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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on January 19, 2017

Registration No. 333-            


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



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



Centennial Resource Development, Inc.
(Exact Name of Registrant as Specified in its Charter)



Delaware
(State or other jurisdiction
of incorporation)
  1311
(Primary Standard Industrial
Classification Code Number)
  47-5381253
(I.R.S. Employer
Identification No.)

1401 Seventeenth Street, Suite 1000
Denver, Colorado 80202
(720) 441-5515
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)



Copies to:

William N. Finnegan IV
Debbie P. Yee
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
(713) 546-5400

Approximate date of commencement of proposed sale to the public:
From time to time 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.     ý

           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. (Check one):

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
registered(1)

  Proposed maximum
offering price per
share

  Proposed maximum
aggregate offering
price

  Amount of
registration fee

 

Class A Common Stock, par value $0.0001 per share

  26,100,000(2)   $18.39(4)   $479,979,000   $55,630
 

Class A Common Stock, par value $0.0001 per share

  36,485,970(3)   $18.39(4)   $670,976,989   $77,766
 

Total

  62,585,970       $1,150,955,989   $133,396

 

(1)
Pursuant to Rule 416(a) under the Securities Act of 1933, as amended (the "Securities Act"), there are also being registered such indeterminable additional shares of Class A Common Stock, par value $0.0001 per share, of the Registrant (the "Class A Common Stock") as may be issued to prevent dilution as a result of stock splits, stock dividends or similar transactions.

(2)
Represents the resale of 26,100,000 shares of Class A Common Stock that are issuable upon the conversion of 104,400 shares of Series B Preferred Stock, par value $0.0001 per share, of the Registrant, which the Registrant issued to an affiliate of SB RS Holdings, LLC in a private placement in connection with the Registrant's acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC and that are convertible into shares of Class A Common Stock on a 250-to-1 basis (subject to certain adjustments) in accordance with the Certificate of Designation of Series B Preferred Stock of Centennial Resource Development, Inc. filed with the Secretary of State of the State of Delaware on December 28, 2016.

(3)
Represents the resale of 36,485,970 shares of Class A Common Stock issued to certain investors in private placements in connection with the Registrant's acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC.

(4)
Estimated at $18.39 per share, the average of the high and low prices of the Class A Common Stock as reported on The NASDAQ Capital Market on January 13, 2017, solely for the purpose of calculating the registration fee in accordance with Rule 457(f)(1) under the Securities Act.

            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 which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act, or until the 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 contained in this prospectus is not complete and may be changed. No securities may be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state where the offer or sale is not permitted.

Subject to Completion, dated January 19, 2017

Preliminary Prospectus

CENTENNIAL RESOURCE DEVELOPMENT, INC.

62,585,970 Shares of Class A Common Stock



        This prospectus relates to the resale of 62,585,970 shares of Class A Common Stock, par value $0.0001 per share (the "Class A Common Stock"), of Centennial Resource Development, Inc. (the "Company," "we," "our" or "us") by the selling stockholders named in this prospectus or their permitted transferees. The shares of Class A Common Stock being offered by the selling stockholders consist of (i) 26,100,000 shares of Class A Common Stock (the "Conversion Shares") that are issuable upon the conversion of 104,400 shares of our Series B Preferred Stock, par value $0.0001 per share (the "Series B Preferred Stock"), and (ii) 36,485,970 shares of Class A Common Stock (the "Private Placement Shares"). We sold the shares of Series B Preferred Stock and the Private Placement Shares in private placements that closed simultaneously with the consummation of our acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC on December 28, 2016.

        The selling stockholders may offer, sell or distribute all or a portion of their shares of Class A Common Stock publicly or through private transactions at prevailing market prices or at negotiated prices. We will not receive any of the proceeds from the sale of the shares of Class A Common Stock owned by the selling stockholders. We will bear all costs, expenses and fees in connection with the registration of these shares of Class A Common Stock, including with regard to compliance with state securities or "blue sky" laws. The selling stockholders will bear all commissions and discounts, if any, attributable to their sale of shares of Class A Common Stock. See "Plan of Distribution" beginning on page 131 of this prospectus.

        Our Class A Common Stock is quoted on The NASDAQ Capital Market ("NASDAQ") under the symbol "CDEV". On January 18, 2017, the closing price of our Class A Common Stock was $18.87. As of January 18, 2017, we had 200,835,049 shares of Class A Common Stock issued and outstanding.

        We are an "emerging growth company" as defined in Section 2(a) of the Securities Act of 1933, as amended (the "Securities Act"), as modified by the Jumpstart Our Business Startups Act of 2012 (the "JOBS Act") and are subject to reduced public company reporting requirements. This prospectus complies with the requirements that apply to an issuer that is an emerging growth company.

         INVESTING IN THESE SECURITIES INVOLVES CERTAIN RISKS. SEE "RISK FACTORS" ON PAGE 8.

         Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

   

The date of this prospectus is                    , 2017


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TABLE OF CONTENTS

PROSPECTUS SUMMARY

    1  

RISK FACTORS

    8  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

    35  

USE OF PROCEEDS

    37  

DETERMINATION OF OFFERING PRICE

    37  

PRICE RANGE OF SECURITIES AND DIVIDENDS

    37  

SELECTED HISTORICAL FINANCIAL INFORMATION

    38  

DESCRIPTION OF BUSINESS

    42  

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

    70  

MANAGEMENT

    99  

EXECUTIVE AND DIRECTOR COMPENSATION

    106  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

    114  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

    120  

SELLING STOCKHOLDERS

    125  

PLAN OF DISTRIBUTION

    131  

DESCRIPTION OF CAPITAL STOCK

    134  

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS

    144  

LEGAL MATTERS

    149  

EXPERTS

    149  

WHERE YOU CAN FIND MORE INFORMATION

    149  

INDEX TO FINANCIAL STATEMENTS

    F-1  

ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS

    A-1  

        You should rely only on the information contained in this prospectus, any prospectus supplement or in any free writing prospectus we may authorize to be delivered or made available to you. We have not, and the selling stockholders have not, authorized anyone to provide you with different information. We and the selling stockholders are not offering to sell, or seeking offers to buy, shares of our Class A Common Stock in jurisdictions where offers and sales are not permitted. The information contained 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 shares of our Class A Common Stock.

