax provision for the year ended December 31, 2013 and 2012 and the three months ended March 31, 2014, 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 January 1, 2012. 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.

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⁶: 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.

	RSP Permian, Inc.		Our Predecessor

			December 31,
	March 31, 2014		December 31,
	March 31, 2014		2013		2012		2011
	(Unaudited)
	(In thousands)
Balance Sheet Data:
Cash and cash equivalents	$	10,737	$	13,234	$	51,232	$	10,066
Other current assets		42,166		33,901		31,124		27,362


Total current assets		52,903		47,135		82,356		37,428
Property, plant and equipment, net		1,489,812		516,288		421,412		349,598
Other long-term assets		29,420		24,232		9,470		8,636


Total assets	$	1,572,135	$	587,655	$	513,238	$	395,662




Current liabilities		54,841		30,866		28,165		27,916
Long-term debt		110,000		128,155		111,586		46,586
NPI payable		—		36,931		16,583		—
Other long-term liabilities		337,327		4,822		3,061		3,225
Total members'/ stockholders' equity		1,069,967		386,881		353,843		317,935


Total liabilities and members'/ stockholders' equity	$	1,572,135	$	587,655	$	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, other income, 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.

	RSP Permian, Inc.¹			Our Predecessor			Our Predecessor									RSP Permian, Inc. Pro Forma

	Three Months Ended March 31,															Three Months Ended March 31, 2014
							Year Ended December 31,
							Year Ended December 31,												Year Ended December 31, 2013
	2014			2013			2013			2012			2011						Year Ended December 31, 2013
	(Unaudited)															(Unaudited)
	(In thousands)
Adjusted EBITDAX reconciliation to net income:
Net income (loss)	$	(127,530	)	$	12,866		$	62,738		$	35,908		$	131,172		$	14,741		$	40,838
Interest expense		1,131			624			5,216			3,474			3,472			1,131			10,890
Income tax expense (benefit)		135,213			—			2,262			(339	)		550			8,292			22,717
Depreciation, depletion and amortization		16,361			10,202			47,158			48,803			16,612			19,994			80,487
Exploration expense		756			63			551			161			191			756			551
Loss on derivative instruments		4,153			1,657			2,607			796			1,979			4,153			2,607
Net cash (payments) receipts on settled derivative instruments		(380	)		94			(886	)		(474	)		(856	)		(380	)		(886	)
Premiums paid for put options that settled during the period²		—			(830	)		(4,494	)		(2,804	)		(1,185	)		—			(4,494	)
Impairments		—			—			—			—			2,241			—			—
Non-cash equity based compensation		12,015			—			—			—			—			294			—
Asset retirement obligation accretion		29			25			121			115			46			38			199
Other income		(310	)		(199	)		(1,202	)		(884	)		(163	)		(310	)		(1,202	)
(Gain) on sale of assets		—			(6,129	)		(22,700	)		(6,734	)		(105,333	)		—			—


Adjusted EBITDAX	$	41,438		$	18,373		$	91,371		$	78,022		$	48,726		$	48,709		$	151,707

¹: Represents our predecessor's historical financial data for the first 22 days of the quarter plus RSP Permian, Inc.'s historical financial data for the remainder of the quarter.
²: 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 December 31, 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 Forma¹

	December 31, 2013
Proved Developed Reserves:
Oil (MBbls)		13,921
NGLs (MBbls)		3,965
Natural gas (MMcf)		21,008


Total proved developed reserves (MBoe)²		21,387
Proved developed reserves as a percentage of total proved reserves		39.7	%
Proved Undeveloped Reserves:
Oil (MBbls)		21,011
NGLs (MBbls)		6,207
Natural gas (MMcf)		31,665


Total proved undeveloped reserves (MBoe)		32,496
Total Proved Reserves:
Oil (MBbls)		34,932
NGLs (MBbls)		10,172
Natural gas (MMcf)		52,673


Total proved reserves		53,883
Oil and Natural Gas Prices:
Oil—NYMEX—WTI per Bbl	$	96.78
Natural gas—NYMEX—Henry Hub per MMBtu		3.67

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 Forma¹

	Three Months Ended March 31, 2014		Year Ended December 31, 2013
	(Unaudited)
Production and operating data:
Net production volumes:
Oil (MBbls)		594		1,867
NGLs (MBbls)		143		414
Natural gas (MMcf)		621		2,287


Total (MBoe)		841		2,662




Average net daily production (Boe/d)		9,339		7,293
Average sales price before effects of hedges^2,3
Oil (per Bbl)	$	94.21	$	95.01
NGLs (per Bbl)		30.82		28.16
Natural gas (per Mcf)		3.86		3.34


Average price per Boe	$	74.65	$	73.89
Average sales price after effects of hedges^2,3
Oil (per Bbl)	$	93.57	$	95.24
NGLs (per Bbl)		30.82		28.16
Natural gas (per Mcf)		3.86		3.34


Average price per Boe	$	74.19	$	74.06
Average unit costs per Boe:
Lease operating expenses	$	9.23	$	8.52
Production and ad valorem taxes		4.91		4.97
Depreciation, depletion and amortization		23.79		30.24
General and administrative expenses⁴		2.46		1.40

¹: Does not include the results related to the Verde Acquisition or the Pecos Contribution for periods prior to the consummation of such transactions due to their lack of significance to our combined results.
²: Average prices shown in the table reflect prices both before and after the effects of our cash payments/receipts on our commodity derivative transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period.
³: 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.
⁴: Pro forma general and administrative expenses do not include additional expenses we would have incurred as a result of being a public company for the entire period presented. In addition, non-recurring general and administrative expenses associated with non-cash compensation expense were excluded from the pro forma general and administrative expenses.

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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, NGLs and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil, NGLs and natural gas 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, NGLs and natural gas;
•: 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 Organization of the Petroleum Exporting 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, NGLs and natural gas 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. Our 2014 capital budget for drilling, completion, recompletion and infrastructure is approximately $425 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;

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•: make loans to others;
•: make investments;
•: merge or consolidate with another entity;
•: make certain payments;
•: hedge future production or interest rates;
•: incur liens;
•: sell assets; and
•: engage in certain other transactions without the prior consent of the lenders.

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

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

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

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based, among other things, upon projected revenues from, and asset values of, the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. The borrowing base under our revolving credit facility is currently $375 million, with lender commitments of $500 million.

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.

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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 March 31, 2014, we had entered into hedging contracts through December 31, 2015 covering a total of approximately 1,941 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 March 31, 2014, the estimated fair value of our commodity derivative contracts was a net liability of approximately $3.7 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

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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.

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 55,355 gross (40,086 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 June 30, 2014, we had identified 1,572 horizontal drilling locations on our acreage based on approximately 750 to 1,050 foot spacing between wells in the same horizontal zone. Additionally, based on our evaluation of applicable geologic and engineering data as of June 30, 2014, we had 280 identified vertical drilling locations on 40-acre spacing and an additional 645 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, NGLs and natural gas. 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.

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. Drought conditions have persisted in Texas over the past several years. 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 December 31, 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, NGLs or natural gas.

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 December 31, 2013, 60% 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 year ended December 31, 2013, four purchasers each accounted for more than 10% of our revenue: Plains Marketing, L.P. (13%), Shell Trading (US) Company (40%), Enterprise Crude Oil LLC (14%) and Diamondback E&P LLC (11%). For the year ended December 31, 2012, two purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (76%) and Coronado Midstream, LLC (11%). For the year ended December 31, 2011, one purchaser accounted for more than 10% of our revenue: Plains Marketing, L.P. (78%). 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.

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency ("EPA") and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements our business, prospects, financial condition or results of operations could be materially 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;

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•: title problems;
•: 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 as 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.

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

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

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, NGLs, natural gas 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 per day 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

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matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in "Business—Regulation of the Oil and Natural Gas Industry."

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

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction 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. 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. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, in 2013 the Obama administration 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 industry. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our exploration and production operations.

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

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("SDWA") over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, in May 2013, the Bureau of Land Management ("BLM") of the U.S. Department of the Interior published a revised proposed rule that would impose requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, as well as well bore integrity and handling of flowback water. 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. It is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations.

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 late 2014.

Further, in April 2012, the EPA published 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 in October 2012 and 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 are applicable to newly drilled and fractured wells and wells that are refractured on or after January 1, 2015. 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. The EPA received numerous requests for reconsideration of these rules and court challenges were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, in September 2013 the EPA published an amendment extending compliance dates for certain storage vessels. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. 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 water resources and expects to make the final report available for public comment and peer review by late 2014. 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 and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

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additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments 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.

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 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.

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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 July 23, 2014, outstanding borrowings subject to variable interest rates were approximately $170.0 million, and a 1.0% increase in interest rates would result in an increase in annual interest expense of approximately $1.7 million, assuming the $170.0 million in debt was outstanding for the full year, before the effects of 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.

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 2015 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

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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.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in 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

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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.

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 Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management.

We completed our IPO in January 2014. As a public company, we incur significant legal, accounting and other expenses that we did not incur as a private company. We also incur costs associated with our public company reporting requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. These rules and regulations will increase our legal and financial compliance costs and make some activities more time-consuming

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and costly, and we expect that these costs may increase further after we are no longer an "emerging growth company." These rules and regulations 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.

However, for as long as we remain an "emerging growth company" as defined in the JOBS Act, we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We intend to take advantage of these reporting exemptions until we are no longer an emerging growth company.

We will remain an emerging growth company for up to five years, although if the market value of our common stock that is held by non-affiliates exceeds $700 million as of any June 30 before that time, we would cease to be an "emerging growth company" as of the following December 31.

After we are no longer an "emerging growth company," we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not emerging growth companies.

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 price of our common stock in this offering may not be indicative of the market price of our common stock after this offering.

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 price of our common stock in this offering will be negotiated between us, the selling stockholders and representatives of the underwriters 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.

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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;
•: 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 described 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.

Our Principal Investors hold a substantial portion of our outstanding common stock.

Prior to this offering, our Principal Investors collectively hold approximately 66% of our common stock, and immediately following the completion of this offering, assuming no exercise of the underwriters' option to purchase additional shares of our common stock, our Principal Investors will collectively hold approximately 47.6% of our common stock. Furthermore, in connection with the closing of our IPO, we entered into a stockholders' agreement with RSP Permian Holdco, L.L.C., Collins, Wallace LP, Rising Star and Pecos. The stockholders' agreement provides 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. Prior to this offering, RSP Permian Holdco, L.L.C. has the right to designate two nominees and Collins and Wallace LP have the right to each designate one nominee. After this offering, assuming either no exercise or full exercise of the underwriters' option to purchase additional shares of our common stock, RSP Permian Holdco, L.L.C., Collins and Wallace LP will each have the right to designate one nominee. However, we expect the parties to the stockholders' agreement will waive the requirement to have a nominee of RSP Permian Holdco, L.L.C. tender his

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resignation to our board of directors, and as such, we expect the two directors originally designated by RSP Permian Holdco, L.L.C., David Albin and Scott McNeill, will continue to serve as directors after this offering. 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.

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

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

•: limitations on the removal of directors;
•: limitations on the ability of our stockholders to call special meetings;
•: establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;
•: providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and
•: establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders' ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action

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or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the "DGCL"), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder's ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Investors in this offering will experience immediate and substantial dilution of $16.21 per share.

The public offering price will be substantially higher than the net tangible book value per share of our common stock. Purchasers of our common stock in this offering will experience an immediate dilution of $16.21 per share, based on the assumed public offering price of $32.20 (the last reported sale price of our common stock on the NYSE on July 23, 2014). Further, investors purchasing common stock in this offering will contribute approximately 14.8% of the total amount invested by stockholders since our inception, but will own only approximately 7.6% of the shares of common stock outstanding. This dilution is due in large part to earlier investors having paid substantially less than the price of the shares being sold in this offering when they purchased their shares of our capital stock. Purchasers of our common stock in this offering will experience additional dilution upon the issuance of restricted stock to our employees under our equity incentive plans. In addition, we may utilize our common stock as consideration to fund future acquisitions, which could cause you to experience further dilution. See "Dilution."

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

Future sales of our common stock in the public market, or the perception that such sales may occur, 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 or convertible securities in subsequent public offerings. 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

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(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.

On February 4, 2014, we filed a registration statement with the SEC on Form S-8 providing for the registration of 10,000,000 shares of our common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions, the expiration or waiver of lock-up agreements and the requirements of Rule 144 under the Securities Act, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

Following the completion of this offering, and assuming no exercise of the underwriters' option to purchase additional shares, our Principal Investors will own 37,591,799 shares of our common stock, or approximately 47.6% of our total outstanding shares, all of which 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 Principal Investors are a party to a registration rights agreement, which requires us to effect the registration of their shares in certain circumstances. See "Certain Relationships and Related Party Transactions—Registration Rights Agreement."

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

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

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

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

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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 estimate that, after deducting underwriting discounts and commissions and estimated offering expenses payable by us, we will receive approximately $185.6 million of net proceeds from this offering, or $213.6 million if the underwriters exercise their option to purchase additional shares in full, based on an assumed public offering price of $32.20 (which is the last reported sale price of our common stock on the NYSE on July 23, 2014). Each $1.00 increase or decrease in the assumed public offering price would increase or decrease, respectively, our net proceeds by approximately $5.8 million, assuming that the number of shares offered by us, as listed on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase or decrease of one million shares we are offering would increase or decrease, as applicable, the net proceeds to us from this offering by approximately $31.1 million, after deducting the estimated underwriting discounts and estimated offering expenses payable by us, assuming the assumed public offering price stays the same. We will not receive any proceeds from the sale of shares by the selling stockholders.

We intend to use the net proceeds from this offering to fully repay amounts drawn under our revolving credit facility and for general corporate purposes. As of July 23, 2014, we had $170.0 million of borrowings and $0.6 million of letters of credit outstanding under our revolving credit facility. Upon repayment of the outstanding borrowings under our revolving credit facility, we will have $374.4 million of borrowing capacity under our revolving credit facility.

Our revolving credit facility matures on September 10, 2017 and bears interest at a variable rate, which was approximately 1.73% at March 31, 2014, and we incur a facility fee of 0.50% payable on the borrowing base amount. The outstanding borrowings under our revolving credit facility were incurred to fund a portion of our 2014 capital budget. We may at any time reborrow amounts repaid under our revolving credit facility, and we expect to do so to fund a portion of the Pending Glasscock Acquisitions.

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MARKET PRICE OF OUR COMMON STOCK

Our common stock began trading on the NYSE under the symbol "RSPP" on January 17, 2014. Prior to that, there was no public market for our common stock. The table below sets forth, for the periods indicated, the high and low sales prices per share of our common stock since January 17, 2014.

	High		Low

Third Quarter (through July 23, 2014)	$	32.94	$	27.02
Second Quarter	$	33.67	$	25.73
First Quarter¹	$	30.34	$	19.50

¹: For the period from January 17, 2014 through March 31, 2014.

On July 23, 2014, the closing price of our common stock was $32.20 per share. As of July 23, 2014, we had approximately eight holders of record of our common stock. This number excludes owners for whom common stock may be held in "street" name.

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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. We currently intend to retain future earnings, if any, for the development and growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our revolving credit facility places restrictions on our ability to pay cash dividends.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of March 31, 2014:

•: on an actual basis; and
•: as adjusted to give effect to this offering at an assumed public offering price of $32.20 per share (the last reported sale price of our common stock on July 23, 2014) as if it had occurred on March 31, 2014, assuming no exercise of the underwriters' option to purchase additional shares.

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 financial statements and the accompanying notes appearing elsewhere in this prospectus.

	March 31, 2014

	Actual			As Adjusted
	(In thousands, except number of shares and par value)
Cash and cash equivalents	$	10,737		$	86,372
Long-term debt, including current maturities:
Revolving credit facility¹		110,000			—
Term loan		—			—


Total indebtedness	$	110,000		$	—




Stockholders' equity:
Preferred stock—$0.01 par value; 15,000,000 shares authorized, no shares issued or outstanding		—			—
Common stock—$0.01 par value; 300,000,000 shares authorized, 72,500,000 shares issued and outstanding; 300,000,000 shares authorized, 78,500,000 shares issued and outstanding, as adjusted		725			785
Additional paid-in capital²		1,196,772			1,382,347
Accumulated deficit		(127,530	)		(127,530	)


Total stockholders' equity²		1,069,967			1,255,602




Total capitalization²	$	1,179,967		$	1,255,602

¹: As of March 31, 2014, the borrowing base was $300 million, the outstanding amount totaled $110.6 million, including $0.6 million of letters of credit outstanding, and we were able to incur approximately $189.4 million of additional indebtedness under our revolving credit facility. We intend to use the net proceeds from this offering to fully repay amounts drawn under our revolving credit facility. We may at any time reborrow amounts repaid under our revolving credit facility, and we expect to do so to fund a portion of the Pending Glasscock Acquisitions. See "Use of Proceeds."
²: A $1.00 increase or decrease in the assumed public offering price of $32.20 per share would increase or decrease, respectively, additional paid-in capital, total stockholders' equity and total capitalization by approximately $5.8 million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase or decrease of one million shares we are offering would increase or decrease, respectively, additional paid-in capital, total stockholders' equity and total capitalization by approximately $31.1 million, after deducting the estimated underwriting discounts and estimated offering expenses payable by us, assuming the assumed public offering price stays the same.

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DILUTION

If you invest in our common stock, your interest will be diluted to the extent of the difference between the public offering price per share of our common stock and the as adjusted net tangible book value (tangible assets less total liabilities) per share of our common stock immediately after this offering.

Our net tangible book value as of March 31, 2014 was approximately $1,070 million, or $14.76 per share.

After giving effect to the sale of 6,000,000 shares of common stock offered by us in this offering at an assumed public offering price of $32.20 (which is the last reported sale price of our common stock on the NYSE on July 23, 2014), after deducting underwriting discounts and commissions and estimated offering expenses payable by us, our as adjusted net tangible book value as of March 31, 2014 would have been approximately $1,256 million, or $15.99 per share. This represents an immediate increase in net tangible book value of $1.23 per share to our existing stockholders and an immediate dilution of $16.21 per share to investors purchasing common stock in this offering. The following table illustrates this dilution on a per share basis to new investors:


Assumed public offering price per share			$	32.20
Net tangible book value per share as of March 31, 2014	$	1,070
Increase in net tangible book value per share attributable to new investors purchasing shares in this offering		186


As adjusted net tangible book value per share after giving effect to this offering		1,256


Dilution in net tangible book value per share to new investors in this offering			$	16.21

Each $1.00 increase (decrease) in the assumed public offering price of $32.20 per share would increase (decrease) the as adjusted net tangible book value per share after this offering by approximately $1.31 and the dilution per share to new investors by approximately $17.13, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting 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. Each increase or decrease of one million shares we are offering would increase or decrease, as applicable, our as adjusted net tangible book value after this offering by approximately $31.1 million, or $0.19 per share, after deducting the estimated underwriting discounts and estimated offering expenses payable by us, assuming the assumed public offering price stays the same.

If the underwriters' option to purchase additional shares in this offering is exercised in full, the net tangible book value per share after giving effect to this offering would be approximately $16.17 per share, and the dilution in net tangible book value per share to investors in this offering would be approximately $16.03 per share.

The following table summarizes, as of March 31, 2014, the differences between existing stockholders and new investors in this offering with respect to the number of shares of common stock purchased from us, the total cash consideration paid to us, and the average price per share paid, based on an assumed public offering price of $32.20 per share, before deducting the estimated underwriting

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discounts and commissions and estimated offering expenses payable by us. the number of shares of our common stock purchased from us:

						Total Consideration

	Shares Purchased					Total Consideration
	Shares Purchased					Amount (in millions)					Average Price per Share
	Number		Percent			Amount (in millions)		Percent			Average Price per Share
Existing Investors		72,500,000		92.4	%	$	1,070		85.2	%	$	14.76
New Investors		6,000,000		7.6	%		186		14.8	%	$	30.94


Total		78,500,000		100.0	%	$	1,256		100	%	$	15.99

If the underwriters' option to purchase additional shares in this offering is exercised in full, our existing stockholders would own 91.3% and our new investors would own 8.7% of the total number of shares of our common stock outstanding after this offering.

The number of shares of our common stock reflected in the discussion and tables above is based on 72,500,000 shares of our common stock outstanding as of March 31, 2014, assumes the issuance and sale of 6,000,000 shares of our common stock and excludes shares of common stock reserved for future issuance under our equity incentive plan.

To the extent we issue additional shares of common stock in the future, there will be further dilution to investors participating in this offering.

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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 December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 were derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The selected historical combined financial data of our predecessor as of December 31, 2011 was derived from the audited historical financial statements of our predecessor not included in this prospectus. The selected historical interim financial data of our predecessor for the three months ended March 31, 2013 were derived from the unaudited interim consolidated financial statements of our predecessor included elsewhere in this prospectus; the selected historical interim financial data of RSP Permian, Inc. for the three months ended March 31, 2014 were derived from the unaudited interim consolidated financial statements of our predecessor (for the first 22 days of such period) and of RSP Permian, Inc. (for the remainder of such period); and the selected historical interim financial data of RSP Permian, Inc. as of March 31, 2014 were derived from the unaudited interim consolidated financial statements of RSP Permian, Inc. included elsewhere in this prospectus.

The selected unaudited pro forma combined financial data of RSP Permian, Inc. for the three months ended March 31, 2014 and for the year ended December 31, 2013 were derived from the unaudited pro forma combined financial statements included elsewhere in this prospectus. The pro forma combined financial data assumes that our IPO and the transactions that were effected in connection with our IPO and described under "Our IPO and Related 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 January 1, 2013. These transactions include:

•: the exclusion of the Rising Star assets and liabilities that we did not acquire 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.

	RSP Permian, Inc.¹			Our Predecessor			Our Predecessor									RSP Permian, Inc. Pro Forma

	Three Months Ended March 31,															Three Months Ended March 31, 2014
							Year Ended December 31,
							Year Ended December 31,												Year Ended December 31, 2013
	2014			2013			2013			2012			2011						Year Ended December 31, 2013
	(Unaudited)															(Unaudited)
	(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil sales	$	51,471		$	21,923		$	110,345		$	91,441		$	56,772		$	55,930		$	177,415
NGL sales²		4,081			1,567			7,314			8,702			—			4,417			11,644
Natural gas sales		2,206			1,165			5,383			4,284			7,217			2,397			7,647


Total revenues	$	57,758		$	24,655		$	123,042		$	104,427		$	63,989		$	62,744		$	196,706


Operating expenses:
Lease operating expenses³	$	7,063		$	3,355		$	14,113		$	12,693		$	5,521		$	7,757		$	22,667
Production and ad valorem taxes		3,876			1,636			8,326			7,575			4,192			4,127			13,236
Depreciation, depletion and amortization		16,361			10,202			47,158			48,803			16,612			19,994			80,487
Asset retirement obligation accretion		29			25			121			115			46			38			199
Exploration expense³		756			63			551			161			191			756			551
Impairments		—			—			—			—			2,241			—			—
General and administrative expenses		17,016			555			3,852			2,859			3,509			2,064			3,716


Total operating expenses		45,101			15,836			74,121			72,206			32,312			34,736			120,856


(Gain) on sale of assets		—			(6,129	)		(22,700	)		(6,734	)		(105,333	)		—			—


Operating income	$	12,657		$	14,948		$	71,621		$	38,955		$	137,010		$	28,008		$	75,850


Other income (expense):
Other income	$	310		$	199		$	1,202		$	884		$	163		$	310		$	1,202
Loss on derivative instruments		(4,153	)		(1,657	)		(2,607	)		(796	)		(1,979	)		(4,153	)		(2,607	)
Interest expense		(1,131	)		(624	)		(5,216	)		(3,474	)		(3,472	)		(1,131	)		(10,890	)


Total other income (expense)	$	(4,974	)	$	(2,082	)	$	(6,621	)	$	(3,386	)	$	(5,288	)	$	(4,974	)	$	(12,295	)


Income before taxes		7,683			12,866			65,000			35,569			131,722			23,033			63,555
Income tax (expense) benefit		(135,213	)		—			(2,262	)		339			(550	)		(8,292	)		(22,717	)


Net income (loss)	$	(127,530	)	$	12,866		$	62,738		$	35,908		$	131,172		$	14,741		$	40,838




Per share data (unaudited):
Net earnings (loss) per common share:
Basic and diluted⁴	$	(2.03	)													$	0.20		$	0.56
Weighted average common shares outstanding:
Basic and diluted⁴		62,904															72,500			72,500
Pro forma C corporation data (unaudited)⁵:
Net income (loss)	$	(127,530	)				$	62,738		$	35,908
Pro forma for income taxes		132,524						(22,586	)		(12,927	)


Pro forma net income (loss)	$	4,994					$	40,152		$	22,981

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	RSP Permian, Inc.¹			Our Predecessor			Our Predecessor									RSP Permian, Inc. Pro Forma

	Three Months Ended March 31,															Three Months Ended March 31, 2014
							Year Ended December 31,
							Year Ended December 31,											Year Ended December 31, 2013
	2014			2013			2013			2012			2011					Year Ended December 31, 2013
	(Unaudited)															(Unaudited)
	(In thousands, except per share data)
Cash Flow Data:
Net cash provided by operating activities	$	31,001		$	14,585		$	73,345		$	72,803		$	26,243
Net cash provided by (used in) investing activities		(178,824	)		58,357			(119,591	)		(113,220	)		83,846
Net cash provided by (used in) financing activities		145,326			(94,456	)		8,248			81,583			(105,155	)
Other Financial Data:
Adjusted EBITDAX⁶	$	41,438		$	18,373		$	91,371		$	78,022		$	48,726		$	48,709	$	151,707

¹: Represents our predecessor's historical financial data for the first 22 days of the quarter plus RSP Permian, Inc.'s historical financial data for the remainder of the quarter.
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: Prior to 2014, exploration expense was included in lease operating expenses on our statement of operations. We have included exploration expense as a separate line item outside of lease operating expense for the 2013, 2012 and 2011 periods to conform to current period presentation.
⁴: The outstanding shares of restricted stock are deemed non-dilutive under the two-class method associated with participating equity securities and therefore do not increase the diluted share count for financial reporting purposes.
⁵: 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 is subject to income taxes. The Company computed a pro forma income tax provision for the year ended December 31, 2013 and 2012 and the three months ended March 31, 2014, 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 January 1, 2012. 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.

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⁶: 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."

	RSP Permian, Inc.		Our Predecessor

			December 31,
	March 31, 2014		December 31,
	March 31, 2014		2013		2012		2011
	(Unaudited)
	(In thousands)
Balance Sheet Data:
Cash and cash equivalents	$	10,737	$	13,234	$	51,232	$	10,066
Other current assets		42,166		33,901		31,124		27,362


Total current assets		52,903		47,135		82,356		37,428
Property, plant and equipment, net		1,489,812		516,288		421,412		349,598
Other long-term assets		29,420		24,232		9,470		8,636


Total assets	$	1,572,135	$	587,655	$	513,238	$	395,662




Current liabilities		54,841		30,866		28,165		27,916
Long-term debt		110,000		128,155		111,586		46,586
NPI payable		—		36,931		16,583		—
Other long-term liabilities		337,327		4,822		3,061		3,225
Total members'/stockholders' equity		1,069,967		386,881		353,843		317,935


Total liabilities and members'/stockholders' equity	$	1,572,135	$	587,655	$	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, prior to the consummation of our IPO, did 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 our IPO, pursuant to the terms of a corporate reorganization, all of the interests in RSP Permian, L.L.C. were exchanged for shares of common stock of RSP Permian, Inc. and the right to receive approximately $27.7 million in cash. Also in connection with our IPO, Rising Star contributed to RSP Permian, Inc. working interests in certain acreage and wells in which RSP Permian, L.L.C. already had working interests in exchange for shares of RSP Permian, Inc.'s common stock and the right to receive approximately $1.7 million in cash. These contributed assets represented substantially all of Rising Star's production and revenues for each of the years ended December 31, 2013 and December 31, 2012. See "Our IPO and Related 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 our IPO and the transactions listed below, which were completed in connection therewith, had taken place on January 1, 2013:

•: the exclusion of the Rising Star assets and liabilities that we did not acquire 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 "Our IPO and Related 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 March 31, 2014, we had interests in 536 gross (279 net) producing wells across our properties. As of March 31, 2014, we operate approximately 94% of our net acreage. As of December 31, 2013, on a pro forma basis, our total estimated proved reserves were approximately 53,883 MBoe (approximately 65% oil, 19% NGLs and 16% natural gas), of which approximately 40% 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, NGLs and natural gas, including the effect of our commodity derivative contracts on our oil production;
•: lease operating expenses; and
•: Adjusted EBITDAX.

See "—Sources of Our 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 each of the three months ended March 31, 2014 and 2013, our revenues were derived 89% from oil sales. Natural gas sales accounted for approximately 4% and 5% of total sales for the three months ended March 31, 2014 and 2013, respectively. Our revenues from NGL sales for the three months ended March 31, 2014 and 2013 were 7% and 6%, respectively. For the years ended December 31, 2013, 2012 and 2011, our revenues were derived 90%, 88% and 89%, respectively, from oil sales and 4%, 4% and 11%, respectively, from natural gas sales. Our revenues from NGL sales for the years ended December 31, 2013 and 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 three months ended March 31, 2013 and 2012 and the years ended December 31, 2013, 2012 and 2011

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and our pro forma production volumes for the three months ended March 31, 2014 and the year ended December 31, 2013.

	RSP Permian, Inc.¹		Our Predecessor		Our Predecessor							RSP Permian, Inc. Pro Forma

	For the Three Months Ended March 31,											For the Three Months Ended March 31, 2014
	For the Three Months Ended March 31,						For the Years Ended December 31, 2012							For the Year Ended December 31, 2013
	2014		2013		2013		For the Years Ended December 31, 2012		2011					For the Year Ended December 31, 2013
Oil (MBbls)		544		259		1,167		1,040		618			594		1,867
NGLs (MBbls)		133		60		250		264		—	²		143		414
Natural gas (MMcf)		573		426		1,597		1,576		971			621		2,287


Total (MBoe)		772		390		1,683		1,567		780			841		2,662
Average net daily production (Boe/d)		8,578		4,333		4,611		4,281		2,137			9,339		7,293

¹: Represents our predecessor's production volumes for the first 22 days of the quarter plus RSP Permian, Inc.'s volumes for the remainder of the quarter.
²: 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, NGLs and Natural Gas

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.

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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 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.

	Three Months Ended March 31,						Year Ended December 31,

	2014			2013			2013			2012			2011
Oil:
NYMEX WTI High	$	104.92		$	97.94		$	110.53		$	109.77		$	113.93
NYMEX WTI Low		91.66			90.12			86.68			77.69			75.67
Average NYMEX WTI		98.61			94.41			98.02			94.15			95.11
Differential to Average NYMEX WTI		(4.01	)		(9.76	)		(3.47	)		(6.23	)		(3.27	)
NGLs:
NGL Realized Price as a % of Average NYMEX WTI		31	%		28	%		30	%		35	%		—	¹
Natural Gas:
NYMEX Henry Hub High	$	6.15		$	4.07			4.46		$	3.90		$	4.85
NYMEX Henry Hub Low		4.01			3.11			3.11			1.91			2.99
Average NYMEX Henry Hub		4.72			3.48			3.73			2.83			4.03
Differential to Average NYMEX Henry Hub		(0.87	)		(0.74	)		(0.36	)		(0.11	)		—	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 or the percentage of average NYMEX WTI are numbers that are not meaningful.

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the three months ended March 31, 2014, the NYMEX WTI prompt month oil price ranged from a high of $104.92 per Bbl to a low of $91.66 per Bbl, while the NYMEX Henry Hub prompt month natural gas price ranged from a high of $6.15 per MMBtu to a low of $4.01 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; however, we have recently added to our commodity derivative portfolio certain natural gas collars on approximately 60% of our reasonably anticipated natural gas production volumes for the remainder of 2014. 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 commodity 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 commodity 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

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different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our production.

Our open positions as of March 31, 2014 were as follows:

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

Crude Oil Swaps:
April 2014 - December 2014	90,000	$	—	$	—	$	96.40
April 2014 - December 2015	210,000		—		—		92.60
Crude Oil Collars:
April 2014 - September 2014	6,000	$	85.00	$	113.04	$	—
April 2014 - December 2014	738,000		85.79		102.11		—
April 2014 - December 2015	525,000		85.00		95.00		—
July 2014 - September 2014	90,000		90.00		101.50		—
October 2014 - December 2014	90,000		90.00		97.33		—
January 2015 - March 2015	120,000		90.00		92.53		—
January 2015 - December 2015	72,000		80.00		93.25		—

		Weighted Average Floor price ($/MMBtu)²		Weighted Average Ceiling price ($/MMBtu)²		Weighted Average Swap price ($/MMBtu)²

Natural Gas Collars:
April 2014 - December 2014	1,350,000	$	4.00	$	4.78	$	—

¹: The crude oil derivative contracts are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude.
²: The natural gas derivative contracts are settled based on the NYMEX closing settlement price.

Subsequent to March 31, 2014, we entered into the following oil and natural gas commodity hedges:

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

Crude Oil Collars:
October 2014 - December 2014	150,000	$	90.00	$	103.37	$	—
January 2015 - March 2015	75,000		90.00		96.68		—
January 2015 - June 2015	240,000		90.00		96.00		—
January 2015 - December 2015	1,260,000		86.19		94.72		—

¹: The crude 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.

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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, NGLs and natural gas based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil, NGL and natural gas 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 2013 Fiscal Year-End."

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At such time that the occurrence of the performance conditions associated with these incentive units are deemed probable, we record a non-cash compensation expense based upon the grant date fair value of the incentive units that are probable of reaching payout as a result of reaching established distribution thresholds. As of December 31, 2013, the unrecognized non-cash compensation expense associated with all tiers of the incentive units is approximately $16.2 million. After the successful completion of our IPO, the performance conditions associated with the Tier I, Tier I A, and Tier II incentive units were deemed probable of reaching payout, which resulted in the recognition of non-cash compensation expense of approximately $11.2 million in the first quarter of 2014. The Tier I A and Tier II incentive units have a remaining unrecognized non-cash compensation expense of approximately $1.5 million which will be amortized over the remaining service period and result in a $0.7 million non-cash compensation expense in the remainder of 2014 and $0.8 million in 2015. The remaining unrecognized non-cash compensation expense related to the Tier III and Tier IV incentive units is approximately $3.5 million and will be recognized when it is deemed that the Tier III and Tier IV incentive units are probable of reaching payout as a result of reaching the established distribution thresholds. Please read "Executive Compensation—Outstanding Equity Awards at 2013 Fiscal Year-End" for more information on the incentive units.

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 had a term loan that was fully repaid with a portion of the net proceeds from our IPO. The term loan was used to partially fund our acquisition of the Spanish Trail Assets. We reflect interest paid to the lenders under our revolving credit facility and term loan in interest expense.

Adjusted EBITDAX

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

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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:

Our IPO and Related Transactions

The historical results of operations from before our IPO 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 "Our IPO and Related Transactions," which will increase the scope of our operations.

Public Company Expenses

We 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 for the years ended December 31, 2013, 2012 and 2011 or the three months ended March 31, 2013.

Income Taxes

Our predecessor was not subject to federal income taxes. Accordingly, the financial data attributable to our predecessor contain no provision for federal income taxes because the tax liability with respect to our taxable income was passed through to our predecessor's members. Our predecessor was subject to State of Texas franchise taxes at less than 1% of modified pre-tax earnings. We are taxed as a C-corp under the Code and subject to income taxes at a blended statutory rate of 35% of pretax earnings.

Increased Drilling Activity

Our board of directors has approved a capital budget for 2014 of $425 million, of which $400 million is allocated for drilling and completion and $25 million is allocated for infrastructure. We expect that approximately 75% of our total drilling and completion expenditures in 2014 will be allocated to the drilling of horizontal wells. Our 2014 capital budget represents a 97% increase over the $216 million of capital spent during 2013. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results.

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Historical Results of Operations

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Oil, NGL and Natural Gas 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:

	Three Months Ended March 31,

	2014		2013		$ Change		% Change
	(Unaudited)
Revenues (in thousands, except percentages):
Oil sales	$	51,471	$	21,923	$	29,548		135	%
NGL sales		4,081		1,567		2,514		160	%
Natural gas sales		2,206		1,165		1,041		89	%


Total revenues	$	57,758	$	24,655	$	33,103		134	%




Average sales prices:
Oil (per Bbl) (excluding impact of cash settled derivatives)	$	94.60	$	84.64	$	9.96		12	%
Oil (per Bbl) (after impact of cash settled derivatives)		93.91		85.01		8.90		10	%
NGLs (per Bbl)		30.79		26.12		4.67		18	%
Natural gas (per Mcf)		3.85		2.73		1.12		41	%


Total (per Boe) (excluding impact of cash settled derivatives)	$	74.82	$	63.22	$	11.60		18	%
Total (per Boe) (after impact of cash settled derivatives)	$	74.32	$	63.46	$	10.86		17	%




Production:
Oil (MBbls)		544		259		285		110	%
NGLs (MBbls)		133		60		73		122	%
Natural gas (MMcf)		573		426		147		34	%


Total (MBoe)		772		390		382		98	%




Average daily production volume:
Oil (Bbls/d)		6,045		2,878		3,167		110	%
NGLs (Bbls/d)		1,472		667		805		120	%
Natural gas (Mcf/d)		6,363		4,733		1,630		34	%


Total (Boe/d)		8,578		4,333		4,245		98	%

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

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

	Three Months Ended March 31,

	2014			2013
Average realized oil price ($/Bbl)	$	94.60		$	84.64
Average NYMEX ($/Bbl)		98.61			94.41
Differential to NYMEX		(4.01	)		(9.76	)
Average realized oil price to NYMEX percentage		96	%		90	%
Average realized NGL price ($/Bbl)	$	30.79		$	26.12
Average NYMEX ($/Bbl)		98.61			94.41
Average realized NGL price to NYMEX percentage		31	%		28	%
Average realized natural gas price ($/Mcf)	$	3.85		$	2.73
Average NYMEX ($/Mcf)		4.72			3.48
Differential to NYMEX		(0.87	)		(0.74	)
Average realized natural gas price to NYMEX percentage		82	%		79	%

Our average realized oil price as a percentage of the average NYMEX price increased to 96% for the three months ended March 31, 2014 as compared to 90% for the three months ended March 31, 2013. All of our oil contracts are impacted by the NYMEX differential, which was negative $4.01 per Bbl for the three months ended March 31, 2014 as compared to negative $9.76 per Bbl for the three months ended March 31, 2013. Our average realized natural gas price as a percentage of the average NYMEX price was 82% for the three months ended March 31, 2014 and 79% for the three months ended March 31, 2013.

Oil revenues increased 135% from $21.9 million for the three months ended March 31, 2013 to $51.5 million for the three months ended March 31, 2014 as a result of a $9.96 per Bbl increase in our average realized price for oil, compounded by an increase in oil production volumes of 285 MBbls. Our higher oil production was a result of increased production from our horizontal drilling program, the Spanish Trail Acquisition in September 2013, the Collins and Wallace Contributions in January 2014 and the acquisition of producing properties in Martin County in February 2014. This increase was offset by the sale of working interests in 80 producing wells to Resolute in March 2013, which accounted for approximately 28% of total production for the three months ended March 31, 2013.

NGL revenues increased 160% from $1.6 million for the three months ended March 31, 2013 to $4.1 million for the three months ended March 31, 2014 as a result of a $4.67 per Bbl increase in our average realized NGL price and a 122% increase in production. Our higher average realized NGL price and higher production were due to the recent expansion of the processing capacity of Coronado Midstream, LLC's natural gas processing plant.

Natural gas revenues increased 89% from $1.2 million for the three months ended March 31, 2013 to $2.2 million for the three months ended March 31, 2014 as a result of an increase in natural gas production volumes of 147 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 along with our Spanish Trail Acquisition in September 2013, the Collins and Wallace Contributions in January 2014 and the acquisition of producing properties in Martin County in February 2014 offset by the sale of working interests in 80 producing wells to Resolute in March 2013, which accounted for approximately 28% of total production for the three months ended March 31, 2013.

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

	Three Months Ended March 31,

	2014		2013			$ Change			% Change
	(Unaudited)
Operating expenses (in thousands, except percentages):
Lease operating expenses	$	7,063	$	3,355		$	3,708			111	%
Production and ad valorem taxes		3,876		1,636			2,240			137	%
Depreciation, depletion and amortization		16,361		10,202			6,159			60	%
Asset retirement obligation accretion		29		25			4			16	%
Exploration expense¹		756		63			693			1,100	%
General and administrative expenses		17,016		555			16,461			2,966	%


Total operating expenses before gain on sale of assets	$	45,101	$	15,836		$	29,265			185	%




(Gain) on sale of assets		—		(6,129	)		6,129			NM
Total operating expenses after gain on sale of assets		45,101		9,707			35,394			365	%
Expenses per Boe:
Lease operating expenses	$	9.15	$	8.60			0.55			6	%
Production and ad valorem taxes		5.02		4.19			0.83			20	%
Depreciation, depletion and amortization		21.19		26.16			(4.97	)		(19	)%
Asset retirement obligation accretion		0.04		0.06			(0.02	)		(33	)%
Exploration expense¹		0.98		0.16			0.82			513	%
General and administrative expenses		22.04		1.42			20.62			1,452	%


Total operating expenses per Boe	$	58.42		40.59		$	17.83			44	%

¹: Prior to 2014, exploration expense was included in lease operating expenses on our statement of operations. We have included exploration expense as a separate line item outside of lease operating expense for the 2013 period to conform to current period presentation.

Lease Operating Expenses. Lease operating expenses increased 111% from $3.4 million for the three months ended March 31, 2013 to $7.1 million for the three months ended March 31, 2014. The increase in our lease operating expense was attributable to the increase in production in the 2014 period along with higher workover costs, as we performed more workovers in the current period primarily related to wells affected by severe winter weather in the previous quarter.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 137% from $1.6 million for the three months ended March 31, 2013 to $3.9 million for the three months ended March 31, 2014 primarily as a result of higher wellhead revenues.

Depreciation, Depletion and Amortization. DD&A expense increased 60% from $10.2 million for the three months ended March 31, 2013 to $16.4 million for the three months ended March 31, 2014 mainly due to increased production and the property acquisitions in conjunction with the IPO. The DD&A rate decreased 19% from $26.16 per Boe for the three months ended March 31, 2013 to $21.19 per Boe for the three months ended March 31, 2014 due to the increase in our proved reserves associated with contributed properties more than offsetting the amount of the purchase price of these assets that is allocated to our depletable property pool.

Exploration Expenses. Exploration expense increased by $0.7 million from less than $0.1 million for the three months ended March 31, 2013 to $0.8 million for the three months ended March 31, 2014 due to additional collection and analysis of geophysical and seismic data in the 2014 period.

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General and Administrative Expenses. General and administrative ("G&A") expenses increased from $0.6 million for the three months ended March 31, 2013 to $17.0 million for the three months ended March 31, 2014 primarily due to increases in expensing non-cash incentive unit compensation and equity-based compensation and increases in compensation expense associated with additions to personnel.

Gain on Sale of Assets. Gain on sale of assets was $6.1 million for the three months ended March 31, 2013 as a result of the property sale to Resolute in March 2013. There were no asset sales in the three months ended March 31, 2014.

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

	Three Months Ended March 31,

	2014			2013			$ Change			% Change
	(Unaudited)
Other income (expense) (in thousands, except percentages):
Other income	$	310		$	199		$	111			56	%
Loss on derivative instruments		(4,153	)		(1,657	)		(2,496	)		151	%
Interest expense		(1,131	)		(624	)		(507	)		81	%


Total other income (expense)	$	(4,974	)	$	(2,082	)	$	(2,892	)		139	%

Other Income. Other income increased 56% from $0.2 million for the three months ended March 31, 2013 to $0.3 million for the three months ended March 31, 2014 primarily due to an increase in income related to water we sourced and sold to other working interest partners for use in completion activities.

Loss on Derivative Instruments. During the three months ended March 31, 2013, we recorded a $1.7 million loss as compared to a $4.2 million loss in the three months ended March 31, 2014. The change was a result of the future commodity price outlook during the three months ended March 31, 2014 as compared to 2013.

Interest Expense. During the three months ended March 31, 2013, we recorded $0.6 million of interest expense as compared to $1.1 million in the three months ended March 31, 2014. The change was primarily the result of additional borrowings under our revolving credit facility in the 2014 period.

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Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Oil, NGLs and Natural Gas 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,

	2013		2012		$ Change			% Change
Revenues (in thousands, except percentages):
Oil sales	$	110,345	$	91,441	$	18,904			21	%
NGL sales		7,314		8,702		(1,388	)		(16	)%
Natural gas sales		5,383		4,284		1,099			26	%


Total revenues	$	123,042	$	104,427	$	18,615			18	%




Average sales prices:
Oil (per Bbl) (excluding impact of cash settled derivatives)	$	94.55	$	87.92	$	6.63			8	%
Oil (per Bbl) (after impact of cash settled derivatives)		94.95		88.25		6.70			8	%
NGLs (per Bbl)		29.26		32.94		(3.68	)		(11	)%
Natural gas (per Mcf)		3.37		2.72		0.65			24	%


Total (per Boe) (excluding impact of cash settled derivatives)	$	73.11	$	66.65	$	6.46			10	%
Total (per Boe) (after impact of cash settled derivatives)	$	73.37	$	66.86	$	6.51			10	%




Production:
Oil (MBbls)		1,167		1,040		127			12	%
NGLs (MBbls)		250		264		(14	)		(5	)%
Natural gas (MMcf)		1,597		1,576		21			1	%


Total (MBoe)		1,683		1,567		116			7	%




Average daily production volumes:
Oil (Bbls/d)		3,197		2,842		355			13	%
NGLs (Bbls/d)		685		722		(37	)		(5	)%
Natural gas (Mcf/d)		4,375		4,305		70			2	%


Total (Boe/d)		4,611		4,281		330			8	%

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

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

	Year Ended December 31,

	2013			2012
Average realized oil price ($/Bbl)	$	94.55		$	87.92
Average NYMEX ($/Bbl)		98.02			94.15
Differential to NYMEX		(3.47	)		(6.23	)
Average realized oil price to NYMEX percentage		96	%		93	%
Average realized NGL price ($/Bbl)	$	29.26		$	32.94
Average NYMEX ($/Bbl)		98.02			94.15
Average realized NGL price to NYMEX percentage		30	%		35	%
Average realized natural gas price ($/Mcf)¹	$	3.37		$	2.72
Average NYMEX ($/Mcf)		3.73			2.83
Differential to NYMEX		(0.36	)		(0.11	)
Average realized natural gas price to NYMEX percentage		90	%		96	%

Our average realized oil price as a percentage of the average NYMEX price increased to 96% for the year of 2013 as compared to 93% for the year of 2012. All of our oil contracts are impacted by the NYMEX differential, which was negative $3.47 per Bbl in 2013 as compared to negative $6.23 per Bbl in 2012. Our average realized natural gas price as a percentage of the average NYMEX price was 96% for 2012 and 90% for 2013.

Oil revenues increased 21% from $91.4 million for the year ended December 31, 2012 to $110.3 million for the year ended December 31, 2013 as a result of a $6.63 per Bbl increase in our average realized price for oil, compounded by an increase in oil production volumes of 127 MBbls for the period. Our higher oil production was a result of increased production from our horizontal drilling program and the Spanish Trail acquisition in September 2013. Our production from our horizontal drilling program accounted for 15% of our total production for the year ended December 31, 2013 compared to 0% for the year ended December 31, 2012. This increase was partially offset by the sale working interests in of 80 producing wells to Resolute in March 2013, which accounted for 38% of total production for the year ended December 31, 2012 compared to 7% of total production for the year ended December 31, 2013.

NGL revenues decreased 16% from $8.7 million for year ended December 31, 2012 to $7.3 million for the year ended December 31, 2013 as a result of a $3.68 per Bbl decrease in our average realized NGL price and a 5% decrease in production. 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.

Natural gas revenues increased 26% from $4.3 million for the year ended December 31, 2012 to $5.4 million for the year ended December 31, 2013 as a result of an increase in natural gas production volumes of 21 MMcf and a $0.65 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 along with our Spanish Trail acquisition in September 2013 offset by the sale of working interests in 80 producing wells to Resolute in March 2013.

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

	Year Ended December 31,

	2013			2012			$ Change			% Change
Operating expenses (in thousands, except percentages):
Lease operating expenses¹	$	14,113		$	12,693		$	1,420			11	%
Production and ad valorem taxes		8,326			7,575			751			10	%
Depreciation, depletion and amortization		47,158			48,803			(1,645	)		(3	)%
Asset retirement obligation accretion		121			115			6			5	%
Exploration expense¹		551			161			390			242	%
General and administrative expenses		3,852			2,859			993			35	%


Total operating expenses before gain on sale	$	74,121		$	72,206		$	1,915			3	%




(Gain) on sale of assets		(22,700	)		(6,734	)		(15,966	)		NM
Total operating expenses after gain on sale	$	51,421		$	65,472		$	(14,051	)		(21	)%
Average unit costs per Boe:
Lease operating expenses¹	$	8.39		$	8.10		$	0.29			4	%
Production and ad valorem taxes		4.95			4.83			0.12			2	%
Depreciation, depletion and amortization		28.02			31.15			(3.13	)		(10	)%
Asset retirement obligation accretion		0.07			0.07			—			0	%
Exploration expense¹		0.33			0.10			0.23			230	%
General and administrative expenses		2.29			1.82			0.47			26	%


Total operating expenses per Boe	$	44.04		$	46.07		$	(2.03	)		(4	)%

¹: Prior to 2014, exploration expense was included in lease operating expenses on our statement of operations. We have included exploration expense as a separate line item outside of lease operating expense for the 2013 and 2012 periods to conform to current period presentation.

Lease Operating Expenses. Lease operating expenses increased 11% from $12.7 million for the year ended December 31, 2012 to $14.1 million for the year ended December 31, 2013. The increase in our average lease operating expenses was attributable to increased drilling activity, which resulted in additional producing wells for the year ended December 31, 2013 as compared to the year ended December 31, 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 10% from $7.6 million for the year ended December 31, 2012 to $8.3 million for the year ended December 31, 2013 primarily as a result of higher wellhead revenues.

Depreciation, Depletion and Amortization. DD&A expense decreased 3% from $48.8 million for the year ended December 31, 2012 to $47.2 million for the year ended December 31, 2013 due to a decrease in our per Boe DD&A rate. The DD&A rate decreased 10% from $31.15 per Boe for the year ended December 31, 2012 to $28.02 per Boe for the year ended December 31, 2013 as a result of additional drilling activity due to an addition of 115 wells during 2013 and the related increase in reserve estimates used in computing depletion.

General and Administrative Expenses. G&A expenses increased 35% from $2.9 million for the year ended December 31, 2012 to $3.9 million for the year ended December 31, 2013 primarily due to

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increases in advisory fees associated with our property sale to Resolute in March 2013 and asset purchase of Spanish Trail Assets in September 2013 and increases in compensation expense associated with additions to personnel.

Gain on Sale of Assets. Gain on sale of assets increased from a $6.7 million gain for the year ended December 31, 2012 to a $22.7 million gain for the year ended December 31, 2013 as a result of the property sale to Resolute in March 2013. See "Our IPO and Related Transactions—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,

	2013			2012			$ Change			% Change
Other income (expense) (in thousands, except percentages):
Other income	$	1,202		$	884		$	318			36	%
Gain (loss) on derivative instruments		(2,607	)		(796	)		(1,811	)		228	%
Interest expense		(5,216	)		(3,474	)		(1,742	)		50	%


Total other income (expense)	$	(6,621	)	$	(3,386	)	$	(3,235	)		96	%

Other Income. Other income increased 36% from $0.9 million for the year ended December 31, 2012 to $1.2 million for the year ended December 31, 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.

Loss on Derivative Instruments. During the year ended December 31, 2012, we recorded a $0.8 million loss as compared to $2.6 million loss in the year ended December 31, 2013. The change was a result of the future commodity price outlook during 2013 as compared to 2012.

Interest Expense. During the year ended December 31, 2012, we recorded $3.5 million of interest expense as compared to $5.2 million in the year ended December 31, 2013. The change was primarily the result of the accelerated amortization of deferred financing costs associated with our previous credit facility of $1.2 million into interest expense in 2013.

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

Oil, NGL and Natural Gas 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	%
NGL sales¹		8,702		—		NM			NM
Natural gas sales¹		4,284		7,217		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	)%
NGLs (per Bbl)¹		32.94		—		NM			NM
Natural gas (per Mcf)¹		2.72		7.44		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	%
NGLs (MBbls)¹		264		—		NM			NM
Natural gas (MMcf)¹		1,576		971		NM			NM


Total (MBoe)		1,567		780		787			101	%




Average daily production volumes:
Oil (Bbls/d)		2,842		1,694		1,148			68	%
NGLs (Bbls/d)¹		722		—		NM			NM
Natural gas (Mcf/d)¹		4,305		2,659		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 NGLs and natural gas between 2011 and 2012 is not meaningful.

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

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

	Year Ended December 31,

	2012			2011
Average realized oil price ($/Bbl)	$	87.92		$	91.84
Average NYMEX ($/Bbl)		94.15			95.11
Differential to NYMEX		(6.23	)		(3.27	)
Average realized oil price to NYMEX percentage		93	%		97	%
Average realized NGL price ($/Bbl)	$	32.94			—	¹
Average NYMEX ($/Bbl)		94.15		$	95.11
Average realized NGL price to NYMEX percentage		35	%		—	¹
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

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 price 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 NGL or natural gas 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
	(Unaudited)
Operating expenses (in thousands, except percentages):
Lease operating expenses¹	$	12,693		$	5,521		$	7,172			130	%
Production and ad valorem taxes		7,575			4,192			3,383			81	%
Depreciation, depletion and amortization		48,803			16,612			32,191			194	%
Asset retirement obligation accretion		115			46			69			150	%
Exploration expense¹		161			191			(30	)		(16	)%
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 expenses¹	$	8.10		$	7.08		$	1.02			14	%
Production and ad valorem taxes		4.83			5.37			(0.54	)		(10	)%
Depreciation, depletion and amortization		31.15			21.30			9.85			46	%
Asset retirement obligation accretion		0.07			0.06			0.01			17	%
Exploration expense¹		0.10			0.24			(0.14	)		(58	)%
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	%

¹: Prior to 2014, exploration expense was included in lease operating expenses on our statement of operations. We have included exploration expense as a separate line item outside of lease operating expense for the 2012 and 2011 periods to conform to current period presentation.

Lease Operating Expenses. Lease operating expenses increased 130% from $5.5 million in 2011 to $12.7 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 $1.02 per Boe to $8.10 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 81% from $4.2 million in 2011 to $7.6 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.

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

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

•: $360 million, or 85%, for the drilling and completion of operated wells;
•: $40 million, or 9%, for our participation in the drilling and completion of non-operated wells; and
•: $25 million, or 6%, for infrastructure.

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We used a portion of the net proceeds from our IPO to fully repay our term loan and outstanding borrowings under our revolving credit facility, and we intend to use the net proceeds from this offering to fully repay amounts drawn under our revolving credit facility. Our borrowing base under our revolving credit facility was $300 million as of March 31, 2014 and was increased to $375 million on June 9, 2014 in connection with our semiannual borrowing base redetermination. As of March 31, 2014 and July 23, 2014, we had $189.4 million and $204.4 million, respectively, available under our revolving credit facility. After giving effect to this offering (including the use of proceeds therefrom), we will have $374.4 million available under our revolving credit facility. We may at any time reborrow amounts repaid under our revolving credit facility, and we expect to do so to fund a portion of the Pending Glasscock Acquisitions.

Based upon current oil and natural gas price expectations for 2014, 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 negative $1.9 million and $16.3 million at March 31, 2014 and December 31, 2013, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $10.7 million and $13.2 million at March 31, 2014 and December 31, 2013, 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, NGLs 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, 2013 is provided in the following table.

	Our Predecessor

	Payments Due by Period For the Year Ended December 31,
	2014		2015		2016		2017		2018		Thereafter		Total
	(In thousands)
Revolving credit facility¹	$	—	$	—	$	—	$	58,155	$	—	$	—	$	58,155
Term loan		—		—		70,000		—		—		—		70,000
Drilling rig commitments²		15,690		—		—		—		—		—		15,690
Office and equipment leases		653		490		372		174		178		74		1,941
Asset retirement obligations³		—		—		—		—		—		2,584		2,584


Total	$	16,343	$	490	$	70,372	$	58,329	$	178		2,658	$	148,370

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.

We intend to use the net proceeds from this offering to reduce amounts drawn under our revolving credit facility. Please see "Use of Proceeds."
²: The values in the table represent the gross amounts that our predecessor is committed to pay.
³: 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.

As of March 31, 2014, there were no material changes in our contractual obligations, except with respect to our term loan, which we repaid in full on January 23, 2014. As of March 31, 2014, we have no contractual obligations with respect to our term loan.

Cash Flows

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

	RSP Permian, Inc.¹			Our Predecessor			Our Predecessor

	Three Months Ended March 31, 2014			Three Months Ended March 31, 2013
							Years Ended December 31,
							2013			2012			2011
	(Unaudited)
	(In thousands)
Net cash provided by operating activities	$	31,001		$	14,585		$	73,345		$	72,803		$	26,243
Net cash provided by (used in) investing activities		(178,824	)		58,357			(119,591	)		(113,220	)		83,846
Net cash provided by (used in) financing activities		145,326			(94,456	)		8,248			81,583			(105,155	)

¹: Represents our predecessor's historical financial data for the first 22 days of the quarter plus RSP Permian, Inc.'s historical financial data for the remainder of the quarter.

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Net cash provided by operating activities was approximately $31.0 million and $14.6 million for the three months ended March 31, 2014 and 2013, respectively. Revenues increased for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013. This increase was due to increased production related to properties acquired in the first quarter of 2014.

Net cash provided by operating activities was approximately $73.3 million and $72.8 million for the years ended December 31, 2013 and 2012, respectively. Revenues increased for the year ended December 31, 2013 as compared to the year ended December 31, 2012 as a result of increased production and the Spanish Trail acquisition in 2013. However, this increase was offset by changes in other assets and liabilities and, therefore, our net cash provided by operating activities was flat 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 $178.8 million for the three months ended March 31, 2014, and net cash provided by investing activities for the three months ended March 31, 2013 was approximately $58.4 million. The increase in the amount of cash used in investing activities in the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was due to capital expenditures totaling $177.5 million. These included the purchase of oil and gas assets for $80.0 million and $31.7 million for partial consideration of certain working interests in oil and gas properties contributed in conjunction with our IPO in the first quarter of 2014, offset by $115.3 million received from the sale of properties to Resolute in March 2013.

Net cash used in investing activities was approximately $119.6 million and $113.2 million for the years ended December 31, 2013 and 2012, respectively. The increase in the amount of cash used in investing activities in the year ended December 31, 2013 compared to the year ended December 31, 2012 is due to the purchase of the Spanish Trail assets for $90.4 million in September 2013 offset by $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 $145.3 million for the three months ended March 31, 2014 and net cash used in financing activities for the three months ended March 31, 2013 was approximately $94.5 million. For the three months ended March 31, 2014, the increased cash provided by financing activities was primarily the result of capital contributions received in connection with our IPO.

Net cash provided by financing activities was approximately $8.2 million and $81.6 million for the years ended December 31, 2013 and 2012, respectively. For the year ended December 31, 2013, the decreased cash provided by financing activities was primarily the result of incremental borrowings under long-term debt of $11.6 million offset by long-term debt repayments of $85.0 million and capital distributions of $30.0 million. For the year ended December 31, 2012, the cash provided by financing activities included $90.0 million in borrowings.

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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 Term Loan and Revolving Credit Facility

On September 10, 2013, in conjunction with the Spanish Trail Acquisition, we amended and restated our credit agreement, dated December 15, 2010, with Comerica Bank, as administrative agent, and expanded our syndicated bank group to 11 lenders and entered into a new term loan in the amount of $70 million, which was fully repaid in January 2014 with proceeds from our IPO. On June 9, 2014, we further amended our credit agreement to reflect an increase in the borrowing base under our revolving credit facility from $300 million to $375 million in connection with our semiannual borrowing base redetermination. As of June 9, 2014, we have lender commitments of $500 million and a sublimit for letters of credit of $10 million.

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, estimated cash flows from these reserves and our commodity hedge positions. As of March 31, 2014 and July 23, 2014, we had $110.0 million and $170.0 million, respectively, of borrowings and $0.6 million and $0.6 million, respectively, of letters of credit outstanding under our revolving credit facility. After giving effect to this offering and the use of proceeds therefrom, we expect to have no borrowings and $0.6 million of letters of credit outstanding under our revolving credit facility. Our revolving credit facility matures September 10, 2017.