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INDUSTRY AND MARKET DATA

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


TRADEMARKS AND TRADE NAMES

        We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, that 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 us or an endorsement or sponsorship by or of 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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GLOSSARY

        Unless the context otherwise requires, references in this prospectus to:

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        For additional defined terms commonly used in the oil and natural gas industry and used in this prospectus, please see "Glossary of Oil and Natural Gas Terms" set forth in Annex A.

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PROSPECTUS SUMMARY

        This summary highlights certain information appearing elsewhere in this prospectus. For a more complete understanding of this offering, you should read the entire prospectus carefully, including the risk factors and the financial statements. Unless otherwise specified herein, the information set forth in this prospectus describes the Company and its operations as of and for the periods preceding September 30, 2016, and does not reflect the completion of the Silverback Acquisition.


Our Company

Corporate History

        We were originally formed in November 2015 as a special purpose acquisition company under the name Silver Run Acquisition Corporation for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving us and one or more businesses. Until the consummation of the Business Combination, our shares of Class A Common Stock, Public Warrants and Units were traded on The NASDAQ Capital Market ("NASDAQ") under the ticker symbols "SRAQ," "SRAQW" and "SRAQU," respectively.

        On October 11, 2016 (the "Business Combination Closing Date"), we consummated the acquisition of approximately 89% of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company ("CRP"), pursuant to (i) that certain Contribution Agreement, dated as of July 6, 2016 (as amended by Amendment No. 1 thereto, dated as of July 29, 2016, the "Contribution Agreement"), among Centennial Resource Development, LLC, a Delaware limited liability company ("CRD"), NGP Centennial Follow-On LLC, a Delaware limited liability company ("NGP Follow-On"), Celero Energy Company, LP, a Delaware limited partnership (together with CRD and NGP Follow-On, the "Centennial Contributors"), CRP and New Centennial, LLC, a Delaware limited liability company ("NewCo"), (ii) that certain Assignment Agreement, dated as of October 7, 2016, between NewCo and the Company and (iii) that certain Joinder Agreement, dated as of October 7, 2016, by the Company (such acquisition, together with the other transactions contemplated by the Contribution Agreement, the "Business Combination").

        At the closing of the Business Combination, we contributed to CRP approximately $1.49 billion in cash and CRP then distributed to the Centennial Contributors cash in the amount of approximately $1.18 billion in partial redemption of the Centennial Contributors' membership interests in CRP. At the closing of the Business Combination, we and the Centennial Contributors effected a recapitalization of CRP pursuant to which (1) all of the remaining outstanding membership interests in CRP of the Centennial Contributors were converted into 20,000,000 units representing common membership interests in CRP (the "CRP Common Units") and (2) we were admitted as a member of CRP and issued 163,505,000 CRP Common Units.

        Following the Business Combination, we changed our name from "Silver Run Acquisition Corporation" to "Centennial Resource Development, Inc." and continued the listing of our Class A Common Stock and Public Warrants on NASDAQ under the symbols "CDEV" and "CDEVW," respectively.

Business Overview

        Our only significant asset is our ownership of an approximate 92% membership interest in CRP. We are an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and our properties consist of large, contiguous acreage blocks in Reeves, Ward and Pecos counties in West Texas.

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        As of September 30, 2016, our portfolio included 63 operated producing horizontal wells. The horizontal wells span an area approximately 45 miles long by 20 miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we have broadly appraised this acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling inventory with a focus on maximizing returns to our stockholders. In addition, we believe this acreage may be prospective for the 2nd and 3rd Bone Spring shales and Avalon Shale, where other operators have experienced drilling success near our acreage.

        As of September 30, 2016, we have leased or acquired approximately 42,300 net acres, approximately 80% of which we operate. Our acreage is predominantly located in the southern portion of the Delaware Basin, where production and reserves typically contain a higher percentage of oil and natural gas liquids and a correspondingly lower percentage of natural gas compared to the northern portion of the Delaware Basin. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, we added one horizontal rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. During 2016, we placed 11 horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on optimizing completions, reducing drilling times and reducing costs.

        Our goal is to build a premier development and acquisition company focused on horizontal drilling in the Delaware Basin.

Recent Developments

Silverback Acquisition

        On December 28, 2016, we completed the acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC (collectively, "Silverback") for a cash purchase price of approximately $855,000,000, subject to customary purchase price adjustments. The assets acquired from Silverback include 30 operated producing horizontal wells and approximately 35,000 net acres in Reeves County, Texas that directly offset our existing acreage. We operate approximately 95% of, and have an approximate 88% working interest in, this acreage and believe that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations.

        The acreage acquired in the Silverback Acquisition includes 11,694 net acres, with an allocated value of approximately $300 million, subject to an area of mutual interest (the "AMI") among various parties. Pursuant to the AMI, one or more of three separate counterparties may elect to acquire up to an aggregate of 80.75% of the acreage subject to the AMI by paying to us, on or before January 30, 2017, such counterparty's share of the cost and expense of acquiring the acreage. The failure of a counterparty to make such payment on or before January 30, 2017 will be deemed to be an election not to acquire the AMI acreage.

Issuance of Class A Common Stock and Preferred Stock in Private Placements

        In connection with the Silverback Acquisition, we issued and sold in private placements (i) 3,473,590 shares of Class A Common Stock and 104,400 shares of Series B Preferred Stock to the Riverstone Purchasers and (ii) 33,012,380 shares of our Class A Common Stock to certain other investors, resulting in gross proceeds of approximately $910 million. We used the proceeds from the private placements to fund the cash consideration for the Silverback Acquisition and expect to use any remaining proceeds for general corporate purposes.

        The shares of Series B Preferred Stock are automatically convertible into shares of our Class A Common Stock on a 250-to-1 basis (subject to certain adjustments) at such time as we receive

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stockholder approval for the issuance of such shares of Class A Common Stock in compliance with NASDAQ listing rules ("Stockholder Approval"). We intend to call a special meeting of our stockholders in order to receive such approval. For a more detailed description of the Series B Preferred Stock, please see "Description of Capital Stock—Series B Preferred Stock."