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 at the end of each fiscal quarter thereafter;

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•: 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 March 31, 2014; 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 March 31, 2014.

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. At March 31, 2014, the variable rate of interest under our revolving credit facility was 1.73%. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

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, NGL and natural gas production. Pricing for oil, NGLs and natural gas 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 NGLs and natural gas. 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.

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Our open positions as of March 31, 2014 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:
April 2014 - December 2014	90,000	$	—	$	—	$	96.40
April 2014 - December 2015	210,000		—		—		92.60
Crude Oil Collars:
April 2014 - September 2014	6,000	$	85.00	$	113.04	$	—
April 2014 - December 2014	738,000		85.79		102.11		—
April 2014 - December 2015	525,000		85.00		95.00		—
July 2014 - September 2014	90,000		90.00		101.50		—
October 2014 - December 2014	90,000		90.00		97.33		—
January 2015 - March 2015	120,000		90.00		92.53		—
January 2015 - December 2015	72,000		80.00		93.25		—

¹: The crude oil derivative contracts are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The natural gas derivative contracts are settled based on the NYMEX closing settlement price.

Description & Production Period		Weighted Average Floor price ($/MMBtu)¹		Weighted Average Ceiling price ($/MMBtu)¹		Weighted Average Swap price ($/MMBtu)¹

Natural Gas Collars:
April 2014 - December 2014	1,350,000	$	4.00	$	4.78	$	—

¹: The natural gas derivative contracts are settled based on the NYMEX closing settlement price.

Subsequent to March 31, 2014, we entered into the following oil and natural gas commodity hedges:

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

Crude Oil Collars:
October 2014 - December 2014	150,000	$	90.00	$	103.37	$	—
January 2015 - March 2015	75,000		90.00		96.68		—
January 2015 - June 2015	240,000		90.00		96.00		—
January 2015 - December 2015	1,260,000		86.19		94.72		—

¹: The crude 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 derivative contracts as of March 31, 2014 was a net liability of $3.7 million. For information regarding the terms of these hedges, see "—Overview—Sources of Our Revenues—Realized Prices on the Sale of Oil, NGLs and Natural Gas" above.

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Counterparty and Customer Credit Risk

Our commodity derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our derivative contracts currently in place have investment grade ratings.

Our principal exposures to credit risk are through receivables resulting from joint interest owners on properties we operate and receivables from the sale of our oil and natural gas production due to the concentration of our 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 March 31, 2014 and July 23, 2014, we had $110 million and $170 million, respectively, of debt outstanding that was subject to interest rate risk, in each case with an assumed weighted average interest rate of 1.7%. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the assumed weighted average interest rate would be approximately $1.1 million per year (with respect to the debt outstanding as of March 31, 2014) and $1.7 million per year (with respect to the debt outstanding as of July 23, 2014). We currently do not engage in any interest rate hedging activity.

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.

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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, 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, NGLs and natural gas 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, NGL and natural gas 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.

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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. Estimating the fair value of derivative financial instruments requires management to make estimates and judgments regarding volatility and counterparty credit risk.

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.

Equity-Based Compensation

In connection with the IPO, we adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (the "LTIP") for our employees, consultants and directors who perform services for us. See "Executive Compensation" for additional information related to the LTIP. The valuation and expense recognition of equity-based compensation requires the use of estimates.

Income Taxes

We became a taxable entity as a result of the contribution of our predecessors, which were limited liability companies, to a corporation on January 23, 2014 as described under "Our IPO and Related Transactions." Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of enacted

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tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2014, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

Recently Issued Accounting Pronouncements

The Financial Accounting Standards Board (the "FASB") issued Accounting Standards Update ("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.

Internal Controls and Procedures

As a result of becoming a public company in January 2014, we are 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 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. 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 2013, 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 Transactions.

The pro forma estimated proved reserve information for our properties as of December 31, 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

Since initiating our horizontal drilling program, we have participated in the drilling and completion of 75 horizontal wells (36 of which we operate), which have targeted the Middle Spraberry, Lower Spraberry, Wolfcamp A, 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, Strawn, Atoka, Mississippian and Devonian formations. We have 12 horizontal wells we operate in various stages of drilling or completion that target four different horizontal zones on our properties, primarily from multi-well, multi-zone pads to increase our capital efficiency. We expect the remainder of our horizontal wells to be drilled in 2014 on multi-well pads that target multiple horizons on our properties. Currently, all four of our horizontal rigs are drilling from multi-well, multi-zone pads.

We expect that approximately 75% of our 2014 drilling and completion budget will be devoted to the drilling of horizontal wells, with approximately half of the remaining horizontal drilling budget devoted to the Wolfcamp B and Wolfcamp A formations, and half of the remaining horizontal drilling

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budget devoted to the Lower Spraberry and Middle Spraberry formations. We expect to add a fifth horizontal rig during the fourth quarter of 2014 and a sixth horizontal rig during the first quarter of 2015.

We are developing our acreage from multi-well, multi-zone drilling pads to optimize our capital efficiency. The following table provides a summary of our operated horizontal wells that we have drilled or are drilling to date utilizing multi-well, multi-zone drilling pads.

Horizontal Target Zones	Type

Lower Spraberry & Wolfcamp B	Two-Well Pad	4	8
Middle Spraberry & Lower Spraberry	Two-Well Pad	2	4
Middle Spraberry & Wolfcamp B	Two-Well Pad	1	2
Wolfcamp A & Wolfcamp B	Two-Well Pad	1	2
Wolfcamp B & Wolfcamp D	Two-Well Pad	1	2
Middle Spraberry, Lower Spraberry, & Wolfcamp B	Three-Well Pad	1	3
Middle Spraberry, Lower Spraberry, Wolfcamp A, & Wolfcamp B	Four-Well Pad	1	4


Total Multi-Well Pads		11	25

We expect the remainder of our 2014 horizontal development program to be drilled from multi-well, multi-zone pads with approximately 90% of these wells scheduled to be long lateral horizontal wells.

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 "Our IPO and Related Transactions" for information regarding our acquisitions and other transactions since December 2010.

The following table provides a summary of our target horizontal zones and vertical drilling inventory as of June 30, 2014. While our near term drilling program will be focused primarily on the Middle Spraberry, Lower Spraberry, Wolfcamp A 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 D (Cline) interval is prospective and expect it will be integrated into our future drilling program. We also believe we have the potential to increase our multi-year drilling inventory through horizontal downspacing and 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 large, contiguous acreage position allows us to optimize our

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horizontal and vertical development programs to maximize our resource recovery on a per 640-acre section basis and thus our returns.

	Identified Drilling Locations¹

	Target Horizontal Locations²
	Short Laterals³		Long Laterals³		Total
Target Horizontal Zones⁴:
Middle Spraberry		117		295		412
Lower Spraberry		112		289		401
Wolfcamp A		77		149		226
Wolfcamp B		82		199		281
Wolfcamp D (Cline)		77		175		252


Total Target Horizontal Locations		465		1,107		1,572

	Vertical Locations

	40-acre		20-acre		Total
Vertical Locations		280		645		925


Total Target Horizontal and Vertical Locations						2,497	⁵

¹: Our total identified drilling locations include 313 locations associated with proved undeveloped reserves as of December 31, 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 approximately 750 to 1,050 foot spacing between wells in the same horizontal zone.
³: We define short laterals as horizontal lateral lengths ranging from approximately 4,500 to 5,500 feet and long laterals as horizontal lateral lengths ranging from approximately 6,500 to 10,000 feet. The average lateral length of our target horizontal locations is approximately 6,700 feet.
⁴: In addition to these target horizontal zones, we believe we have the potential to increase our multi-year drilling inventory through horizontal downspacing and with additional horizontal locations in the Clearfork, Jo Mill, Dean, Strawn, Atoka, Mississippian and Devonian formations.
⁵: As of June 30, 2014, seven and 103 of our 2,497 total target horizontal and vertical locations are associated with acreage that will expire in 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 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

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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 December 31, 2013, none of our 313 locations associated with proved undeveloped reserves is associated with acreage that will expire prior to scheduled drilling.

•: $360 million, or 85%, for the drilling and completion of operated wells;
•: $40 million, or 9%, for our participation in the drilling and completion of non-operated wells; and
•: $25 million, or 6%, for infrastructure.

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	Effective Horizontal Acreage¹

	Gross		Net
Target Horizontal Zones:
Middle Spraberry		53,306		38,370
Lower Spraberry		54,064		39,053
Wolfcamp A		34,255		21,645
Wolfcamp B		47,644		33,125
Wolfcamp D (Cline)		39,917		26,890


Total Effective Horizontal Acreage		229,186		159,083

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."

As of December 31, 2013, our estimated proved oil and natural gas reserves were 53,883 MBoe based on a reserve report prepared by Ryder Scott, our independent reserve engineer. Of these reserves, approximately 40% were classified as PDP. PUDs included in this estimate are from 290 vertical well locations and 23 horizontal well locations. As of December 31, 2013, these proved reserves were approximately 65% oil, 19% NGLs and 16% natural gas.

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which have an average assumed lateral length of approximately 6,400 feet, and 428 MBoe (approximately 65% oil, 18% NGLs and 17% natural gas) for our Middle Spraberry wells, which have an average assumed lateral length of approximately 5,000 feet.

	Estimated Total Proved Reserves

	Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Total (MMBoe)		% Oil		% Liquids¹		% Developed		Average Net Production (Boe/d)			R/P Ratio (Years)²
Midland Basin		34.9		10.2		52.7		53.9		65		84		40		9,339	³		15.8

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 March 31, 2014. 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 71% oil, 17% NGLs and 12% natural gas.

Recent Events

During the first quarter of 2014, we acquired additional acreage that we believe is prospective for horizontal development located in Martin, Glasscock and Dawson counties in Texas for an aggregate purchase price of approximately $79 million in three separate transactions with approximately $69 million recorded as proved oil and natural gas properties. These transactions were financed with borrowings under our revolving credit facility. These transactions are described in further detail below:

•: In Martin County, we acquired a 17.5% non-operated working interest in producing properties located between our operated leasehold positions. The properties include 6,451 gross (1,125 net) acres, and net production, on a two-stream basis, averaged approximately 500 Boe/d (76% oil) for the month of March 2014 from 147 vertical wells. The operator of these properties has indicated it has identified 196 horizontal drilling locations in six target intervals, including the Middle Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B, Wolfcamp D (Cline) and Clearfork formations.
•: In Glasscock County, we acquired a 100% operated working interest in 961 acres of undeveloped leasehold. We have identified 28 horizontal locations on these properties in the Middle Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B and Wolfcamp D (Cline) formations.
•: In Dawson County, we acquired 3,766 gross (3,230 net) undeveloped acres in the same area as the assets acquired in the Verde Acquisition, bringing our total acreage in Dawson County to 13,389 gross (11,481 net) acres. We have identified approximately 61 additional net horizontal locations in the Middle Spraberry, Lower Spraberry and Wolfcamp A/B formations.

On July 25, 2014 we announced our entry into definitive agreements in separate transactions with multiple sellers to acquire certain undeveloped acreage and oil and natural gas producing properties located in Glasscock County for an approximate aggregate price of $259 million in cash, the substantial majority of which was to acquire undeveloped acreage. We will operate 100% of, and have approximately an 87% average working interest in, the properties to be acquired. The acquisitions are expected to close in late August 2014 and are subject to the completion of customary due diligence, closing conditions and purchase price adjustments. We intend to use the net proceeds from this offering to fully repay amounts drawn under our revolving credit facility and expect to reborrow amounts under our revolving credit facility to fund a portion of the Pending Glasscock Acquisition. Please read "Use of Proceeds." In addition, following the closing of the Pending Glasscock Acquisition, we will evaluate the potential issuance of senior notes.

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The properties to be acquired consist of 7,680 gross (6,652 net) surface acres or 21,440 gross (19,367 net) Effective Horizontal Acres in Glasscock County, adding another primary operating area in the core of the Northern Midland Basin. We have identified 188 gross (156 net) horizontal drilling locations, 158 gross (132 net) vertical locations on 40-acre spacing and an additional 158 gross (132 net) vertical drilling locations on 20-acre spacing. The aggregate current net production associated with the developed portion of the properties to be acquired is approximately 1,106 Boe/d (approximately 47% oil, 27% NGLs and 26% natural gas), with 13 vertical wells drilled to date. Based on our internal reserve estimates, the properties contain net proved reserves of approximately 22 MBoe (approximately 9% developed). The foregoing information regarding the assets to be acquired in the Pending Glasscock Acquisitions is based solely on our internal evaluation and interpretation of reserve and other information provided to us by the sellers of those assets in the course of our due diligence with respect to the Pending Glasscock Acquisitions and has not been independently verified or estimated by our independent petroleum engineers or any other party.

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 four horizontal drilling rigs focused on the Wolfcamp B and Lower Spraberry target zones and two vertical rigs targeting the Wolfberry play. We plan to accelerate our growth by adding two horizontal drilling rigs in 2015, one in 2016 and one in 2017, which will give us a total of eight operated horizontal rigs by the end of 2017, and two vertical rigs in 2015, which will give us a total of four operated vertical rigs by the end of 2015.
•: Apply horizontal drilling technology in multiple pay zones to increase production. In 2014, we plan to spend approximately 75% 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 June 30, 2014, we had drilled or were currently drilling 36 horizontal wells as the operator and had participated in 39 additional horizontal wells as a non-operator. Of these 75 total horizontal wells, 49 are Wolfcamp B wells, three are Wolfcamp A wells, two are Wolfcamp D (Cline) wells, six are Middle Spraberry wells, 14 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.

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•: 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. We expect the remainder of our 2014 horizontal development program to be drilled from multi-well, multi-zone pads to increase our capital efficiency. 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 87 miles of oil, natural gas and water transport lines to support gathering and transportation activities on our properties, operate ten water source wells drilled into the Santa Rosa formation in West Texas, operate four saltwater disposal wells on our properties, and have an additional saltwater disposal well in the completion 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 more than 800% 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 December 31, 2013, our estimated net proved reserves were comprised of approximately 65% oil, 19% NGLs and 16% natural gas. 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 640-acre 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 and use of multi-well, multi-zone pads, in order to optimize our well results, drilling costs and returns. As the operator of approximately 94% 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. We recently drilled our first successful horizontal well targeting the Wolfcamp A formation on a dual-well pad with a second completion into the Wolfcamp B formation and did not notice any communication between the zones. 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 June 30, 2014, we had identified 1,572 horizontal drilling locations on our acreage based on approximately 750 to 1,050 foot spacing between wells in the same horizontal zone. 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 1,572 identified horizontal drilling locations, 412 are in the Middle Spraberry horizon, 401 are in the Lower Spraberry horizon, 226 are in the Wolfcamp A horizon, 281 are in the Wolfcamp B horizon and 252 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 330 vertical Wolfberry wells across our concentrated leasehold position. As of June 30, 2014, our vertical Wolfberry play drilling plan included 280 identified drilling locations based on 40-acre spacing and an additional 645 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

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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. None of the members of our senior management are selling any shares in this offering.

•: 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. As of July 23, 2014, we had $170.0 million of borrowings and $0.6 million of letters of credit outstanding under our revolving credit facility, providing $204.4 million of available borrowing capacity. After giving effect to this offering and the use of proceeds therefrom, we expect to have no borrowings and $0.6 million of letters of credit outstanding, and $374.4 million of borrowing capacity, under our revolving credit facility. 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 55,355 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 March 31, 2014.



County:
Andrews	4,780	4,522
Ector	4,830	4,715
Martin	12,906	6,768
Midland	17,730	11,196
Dawson	13,389	11,481
Upton	758	683
Glasscock	962	721


Total Surface Acreage	55,355	40,086

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 960 MBbls/d from over 80,000 wells during 2013, production from the Permian Basin represented 50% 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.

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,

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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 640-acre 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 and use of multi-well, multi-zone pads, 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 159,083 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 Acreage¹

	Gross		Net
Target Horizontal Zones:
Middle Spraberry		53,306		38,370
Lower Spraberry		54,064		39,053
Wolfcamp A		34,255		21,645
Wolfcamp B		47,644		33,125
Wolfcamp D (Cline)		39,917		26,890


Total		229,186		159,083

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 March 2014, there were 109 horizontal rigs and approximately 166 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,

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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 December 31, 2013, proved reserves net to our interest in our properties were approximately 53,883 MBoe, of which 40% were classified as PDP. The proved reserves are generally characterized as long-lived, with predictable production profiles.

Production Status. For the three months ended March 31, 2014, our average net daily production was 9,339 Boe/d (approximately 71% oil, 17% NGLs and 12% natural gas), of which 31% was from horizontal well production and 68% was from vertical well production. For the year ended December 31, 2013, our average net daily production was 7,293 Boe/d (approximately 70% oil, 16% NGLs and 14% natural gas), of which 15% was from horizontal well production and 85% was from vertical well production. During 2012, our average net daily production was 5,089 Boe/d (approximately 69% oil, 17% NGLs and 14% natural gas), of which 1% was from horizontal well production and 99% was from vertical well production. As of March 31, 2014, we produced from 35 horizontal and 501 vertical wells and were the operator of approximately 94% 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 87 miles of oil, natural gas and water transport lines to support gathering and transportation activities on our properties. To secure adequate water supplies, we operate ten water source wells drilled 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 operate four saltwater disposal wells on our properties. 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 2013, 102 gross (53 net) wells were drilled on our acreage. During the three months ended March 31, 2014, 27 gross (13 net) wells were drilled on our acreage. We recently drilled our first multi-well pad (two well) layout and anticipate utilizing a three-well pad layout in 2014. We expect these multi-well pads to increase our capital efficiency and intend to begin implementing multi-well pad drilling on a regular basis.

As of June 30, 2014, we had identified 1,572 horizontal drilling locations on our acreage based on approximately 750 to 1,050 foot spacing between wells in the same horizontal zone. In addition, based on our evaluation of applicable geologic and engineering data, as of June 30, 2014 we had 280 identified vertical drilling locations on 40-acre spacing and an additional 645 identified vertical drilling locations based on 20-acre downspacing. In this prospectus, 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.

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Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Proved Reserves. Our pro forma proved reserve estimates as of December 31, 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 December 31, 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 Executive 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 Executive 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 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 December 31, 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

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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 December 31, 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 December 31, 2013 and 2012, based on the proved reserve reports as of December 31, 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 December 31, 2013 prepared by Ryder Scott with

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respect to our properties is included as an exhibit to the registration statement of which this prospectus forms a part.



Proved developed reserves:
Oil (MBbls)	13,921	8,712
NGLs (MBbls)	3,965	3,074
Natural gas (MMcf)	21,008	16,037
Total (MBoe)	21,387	14,459
Proved undeveloped reserves:
Oil (MBbls)	21,011	18,726
NGLs (MBbls)	6,207	5,457
Natural gas (MMcf)	31,665	29,044
Total (MBoe)	32,496	29,024
Total proved reserves:
Oil (MBbls)	34,932	27,438
NGLs (MBbls)	10,172	8,531
Natural gas (MMcf)	52,673	45,081
Total (MBoe)	53,883	43,483

The changes from December 31, 2012 estimated proved reserves to December 31, 2013 estimated proved reserves reflect production during this period of approximately 2,662 MBoe, net negative revisions of approximately 225 MBoe and additions of approximately 13,287 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 December 31, 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, 2013

As of December 31, 2013, our PUDs totaled 21,011 MBbls of oil, 6,207 MBbls of NGLs and 31,665 MMcf of natural gas, for a total of 32,496 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production. Changes in PUDs that occurred during 2013 were primarily due to:

•: additions of approximately 9,747 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position; and

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•: the conversion of approximately 5,599 MBoe attributable to PUDs into proved developed reserves.

During the year ended December 31, 2013, we spent $108.9 million to convert PUDs to proved developed reserves and $97.7 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, 2013, 1% of our total proved reserves were classified as proved developed non-producing.

Oil and Natural Gas Production Prices and Costs

Production and Price History

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

	RSP Permian, Inc.¹		Predecessor		Predecessor							Pro Forma²

	For the Three Months Ended March 31,				For the Years Ended December 31,							Three Months Ended March 31, 2014
	For the Three Months Ended March 31,				For the Years Ended December 31,									Year Ended December 31, 2013
	2014		2013		2013		2012		2011					Year Ended December 31, 2013
Production data:
Oil (MBbls)		544		259		1,167		1,040		618			594		1,867
NGLs (MBbls)		133		60		250		264		—	³		143		414
Natural gas (MMcf)		573		426		1,597		1,576		971			621		2,287


Total (MBoe)		772		390		1,683		1,567		780			841		2,662




Average prices before effects of hedges^4,5:
Oil (per Bbl)	$	94.60	$	84.64	$	94.55	$	87.92	$	91.84		$	94.21	$	95.01
NGLs (per Bbl)³		30.79		26.12		29.26		32.94		—			30.82		28.16
Natural gas (per Mcf)		3.85		2.73		3.37		2.72		7.44			3.86		3.34


Total (per Boe)	$	74.82	$	63.22	$	73.11	$	66.65	$	82.05		$	74.65	$	73.89




Average realized prices after effects of hedges^4,5:
Oil (per Bbl)	$	93.91	$	85.01	$	94.95	$	88.25	$	91.66		$	93.57	$	95.24
NGLs (per Bbl)³		30.79		26.12		29.26		32.94		—			30.82		28.16
Natural gas (per Mcf)		3.85		2.73		3.37		2.72		7.44			3.86		3.34


Total (per Boe)	$	74.32	$	63.46	$	73.37	$	66.86	$	81.90		$	74.19	$	74.06




Average costs (per Boe):
Lease operating expenses	$	9.15	$	8.60	$	8.39	$	8.10	$	7.08		$	9.23	$	8.52
Production and ad valorem taxes		5.02		4.19		4.95		4.83		5.37			4.91		4.97
Depreciation, depletion and amortization		21.19		26.16		28.02		31.15		21.30			23.79		30.24
General and administrative expenses⁶		22.04		1.42		2.29		1.82		4.50			2.46		1.40

¹: Represents our predecessor's production volumes for the first 22 days of the quarter plus RSP Permian, Inc.'s volumes for the remainder of the quarter.

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²: Does not include the results related to the Verde Acquisition or Pecos Contribution for periods prior to the consummation of such transactions due to their lack of significance to our combined financial results.
³: 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.
⁴: 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.
⁵: 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.
⁶: Pro forma general and administrative expenses do not include additional expenses we would have incurred as a result of being a public company.

Productive Wells

As of March 31, 2014, we owned an average 52% working interest in 536 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.

Developed and Undeveloped Acreage

The following table sets forth information as of March 31, 2013 relating to our leasehold acreage:

	Developed acreage¹				Undeveloped acreage²				Total acreage

	Gross³		Net⁴		Gross³		Net⁴		Gross³		Net⁴
Midland Basin		20,040		10,495		35,315		29,591		55,355		40,086

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 December 31, 2013, that will expire over the next five years unless production is established within the spacing units

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covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

	2014				2015				2016				2017				2018

	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Midland Basin		357		302		5,404		4,570		9,774		8,277		2,635		2,196		16		14

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.

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

	For the Three Months Ended March 31,								For the Year Ended December 31,

	2014				2013				2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive¹		1.0		1.0		—		—		—		—		1.0		0.4		—		—
Dry		—		—		—		—		—		—		—		—		—		—


Total Exploratory		1.0		1.0		—		—		—		—		1.0		0.4		—		—




Development Wells:
Productive¹		26.0		12.1		34.0		22.2		102.0		52.9		108.0		68.8		80.0		61.8
Dry		—		—		—		—		—		—		—		—		—		—


Total Development		26.0		12.1		34.0		22.2		102.0		52.9		108.0		68.8		80.0		61.8




Total Wells:
Productive¹		27.0		13.1		34.0		22.2		102.0		52.9		109.0		69.2		80.0		61.8
Dry		—		—		—		—		—		—		—		—		—		—


Total		27.0		13.1		34.0		22.2		102.0		52.9		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 94% 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.

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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 year ended December 31, 2013, four purchasers each accounted for more than 10% of our revenue: Shell Trading (40%), Enterprise Crude Oil LLC (14%), Plains Marketing, L.P. (13%) and Diamondback E&P LLC (11%). 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 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

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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 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 right-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 20% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 80%.

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

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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 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, NGLs and natural gas 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. FERC

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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.

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: (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

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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.

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.

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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 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

The Comprehensive Environmental Response, Compensation, and Liability Act ("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 also generate materials in the course of our operations that may be regulated as hazardous substances. We are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act ("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

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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 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 federal Water Pollution Control Act (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.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act ("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.

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Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, including 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 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, in 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 NESHAPS 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. However, the "other" wells must use reduced emission completions, also known as "green completions," with or without combustion devices, beginning in January 2015. These regulations also established specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. 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 that are likely responsive to some of these requests. For example, in September 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels. We cannot predict what additional actions the EPA may take with respect to these regulations. 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 the public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction 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. 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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regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, in 2013 the Obama administration 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 industry. 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.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas 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 is typically 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 permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, in May 2013, the BLM of the U.S. Department of the Interior published a revised proposed rule that would impose requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, as well as well bore integrity and handling of flowback water. 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. It is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations.

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regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

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, May 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 took 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.

Endangered Species Act and Migratory Birds

The Endangered Species Act ("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 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 material restrictions on 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 ("FWS") 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. For example, in March 2014, FWS listed the lesser prairie chicken as a threatened species under the ESA. In addition, 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

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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 Occupation Health and Safety Act ("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.

Employees

As of May 1, 2014, we had 52 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 and executive officers.

Name		Position

Michael Grimm	59	Chairman of the Board
Steven Gray	54	Chief Executive Officer and Director
Scott McNeill	43	Chief Financial Officer and Director
David Albin	55	Director
Joseph B. Armes	52	Director
Ted Collins, Jr.	76	Director
Matthew S. Ramsey	59	Director
Michael W. Wallace	50	Director
Zane Arrott	56	Chief Operating Officer
Erik B. Daugbjerg	44	Vice President of Oil & Gas Marketing/Business Development
William Huck	58	Vice President of Operations
James Mutrie	41	Vice President and General Counsel
Tamara Pollard	53	Executive Vice President of Planning and Reserves
Barry Turcotte	43	Chief Accounting Officer

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

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industry. We believe his background and skill enables Mr. Gray to provide our board of directors with executive counsel on a full range of business, strategic and professional matters.

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.

David Albin, Director, has served as a member of our board of directors since our formation. Mr. Albin is a co-founder and senior 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 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, and was a member of the audit committee, of Energy Transfer Partners, LP and as a director of 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.

Joseph B. Armes, Director, has served as a member of our board of directors since December 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 June 2013 and as Chairman of the board of directors of Capital Southwest Corporation since January 2014. 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, has served as a member of our board of directors since January 2014. 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

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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 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 enables 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, has served as a member of our board of directors since January 2014. 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 April 2014, Mr. Ramsey has served as a member of the board of directors of the general partner of the general partner of Regency Energy Partners LP, and as a member of the audit and risk, compensation and nominating committees of such board. Since July 2012, Mr. Ramsey has served as a member of the board of directors 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, has served as a member of our board of directors since January 2014. 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.

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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 believe his background and skill set enables 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.

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 of Operations, co-founded RSP Permian, L.L.C. in 2010. He has served as our Vice President of 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.

James Mutrie, Vice President and General Counsel, has served as our Vice President and General Counsel since June 2014. From February 2007 to May 2014, Mr. Mutrie first served as Assistant General Counsel and later as General Counsel and Compliance Officer at United Surgical Partners International, Inc. From October 2003 to January 2007, Mr. Mutrie practiced corporate law at Vinson & Elkins L.L.P., representing public and private companies in capital markets offerings and mergers and acquisitions, frequently in the oil and gas industry. He received a B.A. in History from Cornell University and a J.D. from Northwestern University School of Law.

Tamara Pollard, Executive Vice President of Planning and Reserves, has served as our Executive Vice President of Planning and Reserves since February 2014 and previously served as our Vice President of Planning and Reserves from our formation until February 2014. She has also served RSP Permian, L.L.C. as Executive Vice President of Planning and Reserves since February 2014 and as Vice President

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of Planning and Reserves from its inception in 2010 until February 2014. 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.

Barry Turcotte, Chief Accounting Officer, has served as our Chief Accounting Officer since April 2014. From December 2009 to April 2014, Mr. Turcotte served as Vice President and Controller of Swift Energy Company, a publicly-listed oil and natural gas exploration and production company in Houston, Texas. Mr. Turcotte held the position of Assistant Controller at Swift Energy Company from April 2005 to November 2009 and served in other progressive positions of responsibility after joining Swift Energy Company in 2001. From 1995 to 2001, he served in various roles with Westlake Group of Companies in Houston, Texas. Mr. Turcotte has over 20 years of accounting experience, is a Certified Public Accountant and received a B.B.A. with a concentration in Accounting from the University of Houston in 1992 and an M.B.A. from the University of Houston in 2000.

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

Board of Directors

Our board of directors currently consists of eight members, Michael Grimm, Steven Gray, Scott McNeill, David Albin, Joseph B. Armes, Ted Collins, Jr., Matthew S. Ramsey and Michael W. Wallace. Our board of directors has determined that Messrs. Albin, Armes, Collins, Ramsey and Wallace are independent as defined by the rules of the NYSE and under Rule 10A-3 promulgated under the Exchange Act.

In connection with our IPO, we entered into a stockholders' agreement with RSP Permian Holdco, L.L.C., Collins, Wallace LP, Rising Star and Pecos. The stockholders' agreement provides each of RSP Permian Holdco, L.L.C., Wallace LP and Collins 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. The stockholders' agreement also provides RSP Permian Holdco, L.L.C. the right to designate a non-voting representative to attend meetings of our board and committees of the board for so long as RSP Permian Holdco, L.L.C. beneficially owns at least 5% of the outstanding shares of our common stock and has designated a nominee to the board that is not a manager, employee, director or officer of Production Opportunities or Natural Gas Partners IX, L.P. or any affiliate thereof. Prior to this offering, RSP Permian Holdco, L.L.C. has the right to designate two nominees and Collins and Wallace LP have the right to each designate one nominee. After this offering, (i) assuming no exercise of the underwriters' option to purchase additional shares of our common stock, RSP Permian Holdco, L.L.C., Collins and Wallace LP will each have the right to designate one nominee, and (ii) assuming full exercise of the underwriters' option to purchase additional shares of our common stock, Collins and Wallace LP will each have the right to designate one nominee, and RSP Permian Holdco, L.L.C. will no longer have the right to designate any nominee. However, we expect the parties to the stockholders' agreement will waive the requirement to have the nominees of RSP Permian Holdco, L.L.C. tender resignations to our board of directors, and as such, we expect the two directors originally designated by RSP Permian Holdco, L.L.C., David Albin and Scott McNeill, will continue to serve as directors after this offering. See "Certain Relationships and Related Party Transactions—Stockholders' Agreement."