Credit Agreement Amendment

        On December 28, 2016, in connection with the closing of the Silverback Acquisition, CRP entered into an amendment to its credit agreement to, among other things, increase the borrowing base thereunder from $200.0 million to $250.0 million.

Organizational Structure

        The following diagram illustrates the current ownership structure of the Company, after giving effect to the conversion of our Series B Preferred Stock.

GRAPHIC


(1)
Includes the 33,012,380 shares of Class A Common Stock of the selling stockholders (other than the Riverstone Purchasers) registered under this prospectus for resale.

(2)
Gives effect to the issuance of the 26,100,000 Conversion Shares, which are registered under this prospectus for resale (and not accounting for the outstanding Public Warrants and Private Placement Warrants).

(3)
CRD, one of the Centennial Contributors, also owns one share of our Series A Preferred Stock, par value $0.0001 per share (the "Series A Preferred Stock"), which does not have any voting rights (other than the right to nominate and elect one director to our board of directors) or rights with respect to dividends but is entitled to preferred distributions in liquidation in the amount of $0.0001 per share.

(4)
The economic and voting interests set forth in the diagram do not account for the outstanding Public Warrants and Private Placement Warrants.

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Additional Information

        Our principal executive offices are located at 1401 Seventeenth Street, Suite 1000, Denver, Colorado 80202, and our telephone number is (720) 441-5515. Our website is www.cdevinc.com. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

Our Emerging Growth Company Status

        As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an "emerging growth company" as defined in the JOBS Act. As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:

    the presentation of only two years of audited financial statements and only two years of related Management's Discussion and Analysis of Financial Condition and Results of Operations;

    deferral of the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;

    exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

    exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board 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; and

    reduced disclosure about executive compensation arrangements.

        We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following February 29, 2021, the fifth anniversary of our IPO, (ii) the last day of the fiscal year in which we have more than $1.0 billion in annual revenue, (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period and (iv) the date on which we are deemed to be a "large accelerated filer," as defined in Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). We have elected to take advantage of each of the exemptions for emerging growth companies, other than the presentation of only two years of audited financial statements and related Management's Discussion and Analysis of Financial Conditions and Results of Operations.

        Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

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The Offering

        We are registering the resale of 62,585,970 shares of Class A Common Stock by the selling stockholders named in this prospectus, or their permitted transferees.

Shares Offered by the Selling Stockholders

  We are registering 62,585,970 shares of Class A Common Stock to be offered by the selling stockholders named herein, which includes (i) 26,100,000 Conversion Shares and (ii) 36,485,970 Private Placement Shares.

Terms of the Offering

 

The selling stockholders will determine when and how they will dispose of the shares of Class A Common Stock registered under this prospectus for resale.

Shares Outstanding Prior to This Offering (Prior to the Conversion of the Series B Preferred Stock)(1)(2)

 

As of January 18, 2017, we had issued and outstanding (i) 200,835,049 shares of Class A Common Stock, (ii) 19,155,921 shares of Class C Common Stock, (iii) 1 share of Series A Preferred Stock and (iv) 104,400 shares of Series B Preferred Stock.

Shares Outstanding After This Offering (Assuming Conversion of the Series B Preferred Stock)(1)

 

(i) 226,935,049 shares of Class A Common Stock (ii) 19,155,921 shares of Class C Common Stock and (iii) 1 share of Series A Preferred Stock.

Use of Proceeds

 

We will not receive any of the proceeds from the sale of shares of Class A Common Stock by the selling stockholders.

Trading Market and Ticker Symbol

 

Our Class A Common Stock is listed on NASDAQ under the symbol "CDEV".


(1)
The number of shares of Class A Common Stock does not include (i) the 16,500,000 shares of Class A Common Stock available for future issuance under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan or (ii) the 24,666,643 shares of Class A Common Stock issuable upon the exercise of the Public Warrants and the Private Placement Warrants.

(2)
The number of shares of Class A Common Stock does not include the 26,100,000 Conversion Shares, which are issuable upon the conversion of our Series B Preferred Stock at such time as we receive Stockholder Approval.

        For additional information concerning the offering, see "Plan of Distribution" beginning on page 131.

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Risk Factors

        Before investing in our securities, you should carefully read and consider the information set forth in "Risk Factors" beginning on page 8.


Summary Historical Reserve and Operating Data

        The following tables present, for the periods and as of the dates indicated, summary data with respect to our estimated net proved oil and natural gas reserves and operating data.

        The reserve estimates attributable to our properties as of December 31, 2015 presented in the table below are based on a reserve report prepared by Netherland, Sewell & Associates, Inc., our independent petroleum engineer. A copy of the reserve report is included as Exhibit 99.2 to the registration statement of which this prospectus forms a part. 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, natural gas and NGLs with respect to such properties.

        Please see the sections of this prospectus entitled "Description of Business—Oil and Natural Gas Data—Proved Reserves" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in evaluating the information presented below.

 
  As of
December 31,
2015(1)
 

Proved Reserves:

       

Oil (MBbls)

    23,199  

Natural gas (MMcf)

    32,442  

NGLs (MBbls)

    3,851  

Total proved reserves (MBoe)

    32,457  

Proved Developed Reserves:

       

Oil (MBbls)

    9,347  

Natural gas (MMcf)

    12,711  

NGLs (MBbls)

    1,603  

Total proved developed reserves (MBoe)

    13,068  

Proved developed reserves as a percentage of total proved reserves

    40 %

Proved Undeveloped Reserves:

       

Oil (MBbls)

    13,852  

Natural gas (MMcf)

    19,731  

NGLs (MBbls)

    2,248  

Total proved undeveloped reserves (MBoe)

    19,389  

Oil and Natural Gas Prices:

       

Oil—WTI posted price per Bbl

  $ 46.79  

Natural gas—Henry Hub spot price per MMBtu

  $ 2.59  

(1)
Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average West Texas Intermediate posted price of $46.79 per barrel as of December 31, 2015 was adjusted for quality, transportation fees and a regional price differential. For gas volumes, the average Henry Hub spot price of $2.59 per MMBtu as of December 31, 2015 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production

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    over the remaining lives of the properties are $41.85 per barrel of oil, $13.94 per barrel of NGL and $1.71 per Mcf of gas as of December 31, 2015.