Our directors are divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2015, 2016 and 2017,

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respectively. Messrs. Albin, Collins and Wallace are Class I, Messrs. Armes and Ramsey are Class II, and Messrs. Gray, Grimm and McNeill are Class III. At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Committees of the Board of Directors

We 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. Each of the standing committees of the board of directors will have the responsibilities described below.

In connection with our IPO, we entered into a stockholders' agreement with RSP Permian Holdco, L.L.C., Collins, Wallace LP, Rising Star and Pecos, which provides that for so long as RSP Permian Holdco, L.L.C. and its affiliates collectively own 15% or more of the outstanding shares of our common stock, we will cause any committee of our board to include in its membership at least one director designated by RSP Permian Holdco, L.L.C., except to the extent that such membership would violate applicable securities laws or stock exchange rules. After this offering, RSP Permian Holdco, L.L.C. and its affiliates will no longer collectively own 15% or more of the outstanding shares of our common stock.

Audit Committee

Rules implemented by the NYSE and 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 our IPO. Our audit committee consists of Messrs. Armes (Chair) and Ramsey, each of whom is independent under the rules of the SEC. Subsequent to the transitional period, we will comply with the requirement to have three independent directors on our audit committee. As required by the rules of the SEC and listing standards of the NYSE, the audit committee consists solely of independent directors. Our board of directors has determined that Messrs. Armes and Ramsey satisfy the definition of "audit committee financial expert."

This committee oversees, reviews, acts on and reports 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 oversees our compliance programs relating to legal and regulatory requirements. We have 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. A copy of our audit committee charter is posted on the Company's website at http://rsppermian.investorroom.com/committee-charters.

Compensation Committee

Our compensation committee establishes salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee also administers our incentive compensation and benefit plans. Our compensation committee charter defines 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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Our compensation committee consists of Messrs. Ramsey (Chair), Albin and Armes, each of whom are independent under the rules of the NYSE. A copy of our compensation committee charter is posted on the Company's website at http://rsppermian.investorroom.com/committee-charters.

Nominating and Corporate Governance Committee

Our nominating and corporate governance committee identifies, evaluates and recommends qualified nominees to serve on our board of directors, develops and oversees our internal corporate governance processes and maintains a management succession plan. Our nominating and corporate governance committee charter defines the committee's primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Our nominating and governance committee consists of Messrs. Collins (Chair), Albin, Armes, Ramsey and Wallace. A copy of our nominating and corporate governance committee charter is posted on the Company's website at http://rsppermian.investorroom.com/committee-charters.

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

We have a Code of Business Conduct and Ethics that applies to our directors, officers and employees as well as a Financial Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, controller and the other senior financial officers, each as required by SEC and NYSE rules. Each of the foregoing is available on our website at www.rsppermian.com in the "Corporate Governance" section. We will provide copies, free of charge, of any of the foregoing upon receipt of a written request to RSP Permian, Inc., 3141 Hood Street, Suite 500, Dallas, Texas 75219, Attn: Investor Relations. We intend to disclose amendments to and waivers from our Financial Code of Ethics, if any, on our website promptly following the date of any such amendment or waiver.

Corporate Governance Guidelines

We have Corporate Governance Guidelines in accordance with the corporate governance rules of the NYSE. Each of the foregoing is available on our website at www.rsppermian.com in the "Corporate Governance" section. We will provide copies, free of charge, of any of the foregoing upon receipt of a written request to RSP Permian, Inc., 3141 Hood Street, Suite 500, Dallas, Texas 75219, Attn: Investor Relations.

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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 2013, our named executive officers were:

Name		Principal Position

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

Messrs. Grimm and Gray served as co-Chief Executive Officers during the 2013 fiscal year. Messrs. Arrott and Huck and Ms. Pollard were paid the same amount of compensation for the 2013 year, thus we have disclosed three officers in addition to Mr. McNeill rather than the one additional officer that would have been necessary for disclosure under the emerging growth company disclosure rules.

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 and 2013.

Name and Principal Position

Michael Grimm	2013	225,000	50,000	N/A	275,000
(Chief Executive Officer)	2012	225,000	N/A	N/A	225,000
Steven Gray	2013	225,000	50,000	N/A	275,000
(Chief Executive Officer)	2012	225,000	N/A	N/A	225,000
Scott McNeill	2013	300,000	N/A	0	300,000
(Chief Financial Officer)
Zane Arrott	2013	225,000	50,000	N/A	275,000
(Chief Operating Officer)	2012	225,000	N/A	N/A	225,000
Tamara Pollard	2013	225,000	50,000	N/A	275,000
(Vice President of Planning and Reserves)	2012	225,000	N/A	N/A	225,000
William Huck	2013	225,000	50,000	N/A	275,000
(Vice President of Operations)	2012	225,000	N/A	N/A	225,000

¹: Each of the named executive officers (other than Mr. McNeill) received a discretionary bonus for the 2013 year. The amounts were paid in the first quarter of the 2014 year.
²: Mr. McNeill received a grant of Tier I A incentive units at the time that he began his employment in 2013. We believe that, despite the fact that the incentive units do not require the payment of an exercise price, they are most similar economically to stock options, and as such, they are properly classified as "options" under the definition provided in Item 402(a)(6)(i) of Regulation S-K as an

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instrument with an "option-like feature." Amounts reflected in this column for Mr. McNeill reflect a grant date fair value of the incentive units in accordance with FASB ASC Topic 718 of $0. Because the performance conditions related to these awards were not deemed probable at the time of grant in 2013, no amounts have been reported in 2013 for purposes of this table. While the awards do not have target or maximum payout levels, the maximum amount of compensation cost that we believe could have been reported on the grant date under FASB ASC Topic 718 had the performance conditions been deemed probable would have been $1.1 million.

³: None of the individuals serving as our named executive officers during the 2012 year received compensation other than base salary during the 2012 fiscal year.

Outstanding Equity Awards at 2013 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, 2013. Prior to our IPO, the incentive units were profits interests, rather than capital interests, in us. In connection with our IPO, the profits interests became incentive units, or profits interest awards, in RSP Permian Holdco, L.L.C., although the terms and conditions of the profits interest awards remained substantially similar to the terms applicable to the profits interest awards prior to our IPO, including the retention of existing vesting schedules. Where terms have been modified following our IPO, they have been described in the narrative below. Prior to our IPO, however, the incentive units were 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 refers to the terms and conditions of the profits interest awards as they exist at the end of the 2013 fiscal year. The profits interest awards held by the named executive officers described in the following table

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no longer relate directly to our securities, and we are not financially or otherwise responsible for distributions or settlements relating to such profits interest awards.

Name

Michael Grimm²
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 Gray³
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
Scott McNeill
Tier I A Units	100	0	N/A	N/A
Zane Arrott⁴
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 Pollard⁵
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: We believe that, despite the fact that the incentive units do not require the payment of an exercise price, they are most similar economically to stock options, and as such, they are properly classified as "options" under the definition provided in Item 402(a)(6)(i) of Regulation S-K as an instrument with an "option-like feature." The profits interest awards are divided into five 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 I A units for Mr. McNeill will vest in three equal annual installments beginning on the grant date of April 1, 2013. The Tier II, Tier III and Tier IV units in the "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.

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²: Each of the incentive units reported in the table above for Mr. Grimm has been transferred, without value, to a family partnership titled the Grimm Family Limited Partnership. Mr. Grimm will still be deemed to beneficially own the incentive units reported in the table through this family partnership.
³: The incentive units reported in the table above for Mr. Gray have been irrevocably transferred, without value, to the Steven D. Gray and Debora K. Gray 2012 GST Exempt Trust and the Steven D. Gray GRAT No. 2005-1, trusts maintained solely for the benefit of Mr. Gray's children or grandchildren. 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 was considered to be a compensatory award to Mr. Gray at the time of grant.
⁴: Each of the incentive units reported in the table above for Mr. Arrott has been transferred, without value, to a family partnership titled Arrott Family Holdings, L.P. Mr. Arrott will still be deemed to beneficially own the incentive units reported in the table through this family partnership.
⁵: Each of the incentive units reported in the table above for Ms. Pollard has been transferred, without value, to a family partnership titled Pollard Resource Holdings, LP. Ms. Pollard will still be deemed to beneficially own the incentive units reported in the table through this family partnership.

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 five 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 and I A units are designed to vest in three equal annual installments, although vesting will be fully accelerated if a "Fundamental Change" (as defined below) occurs prior to the time-based vesting conditions becoming satisfied. The Tier I units granted to the applicable named executive officers in 2010 became fully time-vested on October 18, 2013. Tier II units, Tier III units and Tier IV units will each vest only upon the attainment of distribution 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. After our IPO was consummated, the following changes were made to the terms of the profits interest awards:

•: the profits interest awards became 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;

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•: the board of managers of RSP Permian Holdco, L.L.C. has 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, are based on all distributions to the members of equity interests in RSP Permian Holdco, L.L.C., not only on cash distributions as was the case while the awards were 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 our IPO.

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 our IPO, to RSP Permian Holdco, L.L.C.) shall have received cumulative distributions in respect of their membership 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 I A units will be entitled to 4% of future distributions to members only after all of the members that have made capital contributions to RSP Permian, L.L.C. (or after our IPO, to RSP Permian Holdco, L.L.C.) shall have received cumulative distributions in respect of their membership interests equal to their cumulative capital contributions multiplied by 1.08n, 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 our IPO, 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 our IPO, 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 our IPO, 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. Upon consummation of our IPO, distribution thresholds were not modified as part of the transactions that are necessary to effect our IPO 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.

We expect that RSP Permian Holdco, L.L.C.'s assets will consist only of the shares of our common stock that it received as part of the Transactions. Accordingly, the only events that would cause distributions to its members, including to the holders of the profits interest awards, would be either sales of shares of our common stock by RSP Permian Holdco, L.L.C. or in-kind distributions of such shares to its members.

A "Fundamental Change" is generally defined in the RSP Permian, L.L.C. limited liability company agreement as any of the following events: (i)(a) we merge or consolidate with or into an entity other than one of our subsidiaries; (b) our outstanding interests are sold or exchanged to any person other than one of our subsidiaries; or (c) we sell, lease, license or exchange all or substantially all of our assets to a person that is not an affiliate, a member or a related party, and in each case the individuals that served as members of our board of directors immediately prior to the applicable transaction cease to constitute a majority of the members of the new board of directors; (ii) any person or group (other than us or any of our members) acquires the right to vote or dispose of our securities, unless the transaction was approved by our board; or (iii) our company is dissolved and liquidated. The definition of a "Fundamental Change" was not modified in the limited liability company agreement of

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RSP Permian Holdco, L.L.C. following our IPO, although references to "us," "our" or "we" in the definition above now refer to RSP Permian Holdco, L.L.C.

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. Upon consummation of our IPO, a "capital contribution" to RSP Permian Holdco, L.L.C. generally means, 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 our IPO, and (ii) other than the interests in RSP Permian, L.L.C. that were contributed to RSP Permian, Inc. in connection with our corporate reorganization (as further described in "Our IPO and Related 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; or (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. Upon consummation of our IPO, the definition of termination for "Cause" was modified to generally occur upon the individual's (a) conviction of, or plea of nolo contendere to, any felony or to any crime or offense causing substantial harm to RSP Permian Holdco, L.L.C. or its affiliates or involving acts of theft, fraud, embezzlement, moral turpitude, or similar conduct, (b) repeated intoxication by alcohol or drugs during the performance of such holder's duties in a manner that materially and adversely affects the holder's performance of such duties, (c) malfeasance, in the conduct of such holder's duties, including, but not limited to, (1) misuse or diversion of funds of RSP Permian Holdco, L.L.C. or its affiliates, (2) embezzlement, or (3) material and intentional misrepresentations or concealments on any written reports submitted to RSP Permian Holdco, L.L.C. or its affiliates, (d) violation of any material provision of any voting and transfer restriction agreement or of a confidentiality and noncompete agreement that such person has executed with RSP Permian Holdco, L.L.C. or its affiliates, and such person has failed to cure such violation, if capable of being cured, within a reasonable period of time after such person has received notice of such violation, or (e) failure to perform the duties of such holder's employment or service relationship with RSP Permian Holdco, L.L.C. or its affiliates, or failure to follow or comply with the reasonable and lawful written directives of the board of managers of RSP Permian Holdco, L.L.C. or the managers or directors of an affiliate of RSP Permian Holdco, L.L.C. by which such holder is employed or in a service relationship, and such person has failed to cure such failure, if capable of being cured, within a reasonable period of time after such person has received notice of such failure.

A "Disability" is 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.

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Because we are not a party to the RSP Permian Holdco, L.L.C. limited liability company agreement, we cannot assure you that the terms of the profits interest units or the limited liability company agreement of RSP Permian Holdco, L.L.C. 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 is entitled to any payments or other benefits in connection with a termination of their employment or a change in control other than as described in the "Compensation Following Our IPO—IPO Bonuses and Awards" and "Compensation Following Our IPO—Executive Change in Control and Severance Benefit Plan" sections below.

Compensation Following Our IPO

IPO Bonuses and Awards

We granted certain employees, including our named executive officers, bonuses in connection with the successful completion of our IPO. One portion of the bonuses was made in a single lump sum cash payment upon the completion of our IPO, and a second portion of the value of the bonuses was granted to the employees in the form of restricted stock awards that are governed by the LTIP described below.

The cash portion of the IPO bonuses was approximately $3,100,000 for all employees, with Messrs. Grimm and Gray each receiving $200,000; Mr. McNeill receiving $833,333; Messrs. Arrott and Huck each receiving $300,000 and Ms. Pollard receiving $350,000.

With respect to the restricted stock award portion of the IPO bonuses, we granted each of our named executive officers time-based restricted stock awards on two dates in 2014: the "first grant" was made on February 11, 2014, and the "second grant" was made on February 25, 2014.

Pursuant to the first grant, Mr. Grimm received 19,512 shares of restricted stock that will vest in two equal installments occurring on February 11, 2015 and February 11, 2016. Pursuant to the second grant, Mr. Grimm received an additional 16,875 shares of restricted stock that will vest in three equal installments occurring on March 1, 2015, March 1, 2016 and March 1, 2017.

Pursuant to the first grant, Mr. Gray received 19,512 shares of restricted stock that will vest in two equal installments occurring on February 11, 2015 and February 11, 2016. Pursuant to the second grant, Mr. Gray received an additional 42,000 shares of restricted stock that will vest in three equal installments occurring on March 1, 2015, March 1, 2016 and March 1, 2017.

Pursuant to the first grant, Mr. McNeill received 81,301 shares of restricted stock that will vest in two equal installments occurring on February 11, 2015 and February 11, 2016. Pursuant to the second grant, Mr. McNeill received an additional 20,000 shares of restricted stock that will vest in three installments, with the first installment of 6,667 shares occurring on March 1, 2015, the second installment of 6,667 shares occurring on March 1, 2016 and the third installment of 6,666 shares occurring on March 1, 2017.

Pursuant to the first grant, Mr. Arrott received 19,512 shares of restricted stock that will vest in two installments, with the first installment of 14,634 shares occurring on February 11, 2015 and the second installment of 4,878 shares occurring on February 11, 2016. Pursuant to the second grant, Mr. Arrott received an additional 21,875 shares of restricted stock that will vest in three installments, with the first installment of 7,291 shares occurring on March 1, 2015, the second installment of 7,292 shares occurring on March 1, 2016 and the third installment of 7,292 shares occurring on March 1, 2017.

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Pursuant to the first grant, Ms. Pollard received 17,073 shares of restricted stock that will vest in one installment on February 11, 2015. Pursuant to the second grant, Ms. Pollard received an additional 12,188 shares of restricted stock that will vest in three installments, with the first installment of 4,063 shares occurring on March 1, 2015, the second installment of 4,063 shares occurring on March 1, 2016 and the third installment of 4,062 shares occurring on March 1, 2017.

Pursuant to the first grant, Mr. Huck received 14,634 shares of restricted stock that will vest in one installment on February 11, 2015. Pursuant to the second grant, Mr. Huck received an additional 12,188 shares of restricted stock that will vest in three installments, with the first installment of 4,063 shares occurring on March 1, 2015, the second installment of 4,063 shares occurring on March 1, 2016 and the third installment of 4,062 shares occurring on March 1, 2017.

2014 Long Term Incentive Plan

We have adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan for the employees, consultants and the directors of our company and its affiliates who perform services for us. 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.

The LTIP provides 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").

Executive Change in Control and Severance Benefit Plan

On July 22, 2014, our board of directors, upon recommendation of the compensation committee of our board of directors, approved and adopted the Executive Change in Control and Severance Benefit Plan (the "Severance Plan"). The Severance Plan provides certain severance and change in control benefits to our executive officers who are selected by the compensation committee to participate in the plan.

If a plan participant's employment with us is terminated due to death or "disability" (as defined in the Severance Plan), the participant is entitled to receive (i) one times the participant's annual base salary, paid in a lump sum, (ii) continued health benefits for 18 months, (iii) a pro-rated annual bonus for the calendar year in which the participant's employment termination date occurs and (iv) all unpaid salary and other outstanding amounts owed to the participant. If a plan participant's employment with us is terminated by us without "cause" (as defined in the Severance Plan) or by the participant for "good reason" (as defined in the Severance Plan), the participant is entitled to receive (i) a lump sum payment equal to 1.5 times (two times, in the case of our Chief Executive Officer) the sum of (a) the participant's annual base salary, plus (b) the greater of the participant's average annual performance bonus for the preceding two calendar years or the participant's target annual performance bonus for the calendar year in which the termination occurs, (ii) continued health benefits for 18 months (two years, in the case of our Chief Executive Officer), (iii) a pro-rated annual bonus for the calendar year in which the participant's employment termination date occurs, (iv) all unpaid salary and other outstanding amounts owed to the participant and (v) accelerated vesting of all outstanding, unvested equity awards.

Upon the occurrence of a "change in control" (as defined in the Severance Plan), all outstanding, unvested equity awards held by a plan participant will immediately become fully vested. If a plan

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participant's employment with us is terminated by us without cause or by the participant for good reason, in either case, within two years following the occurrence of a change in control, the participant is entitled to receive (i) a lump sum payment equal to 2.5 times (three times, in the case of our Chief Executive Officer) the sum of (a) the participant's annual base salary, plus (b) the greater of the participant's average annual performance bonus for the preceding two calendar years or the participant's target annual performance bonus for the calendar year in which the termination occurs, (ii) continued health benefits for 2.5 years (three years, in the case of our Chief Executive Officer), (iii) a pro-rated annual bonus for the calendar year in which the participant's employment termination date occurs and (iv) all unpaid salary and other outstanding amounts owed to the participant.

The Severance Plan does not provide a tax gross-up provision for federal excise taxes that may be imposed under section 4999 of the Internal Revenue Code of 1986, as amended (the "Code"). Instead, the Severance Plan includes a modified cutback provision, which states that, if amounts payable to a plan participant under the Severance Plan (together with any other amounts that are payable by us as a result of a change in control, the "Payments") exceed the amount allowed under section 280G of the Code for such participant, thereby subjecting the participant to an excise tax under section 4999 of the Code, then the Payments shall either be: (i) reduced to the level at which no excise tax applies, such that the full amount of the Payments would be equal to $1 less than three times the participant's "base amount," which is the average W-2 earnings for the five calendar years immediately preceding the date of termination, or (ii) paid in full, which would subject the participant to the excise tax. We will determine, in good faith, which alternative produces the best net after tax position for a participant. The Severance Plan may be amended or terminated by resolution of two-thirds of our board of directors, except that (i) no amendment adopted within one year prior to a change in control may adversely affect any plan participant without his or her consent, (ii) no amendment may be made at the request of a third party that takes steps to effectuate a change in control or otherwise in connection with a change in control and (iii) no amendment may be made within two years following the occurrence of a change in control that would adversely affect any individual who is a plan participant on the change in control date.

Compensation of Directors

We did not award any compensation to our non-employee individual directors during 2013. 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.

In connection with our IPO, we granted our non-employee directors, except Mr. Albin, an initial restricted stock award of 5,000 shares, which vest over three years. For 2015 and future years, we expect to grant shares valued at $100,000 annually to each non-employee director, except Mr. Albin, which shares will vest over three years. In addition, for 2014, we will pay a $50,000 annual cash retainer in quarterly installments to each non-employee director and expect to continue to do so in future years. See "Certain Relationships and Related Party Transactions—Transactions with Affiliates—Director Cash Retainer" for information regarding Mr. Albin's compensation as a non-employee director.

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.

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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, 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 officers; and
•: all of our directors and executive officers as a group.

For further information regarding material transactions between us and certain of our stockholders, see "Certain Relationships and Related Party Transactions."

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 500, Dallas, Texas 75219.

To the extent that the underwriters sell more than 15,000,000 shares of common stock, the underwriters have the option to purchase up to an additional 900,000 and 1,350,000 shares from us and certain selling stockholders, respectively.

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	Shares Beneficially Owned Before RSP Permian Holdco, L.L.C.'s Distribution and Before this Offering(1)					Shares Beneficially Owned After RSP Permian Holdco, L.L.C.'s Distribution and Before this Offering(1)

Name of Beneficial Owner(2)	Number		Percent			Number		Percent
Selling Stockholders:
Ted Collins, Jr.(3)(4)		11,536,278		15.8	%		11,536,278		15.8	%
Michael G. Cook(1)(5)		5,000		*			28,477		*
Erik B. Daugbjerg(1)(6)(7)		22,134		*			180,440		*
Buster Groves(1)(8)		9,459		*			85,679		*
William Huck(1)(7)(9)		26,822		*			327,295		*
William Christopher Krusz(1)(10)		—		—			14,019		*
Robert Lemmons(1)(11)		12,478		*			90,628		*
Natural Gas Partners IX, L.P.(1)(12)		16,285,481		22.3	%		13,784,929		18.9	%
Rising Star Energy Development Co., L.L.C.(13)		1,023,319		1.4	%		1,023,319		1.4	%
Steve Smith(1)(14)		2,545		*			12,051		*
Leslyn Wallace(1)(4)(15)(16)		11,911,078		16.3	%		11,968,017		16.4	%
Wallace Family Partnership, LP(16)		9,739,126		13.3	%		9,739,126		13.3	%
Other 5% Stockholders:
ACTOIL, LLC(17)		10,816,626		14.8	%		10,816,626		14.8	%
RSP Permian Holdco, L.L.C.(1)(18)		16,285,481		22.3	%		6,049,769		8.3	%
Directors and Named Executive Officers:
Michael Grimm(1)(19)		36,387		*			336,899		*
Steven Gray(1)(7)(20)		76,512		*			76,512		*
Scott McNeill(1)(21)		111,301		*			517,333		*
David Albin		—		—			—		—
Joseph B. Armes(3)(21)		7,500		*			7,500		*
Ted Collins, Jr.(3)(4)		11,536,278		15.8	%		11,536,278		15.8	%
Matthew S. Ramsey(22)		10,000		*			10,000		*
Michael W. Wallace(4)(16)(22)(23)		11,911,078		16.3	%		11,968,017		16.4	%
Zane Arrott(1)(24)		41,387		*			341,899		*
William Huck(1)(7)(9)		26,822		*			327,295		*
Tamara Pollard(1)(25)		32,261		*			332,773		*
Directors and executive officers as a group (14 persons)		21,667,660		30.0	%		23,490,946		32.2	%

	Assuming No Exercise of the Underwriters' Option to Purchase Additional Shares							Assuming Full Exercise of the Underwriters' Option to Purchase Additional Shares

			Shares Beneficially Owned After this Offering									Shares Beneficially Owned After this Offering
								Additional Shares Distributed from RSP Permian Holdco, L.L.C.(1)
	Shares Offered Hereby									Shares Offered Hereby
Name of Beneficial Owner(2)	Shares Offered Hereby		Number		Percent					Shares Offered Hereby		Number		Percent
Selling Stockholders:
Ted Collins, Jr.(3)(4)		200,000		11,336,278		14.4	%		—		—		11,336,278		14.2	%
Michael G. Cook(1)(5)		12,000		16,477		*			4,460		2,280		18,657		*
Erik B. Daugbjerg(1)(6)(7)		40,914		139,526		*			30,203		7,807		161,922		*
Buster Groves(1)(8)		23,586		62,093		*			15,003		4,643		72,453		*
William Huck (1)(7)(9)		92,980		234,315		*			57,864		17,907		274,272		*
William Christopher Krusz(1)(10)		10,630		3,389		*			2,595		1,968		4,016		*
Robert Lemmons(1)(11)		20,198		70,430		*			15,303		3,955		81,778		*
Natural Gas Partners IX, L.P.(1)(12)		7,735,160		6,049,769		9.8	%		1,228,682		1,228,682		4,352,175		5.5	%
Rising Star Energy Development Co., L.L.C.(13)		499,575		523,744		*			—		79,814		443,930		*
Steve Smith(1)(14)		2,457		9,594		*			1,870		483		10,981		*
Leslyn Wallace(1)(4)(15)(16)		12,500		11,605,517		14.7	%		11,208		2,461		11,614,264		14.5	%
Wallace Family Partnership, LP(16)		350,000		9,389,126		11.9	%		—		—		9,389,126		11.8	%
Other 5% Stockholders:
ACTOIL, LLC(17)		—		10,816,626		13.7	%		—		—		10,816,626		13.5	%
RSP Permian Holdco, L.L.C.(1)(18)		—		6,049,769		7.7	%		—		—		4,352,175		5.5	%
Directors and Named Executive Officers:
Michael Grimm(1)(19)		—		336,899		*			57,254		—		394,153		*
Steven Gray(1)(7)(20)		—		76,512		*			—		—		76,512		*
Scott McNeill(1)(21)		—		517,333		*			67,345		—		584,678		*
David Albin		—		—		—			—		—		—		—
Joseph B. Armes(3)(21)		—		7,500		*			—		—		7,500		*
Ted Collins, Jr.(3)(4)		200,000		11,336,278		14.4	%		—		—		11,336,278		14.2	%
Matthew S. Ramsey(22)		—		10,000		*			—		—		10,000		*
Michael W. Wallace(4)(16)(22)(23)		—		11,605,517		14.7	%		—		—		11,614,264		14.5	%
Zane Arrott(1)(24)		—		341,899		*			57,254		—		399,153		*
William Huck(1)(7)(9)		92,980		234,315		*			57,864		17,907		274,272		*
Tamara Pollard(1)(25)		—		332,773		*			—		—		388,177		*
Directors and executive officers as a group (14 persons)		333,174		22,794,552		28.9	%		269,920		25,714		23,102,909		28.9	%

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¹: In connection with and immediately prior to this offering, RSP Permian Holdco, L.L.C. will distribute 10,235,712 shares of our common stock to its members (assuming a public offering price per common share of $32.20, which is the last sale price of our common stock as reported on the NYSE on July 23, 2014). In the event the underwriters exercise their option to purchase additional shares in full, RSP Permian Holdco, L.L.C. will make an additional distribution of shares of 1,697,594 shares of our common stock to its members (assuming a public offering price per common share of $32.20). The number of shares to be distributed is based, in part, on the public offering price of the common stock offered in this offering. A $1.00 increase or decrease in the assumed public offering price of $32.20 per share would cause the number of shares of our common stock to be distributed by RSP Permian Holdco, L.L.C. to increase or decrease, respectively, by less than 1%. Certain of those members, Michael G. Cook, Erik B. Daugbjerg, David Groves, William Huck, William Christopher Krusz, Robert Lemmons, Steve Smith and Leslyn Wallace, will sell all or a portion of the shares of our common stock distributed to them to the underwriters in this offering. One of RSP Permian Holdco, L.L.C.'s members, Production Opportunities, will immediately distribute the shares of our common stock distributed to it by RSP Permian Holdco, L.L.C. to its partners, including Natural Gas Partners IX, L.P., which will sell all such shares to the underwriters in this offering. None of the members of our senior management are selling any shares in this offering.
²: 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.
³: Mr. Collins has served as a member of our board of directors since January 2014. See "Certain Relationships and Related Party Transactions" for additional information relating to Mr. Collins' relationship with RSP.

5,000 shares are restricted stock that will vest in three installments, with the first installment of 1,666 shares occurring on March 1, 2015, the second installment of 1,667 shares occurring on March 1, 2016 and the third installment of 1,667 shares occurring on March 1, 2017.

1,000 shares are held by Mr. Collins' spouse. Mr. Collins disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein.

⁴: 2,166,152 shares are held of record by Collins & Wallace Holdings, LLC. Mr. Collins and Wallace LP are the members of Collins & Wallace Holdings, LLC. Michael Wallace Management, LLC ("Wallace Management") is the general partner of Wallace LP, and Mr. and Mrs. Wallace are the managers of Wallace Management. Accordingly, Mr. Collins and Mr. and Mrs. Wallace may be deemed to share voting and dispositive power over the 2,166,152 shares held of record by Collins & Wallace Holdings, LLC, and as a result may be deemed to beneficially own these shares. Mr. Collins and Mr. and Mrs. Wallace each disclaim beneficial ownership of these shares except to the extent of their respective pecuniary interest therein Messrs. Collins and Wallace have each served as a member of our board of directors since January 2014. See "Certain Relationships and Related Party Transactions" for information relating to their relationship with RSP.

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⁵: Mr. Cook serves, and for the past three years has served, RSP as a consulting geologist.
⁶: Mr. Daugbjerg serves, and for the past three years has served, RSP as Vice President of Oil & Gas Marketing/Business Development. See "Certain Relationships and Related Party Transactions" for additional information relating to his relationship with RSP.

14,634 shares are restricted stock that will vest on March 1, 2015. 7,500 shares are restricted stock that will vest in three equal installments occurring on March 1, 2015, March 1, 2016 and March 1, 2017.

⁷: Each of Messrs. Gray, Daugbjerg and Huck own one-third of the outstanding limited partnership interests of Pecos, directly and through their membership interest in Pecos Operating Company, LLC, the general partner of Pecos ("Pecos GP"), and serve as managers of Pecos GP. Pecos GP is manager-managed and actions require a majority of the three managers to take any actions, including with respect to all investment and dispositive decisions for the shares of the Company's common stock held by Pecos. As a result, none of Messrs. Gray, Daugbjerg and Huck individually have voting or dispositive power over these shares. Pecos GP has voting and dispositive power over such shares. Pecos owns 105,170 shares of the Company's common stock.
⁸: Mr. Groves serves, and for the past three years has served, RSP as Production Superintendent.

3,659 shares are restricted stock that will vest on February 11, 2015. 4,800 shares are restricted shares that will vest in three equal installments occurring on March 1, 2015, March 1, 2016 and March 1, 2017.

⁹: Mr. Huck serves, and for the past three years has served, RSP as Vice President of Operations. See "Certain Relationships and Related Party Transactions" for additional information relating to his relationship with RSP.

14,634 shares are restricted stock that will vest in one installment on February 11, 2015. 12,188 shares are restricted stock that will vest in three installments, with the first installment of 4,063 shares occurring on March 1, 2015, the second installment of 4,063 shares occurring on March 1, 2016 and the third installment of 4,062 shares occurring on March 1, 2017.

¹⁰: Mr. Krusz serves, and for the past three years, has served RSP as a consulting geophysicist.
¹¹: Mr. Lemmons serves, and for the past three years, has served RSP as Manager of Drilling Operations.

4,878 shares are restricted stock that will vest on February 11, 2015. 6,600 shares are restricted stock that will vest in three equal installments on March 1, 2015, March 1, 2016 and March 1, 2017.

1,000 shares are held by Mr. Lemmons' spouse. Mr. Lemmons disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein.

¹²: G.F.W. Energy IX, L.P. is the sole general partner of Natural Gas Partners IX, L.P., and GFW IX, L.L.C. is the sole general partner of G.F.W. Energy IX, L.P. As such, G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares. Kenneth A. Hersh, an Authorized Member of GFW IX, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition of, such shares. Mr. Hersh does not own directly any shares of our common stock. 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 shares by virtue of his shared control of GFW IX, L.L.C. Mr. Albin does not own directly any shares of our common stock. GFW IX, L.L.C. has delegated full power and authority to manage Natural Gas Partners IX, L.P. to NGP Energy Capital Management, L.L.C., and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and

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dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares.

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.), certain members of our management team and certain of our employees. As such, Natural Gas Partners IX, L.P. may be deemed to share voting and dispositive power over the shares directly held by RSP Permian Holdco, L.L.C. and therefore may also be deemed to be the beneficial owner of the shares held by RSP Permian Holdco, L.L.C. Natural Gas Partners IX, L.P. disclaims beneficial ownership of such shares in excess of its pecuniary interest in the shares. See note (18) below for information regarding RSP Permian Holdco, L.L.C.'s beneficial ownership of our common stock.

Prior to the distribution of shares of our common stock by RSP Permian Holdco, L.L.C. to its members (discussed in note (1) above) and this offering, RSP Permian Holdco, L.L.C. holds 16,285,481 shares of our common stock directly and Natural Gas Partners IX, L.P. holds no shares of our common stock directly. After the distribution of shares of our common stock by RSP Permian Holdco, L.L.C. to its members and the distribution of shares of our common stock by Production Opportunities to its partners, but prior to this offering, RSP Permian Holdco, L.L.C. will hold 6,049,769 shares of our common stock shares directly and Natural Gas Partners IX, L.P. will hold 7,735,160 shares of our common stock directly. RSP Permian Holdco, L.L.C. is not selling any shares in this offering, and Natural Gas Partners IX, L.P. is selling all of its shares in this offering. Assuming the underwriters' option to purchase additional shares is not exercised, immediately after this offering, RSP Permian Holdco, L.L.C. will hold 6,049,769 shares of our common stock shares directly and Natural Gas Partners IX, L.P. will hold no shares of our common stock directly. In the event the underwriters exercise their option to purchase additional shares in full, (i) RSP Permian Holdco, L.L.C. will make an additional distribution of 1,697,594 shares of our common stock to its members, and Production Opportunities will, in turn, make an additional distribution of 1,228,682 shares of our common stock to Natural Gas Partners IX, L.P. (which will in turn sell all such shares to the underwriters), and (ii) immediately after this offering, RSP Permian Holdco, L.L.C. will hold 4,352,175 shares of our common stock directly and Natural Gas Partners IX, L.P. will hold no shares of our common stock directly. See "Certain Relationships and Related Party Transactions" for information relating to Natural Gas Partners IX, L.P.'s relationship with RSP.

¹³: 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. The board of managers of Rising Star GP has voting and dispositive power over these shares. The board of managers of Rising Star GP consists of Michael Grimm, Zane Arrott, Ken Hersh, David Albin and Dick Covington, none of whom individually have voting and dispositive power over these shares. Each such person expressly disclaims beneficial ownership over these shares, except to the extent of any pecuniary interest therein. 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 shares and therefore may also be deemed to be the beneficial owner of these shares. NGP VIII disclaims beneficial ownership of the reported shares in excess of its pecuniary interest in the shares. GFW VIII, L.L.C. and G.F.W. Energy VIII, L.P. may be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares by virtue of GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P., which is the general partner of NGP VIII. Kenneth A. Hersh, an Authorized Member of GFW VIII, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition of, such shares. Mr. Hersh does not own directly any shares of our common stock. 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, such shares. Mr. Albin does not own directly any shares of our common stock. See

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"Certain Relationships and Related Party Transactions" for information relating to Rising Star Energy Development Co., L.L.C.'s relationship with RSP.

¹⁴: Mr. Smith serves, and for the past three years has served, RSP as Accounting Manager.

1,220 shares are restricted stock that will vest on February 11, 2015. 1,125 shares are restricted stock that will vest in three equal installments on March 1, 2015, March 1, 2016 and March 1, 2017.

¹⁵: During 2011 to 2013, Mrs. Wallace served RSP as Land Manager.

300 shares are held by a member of Mrs. Wallace's immediate family sharing the same household. Mrs. Wallace disclaims beneficial ownership of these shares except to the extent of her pecuniary interest therein. Also, as Michael W. Wallace's spouse, Mrs. Wallace may be deemed to be the beneficial owner of shares beneficially owned by Mr. Wallace. Mrs. Wallace disclaims beneficial ownership of such shares except to the extent of her pecuniary interest therein. See notes (4) and (23) for information regarding Mr. Wallace's beneficial ownership of our common stock.

¹⁶: Mr. and Mrs. Wallace have voting and dispositive power over shares directly held by Wallace Family Partnership, LP but disclaim beneficial ownership over these shares in excess of their respective pecuniary interest in these shares. Wallace Family Partnership, LP is a family-owned entity owned by Mr. and Mrs. Wallace. The general partner of Wallace Family Partnership, LP is Wallace Management, and Mr. and Mrs. Wallace are the managers of Wallace Management. Wallace Management may be deemed to have voting and dispositive power over the reported shares and may also be deemed to be the beneficial owner of these shares. Wallace Management disclaims beneficial ownership of the reported shares in excess of its pecuniary interest in the shares. See "Certain Relationships and Related Party Transactions" for information relating to Wallace Family Partnership, LP's relationship with RSP.
¹⁷: 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 shares and may also be deemed to be the beneficial owner of these shares. Each of ACTOIL, LLC, TIAA Oil and Gas Investments, LLC and Teachers Insurance and Annuity Association of America disclaim beneficial ownership of the reported shares in excess of its pecuniary interest in the shares.
¹⁸: The board of managers of RSP Permian Holdco, L.L.C. has voting and dispositive power over these shares. The board of managers of RSP Permian Holdco, L.L.C. consists of Michael Grimm, Steven D. Gray, Scott McNeill, Tony Weber, David Albin and Roy Aneed, none of whom individually have voting and dispositive power over these shares. Each such person expressly disclaims beneficial ownership over these shares, except to the extent of any pecuniary interest therein. 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 2013 Fiscal Year-End" for more information on the incentive units. NGP IX may be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares. NGP IX disclaims beneficial ownership of the reported shares in excess of its pecuniary interest in the shares. GFW IX, L.L.C. and G.F.W. Energy IX, L.P. may be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares 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). Kenneth A. Hersh, an

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Authorized Member of GFW IX, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition of, such shares. Mr. Hersh does not own directly any shares of our common stock. 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 shares by virtue of his shared control of GFW IX, L.L.C. Mr. Albin does not own directly any shares of our common stock. GFW IX, L.L.C. has delegated full power and authority to manage NGP IX to NGP Energy Capital Management, L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares.

¹⁹: 19,512 shares are restricted stock that will vest in two equal installments occurring on February 11, 2015 and February 11, 2016. 16,875 shares are restricted stock that will vest in three equal installments occurring on March 1, 2015, March 1, 2016 and March 1, 2017.

After this offering, 300,512 shares (assuming no exercise of the underwriters' option to purchase additional shares) or 357,766 shares (assuming full exercise of the underwriters' option to purchase additional shares) will be held directly by a family partnership titled the Grimm Family Limited Partnership. Such shares will be distributed to the family partnership by RSP Permian Holdco, L.L.C. as discussed in note (1) above prior to this offering. Mr. Grimm has voting and dispositive power with respect to such shares. Mr. Grimm disclaims beneficial ownership over these shares except to the extent of his pecuniary interest therein.

²⁰: 19,512 shares are restricted stock that will vest in two equal installments occurring on February 11, 2015 and February 11, 2016. 42,000 shares are restricted stock that will vest in three equal installments occurring on March 1, 2015, March 1, 2016 and March 1, 2017.
²¹: 81,301 shares are restricted stock that will vest in two equal installments occurring on February 11, 2015 and February 11, 2016. 20,000 shares are restricted stock that will vest in three installments, with the first installment of 6,667 shares occurring on March 1, 2015, the second installment of 6,667 shares occurring on March 1, 2016 and the third installment of 6,666 shares occurring on March 1, 2017.

900 shares are held by Mr. McNeill as custodian for minor children under the Uniform Transfer to Minors Act. Mr. McNeill disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein.

²²: 5,000 shares are restricted stock that will vest in three installments, with the first installment of 1,666 shares occurring on March 1, 2015, the second installment of 1,667 shares occurring on March 1, 2016 and the third installment of 1,667 shares occurring on March 1, 2017.

2,500 shares are held by a family limited partnership. Mr. Armes owns 50% of the general partner of the family limited partnership. Mr. Armes disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein.

²³: 5,000 shares are restricted stock that will vest in three installments, with the first installment of 1,666 shares occurring on March 1, 2015, the second installment of 1,667 shares occurring on March 1, 2016 and the third installment of 1,667 shares occurring on March 1, 2017.
²⁴: 500 shares are held by Mr. Wallace as custodian for a minor child under the Uniform Transfer to Minors Act. Mr. Wallace disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. 300 shares are held by a member of Mr. Wallace's immediate family sharing the same household. Mr. Wallace disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. In addition, as Mrs. Wallace's spouse, Mr. Wallace may be deemed to be the beneficial owner of shares beneficially owned by Mrs. Wallace. Mr. Wallace disclaims beneficial ownership of such shares except to the extent of his pecuniary interest therein.

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²⁵: 19,512 shares are restricted stock that will vest in two installments, with the first installment of 14,634 shares occurring on February 11, 2015 and the second installment of 4,878 shares occurring on February 11, 2016. 21,875 shares are restricted stock that will vest in three installments, with the first installment of 7,291 shares occurring on March 1, 2015, the second installment of 7,292 shares occurring on March 1, 2016 and the third installment of 7,292 shares occurring on March 1, 2017.

After this offering, 300,512 shares (assuming no exercise of the underwriters' option to purchase additional shares) or 357,766 shares (assuming full exercise of the underwriters' option to purchase additional shares) will be held directly by a family partnership titled Arrott Family Holdings, L.P. Such shares will be distributed to the family partnership by RSP Permian Holdco, L.L.C. as discussed in note (1) above. Mr. Arrott has voting and dispositive power with respect to such shares. Mr. Arrott disclaims beneficial ownership over these shares except to the extent of his pecuniary interest therein.

²⁶: 17,073 shares are restricted stock that will vest on February 11, 2015. 12,188 shares are restricted stock that will vest in three installments, with the first installment of 4,063 shares occurring on March 1, 2015, the second installment of 4,063 shares occurring on March 1, 2016 and the third installment of 4,062 shares occurring on March 1, 2017.

Prior to the distribution of shares of our common stock by RSP Permian Holdco, L.L.C. to its members (discussed in note (1)) and this offering, Mrs. Pollard's spouse holds 3,000 shares of our common stock directly. Mrs. Pollard's spouse will receive 9,399 shares of our common stock in the distribution of shares of our common stock by RSP Permian Holdco, L.L.C. to its members, and in the event the underwriters' option to purchase additional shares is exercised in full, RSP Permian Holdco, L.L.C. will make an additional distribution of 1,850 shares of our common stock to him. Mrs. Pollard disclaims beneficial ownership of these shares except to the extent of her pecuniary interest therein.

After this offering, 291,113 shares (assuming no exercise of the underwriters' option to purchase additional shares) or 346,517 shares (assuming full exercise of the underwriters' option to purchase additional shares) will be held directly by a family partnership titled Pollard Resource Holdings, LP. Such shares will be distributed to the family partnership by RSP Permian Holdco, L.L.C. as discussed in note (1) above. Mrs. Pollard has voting and dispositive power with respect to such shares. Mrs. Pollard disclaims beneficial ownership over these shares except to the extent of his pecuniary interest therein.

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OUR IPO AND RELATED TRANSACTIONS

Our IPO

On January 23, 2014, we completed our IPO, selling 23 million shares of our common stock at $19.50 per share to the public. Of the 23 million shares issued and sold to the public, 9.2 million shares were issued by the Company and 13.8 million shares were sold by selling stockholders. Our common stock began trading on the NYSE on January 17, 2014 under the symbol "RSPP." Immediately following the closing of our IPO, common stock held by public holders represented approximately 32% of our outstanding common stock.

The net proceeds to us from our IPO were approximately $163 million. These proceeds were used to fully repay our $70 million term loan, reduce outstanding borrowings under our revolving credit facility, make cash payments as partial consideration for certain working interests in oil and natural gas properties contributed to us in conjunction with our IPO, pay cash bonuses to certain of our employees, and fund a portion of our capital expenditure plan. We did not receive any proceeds from the sale of shares by the selling stockholders in the IPO.

In connection with our IPO, we entered into several transactions that changed the structure and scope of the Company. See "—Corporate Formation Transactions."

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 acquired additional working interests in certain of our existing properties in the Permian Basin from Summit and EGL. Together with the working interests acquired pursuant to the preferential purchase rights and subsequently contributed to us in connection with our IPO, 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 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 Collins & Wallace Holdings, LLC, a newly-formed entity that contributed these acquired 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 effective 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.

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

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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 (8,092 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.

This acreage currently contains no producing wells. However, we have identified a total of approximately 276 gross horizontal drilling locations on this acreage and additional contiguous acreage acquired in Dawson during 2014, of which 92 are located in the Wolfcamp B zone, 92 are located in the Middle Spraberry zone and 92 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.

Pursuant to the terms of a corporate reorganization that was completed in connection with our IPO, (i) the members of RSP Permian, L.L.C. contributed all of their interests in RSP Permian, L.L.C. to RSP Permian Holdco, L.L.C., a newly-formed entity wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. contributed 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., 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 audited historical combined financial statements of RSP Permian, L.L.C. and Rising Star) and the right to receive approximately $27.7 million in cash. As a result of the reorganization, RSP Permian, L.L.C. became a wholly owned subsidiary of RSP Permian, Inc.

The Rising Star Acquisition

In connection with our IPO, we completed the Rising Star Acquisition. In exchange, Rising Star received shares of RSP Permian, Inc.'s common stock and the right to receive approximately $1.7 million in cash. The Rising Star Acquisition increased our average working interest in approximately 3,250 gross acres and 36 gross producing wells in the Permian Basin. The Rising Star Assets represented substantially all of Rising Star's production and revenues for the year ended December 31, 2013.

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The Collins and Wallace Contributions

Collins, Wallace LP and Collins & Wallace Holdings, LLC contributed to us certain working interests in certain of RSP Permian, L.L.C.'s existing properties in the Permian Basin. In exchange, (i) Collins received shares of RSP Permian, Inc.'s common stock and the right to receive approximately $1.6 million in cash, (ii) Wallace LP received shares of RSP Permian, Inc.'s common stock and the right to receive approximately $0.6 million in cash, and (iii) Collins & Wallace Holdings, LLC received shares of RSP Permian, Inc.'s common stock. The Collins and Wallace Contributions occurred in connection with our IPO.

The Pecos Contribution

In connection with our IPO, Pecos, an entity owned by certain members of our management team, contributed to us certain working interests in certain acreage and wells in the Permian Basin in which RSP Permian, L.L.C. already had working interests. In exchange, Pecos received shares of RSP Permian, Inc.'s common stock. The Pecos Contribution increased our working interests in approximately 650 gross acres and six producing wells.

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 "—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 contributed both 25% NPIs to us (the "ACTOIL NPI Repurchase") in exchange for shares of RSP Permian, Inc.'s common stock. This contribution occurred in connection with our IPO.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Transactions with Affiliates

Resolute Disposition

As more fully described under "Our IPO and Related Transactions—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 "Our IPO and Related Transactions—Corporate Formation Transactions—The Rising Star Acquisition," we acquired from Rising Star working interests in certain acreage and wells in the Permian Basin in exchange for shares of RSP Permian, Inc.'s common stock and the right to receive approximately $1.7 million in cash. Prior to our IPO, an affiliate of NGP, Natural Gas Partners VIII, L.P., owned 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. own 3%, 3%, 2% and 4% of the membership interests in Rising Star Energy Holdings, L.P. Immediately prior to the completion of our IPO, Rising Star owned approximately 3% of RSP Permian, Inc.'s common stock.

Corporate Reorganization

As described in "Our IPO and Related Transactions," in connection with our IPO, (i) the members of RSP Permian, L.L.C. contributed all of their interests in RSP Permian, L.L.C. to RSP Permian Holdco, L.L.C., a newly-formed entity that is wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. contributed 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., 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 audited historical combined financial statements of RSP Permian, L.L.C. and Rising Star) and the right to receive approximately $27.7 million in cash. 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

Mr. Collins, Wallace LP and Collins & Wallace Holdings, LLC each contributed to us working interests in certain of RSP Permian, L.L.C.'s existing properties. In exchange, (i) Collins received shares of RSP Permian, Inc.'s common stock and the right to receive approximately $1.6 million in cash, (ii) Wallace LP received shares of RSP Permian, Inc.'s common stock and the right to receive approximately $0.6 million in cash, and (iii) Collins & Wallace Holdings, LLC received shares of RSP Permian, Inc.'s common stock. See "Our IPO and Related 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

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Management, LLC, and Mr. Wallace and Mrs. Wallace are the managers of Wallace Management. Collins & Wallace Holdings, LLC is owned equally by Mr. Collins and Wallace LP. Mr. Collins is the manager of Collins & Wallace Holdings, LLC.

Messrs. Collins and Wallace were appointed to our board of directors shortly after the consummation of our IPO and, prior to this offering, own approximately 15.8% and 16.4% of RSP Permian, Inc.'s common stock, respectively.

Pecos Contribution and Glasscock County Acquisition from Pecos

As described under "Our IPO and Related Transactions," we acquired from Pecos working interests in certain acreage and wells in the Permian Basin in exchange for shares of RSP Permian, Inc.'s common stock. In addition, in July 2014, the Company acquired from Pecos working interests in certain acreage and wells in Glasscock County, Texas for approximately $4.5 million in cash. 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, and each of Messrs. Gray, Daugbjerg and Huck serve as managers of the general partner of Pecos.

Coronado Midstream, LLC

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 each own approximately 10.3% of the ownership interests in Coronado Midstream, LLC, and the remaining interests in Coronado Midstream, LLC are owned by unaffiliated third parties. Mr. Collins is the chairman of the board of managers of Coronado Midstream, LLC. For the year ended December 31, 2013, Coronado Midstream, LLC accounted for 8% of our revenue.

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 approximately $0.3 million during the year ended December 31, 2013. 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 Wallace Management, and Mr. Wallace and Mrs. Wallace are the managers of Wallace Management.

Reimbursement of IPO Expenses

Approximately $1.5 million of the estimated $3.5 million of expenses of our IPO payable by us were borne by the members of RSP Permian Holdco, L.L.C. as a result of the Transactions. During the first quarter of 2014, we reimbursed RSP Permian Holdco, L.L.C. for such expenses.

Director Cash Retainer

Mr. Albin, who is a co-founder and senior partner of NGP, is prohibited by NGP policies from receiving equity compensation in exchange for his service on a company's board of directors. As such, on an annual basis, in lieu of the restricted stock awarded to the other non-employee members of our board of directors, we will pay $100,000 in cash to NGP, in quarterly installments, in exchange for

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Mr. Albin's services as a member of our board of directors. The non-employee members of our board of directors also receive an annual cash retainer of $50,000 in quarterly installments in exchange for serving on our board of directors. Mr. Albin's cash retainer has been directed to be received by NGP.

Registration Rights Agreement

In connection with the closing of our IPO, we entered into a registration rights agreement with RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace LP, ACTOIL, Rising Star and Pecos. Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

Demand Rights. At any time after the 180 day lock-up period following our IPO, and subject to the limitations set forth below, each of RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace LP and ACTOIL (or their permitted transferees) has the right to require us by written notice to prepare and file a registration statement registering the offer and sale of a certain number of their shares of common stock. Generally, we are required to provide notice of the request within five business days following the receipt of such demand request to all other holders of our common stock, who may, in certain circumstances, participate in the registration. Subject to certain exceptions, we will not be obligated to effect a demand registration within 90 days after the closing of any underwritten offering of shares of our common stock. Further, we are not obligated to effect:

•: (i) through December 31, 2016, more than a total of three demand registrations or (ii) on or after January 1, 2017, more than a total of one demand registration per calendar year at the request of RSP Permian Holdco, L.L.C.;
•: more than two demand registrations for Collins;
•: more than two demand registrations for Wallace LP; or
•: more than two demand registrations for ACTOIL.

We are also not obligated to effect any demand registration in which the anticipated aggregate offering price included in such offering is less than $50 million. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. We will be required to use all commercially reasonable efforts to maintain the effectiveness of any such registration statement until all shares covered by such registration statement have been sold.

In addition, each of RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace LP and ACTOIL (or their permitted transferees) has the right to require us, subject to certain limitations, to effect a distribution of any or all of their shares of common stock by means of an underwritten offering. In general, any demand for an underwritten offering (other than the first requested underwritten offering made in respect of a prior demand registration and other than a requested underwritten offering made concurrently with a demand registration) shall constitute a demand request subject to the limitations set forth above.

Piggyback Rights. Subject to certain exceptions, if at any time we propose to register an offering of common stock or conduct an underwritten offering, whether or not for our own account, then we must notify RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace LP, ACTOIL, Rising Star and Pecos (or their permitted transferees) of such proposal at least five business days before the anticipated filing date or commencement of the underwritten offering, as applicable, to allow them to include a specified number of their shares in that registration statement or underwritten offering, as applicable.

Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances.

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We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.

Stockholders' Agreement

In connection with the closing of our IPO, we entered into a stockholders' agreement with RSP Permian Holdco, L.L.C., Collins, Wallace LP, Rising Star and Pecos. The stockholders' agreement provided 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. has 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 has 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 has 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 requires 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.

Prior to this offering, RSP Permian Holdco, L.L.C. has the right to designate two nominees and Collins and Wallace LP have the right to each designate one nominee. After this offering, assuming either no exercise or full exercise of the underwriters' option to purchase additional shares of our common stock, RSP Permian Holdco, L.L.C., Collins and Wallace LP will each have the right to designate one nominee. However, we expect the parties to the stockholders' agreement will waive the requirement to have a nominee of RSP Permian Holdco, L.L.C. tender his resignation to our board of directors, and as such, RSP Permian Holdco, L.L.C. will continue to have two designees after this offering.

In addition, the stockholders' agreement provides that for so long as RSP Permian Holdco, L.L.C. and its affiliates collectively own 15% or more of the outstanding shares of our common stock, we will cause any committee of our board to include in its membership at least one director designated by RSP Permian Holdco, L.L.C., except to the extent that such membership would violate applicable securities laws or stock exchange rules. After this offering, RSP Permian Holdco, L.L.C. and its affiliates will no longer collectively own 15% or more of the outstanding shares of our common stock and will therefore no longer have such right.

Further, the stockholders' agreement provides RSP Permian Holdco, L.L.C. the right to designate a non-voting representative to attend meetings of our board and committees thereof for so long as RSP Permian Holdco, L.L.C. beneficially owns at least 5% of the outstanding shares of our common stock and has designated a nominee to our board that is not a manager, employee, director or officer of Production Opportunities or Natural Gas Partners IX, L.P. or any affiliate thereof. After this offering, RSP Permian Holdco, L.L.C. will continue to beneficially own at least 5% of the outstanding shares of our common stock and will therefore continue to have such right.

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Procedures for Approval of Related Party Transactions

Prior to the closing of our IPO, we did not maintain 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 $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.

Our board of directors periodically reviews all Related Party Transactions that the rules of the SEC require be disclosed in the Company's annual report or proxy statement, as applicable, and makes a determination regarding the initial authorization or ratification of any such transaction.

In determining whether to approve or disapprove entry into a Related Party Transaction, our board of directors takes into account, among other factors, the following: (1) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (2) the extent of the Related Person's interest in the transaction.

Since January 1, 2013, there has not been any transaction or series of similar transactions to which the Company was or is a party in which the amount involved exceeded or exceeds $120,000 and in which any of the Company's directors, executive officers, holders of more than 5% of any class of its voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in "Executive Compensation" and the transactions described or referred to in "Certain Relationships and Related Party Transactions."

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DESCRIPTION OF CAPITAL STOCK

The authorized capital stock of RSP Permian, Inc. consists of 300,000,000 shares of common stock, $0.01 par value per share, of which 72,963,951 shares are issued and outstanding (including 463,951 shares of restricted stock that have been awarded to our directors and certain of our employees and consultants), and 15,000,000 shares of preferred stock, $0.01 par value per share, of which no shares are issued and outstanding. Upon completion of this offering, we will have 78,963,951 shares issued and outstanding (if the underwriters' option to purchase additional shares is not exercised) or 79,863,951 shares issued and outstanding (if the underwriters' option to purchase additional shares is exercised in full).

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, 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 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 authorizes 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 $0.01 per share, covering up to an aggregate of 15,000,000 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.

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Except as provided by law or in a preferred stock designation, the holders of preferred stock are not entitled to vote at or receive notice of any meeting of stockholders.

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 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 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.

Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:

•: establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be

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timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our amended and restated bylaws specify the requirements as to form and content of all stockholders' notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;

•

provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

•

provide that the authorized number of directors may be changed only by resolution of the board of directors;

•

provide that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

•

at any time after the Principal Investors, NGP Energy Capital Management, L.L.C. and their respective affiliates (the "Sponsors") no longer collectively own more than 50% of the outstanding shares of our common stock,

•: provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);
•: provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding common stock (prior to such time, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding common stock); and
•: provide that special meetings of our stockholders may only be called by the board of directors, the chief executive officer or the chairman of the board (prior to such time, a special meeting may also be called at the request of stockholders holding a majority of the outstanding shares entitled to vote);

•

provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, other than directors which may be elected by holders of preferred stock, if any. This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for stockholders to replace a majority of the directors;

•

provide that we renounce any interest in existing and future investments in other entities by, or the business opportunities of, the Sponsors or any of their officers, directors, agents, stockholders, members, partners, affiliates and subsidiaries (other than our directors that are presented business opportunities in their capacity as our directors) and that they have no obligation to offer us those investments or opportunities; and

•

provide that our bylaws can be amended by the board of directors.

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Forum Selection

Our amended and restated certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

•: any derivative action or proceeding brought on our behalf;
•: any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders;
•: any action asserting a claim against us arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws; or
•: any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.

Our amended and restated certificate of incorporation also provides that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and to have consented to, this forum selection provision. Although we believe these provisions will benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. The enforceability of similar exclusive forum provisions in other companies' certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that this provision in our amended and restated certificate of incorporation is inapplicable or unenforceable.

Limitation of Liability and Indemnification Matters

Our amended and restated certificate of incorporation limits 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;
•: 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 also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated bylaws also 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 have entered into indemnification agreements with each of our current and future directors and officers. These agreements require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their

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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 in our amended and restated certificate of incorporation and the indemnification agreements facilitates 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 American Stock Transfer & Trust Company, LLC.

Listing

Our common stock is listed on the NYSE under the symbol "RSPP."

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SHARES ELIGIBLE FOR FUTURE SALE

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. Sales of a substantial number of shares of our common stock in the public market, 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. See "Risk Factors—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."

Sales of Restricted Shares

We have outstanding an aggregate of 72,963,951 shares of common stock, including 463,951 shares of restricted stock that have been awarded to our directors and certain of our employees and consultants. Upon completion of this offering, 78,963,951 shares of our common stock will be outstanding, assuming no exercise of the underwriters' option to purchase additional 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 or that were sold in our IPO) 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 90 days after the date of this prospectus; and
•: shares will be eligible for sale upon the expiration of the lock-up agreements, beginning 90 days after the date of this prospectus (subject to extension) and when permitted under Rule 144 or Rule 701.

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 60 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 purchased shares from us in connection with a compensatory stock or option plan or other written agreement before our IPO, or who purchased shares from us after our IPO upon the exercise of options granted before our IPO, are entitled to sell such shares 90 days after our IPO 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

On February 2, 2014, we filed a registration statement on Form S-8 under the Securities Act to register shares issuable under our equity incentive plan. Shares registered under such registration statement are available for sale in the open market, 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 currently make, and do not plan to make for the foreseeable future, any distributions on our common stock. 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 or successor 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. is acting as the representative of the underwriters named below. Under the terms of an underwriting agreement, to be filed as an exhibit to the registration statement of which this prospectus forms a part, each of the underwriters named below has severally agreed to purchase from the selling stockholders the respective number of shares of common stock shown opposite its name below:

Underwriters		Number of Shares

Barclays Capital Inc.





Total		15,000,000

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 that 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.

	Selling Stockholders

	No Exercise	Full Exercise
Per Share	$	$


Total (in thousands)	$	$

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.

We have agreed to pay expenses incurred by the selling stockholders in connection with this offering, other than the underwriting discounts and commissions, including offering related expenses paid prior to this offering that were borne by such selling stockholders. We estimate that our expenses

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for this offering will be approximately $800,000. We have also agreed to reimburse the underwriters for certain of their expenses in an amount up to $20,000.