 
  Nine Months
Ended
September 30,
2016
  Year Ended
December 31,
2015
 

Production and Operating Data:

             

Net Production Volumes(1):

             

Oil (MBbls)

    1,520     1,830  

Natural gas (MMcf)

    2,551     3,058  

NGLs (MBbls)

    242     331  

Total (MBoe)

    2,187     2,671  

Average net daily production (Boe/d)

    7,982     7,317  

Average Sales Prices:

             

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

  $ 37.48   $ 42.43  

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

    48.42     61.61  

Natural gas (per Mcf) (excluding impact of cash settled derivatives)

    2.24     2.60  

Natural gas (per Mcf) (after impact of cash settled derivatives)

    2.24     3.04  

NGLs (per Bbl)

    12.80     14.66  

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

    30.08     33.87  

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

    37.68     47.51  

Average Unit Costs per Boe:

             

Lease operating expenses

  $ 4.71   $ 7.93  

Severance and ad valorem taxes

    1.61     1.88  

Transportation, processing, gathering and other operating expenses

    2.00     2.15  

Depreciation, depletion, amortization, and accretion of asset retirement obligations

    27.86     33.73  

Abandonment expense and impairment of unproved properties

    1.16     2.85  

Exploration

        0.03  

Contract termination and rig stacking

        0.89  

General and administrative expenses

    4.87     5.32  

(1)
Totals may not sum or recalculate due to rounding.

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RISK FACTORS

         Investing in our securities involves a high degree of risk. You should consider carefully the risks and uncertainties described below, together with all of the other information in this prospectus, including our consolidated financial statements and related notes, before deciding whether to purchase any of our securities. Any of these risks may have a material adverse effect on our business, financial condition, results of operations and cash flows and our prospects could be harmed. In that event, the price of our securities could decline and you could lose part or all of your investment. Unless otherwise specified, operational data is as of September 30, 2016 and does not reflect the completion of the Silverback Acquisition.

Risks Related to Our Business

Our only significant asset is our ownership of an approximate 92% membership interest in CRP. Distributions from CRP may not be sufficient to allow us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations.

        We have no direct operations and no significant assets other than the ownership of an approximate 92% membership interest in CRP. We will depend on CRP for distributions, loans and other payments to generate the funds necessary to meet our financial obligations or to pay any dividends with respect to our Class A Common Stock. Subject to certain restrictions, CRP generally will be required to (i) make pro rata distributions to its members, including us, in an amount at least sufficient to allow us to pay our taxes and (ii) reimburse us for certain corporate and other overhead expenses. However, legal and contractual restrictions in agreements governing future indebtedness of CRP, as well as the financial condition and operating requirements of CRP may limit our ability to obtain cash from CRP. The earnings from, or other available assets of, CRP may not be sufficient to pay dividends or make distributions or loans to enable us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations.

Oil, natural gas and NGL prices are volatile. A sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.

        The prices we receive for our oil, natural gas and NGLs production heavily influence our revenue, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, natural gas and NGLs and market uncertainty. Historically, oil, natural gas and NGL prices have been volatile. For example, during the period from January 1, 2014 through November 1, 2016, the WTI spot price for oil has declined from a high of $107.62 per Bbl on July 23, 2014 to $26.21 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $7.92 per MMBtu on March 4, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:

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        In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and 2016, the global oil supply has continued to outpace demand, resulting in continuing lower realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begin to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and in 2016. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The duration and magnitude of the commodity price declines cannot be accurately predicted. Compared to 2014, our realized oil price for 2015 fell 47.3% to $42.43 per barrel, and our realized oil price for the nine months ended September 30, 2016 has further decreased to $37.48 per barrel. Similarly, our realized natural gas price for 2015 dropped 43.2% to $2.60 per Mcf and our realized price for NGLs declined 52.2% to $14.66 per barrel. For the nine months ended September 30, 2016, our realized price for natural gas was $2.24 per Mcf and our realized price for NGLs was $12.80 per barrel.

        In addition, other governmental actions, including initiatives by OPEC, may continue to impact oil prices. Furthermore, it is uncertain what impact the election of Donald Trump as President of the United States will have on the exploration for and production of domestic oil, natural gas and NGLs. Decisions by OPEC to reduce production or increased domestic oil and natural gas production in a changing regulatory environment could impact the price of oil.

        Lower commodity prices may reduce our cash flows and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in

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proved reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current WTI or Henry Hub strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our 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 and ability to finance planned capital expenditures.

Our development and acquisition 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 production and reserves.

        The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to development and acquisition projects. We have funded, and we expect that we will continue to fund, our capital expenditures with cash generated by operations and borrowings under CRP's 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. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL 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.

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

        If our revenues or the borrowing base under CRP's revolving credit facility decrease as a result of lower oil, natural gas and NGL 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 CRP's 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. This, 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 the following:

        Risks that we face while completing wells include the following:

        In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, 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 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 development, acquisition and production 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 develop or purchase 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:

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The Silverback Acquisition involves risks associated with acquisitions and integrating acquired properties, including the potential exposure to significant liabilities, and the intended benefits of the Silverback Acquisition may not be realized.

        The Silverback Acquisition involves risks associated with acquisitions and integrating acquired properties into existing operations, including that:

        Even if we successfully integrate the properties acquired in the Silverback Acquisition into our operations, it may not be possible to realize the full benefits we anticipate or we may not realize these benefits within the expected timeframe. If we fail to realize the benefits we anticipate from the Silverback Acquisition, our business, results of operations and financial condition may be adversely affected.

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 depends on our financial condition and operating performance, which are subject to prevailing economic and

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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 our 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. CRP's credit agreement 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 CRP's existing and future debt agreements could limit our growth and ability to engage in certain activities.

        CRP's credit agreement contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

        In addition, CRP's credit agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of September 30, 2016, we were in full compliance with such financial ratios and covenants.

        The restrictions in CRP's credit agreement 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 impose on us.

        A breach of any covenant in CRP's credit agreement 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 CRP's credit agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated

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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 the borrowing base under CRP's revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

        CRP's revolving credit facility limits the amounts CRP can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually on April 1 and October 1. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the loan. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under CRP's revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. In connection with the Silverback Acquisition, CRP entered into an amendment to its credit agreement to, among other things, increase the borrowing base from $200 million to $250 million. The next scheduled borrowing base redetermination is expected in the spring of 2017.