Option to Purchase Additional Shares

We and certain of 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 additional 900,000 and 1,350,000 shares, respectively, at the public offering price less underwriting discounts and commissions. This option may be exercised to the extent the underwriters sell more than 15,000,000 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 60 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.

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.

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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 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

Our common stock is listed 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.

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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. In addition, affiliates of several of the underwriters are lenders under our revolving credit facility and term loan and, accordingly, will receive a portion of the net proceeds from this offering. 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 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 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 representative 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

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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 which has implemented the Prospectus Directive (each, a "Relevant Member State") an offer to the public of any common stock which 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 which 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,

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 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 the 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.

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United Kingdom

This 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

The offering of the common stock in Canada is being made on a private placement basis in reliance on exemptions from the prospectus requirements under the securities laws of each applicable Canadian province and territory where the common stock may be offered and sold, and therein may only be made with investors that are purchasing as principal and that qualify as both an "accredited investor" as such term is defined in National Instrument 45-106 Prospectus and Registration Exemptions and as a "permitted client" as such term is defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligation. Any offer and sale of the common stock in any province or territory of Canada may only be made through a dealer that is properly registered under the securities legislation of the applicable province or territory wherein the common stock is offered and/or sold or, alternatively, by a dealer that qualifies under and is relying upon an exemption from the registration requirements therein.

Any resale of the common stock by an investor resident in Canada must be made in accordance with applicable Canadian securities laws, which may require resales to be made in accordance with prospectus and registration requirements, statutory exemptions from the prospectus and registration requirements or under a discretionary exemption from the prospectus and registration requirements granted by the applicable Canadian securities regulatory authority. These resale restrictions may under certain circumstances apply to resales of the common stock outside of Canada.

Upon receipt of this document, each Canadian investor hereby confirms that it has expressly requested that all documents evidencing or relating in any way to the sale of the securities described herein (including for greater certainty any purchase confirmation or any notice) be drawn up in the English language only. Par la réception de ce document, chaque investisseur canadien confirme par les présentes qu'il a expressément exigé que tous les documents faisant foi ou se rapportant de quelque manière que ce soit à la vente des valeurs mobilières décrites aux présentes (incluant, pour plus de certitude, toute confirmation d'achat ou tout avis) soient rédigés en anglais seulement.

Notice to Prospective Investors in Switzerland

This prospectus does not constitute an issue prospectus pursuant to Article 652a or Article 1156 of the Swiss Code of Obligations ("CO") and the shares will not be listed on the SIX Swiss Exchange. Therefore, this prospectus may not comply with the disclosure standards of the CO and/or the listing rules (including any prospectus schemes) of the SIX Swiss Exchange. Accordingly, the shares may not be offered to the public in or from Switzerland, but only to a selected and limited circle of investors, which do not subscribe to the shares with a view to distribution.

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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. Certain matters relating to 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.

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.

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.

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.

Estimates of our oil and natural gas reserves and related future net cash flows related to our properties as of December 31, 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 are required to file annual and quarterly reports and other information with the SEC. You may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C., 20549. Please call 1-800-SEC-0330 for further information on the operation of the Public Reference Room. Our filings will also be available to the public from commercial document retrieval services and at the web site maintained by the SEC at http://www.sec.gov. Our reports and other information that we have filed, or may in the future file, with the SEC are not incorporated by reference into and do not constitute part of this prospectus.

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.

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INDEX TO FINANCIAL STATEMENTS

		Page

RSP PERMIAN, INC.
Unaudited Pro Forma Combined Statements of Operations
Introduction			F-2
Unaudited pro forma combined statement of operations for the year ended December 31, 2013			F-4
Unaudited pro forma combined statement of operations for the three months ended March 31, 2014			F-5
Notes to unaudited pro forma combined financial data			F-6
Unaudited Historical Financial Statements
Unaudited consolidated balance sheet as of March 31, 2014			F-7
Unaudited consolidated statements of operations for the three months ended March 31, 2014 and 2013			F-8
Unaudited consolidated statements of changes in stockholders'/members' equity for the three months ended March 31, 2014			F-9
Unaudited consolidated statements of cash flows for the three months ended March 31, 2014 and 2013			F-10
Notes to unaudited consolidated financial statements			F-11
Historical Financial Statements
Report of independent registered public accounting firm			F-31
Balance sheet as of December 31, 2013			F-32
Notes to balance sheet			F-33
RSP PERMIAN, L.L.C. AND RISING STAR ENERGY DEVELOPMENT CO., L.L.C. (PREDECESSOR)
Historical Combined Financial Statements
Report of independent registered public accounting firm			F-35
Combined balance sheets as of December 31, 2013 and 2012			F-36
Combined statements of operations for the years ended December 31, 2013 and 2012			F-37
Combined statement of changes in members' equity for the years ended December 31, 2013 and 2012			F-38
Combined statements of cash flows for the years ended December 31, 2013 and 2012			F-39
Notes to combined financial statements			F-40
Spanish Trail Assets Financial Statements
Report of independent certified public accountants			F-67
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-68
Notes to statements of revenues and direct operating expenses			F-69
The Contributed Properties Financial Statements
Report of independent certified public accountants			F-73
Statements of revenues and direct operating expenses for the years ended December 31, 2013 and 2012			F-74
Notes to statements of revenues and direct operating expenses			F-75

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RSP PERMIAN, INC.

UNAUDITED PRO FORMA COMBINED STATEMENTS OF OPERATIONS

Introduction

RSP Permian, Inc. (the "Company") is a Delaware corporation formed as a successor to RSP Permian, L.L.C. ("RSP") in September 2013 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 January 1, 2013 for pro forma statements of operations purposes:

•: the exclusion by Rising Star of certain assets and liabilities (the "Rising Star Excluded Assets") that were not 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 IPO.

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 80 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 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 was completed in connection with the IPO, (i) the members of RSP contributed all of their interests in RSP to RSP Permian Holdco, L.L.C., a newly-formed entity that is wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. contributed all of its interests in RSP to the Company in exchange for 28,536,427 shares of the Company's common stock, an assignment of RSP Permian, L.L.C.'s pro rata share of an escrow related to the Resolute Disposition and approximately $27.7 million in cash. As a result of the Corporate Reorganization, RSP became a wholly owned subsidiary of the Company.

The Collins and Wallace Contributions. In connection with the IPO, Ted Collins, Jr., Wallace Family Partnership, LP and Collins & Wallace Holdings, LLC contributed to the Company certain working interests (collectively, the "Collins and Wallace Contributions") in certain oil and natural gas properties owned by RSP. In exchange, (i) Collins received 9,902,876 shares of the Company's common stock and approximately $1.6 million in cash, (ii) Wallace LP received 9,954,626 shares of the Company's common stock and $0.6 million in cash, and (iii) Collins & Wallace Holdings, LLC received 2,166,152 shares of the Company's common stock.

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RSP PERMIAN, INC.

UNAUDITED PRO FORMA COMBINED STATEMENTS OF OPERATIONS (Continued)

The ACTOIL NPI Repurchase. ACTOIL, LLC ("ACTOIL") owned a 25% net profits interest ("NPI") in substantially all of the oil and natural gas properties owned by RSP. In connection with the IPO, ACTOIL contributed 100% of its NPI to the Company in exchange for 10,816,626 shares of the Company's common stock (the "ACTOIL NPI Repurchase").

The IPO. For purposes of the unaudited pro forma combined financial statements, the "IPO" is defined as the issuance and sale to the public of 23 million shares of the Company's common stock of the Company in January 2014, 9.2 million of which were sold by the Company, resulting in approximately $163 million of proceeds, net of underwriting discounts, commissions and offering-related expenses.

The unaudited pro forma combined statements of operations of the Company for the year ended December 31, 2013 are based on: (i) the audited historical combined statements of operations of the Predecessor for the year ended December 31, 2013, adjusted to give effect to the Resolute Disposition, the Spanish Trail Acquisition, the Corporate Reorganization, the Collins and Wallace Contributions, the ACTOIL NPI Repurchase and the IPO as if they occurred on January 1, 2013; (ii) the historical statements of revenues and expenses 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 statements of operations of the Company for the three months ended March 31, 2014 are based on: (i) the unaudited consolidated historical statement of operations of the Company for the three months ended March 31, 2014, adjusted to give effect to the Corporate Reorganization, the Collins and Wallace Contributions, the ACTOIL NPI Repurchase and the IPO as if they occurred on January 1, 2014; and (ii) the historical accounting records of the Company.

The unaudited pro forma statements of operations for both the year ended December 31, 2013 and the three months ended March 31, 2014 have been prepared on the basis that the Company is subject to subchapter C of the Internal Revenue Code of 1986, as amended, and as a result, is subject to U.S. federal and state income taxes at the entity level. The unaudited pro forma combined statements of operations 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 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 above 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. 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 financial statements and related notes are presented for illustrative purposes only. If the IPO and other transactions contemplated herein had occurred in 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 IPO 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 IPO and the other transactions noted in 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, 2013

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

	(In thousands, except per share data)
				(a)			(b)			(c)			(d)
REVENUES
Oil sales	$	110,345		$	(299	)	$	(5,801	)	$	21,659		$	51,510		$	177,415
NGL sales		7,314			(76	)		(501	)		1,416			3,491			11,644
Natural gas sales		5,383			(228	)		(353	)		733			2,112			7,647


Total revenues	$	123,042		$	(603	)	$	(6,655	)	$	23,808		$	57,113		$	196,706
OPERATING EXPENSES
Lease operating expenses		14,113			(108	)		(694	)		2,932			6,423			22,667
Production and ad valorem taxes		8,326			(17	)		(326	)		1,283			3,970			13,236
Depreciation, depletion and amortization		47,158			(134	)		—			3,159			30,304			80,487
Asset retirement obligation accretion		121			(3	)		—			18			63			199
Exploration		551			—						—			—			551
General and administrative expenses		3,852			(135	)		—			—			—			3,716


Total operating expenses		74,121			(397	)		(1,020	)		7,393			40,760			120,856


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


Operating income (loss)		71,621			(206	)		(28,335	)		16,415			16,353			75,850


OTHER INCOME (EXPENSE)
Other income		1,202			—			—			—			—			1,202
Gain (loss) on derivative instruments		(2,607	)		—			—			—			—			(2,607	)
Interest expense		(5,216	)		(127	)		—			(5,547	)(e)		—			(10,890	)


Total other income (expense)		(6,621	)		(127	)		—			(5,547	)		—			(12,295	)


INCOME (LOSS) BEFORE TAXES		65,000			(333	)		(28,335	)		10,868			16,353			63,555
Income tax benefit (expense)		(2,262	)		—			283			(109	)		(20,629	)(f)		(22,717	)


NET INCOME (LOSS)	$	62,738		$	(333	)	$	(28,052	)	$	10,759		$	(4,276	)	$	40,838




Net income per common share(j)
Basic and diluted																$	0.56
Weighted average common shares outstanding(j)
Basic and diluted																	72,500

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 THREE MONTHS ENDED MARCH 31, 2014

	RSP Permian, Inc.			Formation Related Adjustments		IPO Bonus and Incentive Unit Compensation			Income Tax Adjustments		Pro Forma

				(g)		(h)			(i)
REVENUES
Oil sales	$	51,471		$	4,459	$	—		$	—	$	55,930
NGL sales		4,081			335		—			—		4,417
Natural gas sales		2,206			191		—			—		2,397


Total revenues	$	57,758		$	4,985	$	—		$	—	$	62,744
OPERATING EXPENSES
Lease operating expenses		7,063			694		—			—		7,757
Production and ad valorem taxes		3,876			251		—			—		4,127
Depreciation, depletion and amortization		16,361			3,633		—			—		19,994
Asset retirement obligation accretion		29			9		—			—		38
Exploration		756			—							756
General and administrative expenses		17,016			—		(14,952	)		—		2,064


Total operating expenses		45,101			4,587		(14,952	)		—		34,736


Operating income		12,657			398		14,952			—		28,008


OTHER INCOME (EXPENSE)
Other income		310			—		—			—		310
Loss on derivative instruments		(4,153	)		—		—			—		(4,153	)
Interest expense		(1,131	)		—		—			—		(1,131	)


Total other expense		(4,974	)		—		—			—		(4,974	)
INCOME BEFORE TAXES		7,683			398		14,952			—		23,033
Income tax (expense) benefit		(135,213	)		—		—			126,921		(8,292	)


NET INCOME (LOSS)	$	(127,530	)	$	398	$	14,952		$	126,921	$	14,741




Net income per common share(j)
Basic and diluted											$	0.20
Weighted average common shares outstanding(j)
Basic and diluted												72,500

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

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RSP PERMIAN, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

The following notes discuss the columns presented and the entries made to the unaudited combined financial statements.

Predecessor Historical. This column represents the audited historical combined statement of operations of the Predecessor for the year ended December 31, 2013.

RSP Permian, Inc. This column represents the unaudited historical statement of operations for the Company for the three months ended March 31, 2014.

Pro Forma Adjustments. We made the following adjustments in the preparation of the unaudited pro forma statements of operations.

(a): Adjustments to reflect the Rising Star Excluded Assets.
(b): Adjustments to reflect the reduction in revenues, expenses and other income pertaining to certain oil and natural gas properties sold in the Resolute Disposition 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 in the Resolute Disposition.
(c): Adjustments to reflect the historical statements of revenues and expenses relating to the Spanish Trail Assets. The Spanish Trail Acquisition includes assets acquired by RSP, Mr. Collins, Wallace Family Partnership, LP and Collins & Wallace Holdings, LLC.
(d): Adjustments to reflect the total effect of the Corporate Reorganization, the Collins and Wallace Contributions and the ACTOIL NPI Repurchase on the pro forma combined statements of operations.
(e): Adjustments to reflect the increase in interest expense on borrowings by RSP to fund the Spanish Trail Acquisition.
(f): 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%, which is inclusive of federal and state income taxes.
(g): Adjustments to reflect the revenues and expenses of certain oil and natural gas properties that were acquired via the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, less revenues and expenses of the Rising Star Excluded Assets, for the 22 days prior to the completion of the Collins and Wallace Contributions, the ACTOIL NPI Repurchase and the acquisition from Rising Star.
(h): Adjustments to general and administrative expense include a reduction related to non-cash incentive unit compensation and cash bonuses triggered by the IPO totaling approximately $15 million.
(i): Reflects the elimination of a $132 million non-recurring tax adjustment related to the Corporate Reorganization. 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.
(j): Basic and diluted earnings per share is based on the sale of 72,500,000 shares of the Company's common stock in the IPO.

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RSP PERMIAN, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

	March 31, 2014			December 31, 2013

	(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10,737		$	13,234
Accounts receivable		34,819			26,346
Accounts receivable, related party		7,107			3,672
Escrow receivable		—			3,197
Escrow deposit		15			15
Derivative instruments		225			671


Total current assets		52,903			47,135
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method		1,573,057			595,486
Accumulated depletion		(95,899	)		(88,514	)


Total oil and natural gas properties, net		1,477,158			506,972
Other property and equipment, net		12,654			9,316


Total property, plant and equipment		1,489,812			516,288
LONG-TERM ASSETS
Derivative instruments		440			1,078
Restricted cash		150			150
Other assets		28,830			23,004


Total long-term assets		29,420			24,232


TOTAL ASSETS	$	1,572,135		$	587,655




LIABILITIES AND STOCKHOLDERS'/MEMBERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	26,339		$	18,548
Accrued expenses		23,961			10,460
Interest payable		385			296
Derivative instruments		4,156			1,562


Total current liabilities		54,841			30,866
LONG-TERM LIABILITIES
Asset retirement obligations		4,805			2,584
Derivative instruments		207			43
Term loan		—			70,000
Revolving credit facility		110,000			58,155
NPI payable		—			36,931
Deferred taxes		332,315			2,195


Total long-term liabilities		447,327			169,908


Total liabilities		502,168			200,774
STOCKHOLDERS'/MEMBERS' EQUITY
Members' equity		—			386,881
Common stock, $.01 par value; 300,000,000 shares authorized, 72,921,999 shares issued and outstanding at March 31, 2014; 1,000,000 shares authorized, no shares issued or outstanding at December 31, 2013		725			—
Additional paid-in capital		1,196,772			—
Accumulated deficit		(127,530	)		—


Total stockholders'/members' equity		1,069,967			386,881


TOTAL LIABILITIES AND STOCKHOLDERS'/MEMBERS' EQUITY	$	1,572,135		$	587,655

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

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RSP PERMIAN, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,

	2014			2013
	(In thousands, except per share data)
REVENUES
Oil sales	$	51,471		$	21,923
NGL sales		4,081			1,567
Natural gas sales		2,206			1,165


Total revenues		57,758			24,655
OPERATING EXPENSES
Lease operating expenses	$	7,063		$	3,355
Production and ad valorem taxes		3,876			1,636
Depreciation, depletion and amortization		16,361			10,202
Asset retirement obligation accretion		29			25
Exploration		756			63
General and administrative expenses		17,016			555


Total operating expenses		45,101			15,836


(Gain) on sale of assets		—			(6,129	)


OPERATING INCOME	$	12,657		$	14,948
OTHER INCOME (EXPENSE)
Other income	$	310		$	199
Loss on derivative instruments		(4,153	)		(1,657	)
Interest expense		(1,131	)		(624	)


Total other expense		(4,974	)		(2,082	)


INCOME BEFORE TAXES		7,683			12,866
INCOME TAX EXPENSE		(135,213	)		—


NET INCOME (LOSS)	$	(127,530	)	$	12,866




Loss per common share:
Basic	$	(2.03	)
Diluted	$	(2.03	)
Weighted average shares outstanding:
Basic		62,904
Diluted		62,904

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

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RSP PERMIAN, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS'/MEMBERS' EQUITY

(Unaudited)

	Members' Equity				Common Stock		Additional Paid-in Capital			Accumulated Deficit			Total Stockholders' Equity/ Members' Equity

	(In thousands)
BALANCE AT DECEMBER 31, 2013	$	386,881		—	$	—	$	—		$	—		$	386,881
Distribution of net assets to predecessor owner, including cash of $1,663		(21,147	)	—		—		14,168			—			(6,979	)
The corporate reorganization		(365,734	)	—		—		365,734			—			—
RSP Permian Holdco, L.L.C.'s contributions of interests in RSP Permian, L.L.C. in exchange for RSP Permian, Inc.'s common stock		—		63,275		633		(633	)		—			—
Ted Collins, Jr., Wallace Family Partnership, LP, Collins & Wallace Holdings, LLC, Pecos Energy Partners, L.P. and ACTOIL LLC's contributions in exchange for RSP Permian, Inc.'s common stock		—		—		—		642,436			—			642,436
Shares of common stock sold in initial public offering net of offering costs		—		9,225		92		163,052			—			163,144
Equity-based compensation		—		—		—		12,015			—			12,015
Net loss		—		—		—		—			(127,530	)		(127,530	)


BALANCE AT MARCH 31, 2014	$	—		72,500	$	725	$	1,196,772		$	(127,530	)	$	1,069,967

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

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RSP PERMIAN, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,

	2014			2013
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(127,530	)	$	12,866
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		16,361			10,070
Abandoned equipment and intangibles		—			1
Accretion of asset retirement obligations		29			25
Equity based compensation		12,015			—
Amortization of loan fees		208			131
Deferred income taxes		135,213			—
Equity in earnings of investment		—			30
(Gain) on sale of assets		—			(6,129	)
Loss on derivative instruments		4,153			1,657
Net cash payments on settled derivatives		(312	)		(109	)
Changes in operating assets and liabilities:
Accounts receivable and accounts receivable from related parties		(7,529	)		2,464
Other assets		(9,039	)		(6,387	)
Interest payable		89			(227	)
Accounts payable		8,350			365
Accrued expenses		(1,007	)		(172	)


Net cash provided by operating activities	$	31,001		$	14,585




CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of assets		—			115,339
Additions to other property and equipment		(1,294	)		255
Additions to oil and natural gas properties		(177,530	)		(57,237	)


Net cash provided by (used in) investing activities	$	(178,824	)	$	58,357




CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock		163,144			—
Distributions		(1,663	)		(29,805	)
Borrowings under long-term debt		110,000			—
Payments on long-term debt		(126,155	)		(85,000	)
NPI payable		—			20,349


Net cash provided by (used in) financing activities	$	145,326		$	(94,456	)




NET CHANGE IN CASH	$	(2,497	)	$	(21,514	)




CASH AT BEGINNING OF YEAR	$	13,234		$	52,263


CASH AT END OF YEAR	$	10,737		$	30,749




SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	$	624		$	3,420
NON-CASH ACTIVITIES
Assets purchased included in accounts payable and accrued expenses	$	14,442		$	2,202
Asset retirement obligation acquired	$	2,412		$	—
Common stock issued for oil and gas properties	$	677,402		$	—
Deferred tax liabilities recorded for oil and gas property acquisitions	$	195,777		$	—
Elimination of NPI payable	$	36,931		$	—

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

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Organization and Description of the Business

RSP Permian, L.L.C., a Delaware limited liability company ("RSP LLC"), 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 LLC is engaged in the acquisition, development and operation of oil and natural gas properties.

On January 23, 2014, RSP Permian, Inc. ("RSP Inc.") completed an initial public offering (the "IPO") and on January 17, 2014, shares of RSP Inc. began trading on the New York Stock Exchange under the ticker "RSPP." In the IPO, 23 million shares were sold at $19.50 per share, raising $449 million of gross proceeds. Of the 23 million shares, 9.2 million were shares sold by RSP Inc., resulting in approximately $163 million of net proceeds, which were used to fully repay the Company's $70 million term loan, repay outstanding borrowings of $56 million under its revolving credit facility, make cash payments to certain existing investors as partial consideration for the properties contributed to the Company by such persons, pay cash bonuses to certain of the Company's employees in connection with the successful completion of the IPO, and fund a portion of its capital expenditure plan. The remaining 13.8 million shares sold in the IPO were sold by selling stockholders, and the Company did not receive any proceeds from the sale of those shares.

In connection with the IPO, several transactions occurred that changed the structure and scope of the Company:

•: Corporate Reorganization: RSP LLC was contributed to RSP Permian Holdco, L.L.C., a newly-formed limited liability company, which contributed all of its interests in RSP LLC to RSP Inc. in exchange for shares of RSP Inc.'s common stock, an assignment of RSP LLC's pro rata share of an escrow related to the Resolute Sale (as defined and described in Note 3) and cash. As a result of this reorganization, RSP LLC became a wholly owned subsidiary of RSP Inc.
•: The Rising Star Acquisition: RSP Inc. acquired from Rising Star Energy Development Co., L.L.C., a Texas limited liability company ("Rising Star"), working interests in certain acreage and wells in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc.'s common stock and cash.
•: The Collins and Wallace Contributions: Ted Collins, Jr. ("Collins"), Wallace Family Partnership, LP ("Wallace LP") and Collins & Wallace Holdings, LLC, a newly-formed entity that is jointly owned by Collins and Wallace LP, contributed certain working interests in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc.'s common stock and, in the case of Collins and Wallace LP, cash (such contributions, the "Collins and Wallace Contributions"). See Note 3 for additional information.
•: The Pecos Contribution: Pecos Energy Partners, L.P. ("Pecos"), an entity owned by certain members of the Company's management team, contributed certain working interests in acreage and wells in the Permian Basin in which RSP LLC already had a working interest in exchange for shares of RSP Inc.'s common stock.
•: The ACTOIL NPI Repurchase: ACTOIL, LLC ("ACTOIL"), the owner of a 25% net profits interest ("NPI") in substantially all of RSP LLC's oil and natural gas properties taken as a whole, contributed their 25% NPI in exchange for shares of RSP Inc.'s common stock (such contribution, the "ACTOIL NPI Repurchase"). See Note 3 for more information.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION (Continued)

Basis of Presentation

These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the audited annual financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States ("GAAP") have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading.

Subsequent Events

The Company has evaluated subsequent events of its consolidated financial statements. There were no material subsequent events requiring additional disclosure in these financial statements.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the consolidated 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 that may affect the amount at which oil and natural gas properties are recorded. Estimation of asset retirement obligations ("AROs") and valuations of derivative instruments and the fair value of incentive unit compensation also require significant assumptions. It is possible that 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.

Reclassifications

Certain reclassifications have been made to prior periods to conform to current period presentation.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Accounts Receivable from Related Parties

The Company's accounts receivable from related parties as of March 31, 2014 and December 31, 2013 consisted of the following:

	March 31, 2014		December 31, 2013

	(In thousands)
Collins	$	3,261	$	—
Wallace LP		3,594		3,672
Collins & Wallace Holdings, LLC		252		—


	$	7,107	$	3,672

Prior to the IPO, Collins, Wallace LP and Collins & Wallace Holdings, LLC had non-operated working interests in substantially all of the oil and natural gas assets that the Company operates. The Company considers the accounts receivable from these related parties to be fully collectible.

Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for its oil and natural gas exploration and production activities. Costs incurred by the Company 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.

The Company 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 Company did not capitalize any interest in the three months ended March 31, 2014 and 2013 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 expensed 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 and leasehold costs 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 $16.3 million and $10.2 million for the three months ended March 31, 2014 and 2013, respectively, and is included in depreciation, depletion and amortization in the accompanying consolidated statements of operations.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The Company's oil and natural gas properties as of March 31, 2014 and December 31, 2013 consisted of the following:

	March 31, 2014			December 31, 2013

	(In thousands)
Proved oil and natural gas properties	$	1,064,430		$	562,019
Unproved oil and natural gas properties		508,627			33,467


Total oil and natural gas properties		1,573,057			595,486
Less: accumulated depletion		(95,899	)		(88,514	)


Total oil and natural gas properties, net	$	1,477,158		$	506,972

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 March 31, 2014 and December 31, 2013, 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 Company 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.

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 Company 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. No impairment of proved property was recorded for the three months ended March 31, 2014 or 2013.

Natural gas volumes are converted to Boe at the rate of six Mcf of natural gas to one 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. NGL volumes are stated in barrels.

Asset Retirement Obligation

The Company 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

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

The Company 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.

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:

	Three Months Ended March 31, 2014

	(In thousands)
Asset retirement obligation at beginning of period	$	2,584
Liabilities assumed		2,192
Accretion expense		29


Asset retirement obligation at end of period	$	4,805

Income Taxes

RSP LLC was organized as a limited liability company and treated as a flow-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of RSP Inc. from January 23, 2014 through March 31, 2014 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the completion of the contribution of RSP LLC, a limited liability company, to a corporation on January 23, 2014, the Company established a $132 million provision for deferred income taxes, which was recognized as tax expense from continuing operations. The primary upward adjustments in the effective tax rate above the U.S. statutory rate are the adjustments related to the contribution of a limited liability company to a corporation noted above along with non-deductible incentive unit compensation.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The following is an analysis of the Company's consolidated income tax expense:

	Three Months Ended March 31,

	2014		2013
	(In thousands)
Current	$	963	$	—
Deferred		134,250		—


Provision for income taxes	$	135,213	$	—

Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The Company's policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2014 and December 31, 2013, the Company did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

The Company's U.S. federal income tax returns and Texas franchise tax returns for 2010 and beyond remain subject to examination by the taxing authorities. There are no material unresolved items related to periods previously audited by these taxing authorities. No other jurisdiction's returns are significant to the Company's financial position.

New Accounting Pronouncements

The Company has reviewed recently issued accounting standards and plans to adopt those that are applicable to it. It does not expect the adoption of those standards to have a material impact on its financial position, results of operations or cash flows.

NOTE 3—ACQUISITIONS AND SALES OF OIL AND NATURAL GAS PROPERTY INTERESTS

Pro Forma Results

The Company's pro forma results for the three months ended March 31, 2013 were derived from the actual results of the Company's accounting predecessor, which reflects the combined results of RSP LLC and Rising Star, and have been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2013. Additionally, the pro forma results for the three months ended March 31, 2013 include the estimated activity associated with the Spanish Trail Acquisition (as defined below), which was completed in September 2013, and the Resolute Sale, which was completed in March 2013, as if each of these transactions had occurred on January 1, 2013.

Our pro forma results for the three months ended March 31, 2014 were derived from our actual results and have been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2013.

The pro forma financial information included below does not give effect to certain acquisitions that were immaterial to our actual and pro forma results for the periods reflected below and does not make any adjustments for non-recurring expenses associated with the IPO.

The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	Three Months Ended March 31, 2014						Three Months Ended March 31, 2013

	Actual			Pro Forma			Actual		Pro Forma
	(In thousands)						(In thousands)
Contributions:
Revenues	$	57,758		$	62,744		$	24,655	$	34,100
Net income (loss)	$	(127,530	)	$	(127,301	)	$	12,866	$	16,519

Recent Acquisitions

During the first quarter of 2014, the Company acquired additional acreage that we believe is prospective for horizontal development in Martin, Glasscock and Dawson counties for an aggregate purchase price of approximately $79 million in three separate transactions with approximately $69 million recorded as proved oil and natural gas properties. The transactions were financed with borrowings under the Company's revolving credit facility.

Collins and Wallace Contributions

Collins, Wallace LP and Collins & Wallace Holdings, LLC contributed to RSP Inc. certain working interests in the Permian Basin in which RSP LLC already had working interests. In exchange, (i) Collins received shares of RSP Inc.'s common stock and the right to receive approximately $1.6 million in cash, (ii) Wallace LP received shares of RSP Inc.'s common stock and the right to receive $0.6 million in cash, and (iii) Collins & Wallace Holdings, LLC received shares of RSP Inc.'s common stock. The Collins and Wallace Contributions occurred in connection with the IPO.

These contributed working interests consisted of the following: (i) Collins' non-operated working interest in substantially all of the oil and natural gas properties that RSP LLC 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 LLC owned prior to the Spanish Trail Acquisition; and (iii) Collins & Wallace Holdings, LLC's non-operated working interest in the Spanish Trail Assets (as defined below).

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

A summary of the consideration transferred and the fair value of assets and liabilities acquired in connection with the Collins and Wallace Contributions is as follows (in thousands):


Value of the 22,023,654 shares of the Company's common stock issued in the Collins and Wallace Contributions	$	429,461
Cash paid in the Collins and Wallace Contributions		2,219


Total consideration for the assets contributed in the Collins and Wallace Contributions	$	431,680
Fair value of oil and natural gas properties	$	644,052
Asset retirement obligation		(1,063	)
Deferred tax liability*		(211,309	)


Total net assets acquired	$	431,680

*: Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 35%.