        In the future, we may not be able to access adequate funding under CRP's revolving credit facility (or a replacement facility) as a result of a decrease in the 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, CRP 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 CRP's indebtedness.

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

        We enter into derivative instrument contracts for a portion of our oil and natural gas production. As of September 30, 2016, we had entered into hedging contracts through December 2018 covering a total of 905 MBbls of our projected oil production and 1,460 BBtu of our projected natural gas production. In addition, as of September 30, 2016, we had entered into basis swaps covering a total of 448 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:

        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

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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 CRP's borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates. 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.

        Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty's liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty's creditworthiness or ability to perform. Even if we accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

        During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

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 may vary from our estimates. 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 our estimates and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.

        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. For example, our estimated proved reserves as of December 31, 2015 and related standardized measure were calculated under rules of the SEC using twelve-month trailing average benchmark prices of $46.79 per barrel of oil (WTI) and $2.59 per MMBtu (Henry Hub spot), which, for certain periods in 2016, were substantially higher than the available spot prices. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

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We will not be the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

        As of September 30, 2016, we have leased or acquired approximately 42,300 net acres, approximately 80% of which we operate. As of September 30, 2016, we were the operator on 673 of our 1,388 identified gross horizontal drilling locations. We acquired approximately 35,000 net acres in the Silverback Acquisition, approximately 95% of which we operate. We will have limited ability to exercise influence over the operations of the drilling locations operated by our partners, and there is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

        This limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities.

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 amount of capital that would be necessary to drill such locations.

        We have 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 identified drilling locations will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

        As of September 30, 2016, we had identified 1,388 horizontal drilling locations on our acreage based on approximately 880-foot spacing with five to six wells per 640-acre section in the Wolfcamp zones and approximately 1,320-foot spacing with four wells per 640-acre section in the 3rd Bone Spring Sandstone, in each case, consisting of laterals ranging from 4,500 feet up to 9,500 feet. As a result of the limitations described above, we may be unable to drill many of our identified 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. See "—Our development and acquisition 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 production and reserves." Any drilling activities we are able to conduct on these locations may not be successful or enable us to add additional proved reserves to our overall

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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. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.

        As of September 30, 2016, approximately 60% of our total net acreage (approximately 79% of our operated net acreage in Reeves and Ward counties) was either held by production or under continuous drilling provisions. Of the net acreage acquired in the Silverback Acquisition, approximately 37% was either held by production or under continuous drilling provisions at the time of acquisition. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. If our leases expire and we are unable to renew the leases, we will lose the right to develop the related properties. 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.

Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.

        Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.

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 in past 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 Delaware Basin, a sub-basin of the Permian Basin, in West Texas, making us vulnerable to risks associated with operating in a single geographic area.

        All of our producing properties are geographically concentrated in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas. At December 31, 2015, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

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

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

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

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, 2015, 60% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved 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, we may be required to take write-downs of the carrying values of our properties.

        Accounting rules that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and 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 write-down constitutes a non-cash charge to earnings. Recently, commodity prices have declined significantly. On September 30, 2016, the WTI spot price for crude oil was $47.72 per barrel and the Henry Hub spot price for natural gas was $2.84 per MMBtu, representing decreases of 55% and 63%, respectively, from the high of $107.62 per barrel of oil and $7.92 per MMBtu for natural gas during 2014. Likewise, NGLs have suffered significant recent declines in realized prices. NGLs are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which

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have different uses and different pricing characteristics. Lower commodity prices in the future could result in impairments of our properties, 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 exploration and development 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 our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

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

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

We depend upon a significant purchaser for the sale of most of our oil, natural gas and NGL production.

        We normally sell our production to a relatively small number of customers, as is customary in our business. For the years ended December 31, 2015 and 2014, Plains Marketing, L.P. accounted for 64% and 78%, respectively, of our total revenue. During such years, no other purchaser accounted for 10% or more of our revenue. In the third quarter of 2016, we started selling the majority of our oil production to Shell Trading (US) Company ("Shell") under a new marketing contract. The loss of Shell as a purchaser 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 or other approval before conducting regulated 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, natural resource damages, 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

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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.

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

        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:

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        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 canceled as a result of numerous factors, including:

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 assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to 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, CRP's credit agreement imposes certain limitations on our ability to enter into mergers or combination transactions. CRP's credit agreement also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

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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. Although none of our drilling locations associated with proved undeveloped reserves as of December 31, 2015 or September 30, 2016 are on properties currently subject to such land use restrictions, such 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 development activities and perhaps even be precluded from the drilling of wells.

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

        The demand for drilling rigs, pipe and other equipment and supplies, as well as 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. Our operations are concentrated in areas in which industry had increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, had increased, as did the costs for those items. However, beginning in the second half of 2014, commodity prices began to decline and the demand for goods and services has subsided due to reduced activity. To the extent that commodity prices improve in the future, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to resume or increase our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, 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.

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

        Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

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

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adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

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 pursuant to 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 are also required to meet "best available control technology" standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements 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. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require additional personnel time to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

        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, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which requires member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. The United States is one of over 70 nations that has ratified or otherwise consented to be bound by the agreement. 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, many scientists have concluded

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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 operations.

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

        Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants 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 federal Safe Drinking Water Act ("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. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rules in 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming struck down the rule in June 2016. The BLM appealed the ruling to the Tenth Circuit. This appeals remains pending. 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 additional federal regulation of hydraulic fracturing activities may affect our operations.

        Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

        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 Railroad Commission of Texas 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 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

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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 development activities, and perhaps even be precluded from drilling wells.

Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of saltwater gathered from such activities, which could have a material adverse effect on our business.

        State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In addition, a number of lawsuits have been filed in other states, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of saltwater disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well.

        We dispose of large volumes of saltwater gathered from our drilling and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of saltwater gathered from our drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

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

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

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

Our business is difficult to evaluate because we have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion.

        CRP was formed in 2012 and, as a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

        In addition, we have grown rapidly over the last several years. We believe 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:

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

Increases in interest rates could adversely affect our business.

        Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, as of September 30, 2016, outstanding borrowings subject to variable interest rates were approximately $189 million, and a 1.0% increase in interest rates would result in an increase in annual interest expense of approximately $1.9 million, assuming the $189 million of debt was outstanding for the full year. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance 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:

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        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.

As a result of future legislation, certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated and our production may be subject to the imposition of new U.S. federal taxes.

        The U.S. President's Fiscal Year 2017 Budget Proposal and legislation introduced in a prior session of Congress includes proposals that, if enacted into law, would eliminate certain key U.S. federal income tax provisions currently available to oil and gas exploration and production companies or potentially make our operations subject to the imposition of new U.S. federal taxes. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (v) imposition of a $10.25 per barrel fee on oil, to be paid by oil companies (but the budget does not describe where and how such a fee would be collected). It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change, as well as any changes to or the imposition of new U.S. federal, state or local taxes (including the imposition of, or increase in production, severance or similar taxes), could increase the cost of exploration and development of oil and gas resources, which would 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, 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. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.

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

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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 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 October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

        The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow.

        The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, 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 implementing regulations is to lower commodity prices. Any of these consequences could have a material and adverse effect on us and our financial condition.

        In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.

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

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

Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect our business, investments and results of operations.

        We are subject to laws, regulations and rules enacted by national, regional and local governments and NASDAQ. In particular, we are required to comply with certain SEC, NASDAQ and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on our business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.

Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations.

        We are subject to income taxes in the United States, and our domestic tax liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

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        In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.

Risks Related to Our Securities and Capital Structure

The market price of our securities may decline.

        Fluctuations in the price of our securities could contribute to the loss of all or part of your investment. Prior to the closing of the Business Combination, trading in our Class A Common Stock and Public Warrants had been limited. If an active market for our securities develops and continues, the trading price of our securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your investment and our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a further decline.

        Factors affecting the trading price of our securities may include:

        Many of the factors listed above are beyond our control. In addition, broad market and industry factors may materially harm the market price of our securities irrespective of our operating

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performance. The stock market in general, and NASDAQ have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of our Class A Common Stock and Public Warrants which trade on NASDAQ, may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to the Company could depress the price of our securities regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.

If securities or industry analysts do not publish or cease publishing research or reports about us, our business, or our market, or if they change their recommendations regarding our securities adversely, the price and trading volume of our securities could decline.

        The trading market for our securities will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market, or our competitors. Securities and industry analysts do not currently, and may never, publish research on us. If no securities or industry analysts commence coverage of us, our stock price and trading volume would likely be negatively impacted. If any of the analysts who may cover us change their recommendation regarding our securities adversely, or provide more favorable relative recommendations about our competitors, the price of our securities would likely decline. If any analyst who may cover us were to cease coverage of us or fail to regularly publish reports on it, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.

Riverstone and its affiliates own a significant percentage of our outstanding voting common stock.

        Riverstone and its affiliates, including our Sponsor, beneficially own approximately 44.0% of our voting common stock and, upon the conversion of our Series B Preferred Stock, will beneficially own approximately 49.96% of our voting common stock. As long as Riverstone and its affiliates, including our Sponsor, own or control a significant percentage of outstanding voting power, they will have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our charter or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets.

        The interests of Riverstone and its affiliates, including our Sponsor, may not align with the interests of our other stockholders. Our Sponsor is in the business of making investments in companies and may acquire and hold interests in businesses that compete directly or indirectly with us. Riverstone and its affiliates, including our Sponsor, may also pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, our second amended and restated certificate of incorporation (the "Charter") provides that we renounce any interest or expectancy in the business opportunities of our officers and directors and their respective affiliates and each such party shall not have any obligation to offer us those opportunities unless presented to one of our directors or officers in his or her capacity as a director or officer.

We are no longer a "controlled company" within the meaning of the NASDAQ listing rules, and will not be able to take advantage of exemptions from certain corporate governance requirements.

        Riverstone and its affiliates, including our Sponsor, no longer control a majority of our outstanding voting common stock. After the conversion of our Series B Preferred Stock, Riverstone will not own over 50.0% of our voting common stock. As a result, we are no longer a "controlled company" within the meaning of the NASDAQ listing rules, and will not be able to take advantage of exemptions from

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certain corporate governance requirements. Under the NASDAQ listing rules, a company of which more than 50% of the voting power is held by an individual, group or another company is a "controlled company" and is exempt from certain corporate governance requirements, including, among others, the following:

        Pursuant to the requirements of the NASDAQ listing rules, a majority of our board of directors must consist of independent directors within one year after we cease to be a controlled company. In addition, we must comply with the independent board committee requirements as they relate to the nominating and corporate governance and compensation committees on the following phase-in schedule: (1) one independent committee member at the time we cease to be a controlled company, (2) a majority of independent committee members within 90 days of the date we cease to be a controlled company and (3) all independent committee members within one year of the date we cease to be a controlled company. Our board of directors is not currently comprised of a majority of independent directors, and neither our corporate governance and nominating committee nor our compensation committee is currently comprised solely of independent directors. Accordingly, during the applicable phase-in periods provided for under the NASDAQ listing rules, you may not have the same protections afforded to stockholders of companies that are subject to all of the NASDAQ corporate governance standards.

Anti-takeover provisions contained in our Charter and amended and restated bylaws (the "Bylaws"), as well as provisions of Delaware law, could impair a takeover attempt.

        Our Charter and Bylaws contain provisions that could have the effect of delaying or preventing changes in control or changes in our management without the consent of our board of directors. These provisions include:

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        These provisions, alone or together, could delay hostile takeovers and changes in control of the Company or changes in our board of directors and management.

        As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law (the "DGCL"), which prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our outstanding voting common stock. Any provision of our Charter or Bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.

The JOBS Act permits "emerging growth companies" like us to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.

        We qualify as an "emerging growth company" as defined in the JOBS Act. As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies for as long as we continue to be an emerging growth company, including (i) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. As a result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year (a) following February 28, 2021, the fifth anniversary of our IPO, (b) in which we have total annual gross revenue of at least $1.0 billion or (c) in which we are deemed to be a large accelerated filer, which means the market value of our Class A Common Stock that is held by non-affiliates exceeds $700 million as of the last business day of our prior second fiscal quarter, and (ii) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period.