ACTOIL NPI Repurchase

In July 2011, RSP LLC sold to ACTOIL a 25% NPI in substantially all of its oil and natural gas properties taken as a whole. In addition, RSP LLC sold to ACTOIL a 25% NPI in the oil and natural gas properties acquired by RSP LLC in the Spanish Trail Acquisition. In connection with the IPO, ACTOIL contributed both 25% NPIs to the Company in exchange for shares of RSP Inc.'s common stock. The 25% NPIs exchanged for shares in the Company had a value of approximately $210.9 million and were accounted for as asset acquisitions.

The Company's predecessor's sale of properties to Resolute Natural Resources Southwest LLC ("Resolute") in December 2012 and March 2013 resulted in ACTOIL earning cash proceeds through its NPI in the properties sold. ACTOIL reduced its NPI account cumulative deficit balance with these proceeds, rather than receiving a cash distribution. As such, the Company's 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 was eliminated upon ACTOIL contributing its NPI in exchange for common shares.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

A summary of the consideration transferred and the assets acquired and liabilities acquired in connection with the ACTOIL NPI Repurchase is as follows (in thousands):


Value of the 10,816,626 shares of the Company's common stock issued in the ACTOIL NPI Repurchase	$	210,924
Elimination of NPI payable		(36,931	)


Total consideration for the assets contributed in the ACTOIL NPI Repurchase	$	173,993
Oil and natural gas properties cost	$	158,115
Asset retirement obligation		(639	)
Deferred tax asset*		16,517


Total net assets acquired	$	173,993

*: Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 35%.

Spanish Trail Acquisition

On September 10, 2013, RSP LLC 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"). The aggregate purchase price for the assets to be acquired in the Spanish Trail Acquisition (the "Spanish Trail Assets") agreed to by RSP LLC 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 Collins & Wallace Holdings, LLC, a newly-formed entity that is jointly owned by Collins and Wallace LP, which contributed these acquired assets to RSP Inc. in exchange for shares of RSP Inc.'s common stock in connection with the IPO. The exercise of the preferential purchase rights reduced RSP LLC's purchase price from $155 million to $121 million.

Simultaneously with the closing of the Spanish Trail Acquisition, pursuant to ACTOIL's exercise of a right of first refusal granted by RSP LLC in the agreement that governs ACTOIL's NPI investment, RSP LLC 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 RSP LLC's $121 million purchase price.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

RSP LLC allocated the net purchase price to the oil and natural gas properties acquired and asset retirement obligation assumed as follows (in thousands):


Net purchase price	$	120,521
25% NPI Sale to ACTOIL		(30,131	)


Oil and natural gas properties acquired	$	90,390
Asset retirement obligation assumed		296


Oil and natural gas properties	$	90,686

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

Resolute Sale

Effective October 1, 2012, RSP 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 million to Resolute (the "Resolute Sale"). The Company's share of the purchase price was $69 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 Company recorded a gain on the sale. In addition, RSP LLC and the other sellers sold Resolute an option (the "Option") for $5 million, $2.4 million of which was the Company's share. The Option allowed Resolute to acquire the remaining 67.65% interest in these certain assets. The Option was non-refundable and only entitled Resolute to a limited time period during which it could exercise the 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 Company 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 for the year ended December 31, 2012.

In March 2013, Resolute exercised the right to acquire the 67.65% remaining interest in these assets from RSP LLC, ACTOIL and other working interest owners for an additional purchase price of approximately $230 million. RSP LLC's share of the purchase price was $144.2 million. In connection with the transaction closing in March 2013, RSP LLC recorded a gain of approximately $6 million.

The PSA contained customary closing conditions and included a $5 million title and environmental escrow (net to RSP LLC) and an $11 million indemnity escrow (net to RSP LLC) which were held back from the initial purchase price to provide for these contingencies. Amounts held in escrow for potential indemnity matters were not initially considered in the computation of the gain in connection with the sale of these certain assets because the Company could not reasonably estimate the potential outcome of any such matters at the time of the initial closing of the transaction.

Subsequent to the initial closing, in October 2013, RSP LLC received the first two scheduled escrow payments under the terms of the PSA totaling approximately $12 million. The receipt of these funds substantially resolved any uncertainty associated with the ability to collect the remaining portion

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

of the amounts held in escrow, and therefore, the Company recorded the gain associated with all funds received and the remaining escrow amounts not yet received as collectability of such amounts was deemed probable. For the twelve months ended December 31, 2013, the total gain recognized on the Resolute Sale was approximately $22.7 million.

NOTE 4—DERIVATIVE INSTRUMENTS

Commodity Derivative Instruments

The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its crude oil and natural gas production. These include over-the-counter ("OTC") swaps, put options and collars. The derivative instruments are recorded at fair value on the consolidated balance sheets 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 Company 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 Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

Each put transaction has an established floor price. The Company 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 Company 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. All put options have expired as of December 31, 2013.

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

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

The following table summarizes all open positions as of March 31, 2014:

	Year 2014		Year 2015

Crude Oil Swaps:
Notional volume (Bbl)		180,000		120,000
Weighted average price ($/Bbl)¹	$	94.50	$	92.60


Crude Oil Collars:
Notional volume (Bbl)		1,149,000		492,000
Weighted average floor price ($/Bbl)¹	$	86.29	$	85.49
Weighted average ceiling price ($/Bbl)¹	$	100.35	$	94.14


Natural Gas Collars:
Notional volume (Mmbtu)		1,350,000		—
Weighted average floor price ($/Mmbtu)²		4.00		—
Weighted average ceiling price ($/Mmbtu)²		4.78		—

¹: The crude oil derivative contracts are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude.
²: The natural gas derivative contracts are settled based on the NYMEX Henry Hub closing settlement price.

Fair Values and Gains (Losses)

The following table presents the fair value of derivative instruments. The Company's derivatives are presented as separate line items in its consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities. 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 Company's master netting arrangements.

	Assets				Liabilities

	March 31, 2014		December 31, 2013		March 31, 2014			December 31, 2013
	(In thousands)
Derivative Instruments:
Current amounts
Commodity contracts	$	225	$	671	$	(4,156	)	$	(1,562	)
Noncurrent amounts
Commodity contracts		440		1,078		(207	)		(43	)


Total derivative instruments	$	665	$	1,749	$	(4,363	)	$	(1,605	)

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

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 4—DERIVATIVE INSTRUMENTS (Continued)

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

	Three Months Ended March 31,

	2014			2013
	(In thousands)
Loss on derivative instruments:
Commodity derivative instruments	$	(4,153	)	$	(1,653	)
Interest rate derivative instruments		—			(4	)


Total	$	(4,153	)	$	(1,657	)

Offsetting of Derivative Assets and Liabilities

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

	Gross Amount Presented on Balance Sheet			Netting Adjustments^a			Net Amount

	(In thousands)
March 31, 2014
Derivative instrument assets with right of offset or master netting agreements	$	665		$	(507	)	$	158
Derivative instrument liabilities with right of offset or master netting agreements	$	(4,363	)	$	507		$	(3,856	)
December 31, 2013
Derivative instrument assets with right of offset or master netting agreements	$	1,749		$	(1,332	)	$	417
Derivative instrument liabilities with right of offset or master netting agreements	$	(1,605	)	$	1,332		$	(273	)

^a: With all of the Company's financial trading counterparties, the Company 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 Company related to net positions as of March 31, 2014 and December 31, 2013.

NOTE 5—FAIR VALUE MEASUREMENTS

The book values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. The book value of the Company's credit facilities approximate fair value as the interest rates are variable. The fair value of derivative financial instruments is determined utilizing industry standard models using assumptions

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 5—FAIR VALUE MEASUREMENTS (Continued)

and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.

The Company 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 consolidated 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 and can be 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 Company's assets and liabilities that are measured at fair value on a recurring basis.

	Level 1		Level 2			Level 3		Total fair value

	(In thousands)
As of March 31, 2014:
Commodity derivative instruments	$	—	$	(3,698	)	$	—	$	(3,698	)


Total	$	—	$	(3,698	)	$	—	$	(3,698	)

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 5—FAIR VALUE MEASUREMENTS (Continued)

	Level 1		Level 2		Level 3		Total fair value

	(In thousands)
As of December 31, 2013:
Commodity derivative instruments	$	—	$	144	$	—	$	144


Total	$	—	$	144	$	—	$	144

Significant Level 2 assumptions used to measure the fair value of the commodity derivative instruments include current market and contractual commodity prices, implied volatility factors, appropriate risk adjusted discount rates, as well as 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 three months ended March 31, 2014 and the year ended December 31, 2013.

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 AROs 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. 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 6—CREDIT AGREEMENT

On September 10, 2013, in conjunction with the Spanish Trail Acquisition, the Company amended and restated its credit agreement, dated December 15, 2010, with Comerica Bank, as administrative agent, and expanded its syndicated bank group to 11 lenders. In addition, the Company entered into a new term loan in the amount of $70 million to partially finance the Spanish Trail Acquisition.

The Company's revolving credit facility requires it to maintain the following three financial ratios:

•: a working capital ratio, which is the ratio of consolidated current assets (includes unused commitments under its revolving credit facility and excludes restricted cash and derivative assets) to 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;

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 6—CREDIT AGREEMENT (Continued)

•: a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as defined in the credit agreement) to consolidated interest expense, of not less than 3.0 to 1.0; and
•: a leverage ratio, which is the ratio of the sum of all of the Company's debt to the consolidated EBITDAX (as defined in the credit agreement) for the four fiscal quarters then ended, of not greater than 4.0 to 1.0.

The Company's revolving credit facility contains restrictive covenants that may limit its 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 its expected production, enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness, incur liens, sell assets or engage in certain other transactions without the prior consent of the lenders.

The Company was in compliance with such covenants and ratios as of March 31, 2014.

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. RSP LLC has 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 its 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 its borrowing base utilized, plus a facility fee of 0.50% charged on the borrowing base amount. At March 31, 2014, the variable rate of interest under the Company's revolving credit facility was 1.73%. The Company may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. As of March 31, 2014, 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.

The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is re-determined semiannually each May and November and depends on the volumes of proved oil and natural gas reserves and estimated cash flows from these reserves and commodity hedge positions. The borrowing base under the Company's amended and restated credit agreement was $300 million as of March 31, 2014, with lender commitments of $500 million.

The maturity date of the Company's revolving credit facility is September 10, 2017.

On January 23, 2014, the Company repaid the term loan in full, and as of March 31, 2014, the Company had no contractual obligations with respect to the term loan.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 7—COMMITMENTS AND CONTINGENCIES

Legal Matters

In the ordinary course of business, the Company 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 Company's financial position, results of operations or cash flows.

Environmental Matters

The Company 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 Company 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 Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

The Company 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 March 31, 2014 and December 31, 2013, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Leases

During 2011, RSP LLC entered into a month-to-month operating lease agreement and a long-term operating lease agreement for office space. During February 2014, the Company entered into a 64-month lease agreement through May 2019 for office space. Rent expense for the three months ended March 31, 2014 and 2013 was $82 thousand and $62 thousand.

NOTE 8—EQUITY-BASED COMPENSATION

Restricted Stock Awards

In connection with the IPO, the Company adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (the "LTIP") for the employees, consultants and directors of the Company and its affiliates who perform services for the Company.

Share-based compensation expense for restricted stock awards issued to both employees and non-employee directors, which was recorded in "General and administrative expenses" in the accompanying consolidated statements of operations, was $0.8 million for the three months ended March 31, 2014. The Company views restricted stock awards with graded vesting as single awards with an expected life equal to the average expected life and amortize the awards on a straight-line basis over the life of the awards.

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 8—EQUITY-BASED COMPENSATION (Continued)

The compensation expense for these awards was determined based on the market price of the Company's common stock at the date of grant applied to the total number of shares that were anticipated to fully vest. As of March 31, 2014, the Company had unrecognized compensation expense of $8.9 million related to restricted stock awards which is expected to be recognized over a weighted average period of 2.2 years.

The following table represents restricted stock award activity for the three months ended March 31, 2014:

		Wtd. Avg. Grant Price

Restricted shares outstanding, beginning of period	—	$	—
Restricted shares granted	421,999		23.05


Restricted shares outstanding, end of period	421,999	$	23.05

Incentive Units

Pursuant to the LLC Agreement of RSP LLC, certain incentive units are available to be issued to the Company's management and employees, 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 the Company. All incentive units, whether vested or not, are forfeited if payouts are not achieved by a specified date. 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. Tiers II, III and IV incentive units vest only upon the achievement of certain distribution 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.

In connection with the IPO, the incentive units of RSP LLC became incentive units in RSP Permian Holdco, L.L.C. and therefore based upon distributions to members of RSP Permian Holdco, L.L.C. rather than members of RSP LLC. The terms and conditions of the profits interest awards remained substantially similar to the terms applicable to the incentive unit awards prior to the IPO, including the retention of existing vesting schedules.

The achievement of payout conditions is a performance condition that requires the Company 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 Company did not deem as probable that such payouts would be achieved for any Tier of incentive units.

At such time that the occurrence of the performance conditions associated with these incentive units are deemed probable, the Company records a non-cash compensation expense based upon the grant date fair value of the incentive units that are probable of reaching payout as a result of reaching established distribution thresholds. As of December 31, 2013, the unrecognized non-cash compensation expense associated with all tiers of the incentive units was approximately $16.2 million. After successful completion of the IPO, the performance conditions associated with the Tier I, Tier I A and Tier II

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 8—EQUITY-BASED COMPENSATION (Continued)

incentive units were deemed probable of reaching payout, which resulted in the recognition of non-cash compensation expense of approximately $11.2 million. The Tier I A and Tier II incentive units have a remaining unrecognized non-cash compensation expense of approximately $1.5 million which will be amortized over the remaining service period and result in a $0.7 million non-cash compensation expense in the remainder of 2014 and $0.8 million in 2015. The remaining unrecognized non-cash compensation expense related to the Tier III and Tier IV incentive units is approximately $3.5 million and will be recognized when it is deemed that the Tier III and Tier IV incentive units are probable of reaching payout as a result of reaching the established distribution thresholds.

NOTE 9—EARNINGS PER SHARE & PRO FORMA EARNINGS PER SHARE

Earnings per Share

The Company's basic earnings per share amounts have been computed using the two-class method based on the weighted-average number of shares of common stock outstanding for the period. Because the Company recognized a net loss for the first quarter of 2014, unvested restricted share awards were not recognized in dilutive earnings per share calculations as they would be antidilutive. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

	Three Months Ended March 31, 2014

	(In thousands)
Numerator:
Net loss available to stockholders	$	(127,530	)
Basic net loss allocable to participating securities¹		—


Loss available to stockholders	$	(127,530	)




Denominator:
Weighted average number of common shares outstanding—basic		62,904
Effect of dilutive securities:
Restricted stock		—


Weighted average number of common shares outstanding—diluted		62,904




Net loss per share:
Basic	$	(2.03	)
Diluted	$	(2.03	)

¹: Restricted share awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.

Pro Forma Earnings per Share

The Company computed a pro forma income tax provision as if the Company was subject to income taxes since January 1, 2014. 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, and excludes the

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RSP PERMIAN, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 9—EARNINGS PER SHARE & PRO FORMA EARNINGS PER SHARE (Continued)

non-recurring tax adjustment related to the contribution of the Company's predecessor, limited liability companies, to a corporation on January 23, 2014, as further described in Note 2 under "Income Taxes."

The Company's pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued in the IPO were outstanding for the entire year. A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below:

	Three Months Ended March 31, 2014

	(In thousands)
Numerator:
Income before taxes, as reported	$	7,683
Pro forma provision for income taxes		2,689
Basic net income allocable to participating securities		29


Pro forma net income available to stockholders	$	4,965




Denominator:
Weighted average number of common shares outstanding—basic		72,500
Effect of dilutive securities:
Restricted stock		—


Weighted average number of common shares outstanding—diluted		72,500




Net income per share:
Basic	$	0.07
Diluted	$	0.07

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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 December 31, 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. We were not engaged to perform an audit of the Company's internal control over financial reporting. 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 December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Dallas, Texas
March 31, 2014

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RSP PERMIAN, INC.

BALANCE SHEET

	December 31, 2013

Assets
Receivable from stockholder	$	10


Total assets	$	10




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


Total stockholder's 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. 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

On January 23, 2014, the Company completed the initial public offering of common stock to the public (the "IPO"). Shares of common stock of RSP Inc. began trading on the New York Stock Exchange under the ticker RSPP on January 17, 2014. Concurrent with the completion of the IPO, all interests in RSP Permian, L.L.C. ("RSP") and certain assets of Rising Star Energy Development Co., L.L.C. ("Rising Star") were contributed to the Company. The Company sold 23 million shares at $19.50 per share, raising $449 million of gross proceeds. Of the 23 million shares issued to the public, 9.2 million were primary shares issued by the Company, resulting in $166 million of net proceeds, which were used to retire RSP's $70 million term loan, repay RSP's revolving credit facility balance of $56 million in its entirety, pay cash as partial consideration for certain working interest in oil and gas properties contributed to the Company in conjunction with the IPO (described below), and for other general corporate purposes. The remaining 13.8 million shares sold in the IPO were sold by selling stockholders and the Company did not receive any proceeds from the sale of those shares.

In connection with the IPO, several transactions occurred simultaneously which changed the structure and scope of the company and RSP.

•

Corporate Reorganization:

•: RSP was contributed to RSP Permian Holdco L.L.C., a newly-formed limited liability company which simultaneously contributed all of its interests in RSP to the Company in exchange for shares of the Company's common stock and cash. RSP is a wholly owned subsidiary of the Company.

•

The Rising Star Acquisition:

•: RSP acquired from Rising Star certain acreage and wells in the Permian Basin in which RSP already had working interests in for shares of the Company's common stock and cash.

•

The Collins and Wallace Contributions:

•: Ted Collins, Jr. ("Collins"), Wallace Family Partnership, LP ("Wallace LP") and Collins & Wallace Holdings, LLC, a newly-formed entity that is jointly owned by Collins and Wallace LP contributed to RSP certain working interests. In exchange, Collins and Wallace LP received both cash and shares of the Company's common stock and Collins & Wallace Holdings, LLC received only shares of the Company's common stock. The

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RSP PERMIAN, INC.

NOTES TO BALANCE SHEET (Continued)

3. Subsequent Events (Continued)

Company is in the process of evaluating the fair values of the contributed assets in order to determine the appropriate purchase price allocation.

•

The Pecos Contribution:

•: Pecos Energy Partners, L.P. ("Pecos"), an entity owned by certain members of the management team of the Company, contributed to RSP certain working interests in acreage and wells in the Permian Basin in which RSP already had a working interest in exchange for shares of the Company's common stock.

•

The ACTOIL NPI Repurchase:

•: ACTOIL, the owner of a 25% net profits interest issued by RSP, contributed to RSP its 25% net profits interest in exchange for shares in the Company. The Company is in the process of evaluating the fair values of the contributed assets in order to determine the appropriate purchase price allocation.

Subsequent to year-end, RSP, our wholly-owned subsidiary and accounting predecessor, has closed approximately $79 million of acquisitions. On February 28, 2014, RSP closed the acquisition of a 17.5% non-operated working interest in producing properties located in Martin County, Texas. The properties are contiguous to RSP-operated leasehold positions in Martin County. In addition, RSP added additional undeveloped leasehold in Glasscock County and Dawson County during the first quarter of 2014.

The Company has evaluated subsequent events through the date that these financial statements were available to be issued. Except as described above, the Company 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, 2013 and 2012, and the related combined statements of operations, changes in members' equity, and cash flows for each of the three years in the period ended December 31, 2013. 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. We were not engaged to perform an audit of the Predecessor's 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Dallas, Texas
March 31, 2014

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

COMBINED BALANCE SHEETS

				December 31,

	Pro Forma December 31, 2013			December 31,
	Pro Forma December 31, 2013			2013			2012
	(Unaudited)			(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	13,234		$	13,234		$	51,232
Restricted short-term investment		—			—			1,031
Accounts receivable		26,346			26,346			21,614
Accounts receivable, related party		3,672			3,672			4,232
Escrow receivable		3,197			3,197			3,135
Escrow deposit		15			15			—
Derivative instruments		671			671			1,112


Total current assets		47,135			47,135			82,356
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method		595,486			595,486			476,816
Accumulated depletion		(88,514	)		(88,514	)		(60,489	)


Total oil and natural gas properties, net		506,972			506,972			416,327
Other property and equipment, net		9,316			9,316			5,085


Total property, plant and equipment		516,288			516,288			421,412
LONG-TERM ASSETS
Derivative instruments		1,078			1,078			2,325
Restricted cash		150			150			150
Other assets		23,004			23,004			6,995


Total long-term assets		24,232			24,232			9,470


TOTAL ASSETS	$	587,655		$	587,655		$	513,238




LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	18,548		$	18,548		$	23,437
Accrued expenses		10,460			10,460			3,249
Distribution payable		29,484			—			—
Interest payable		296			296			252
Derivative instruments		1,562			1,562			1,227


Total current liabilities		60,350			30,866			28,165
LONG-TERM LIABILITIES
Asset retirement obligations		2,584			2,584			2,716
Derivative instruments		43			43			345
Term loan		70,000			70,000			—
Revolving credit facility		58,155			58,155			111,586
NPI payable		36,931			36,931			16,583
Deferred taxes		2,195			2,195			—


Total long-term liabilities		169,908			169,908			131,230


Total liabilities		230,258			200,774			159,395
MEMBERS' EQUITY		357,397			386,881			353,843


TOTAL LIABILITIES AND MEMBERS' EQUITY	$	587,655		$	587,655		$	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

	For the year ended December 31,

	2013			2012			2011
	(In thousands, except per share data)
REVENUES
Oil sales	$	110,345		$	91,441		$	56,772
NGL sales		7,314			8,702			—
Natural gas sales		5,383			4,284			7,217


Total revenues		123,042			104,427			63,989
OPERATING EXPENSES
Lease operating expenses	$	14,664		$	12,854		$	5,712
Production and ad valorem taxes		8,326			7,575			4,192
Depreciation, depletion and amortization		47,158			48,803			16,612
Asset retirement obligation accretion		121			115			46
Impairments		—			—			2,241
General and administrative expenses		3,852			2,859			3,509


Total operating expenses		74,121			72,206			32,312


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


OPERATING INCOME	$	71,621		$	38,955		$	137,010
OTHER INCOME (EXPENSE)
Other income	$	1,202		$	884		$	163
Loss on derivative instruments		(2,607	)		(796	)		(1,979	)
Interest expense		(5,216	)		(3,474	)		(3,472	)


Total other expense		(6,621	)		(3,386	)		(5,288	)


INCOME BEFORE TAXES		65,000			35,569			131,722
INCOME TAX (EXPENSE) BENEFIT		(2,262	)		339			(550	)


NET INCOME	$	62,738		$	35,908		$	131,172




PRO FORMA INFORMATION (UNAUDITED):
Net income	$	62,738
Pro forma provision for income taxes		(22,586	)


Pro forma net income	$	40,152




Pro forma income per common share
Basic and diluted	$	1.26
Weighted average pro forma shares outstanding
Basic and diluted		31,934

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
Contributions		300			—		300
Distributions		(30,000	)		—		(30,000	)
Net income		60,469			2,269		62,738


BALANCE AT DECEMBER 31, 2013	$	365,734		$	21,147	$	386,881

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,

	2013			2012			2011
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	62,738		$	35,908		$	131,172
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and depreciation		47,158			48,347			16,246
Deferred taxes		2,195			—			—
Abandoned equipment and intangibles		2			135			131
Impairment		—			—			2,241
Accretion of asset retirement obligations		121			115			46
Bad debt expense		—			—			65
Amortization of loan fees		1,746			456			366
Equity in earnings of investment		(14	)		(11	)		(55	)
Gain on certificate of deposit		—			(3	)		(3	)
(Gain) on sale of assets		(22,700	)		(6,734	)		(105,333	)
Loss on derivative instruments		2,607			796			1,979
Net cash payments on settled derivatives		(886	)		(474	)		(856	)
Changes in operating assets and liabilities:
Accounts receivable and accounts receivable from related parties		(3,758	)		(3,907	)		(22,719	)
Other assets		(17,739	)		(2,148	)		(624	)
Interest payable		44			63			23
Accounts payable		(5,380	)		(1,722	)		2,298
Accrued expenses		7,211			1,982			1,266


Net cash provided by operating activities	$	73,345		$	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		115,339			63,196			182,640
Increase in equity investment		—			(1,146	)		—
Additions to other property and equipment		(3,265	)		(1,287	)		(402	)
Additions to oil and natural gas properties		(231,665	)		(173,983	)		(95,654	)


Net cash provided by (used in) investing activities	$	(119,591	)	$	(113,220	)	$	83,846




CASH FLOWS FROM FINANCING ACTIVITIES
Payment of debt issuance costs	$	—		$	—		$	(241	)
Capital contributions		300			—			—
Distributions		(30,000	)		—			—
Borrowings under long-term debt		101,569			90,000			55,086
Restricted short term investment		1,031			—			—
Payments on long-term debt		(85,000	)		(25,000	)		(160,000	)
NPI payable		20,348			16,583			—


Net cash provided by (used in) financing activities	$	8,248		$	81,583		$	(105,155	)




NET CHANGE IN CASH	$	(37,998	)	$	41,166		$	4,934




CASH AT BEGINNING OF YEAR	$	51,232		$	10,066		$	5,132


CASH AT END OF YEAR	$	13,234		$	51,232		$	10,066




SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	$	3,373		$	3,420		$	3,293
NON-CASH INVESTING ACTIVITIES
Assets purchased included in accounts payable and accrued expenses	$	16,901		$	21,416		$	20,099
Asset retirement obligation acquired	$	296		$	—		$	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"). 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 Delaware limited liability company ("Rising Star"), was formed in April 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 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. Certain reclassifications of amounts from lease

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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)

operating expenses to production and ad valorem expenses have been made to prior periods to conform to the current year presentation.

Reclassifications

Certain reclassifications of amounts from lease operating expenses to production and ad valorem expenses have been made to prior periods to conform to current year presentation.

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 has historically entered 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 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 statement of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. 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, NGLs and natural gas, are accrued based on estimates of the volumetric 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. No bad debt expense was recorded for the years ended December 31, 2013, 2012 or 2011.

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

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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)

Wallace LP was approximately $3.7 million and $4.2 million at December 31, 2013 and 2012. The Predecessor considers the accounts receivable from Wallace LP to be fully collectible.

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.

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 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 $46.9 million, $48.0 million and $16.0 million for the years ended December 31, 2013, 2012 and 2011, 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 December 31, 2013 and 2012 consisted of the following:

	December 31,

	2013			2012
	(In thousands)
Proved oil and natural gas properties	$	562,019		$	447,369
Unproved oil and natural gas properties		33,467			29,447
Less: accumulated depletion		(88,514	)		(60,489	)


	$	506,972		$	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 December 31, 2013 and 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

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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)

(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.

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 written down to fair value using Level 3 fair-value inputs. No impairment of proved property was recorded for the years ended December 31, 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 years ended December 31, 2013, 2012 and 2011 was $0.3 million, $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, 2013 and 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 $2.2 million and $1.5 million as of December 31, 2013 and 2012, respectively, net of accumulated amortization, are included in other assets in the accompanying combined balance sheets. Amortization of deferred loan costs of $1.7 million, $0.5 million and $0.4 million was recorded for the years ended December 31, 2013, 2012 and 2011, respectively.

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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)

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.

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.

The ARO consisted of the following for the years indicated:

	Year Ended December 31,

	2013			2012
	(In thousands)
Asset retirement obligation at beginning of year	$	2,716		$	1,114
Liabilities acquired		296			—
Liabilities incurred		348			1,474
Liabilities settled		(897	)		—
Revision of estimate		—			13
Accretion expense		121			115


Asset retirement obligation at end of year	$	2,584		$	2,716

Revenue Recognition

Oil, NGL 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, NGL and natural gas imbalances result when sales differ from the seller's net revenue interest in the particular property's reserves. An imbalance

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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)

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, 2013 and 2012, 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

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 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. A deferred tax liability has been recognized in the combined balance sheets to reflect the future tax consequences attributable to the difference in the book and tax bases of certain assets and liabilities.

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.

Unaudited Pro Forma Income Taxes

These financial statements were prepared in anticipation of the initial public offering of the common stock of the Predecessor's parent entity (the "IPO"). In connection with the IPO, all interests in RSP and certain assets of Rising Star were contributed to a newly-formed Delaware corporation, which is treated as a taxable C corporation and thus is 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 the most recent period presented. The Predecessor has computed pro forma tax expense using a 36% blended corporate level federal and state tax rate. If the Predecessor had affected the change in tax status on December 31, 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.

Unaudited Pro Forma Earnings Per Share

The Predecessor has presented pro forma earnings per share for the most recent period. Pro forma basic and diluted income per share was computed by dividing pro forma net income attributable to the Predecessor by the number of shares of common stock attributable to the Predecessor issued in the IPO, as if such shares were issued and outstanding for the year ended December 31, 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 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Unaudited Pro Forma Distribution Payable

Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or concurrent with an initial public offering be considered as distributions in contemplation of that offering. The pro forma balance sheet as of December 31, 2013 reflects the pro forma distribution accrual related to the estimated $27.8 million and $1.7 million of cash distributions expected to be made to RSP Permian Holdco, L.L.C. and Rising Star, respectively, upon the closing of the IPO. This total pro forma $29.5 million cash distribution will be funded with the net proceeds received in connection with the IPO.

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:

	December 31,

	2013		2012
	(In thousands)
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	15,618	$	9,673
Joint interest owners		10,707		11,935
Other		21		6


Total	$	26,346	$	21,614

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.

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.

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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)

During the years ended December 31, 2013, 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—ACQUISITIONS AND SALES OF OIL AND NATURAL GAS PROPERTY INTERESTS

Resolute Sale

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 and the other sellers sold Resolute an option (the "Option") for $5.0 million, $2.4 million of which is the Predecessor's share. The Option allows Resolute 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 it can exercise a 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 for the year ended December 31, 2012.

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. In connection with the transaction closing in March 2013, RSP recorded a gain of approximately $6.0 million.

The PSA contained customary closing conditions and included a $5.0 million title and environmental escrow (net to RSP) and an $11.0 million indemnity escrow (net to RSP) which were held back from the initial purchase price to provide for these contingencies. Amounts held in escrow for potential indemnity matters were not initially considered in the computation of the gain in

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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—ACQUISITIONS AND SALES OF OIL AND NATURAL GAS PROPERTY INTERESTS (Continued)

connection with the sale of these certain assets because the Predecessor could not reasonably estimate the potential outcome of any such matters at the time of the initial closing of the transaction.