        In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards provided in Section 7(a)(2)(B) of the Securities Act as long as we are an emerging growth company. An emerging growth company can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies, but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our financial statements with another public company which is neither

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an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accountant standards used.

        We cannot predict if investors will find our Class A Common Stock less attractive because we will rely on these exemptions. If some investors find our Class A Common Stock less attractive as a result, there may be a less active trading market for our Class A Common Stock and our stock price may be more volatile.

Non-U.S. holders may be subject to U.S. income tax with respect to gain on disposition of their Class A Common Stock.

        We believe that we are a United States real property holding corporation (a "USRPHC"). As a result, Non-U.S. holders (defined below in the section entitled "Material U.S. Federal Income Tax Considerations") that own (or are treated as owning under constructive ownership rules) more than a specified amount of our Class A Common Stock during a specified time period may be subject to U.S. federal income tax on a sale, exchange, or other disposition of such Class A Common Stock and may be required to file a U.S. federal income tax return. If you are a Non-U.S. holder, we urge you to consult your tax advisors regarding the tax consequences of such treatment.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        Certain statements in this prospectus constitute "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."

        Forward-looking statements may include statements about:

        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 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

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access to capital, the timing of development expenditures and the other risks described under the heading "Risk Factors."

        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 will not receive any of the proceeds from the sale of Class A Common Stock by the selling stockholders named herein.


DETERMINATION OF OFFERING PRICE

        Our Class A Common Stock is listed on NASDAQ under the symbol "CDEV." The actual offering price by the selling stockholders of the shares of Class A Common Stock covered by this prospectus will be determined by prevailing market prices at the time of sale, by private transactions negotiated by the selling stockholders or as otherwise described in the section entitled "Plan of Distribution."


PRICE RANGE OF SECURITIES AND DIVIDENDS

        Our Class A Common Stock is currently listed on NASDAQ under the symbol "CDEV". Through October 11, 2016, our Class A Common Stock was listed under the symbol "SRAQ". The following table sets forth for the periods indicated, the reported high and low bid quotations per share for our Class A Common Stock.

 
  Class A Common
Stock (CDEV)
 
 
  High   Low  

2017:

             

First Quarter(1)

  $ 20.08   $ 18.19  

2016:

             

Fourth Quarter

  $ 16.96   $ 14.09  

Third Quarter

  $ 16.10   $ 9.65  

Second Quarter(2)

  $ 10.70   $ 9.80  

First Quarter(3)

    N/A     N/A  

(1)
Through January 18, 2017.

(2)
Beginning on April 15, 2016.

(3)
Since the Class A Common Stock commenced separate trading on April 15, 2016, there is no information presented for the Class A Common Stock for the first quarter of 2016.

        On January 18, 2017, the closing price of our Class A Common Stock was $18.87. As of January 18, 2017, there were 200,835,049 shares of Class A Common Stock outstanding, held of record by 215 holders. In addition, 24,666,643 shares of Class A Common Stock are issuable upon exercise of the 24,666,643 Warrants, held of record by two holders. The number of record holders of our Class A Common Stock does not include DTC participants or beneficial owners holding shares through nominee names.

Dividend Policy

        We have not paid any cash dividends on our Class A Common Stock or Class C Common Stock to date. Our board of directors may from time to time consider whether or not to institute a dividend policy. It is our present intention to retain any earnings for use in our business operations and, accordingly, the we do not anticipate the board of directors declaring any dividends in the foreseeable future.

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SELECTED HISTORICAL FINANCIAL INFORMATION

        The following table shows selected historical financial information of CRP for the periods and as of the dates indicated. For all periods ending on or prior to and all dates as of or prior to October 15, 2014, the date on which Celero conveyed all of its oil and natural gas properties to CRP, the following table reflects the combined results of CRP and Celero, and for all periods and dates subsequent to October 15, 2014, reflects the results of CRP.

        The selected historical consolidated and combined financial information of CRP as of and for the years ended December 31, 2015, 2014 and 2013 was derived from the audited historical consolidated and combined financial statements of CRP included elsewhere in this prospectus. The selected historical interim consolidated financial information of CRP as of September 30, 2016 and for the nine months ended September 30, 2016 and 2015 was derived from the unaudited interim condensed consolidated financial statements of CRP included elsewhere in this prospectus.

        CRP's historical results are not necessarily indicative of future operating results. The selected consolidated and combined financial information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical

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consolidated and combined financial statements of CRP and accompanying notes included elsewhere in this prospectus.

 
  Nine Months Ended
September 30,
  Year Ended December 31,  
 
  2016   2015   2015   2014   2013  
 
  (Unaudited)
   
   
   
 
 
  (in thousands)
 

Statement of Operations Data:

                               

Revenues:

                               

Oil sales

  $ 56,975   $ 59,068   $ 77,643   $ 114,955   $ 65,863  

Natural gas sales

    5,717     6,082     7,965     9,670     3,024  

NGL sales

    3,097     3,590     4,852     7,200     3,087  

Total revenues

    65,789     68,740     90,460     131,825     71,974  

Operating expenses:

                               

Lease operating expenses

    10,295     17,317     21,173     17,690     19,106  

Severance and ad valorem taxes

    3,523     3,833     5,021     6,875     4,153  

Transportation, processing, gathering and other operating expenses          

    4,375     4,352     5,732     4,772     1,291  

Depreciation, depletion, amortization and accretion of asset retirement obligations

    60,939     64,003     90,084     69,110     29,285  

Abandonment expense and impairment of unproved properties

    2,546     3,851     7,619     20,025     8,561  

Exploration

            84          

Contract termination and rig stacking          

        2,388     2,387          

General and administrative expenses          

    10,655     8,538     14,206     31,694     16,842  

Total operating expenses

    92,333     104,282     146,306     150,166     79,238  

Loss (gain) on sale of oil and natural gas properties

    (11 )   (2,688 )   (2,439 )   2,096     (16,756 )

Total operating (loss) income

    (26,533 )   (32,854 )   (53,407 )   (20,437 )   9,492  

Other income (expense):

                               

Interest expense

    (5,422 )   (4,743 )   (6,266 )   (2,475 )   (513 )

(Loss) gain on derivatives instruments

    (4,184 )   12,320     20,756     41,943     (4,410 )