Subsequent to the initial closing, in October 2013, the Predecessor received the first two scheduled escrow payments under the terms of the PSA totaling approximately $12.0 million. The receipt of these funds substantially resolved any uncertainty associated with the ability to collect the remaining portion of the amounts held in escrow and therefore the Predecessor recorded the gain associated with all funds received and the remaining escrow amounts not yet received as collectability of such amounts was deemed probable. For the twelve months ended December 31, 2013, the total gain recognized on the sale to Resolute was approximately $22.7 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 IPO, 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 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 contributed 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 in connection with the IPO. The exercise of the preferential purchase rights reduced RSP's purchase price from $155 million to $121 million. RSP allocated the net purchase price to the oil and natural gas properties acquired and asset retirement obligation assumed as follows:

	(in thousands)

Net purchase price	$	120,521
Sale to ACTOIL (see Note 7)	$	(30,131	)


Oil and natural gas properties acquired	$	90,390
Asset retirement obligation assumed	$	296


Oil and natural gas properties	$	90,686

The Spanish Trail Acquisition was funded with a $70 million term loan, borrowings under RSP's revolving credit facility (described below in Note 6) and the issuance of a net profits interest (described below in Note 7).

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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—ACQUISITIONS AND SALES OF OIL AND NATURAL GAS PROPERTY INTERESTS (Continued)

Summarized below are the results of operations for the years ended December 31, 2013 and 2012, on an unaudited pro forma basis, as if the Spanish Trail acquisition had occurred on January 1, 2012.

The unaudited pro forma financial information was derived from the historical combined statements of operations of our predecessor, the statements of revenues and direct operating expenses for the Spanish Trail Properties and the historical accounting records of the sellers. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	2013				2012

	Actual		Pro Forma		Actual		Pro Forma
	(In thousands)				(In thousands)
Spanish Trail:
Revenues	$	123,042	$	139,931	$	104,427	$	125,434
Net income	$	62,738	$	67,979	$	35,908	$	44,428

During the year ended December 31, 2013, approximately $6.9 million of revenue and $5.5 million of earnings were recorded in the statement of operations related to the Spanish Trail Acquisition subsequent to the closing date.

Verde Acquisition

On October 10, 2013, the Predecessor acquired leasehold interests in 9,464 gross (8,092 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 Predecessor is the operator on 100% of this acreage. This acreage currently contains no producing wells.

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 combined balance sheets 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 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

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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)

and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires. All put options have expired as of December 31, 2013.

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 all open positions as of December 31, 2013:

	Year 2014		Year 2015

Swaps:
Notional volume (Bbl)		240,000		120,000
Weighted average price ($/Bbl)	$	94.50	$	92.60
Collars:
Notional volume (Bbl)		693,000		372,000
Weighted average floor price ($/Bbl)	$	86.13	$	84.03
Weighted average ceiling price ($/Bbl)	$	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 has historically executed interest rate swaps to fix the interest rate on a portion of the outstanding balance from the Predecessor's credit agreement. As of December 31, 2013, all of the Predecessor's interest rate swaps have expired.

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

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

	Assets				Liabilities

	December 31,				December 31,
	2013		2012		2013			2012
	(In thousands)
Derivative Instruments:
Current amounts
Crude oil contracts	$	671	$	1,112	$	(1,562	)	$	(417	)
Interest rate contracts		—		—		—			(810	)
Noncurrent amounts
Crude oil contracts		1,078		2,325		(43	)		(345	)
Interest rate contracts		—		—					—


Total derivative instruments	$	1,749	$	3,437	$	(1,605	)	$	(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 years presented:

	For the year ended December 31,

	2013			2012			2011
	(In thousands)
Loss on derivative instruments:
Crude oil derivative instruments	$	(2,583	)	$	(408	)	$	(545	)
Interest rate derivative instruments		(24	)		(388	)		(1,434	)


Total	$	(2,607	)	$	(796	)	$	(1,979	)

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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)

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, 2013
Derivative instrument assets with right of offset or master netting agreements	$	1,749		$	(1,332	)	$	417
Derivative instrument liabilities with right of offset or master netting agreements	$	(1,605	)	$	1,332		$	(273	)
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	)

^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 positions as of December 31, 2013 and 2012.

NOTE 5—FAIR VALUE MEASUREMENTS

The Predecessor accounts for its 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 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

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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—FAIR VALUE MEASUREMENTS (Continued)

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 and can be 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.

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

As of December 31, 2013:
Crude oil derivative instruments	$	—	$	144	$	—	$	144


Total	$	—	$	144	$	—	$	144

	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

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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—FAIR VALUE MEASUREMENTS (Continued)

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.

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 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 6—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 consisted 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 a 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. During 2011, the Term Loan was paid off with proceeds from the issuance of a net profits interest (See Note 7).

On September 10, 2013, in conjunction with the Spanish Trail Acquisition, RSP amended and restated the Agreement and expanded its syndicated bank group to 11 Lenders. In addition, RSP entered into a new Term Loan in the amount of $70 million to partially finance the acquisition.

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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—CREDIT AGREEMENT (Continued)

The Revolving Credit Facility requires RSP to maintain the following three financial ratios:

•: a working capital ratio, which is the ratio of consolidated current assets (includes unused commitments under our revolving credit facility and excludes restricted cash and derivative assets) to 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;
•: a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as defined in the Agreement) to consolidated interest expense, of not less than 3.0 to 1.0; and
•: a leverage ratio, which is the ratio of the sum of all our debt to the consolidated EBITDAX (as defined in the Agreement) for the four fiscal quarters then ended, of not greater than 4.0 to 1.0.

RSP was in compliance with such covenants and ratios as of December 31, 2013.

The borrowing base under RSP's amended and restated Agreement is $140 million as of December 31, 2013, with lender commitments of $500 million. The maturity date of the Revolving Credit Facility is September 10, 2017 while the new Term Loan matures on April 1, 2016.

The amount available to be borrowed under the Revolving Credit Facility is subject to a borrowing base that is re-determined semiannually each May and November and depends on the volumes of proved oil and natural gas reserves and estimated cash flows from these reserves and commodity hedge positions. As of December 31, 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%.

NOTE 7—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 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, 2013 and 2012, the NPI Account had a cumulative deficit balance of approximately $8.3 million. The deficit balance attributable to the NPI Account is not recorded in the Predecessor's balance sheet at December 31, 2013 or 2012 because ACTOIL is not obligated to pay

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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—NET PROFITS INTEREST (Continued)

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 and the other sellers 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.

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 8—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 of total revenues for the periods indicated:

	Percentage of Total Revenues for the Year Ended December 31,

	2013			2012			2011
Shell Trading (US) Company		40	%		3	%		—
Enterprise Crude Oil LLC		14	%		—			—
Diamondback E&P, LLC		11	%		2	%		—
Coronado Midstream, LLC		8	%		11	%		9	%
Plains Marketing, L.P.		13	%		76	%		78	%

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.

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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

RSP's operations are governed by the provisions of a limited liability company agreement (the "RSP LLC Agreement"). As of December 31, 2013, 2012 and 2011, the members of RSP had contributed $185.1 million, $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

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. Tiers II, III and IV incentive units vest only upon the achievement of certain distribution 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 for any Tier of incentive units.

At such time that the occurrence of the performance conditions associated with these incentive units are deemed probable, the Predecessor records a non-cash compensation expense based upon the grant date fair value of the incentive units that are probable of reaching payout as a result of reaching established distribution thresholds. As of December 31, 2013, the unrecognized non-cash compensation expense associated with all tiers of the incentive units is approximately $16.2 million. Upon successful completion of the IPO, the performance conditions associated with the Tier I, Tier I A and Tier II incentive units were deemed probable of reaching payout, which resulted in the recognition of non-cash compensation expense of approximately $11.2 million. The Tier I A and Tier II incentive units have a remaining unrecognized non-cash compensation expense of approximately $1.5 million which will be amortized over the remaining service period and result in a $0.7 million non-cash compensation expense in the remainder of 2014 and $0.8 million in 2015. The remaining unrecognized non-cash compensation expense related to the Tier III and Tier IV incentive units is approximately $3.5 million

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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)

and will be recognized when it is deemed that the Tier III and Tier IV incentive units are probable of reaching payout as a result of reaching the established distribution thresholds.

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 December 31, 2013 and 2012, 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 each year ended December 31, 2013, 2012 and 2011 was $0.2 million.

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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)

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:

	2013		2012		2011

	(In thousands)
Property acquisition costs:
Proved	$	86,958	$	—	$	—
Unproved		7,875		—		—
Exploration costs		—		—		—
Development costs		136,832		173,983		95,654


Total costs incurred	$	231,665	$	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:

	2013			2012

	(In thousands)
Capitalized costs:
Proved	$	562,019		$	447,369
Unproved		33,467			29,447


	$	595,486		$	476,816
Less accumulated depreciation, depletion, amortization and impairment		(88,514	)		(60,489	)


Net capitalized costs	$	506,972		$	416,327

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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:

	2013			2012		2011

	(In thousands)
Revenues:
Oil and natural gas sales	$	123,042		$	104,427	$	63,989
Production costs:
Lease operating expenses		14,664			12,854		5,712
Production and ad valorem taxes		8,326			7,575		4,192


		100,052			83,998		54,085
Other costs:
Depreciation, depletion, amortization and impairment		47,158			48,803		16,612
Income tax (expense) benefit		(2,262	)		339		(550	)


Results of operations	$	50,632		$	35,534	$	36,923

Net Proved Oil and Natural Gas Reserves

The Predecessor's proved oil and natural gas reserves as of December 31, 2013 were prepared by independent third party petroleum consultants. The Predecessor's proved oil and natural gas reserves as of December 31, 2012 were prepared internally by management. In accordance with the new SEC regulations, reserves at December 31, 2013 and 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.

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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, 2013 and 2012 is as follows:

	Year Ended December 31, 2013

	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		20,863			4,956			40,692			32,600
Revisions of previous estimates		(941	)		(2,465	)		(2,628	)		(3,844	)
Extensions, discoveries and other additions		6,301			3,440			8,151			11,099
Divestitures		(5,156	)		—			(14,687	)		(7,603	)
Purchases of minerals in place		3,832			1,232			5,872			6,044
Production		(1,167	)		(250	)		(1,597	)		(1,683	)


End of year		23,732			6,913			35,803			36,613




Proved developed reserves:
Beginning of year		7,730			1,723			17,847			12,427
End of year		9,533			2,703			14,396			14,636
Proved undeveloped reserves:
Beginning of year		13,133			3,233			22,845			20,173
End of year		14,199			4,210			21,407			21,977

	Year Ended December 31, 2012

	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		33,371			—			92,416			48,774
Revisions of previous estimates		(15,353	)		391			(57,872	)		(24,608	)
Extensions, discoveries and other additions		3,885			4,829			7,724			10,001
Production		(1,040	)		(264	)		(1,576	)		(1,567	)


End of year		20,863			4,956			40,692			32,600




Proved developed reserves:
Beginning of year		7,550			—			19,825			10,854
End of year		7,730			1,723			17,847			12,427
Proved undeveloped reserves:
Beginning of year		25,821			—			72,591			37,920
End of year		13,133			3,233			22,845			20,173

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, 2013, the Predecessor's negative revision of 3,844 MBoe of previous estimated quantities is primarily due to the change in estimates and type curves. Extensions,

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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)

discoveries and other additions of 11,099 MBoe during the year ended December 31, 2013, result primarily from the drilling of new wells during the year and from new proved undeveloped locations added during the year. The purchase of minerals in places of 6,044 MBoe during the year ended December 31, 2013 were directly related to the wells acquired through the Spanish Trail Acquisition. The divestiture of 7,603 MBoe during the year ended December 31, 2013 was due to the sale of the Western Assets.

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 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, resulted primarily from the drilling of new wells during the year and from new proved 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, 2013 and 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%.

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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)

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

	2013			2012			2011

	(In thousands)
Future cash inflows	$	2,547,566		$	2,210,325		$	3,825,056
Future production costs		(727,939	)		(655,720	)		(759,190	)
Future development costs		(378,695	)		(362,876	)		(505,710	)
Future income tax expenses¹		—			—			—


Future net cash flows		1,440,932			1,191,729			2,560,156
10% discount for estimated timing of cash flows		(890,217	)		(737,556	)		(1,705,732	)


Standardized measure of discounted future net cash flows	$	550,715		$	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, 2013, 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 Predecessor's equity holders. Following the completion of the IPO, the Company became 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, 2013, December 31, 2012 and December 31, 2011 would have been $247,397, $155,662, and $289,022, respectively. The unaudited standardized measure at December 31, 2013, December 31, 2012 and December 31, 2011 would have been $303,318, $298,511 and $565,402, respectively.

In the foregoing determination of future cash inflows, sales prices used for gas and oil for December 31, 2013, 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.

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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)

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

	2013			2012			2011

	(In thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	454,173		$	854,424		$	660,480
Changes in the year resulting from:
Sales, less production costs		(100,052	)		(83,998	)		(54,085	)
Revisions of previous quantity estimates		(53,557	)		(439,043	)		(73,407	)
Extensions, discoveries and other additions		157,086			84,149			32,525
Net change in prices and production costs		45,388			(133,485	)		118,588
Changes in estimated future development costs		2,318			38,096			(1,514	)
Previously estimated development costs incurred during the period		46,938			108,367			76,086
Divestiture of reserves		(151,440	)		—			—
Purchases of minerals in place		94,751			—			—
Accretion of discount		45,417			85,442			66,048
Net change in income taxes		—			—			—
Timing differences and other		9,693			(59,779	)		29,703


Standardized measure of discounted future net cash flows, end of year	$	550,715		$	454,173		$	854,424

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.

NOTE 12—SUBSEQUENT EVENTS

On January 23, 2014, RSP Permian, Inc. ("RSP Inc.") completed the IPO. Shares of common stock of RSP Inc. began trading on the New York Stock Exchange under the ticker RSPP on January 17, 2014. Concurrent with the completion of the IPO, all interests in RSP and certain assets of Rising Star were contributed to a RSP Inc.; RSP Inc. sold 23 million shares at $19.50 per share, raising $449 million of gross proceeds. Of the 23 million shares issued to the public, 9.2 million were primary shares issued by RSP Inc., resulting in approximately $163 million of net proceeds, which were used to retire the $70 million Term Loan, repay the Revolving Credit Facility balance of $56 million in its entirety, pay cash as partial consideration for certain working interest in oil and gas properties contributed in conjunction with the IPO (described below), and for other general corporate purposes.

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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 12—SUBSEQUENT EVENTS (Continued)

The remaining 13.8 million shares sold in the IPO were sold by selling stockholders and RSP Inc. did not receive any proceeds from the sale of those shares.

In connection with the IPO, several transactions occurred simultaneously which changed the structure and scope of RSP.

•

Corporate Reorganization:

•: RSP was contributed to RSP Permian Holdco L.L.C., a newly-formed limited liability company which simultaneously contributed all of its interests to RSP Inc. in exchange for shares of RSP Inc.'s common stock and cash. As a result, RSP became a wholly owned subsidiary of RSP Inc.

•

The Rising Star Acquisition:

•: RSP acquired from Rising Star certain acreage and wells in the Permian Basin in which RSP already had working interests in for shares of RSP Inc.'s common stock and cash.

•

The Collins and Wallace Contributions:

•: Ted Collins, Jr. ("Collins"), Wallace LP and Collins & Wallace Holdings LLC, a newly-formed entity that is jointly owned by Collins and Wallace LP contributed to RSP certain working interests. In exchange, Collins and Wallace LP received both cash and shares of RSP Inc.'s common stock and Collins & Wallace Holdings, LLC received only shares of RSP Inc.'s common stock. RSP Inc. is in the process of evaluating the fair values of the contributed assets in order to determine the appropriate purchase price allocation.

•

The Pecos Contribution:

•: Pecos Energy Partners, L.P. ("Pecos"), an entity owned by certain members of the management team of RSP, contributed to RSP certain working interests in acreage and wells in the Permian Basin in which RSP already had a working interest in exchange for shares of RSP Inc.'s common stock.

•

The ACTOIL NPI Repurchase:

•: ACTOIL, the owner of a 25% NPI issued by RSP, contributed to RSP its 25% NPI in exchange for shares of RSP Inc.'s common stock. RSP Inc. is in the process of evaluating the fair values of the contributed assets in order to determine the appropriate purchase price allocation.

Subsequent to year-end, RSP has closed approximately $79 million of acquisitions. On February 28, 2014, RSP closed the acquisition of a 17.5% non-operated working interest in producing properties located in Martin County, Texas. The properties are contiguous to RSP operated leasehold positions in Martin County. In addition, RSP added additional undeveloped leasehold in Glasscock County and Dawson County during the first quarter of 2014.

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

NOTES TO COMBINED FINANCIAL STATEMENTS (Continued)

NOTE 13—QUARTERLY FINANCIAL DATA (Unaudited)

The Company's unaudited quarterly financial data for 2013 and 2012 is summarized below.

	2013

	First Quarter^a		Second Quarter^a			Third Quarter		Fourth Quarter
Revenues	$	24,655	$	25,147		$	36,860	$	36,380
Income from operations		14,948		7,114			27,039		22,520
Income tax (expense) benefit		—		(68	)		—		(2,194	)
Net income	$	12,866	$	7,859		$	24,037	$	17,976
Pro forma information:
Net income	$	12,866	$	7,859		$	24,037	$	17,976
Pro forma provision for income taxes		4,632		2,829			8,653		6,472
Pro forma net income		8,234		5,030			15,384		11,504
Earnings per share:
Basic and diluted	$	0.26	$	0.16		$	0.48	$	0.36

	2012

	First Quarter			Second Quarter		Third Quarter		Fourth Quarter
Revenues	$	24,538		$	26,195	$	26,895	$	26,799
Income from operations		12,086			13,291		14,476		(898	)
Income tax (expense) benefit		(137	)		97		405		(26	)
Net income (loss)	$	6,564		$	23,174	$	8,865	$	(2,695	)

^a: Amounts in the first and second quarter 2013 columns have been revised from what was previously stated in an unaudited note to our financial statements for the year ended December 31, 2013 included in our Annual Report on Form 10-K for the year ended December 31, 2013 to correct a transposition error. The revisions have no effect on the year to date financial results for the six months ended June 30, 2013 or the annual results for the year ended December 31, 2013.

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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 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 revenues and direct operating expenses.

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SPANISH TRAIL ASSETS

NOTES TO STATEMENTS OF 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, NGL 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 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 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

	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		3,165			—			7,414			4,400
Revisions of previous estimates		(1,201	)		—			(4,202	)		(1,901	)
Extensions, discoveries and other additions		2,476			1,299			3,857			4,418
Purchases of minerals in place		—			—			—			—
Production		(270	)		(66	)		(278	)		(383	)


End of year		4,170			1,233			6,791			6,534




Proved developed reserves:
Beginning of year		1,849			—			4,278			2,562
End of year		1,792			554			3,053			2,854
Proved undeveloped reserves:
Beginning of year		1,316			—			3,136			1,838
End of year		2,378			679			3,738			3,680

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SPANISH TRAIL ASSETS

NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES (Continued)

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Continued)

	Year Ended December 31, 2011

	Oil (MBbls)			NGLs (MBbls)		Natural Gas (MMcf)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		3,846			—		8,014			5,181
Revisions of previous estimates		(813	)		—		(1,136	)		(1,002	)
Extensions, discoveries and other additions		354			—		834			493
Purchases of minerals in place		—			—		—			—
Production		(222	)		—		(298	)		(272	)


End of year		3,165			—		7,414			4,400




Proved developed reserves:
Beginning of year		1,778			—		3,795			2,410
End of year		1,849			—		4,278			2,562
Proved undeveloped reserves:
Beginning of year		2,068			—		4,219			2,771
End of year		1,316			—		3,136			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

Crude oil per Bbl	$	90.71	$	93.04
NGLs per Bbl		35.16		—
Natural gas per Mcf		2.23		7.72

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SPANISH TRAIL ASSETS

NOTES TO STATEMENTS OF 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 Directors and Stockholders
RSP Permian, Inc.

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") acquired by RSP Permian, Inc. (the "Company") for the years ended December 31, 2013 and 2012, 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, 2013 and 2012, 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
May 29, 2014

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CONTRIBUTED PROPERTIES

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

	For Years Ended December 31,

	2013		2012
	(In thousands)
Operating revenues	$	57,114	$	34,639
Direct operating expenses		10,393		6,863


Revenues in excess of direct operating expenses	$	46,721	$	27,776

See notes to statements of revenues and direct operating expenses.

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CONTRIBUTED PROPERTIES

NOTES TO STATEMENTS OF 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. and Wallace Family Partnership, LP ("Wallace LP") to RSP Permian, Inc. (the "Company") immediately prior to the Company's initial public offering for the years ended December 31, 2013 and 2012.

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.

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 December 31, 2013, there were no significant oil and gas imbalances related to the Contributed Properties.

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)

All information set forth herein relating to the proved reserves as of December 31, 2013 and 2012, 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

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CONTRIBUTED PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES (Continued)

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Continued)

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, 2013

	Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		7,590			2,342			12,383			11,997
Revisions of previous estimates		(53	)		(225	)		(326	)		(333	)
Extensions, discoveries and other additions		3,384			876			4,502			5,010
Purchases of minerals in place		—			—			—			—
Production		(543	)		(118	)		(668	)		(773	)


End of year		10,378			2,875			15,891			15,901




Proved developed reserves:
Beginning of year		2,253			806			4,168			3,754
End of year		4,460			1,150			7,262			6,820
Proved undeveloped reserves:
Beginning of year		5,337			1,536			8,215			8,243
End of year		5,918			1,725			8,629			9,081

	Year Ended December 31, 2012

	Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		12,588			—			35,550			18,513
Revisions of previous estimates		(9,733	)		—			(30,755	)		(14,859	)
Extensions, discoveries and other additions		5,081			2,436			8,030			8,856
Purchases of minerals in place		—			—			—			—
Production		(346	)		(94	)		(442	)		(513	)


End of year		7,590			2,342			12,383			11,997




Proved developed reserves:
Beginning of year		2,480			—			6,443			3,554
End of year		2,253			806			4,168			3,754
Proved undeveloped reserves:
Beginning of year		10,108			—			29,107			14,959
End of year		5,337			1,536			8,215			8,243

For the year ended December 31, 2013, the Contributed Properties' negative revision of 333 MBoe of previously estimated quantities is primarily due to a change in development strategy. For the year ended December 31, 2012, the Contributed Properties' negative revision of 14,859 MBoe of previously

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CONTRIBUTED PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES (Continued)

NOTE 3—SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) (Continued)

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):

	2013			2012

	(In thousands)
Future cash inflows	$	1,028,372		$	802,351
Future production costs		(291,390	)		(242,365	)
Future development costs		(207,795	)		(149,173	)
Future income tax expenses		—			—


Future net cash flows		529,187			410,813
10% annual discount for estimated timing of cash flows		(338,691	)		(262,738	)


Standardized measure of discounted future net cash flows	$	190,496		$	148,075

Future cash inflows are computed by applying a 12-month average commodity price adjusted for location and quality differentials for 2013 and 2012 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 was as follows:

Petroleum Product	2013		2012

Crude oil per Bbl	$	93.78	$	91.06
NGLs per Bbl		29.40		35.16
Natural gas per Mcf	$	3.34	$	2.24

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CONTRIBUTED PROPERTIES

NOTES TO STATEMENTS OF 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:

	2013			2012

	(In thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	148,075		$	308,564
Changes from:
Sales, less production costs		(46,721	)		(27,776	)
Revisions of previous quantity estimates		(11,106	)		(247,662	)
Extensions, discoveries and other additions		59,436			109,311
Net change in prices and production costs		8,814			(25,381	)
Changes in estimated future development costs		(15,483	)		2,306
Previously estimated development costs incurred during the period		26,715			13,809
Accretion or discount		14,807			30,856
Timing differences and other		5,959			(15,952	)


Standardized measure of discounted future net cash flows, end of year	$	190,496		$	148,075

NOTE 4—SUBSEQUENT EVENTS

We are not aware of any events that have occurred subsequent to December 31, 2013 but before May 29, 2014, the date the financial statements were available to be issued, that require recognition or disclosure in these financial statements.

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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.

"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.

"Bcf." One billion 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.

"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.

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"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.

"MMBoe." One million Boe.

"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.

"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.

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"Offset operator." Any entity that has an active lease on an adjoining property for oil, NGLs or natural gas 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, NGLs and natural gas that 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).

"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

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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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15,000,000 Shares

RSP Permian, Inc.

Common Stock

Prospectus
, 2014

Barclays

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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, the NYSE listing fee and the FINRA filing fee, the amounts set forth below are estimates.


SEC registration fee	$	70,942.08
FINRA filing fee		83,118.88
NYSE listing fee		45,000.00
Accounting fees and expenses		50,000.00
Legal fees and expenses		400,000.00
Printing and engraving expenses		95,000.00
Transfer agent and registrar fees		5,000.00
Miscellaneous		50,939.04


Total	$	800,000.00

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 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.

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

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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 have entered 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. The indemnification agreements 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 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 to be 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

None.

Item 16. Exhibits and Financial Statement Schedules

(a) Exhibits

Exhibit number		Description

1.1	*	Form of Underwriting Agreement.
3.1		Amended and Restated Certificate of Incorporation of RSP Permian, Inc. (incorporated by reference to Exhibit 3.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).
3.2		Amended and Restated Bylaws of RSP Permian, Inc. (incorporated by reference to Exhibit 3.2 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).
4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company's Registration Statement on Form S-1 (File No. 333-192268) filed with the Commission on January 13, 2014).
4.2		Registration Rights Agreement, dated as of January 23, 2014, 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. (incorporated by reference to Exhibit 4.2 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).

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Exhibit number		Description

4.3		Stockholders' Agreement, dated as of January 23, 2014, 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. (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).
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 (incorporated by reference to Exhibit 10.1 of the Company's Registration Statement on Form S-1 (File No. 377-00338) filed with the Commission on October 8, 2013).
10.2		First Amendment to Amended and Restated Credit Agreement, dated June 9, 2014, by and among RSP Permian, L.L.C., as borrower, Comerica Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on June 9, 2014).
10.3		Amended and Restated Liability Company Agreement of RSP Permian Holdco, L.L.C., dated January 23, 2014 (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).
10.4		Form of Indemnification Agreement (incorporated by reference to Exhibit 10.4 of the Company's Registration Statement on Form S-1 (File No. 333-192268) filed with the Commission on January 2, 2014).
10.5	†	RSP Permian, Inc. 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 22, 2014).
10.6	†	Executive Change in Control and Severance Benefit Plan of RSP Permian, Inc., dated July 22, 2014.
10.7		Purchase and Sale Agreement, dated July 22, 2014, by and among Adventure Exploration Partners II, LLC, Alpine Oil Company, JM Cox Resources, LP and D.R.E. Interests, LLC, as sellers, and RSP Permian, L.L.C., as buyer (incorporated by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on July 25, 2014).
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).
99.1	**	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2013.

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Exhibit number		Description

99.2	**	Ryder Scott Company, L.P., Summary of Pro Forma Reserves at December 31, 2013.
101.INS	**	XBRL Instance Document.
101.SCH	**	XBRL Taxonomy Extension Schema Document.
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	**	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase Document.

*: To be filed by amendment.
**: Previously filed.
†: Compensatory plan or arrangement.

(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.

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. 2 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 July 25, 2014.


		RSP PERMIAN, INC.
		By:		/s/ STEVEN GRAY Steven Gray Chief Executive Officer and Director

Pursuant to the requirements of the Securities Act, this Amendment No. 2 to the Registration Statement has been signed by the following persons on July 25, 2014 in the capacities indicated.

Signature		Title


* Michael Grimm		Chairman of the Board
/s/ STEVEN GRAY Steven Gray		Chief Executive Officer and Director (Principal Executive Officer)
/s/ SCOTT MCNEILL Scott McNeill		Chief Financial Officer and Director (Principal Financial Officer)
/s/ BARRY TURCOTTE Barry Turcotte		Chief Accounting Officer (Principal Accounting Officer)
* David Albin		Director
* Joseph B. Armes		Director
* Ted Collins, Jr.		Director
* Matthew S. Ramsey		Director
* Michael W. Wallace		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		Amended and Restated Certificate of Incorporation of RSP Permian, Inc. (incorporated by reference to Exhibit 3.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).
3.2		Amended and Restated Bylaws of RSP Permian, Inc. (incorporated by reference to Exhibit 3.2 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).
4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company's Registration Statement on Form S-1 (File No. 333-192268) filed with the Commission on January 13, 2014).
4.2		Registration Rights Agreement, dated as of January 23, 2014, 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. (incorporated by reference to Exhibit 4.2 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).
4.3		Stockholders' Agreement, dated as of January 23, 2014, 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. (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).
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 (incorporated by reference to Exhibit 10.1 of the Company's Registration Statement on Form S-1 (File No. 377-00338) filed with the Commission on October 8, 2013).
10.2		First Amendment to Amended and Restated Credit Agreement, dated June 9, 2014, by and among RSP Permian, L.L.C., as borrower, Comerica Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on June 9, 2014).
10.3		Amended and Restated Liability Company Agreement of RSP Permian Holdco, L.L.C., dated January 23, 2014 (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014).
10.4		Form of Indemnification Agreement (incorporated by reference to Exhibit 10.4 of the Company's Registration Statement on Form S-1 (File No. 333-192268) filed with the Commission on January 2, 2014).
10.5	^†	RSP Permian, Inc. 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 22, 2014).

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Exhibit number		Description

10.6	^†	Executive Change in Control and Severance Benefit Plan of RSP Permian, Inc., dated July 22, 2014.
10.7		Purchase and Sale Agreement, dated July 22, 2014, by and among Adventure Exploration Partners II, LLC, Alpine Oil Company, JM Cox Resources, LP and D.R.E. Interests, LLC, as sellers, and RSP Permian, L.L.C., as buyer (incorporated by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on July 25, 2014).
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).
99.1	**	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2013.
99.2	**	Ryder Scott Company, L.P., Summary of Pro Forma Reserves at December 31, 2013.
101.INS	**	XBRL Instance Document.
101.SCH	**	XBRL Taxonomy Extension Schema Document.
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	**	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase Document.

*: To be filed by amendment.
**: Previously filed.
^†: Compensatory plan or arrangement.

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RSP Permian, Inc. - FORM S-1/A - July 25, 2014

Attached files

RSP Permian, Inc. Reports