Other income

    6     (5 )   20     281     122  

Total other (expense) income

    (9,600 )   7,572     14,510     39,749     (4,801 )

(Loss) income before taxes

    (36,133 )   (25,282 )   (38,897 )   19,312     4,691  

Income tax benefit (expense)(2)

    406         572     (1,524 )   (1,079 )

Net (loss) income

    (35,727 )   (25,282 )   (38,325 )   17,788     3,612  

Less: Net loss attributable to noncontrolling interest

                (2 )   (6 )

Net (loss) income

  $ (35,727 ) $ (25,282 ) $ (38,325 ) $ 17,790   $ 3,618  

Cash Flow Data:

                               

Net cash provided by operating activities

  $ 51,511   $ 48,474   $ 68,882   $ 97,248   $ 13,416  

Net cash used in investing activities

    (100,975 )   (171,316 )   (198,635 )   (163,380 )   (136,517 )

Net cash provided by financing activities

    48,106     110,219     118,504     36,966     118,742  

Other Financial Data:

                               

Adjusted EBITDAX(1)

  $ 53,570   $ 60,667   $ 82,279   $ 88,108   $ 18,059  

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  December 31,  
 
  September 30,
2016
 
 
  2015   2014   2013  
 
  (Unaudited)
   
   
   
 
 
  (in thousands)
 

Balance Sheet Data:

                         

Cash and cash equivalents

  $ 410   $ 1,768   $ 13,017   $ 42,183  

Cash held in escrow

                5,000  

Other current assets

    12,840     32,377     54,329     19,132  

Total current assets

    13,250     34,145     67,346     66,315  

Total property and equipment, net

    619,375     578,787     540,624     357,541  

Other long-term assets

    1,287     3,363     7,799     48,229  

Total assets

  $ 633,912   $ 616,295   $ 615,769   $ 472,085  

Current liabilities

  $ 24,822   $ 22,133   $ 103,512   $ 46,169  

Revolving credit facility

    124,000     74,000     65,000     29,000  

Term loan, net of unamortized deferred financing costs

    64,762     64,649     64,568      

Other long-term liabilities

    5,191     4,649     4,757     6,369  

Total liabilities

    218,775     165,431     237,837     81,538  

Owners' equity

    415,137     450,864     377,932     389,859  

Noncontrolling interest in unconsolidated subsidiary

                688  

Total liabilities and owners' equity

  $ 633,912   $ 616,295   $ 615,769   $ 472,085  

(1)
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.

(2)
The Company is a C-corp under the Internal Revenue Code of 1986, as amended, and, as a result, is subject to U.S. federal, state and local income taxes. Although CRP is subject to franchise tax in the State of Texas (at less than 1% of modified pre-tax earnings), as a partnership, it generally passes through its taxable income to its owners for other income tax purposes and is not subject to U.S. federal income taxes or other state or local income taxes.


Non-GAAP Financial Measure

        Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by our 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 and accretion of asset retirement obligations, abandonment expense and impairment of unproved properties, (gains) losses on derivatives excluding net cash receipts (payments) on settled derivatives, non-cash equity based compensation, gains and losses from the sale of assets and other non-cash and non-recurring operating items. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles ("GAAP").

        Our management believes Adjusted EBITDAX is useful because it allows them 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

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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.

        The following table presents a reconciliation of Adjusted EBITDAX to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP.

 
  Nine Months Ended
September 30,
  Year Ended December 31,  
 
  2016   2015   2015   2014   2013  
 
  (Unaudited)
   
   
   
 
 
  (in thousands)
 

Adjusted EBITDAX reconciliation to net income:

                               

Net (loss) income

  $ (35,727 ) $ (25,282 ) $ (38,325 ) $ 17,790   $ 3,618  

Interest expense

    5,422     4,743     6,266     2,475     513  

Income tax (benefit) expense

    (406 )       (572 )   1,524     1,079  

Depreciation, depletion and amortization and accretion of asset retirement obligations

    60,939     64,003     90,084     69,110     29,285  

Abandonment expense and impairment of unproved properties

    2,546     3,851     7,619     20,025     8,561  

Loss (gain) on derivatives

    4,184     (12,320 )   (20,756 )   (41,943 )   4,410  

Net cash received for derivative settlements

    16,623     25,972     36,430     4,611     (12,651 )

Noncash incentive compensation expense

                12,420      

Contract termination and rig stacking

        2,388     2,387          

Write-off of deferred offering costs(1)

            1,585          

Loss (gain) on sale of oil and natural gas properties

    (11 )   (2,688 )   (2,439 )   2,096     (16,756 )

Adjusted EBITDAX

  $ 53,570   $ 60,667   $ 82,279   $ 88,108   $ 18,059  

(1)
During the year ended December 31, 2015, CRP delayed the timing of its initial public offering and, as a result, deferred offering costs of $1.6 million were charged against earnings.

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DESCRIPTION OF BUSINESS

Corporate History

        We were originally incorporated in Delaware on November 4, 2015 as a blank check company under the name Silver Run Acquisition Corporation for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving us and one or more businesses (an "initial business combination").

        On February 29, 2016, we consummated our IPO of 50,000,000 Units (including 5,000,000 Units sold pursuant to the underwriters' partial exercise of their over-allotment option) at $10.00 per Unit, with each Unit consisting of one share of Class A Common Stock and one-third of one Public Warrant. Our IPO generated total gross proceeds of $500,000,000. Prior to the consummation of our IPO, in November 2015, Silver Run Sponsor, LLC (our "Sponsor") purchased 11,500,000 shares of Class B Common Stock (the "founder shares"), for an aggregate purchase price of $25,000, or approximately $0.002 per share. On February 23, 2016, we effected a stock dividend of approximately 0.125 shares for each outstanding share of Class B Common Stock, resulting in the initial stockholders holding an aggregate of 12,937,500 founder shares. Also, in February 2016, our Sponsor transferred 40,000 of its founder shares to each of William D. Gutermuth, Jeffery H. Tepper and Diana J. Walters, our independent directors at the time of the transfer. On April 8, 2016, following the expiration of the underwriters' remaining over-allotment option in connection with our IPO, our Sponsor forfeited 437,500 founder shares.

        Simultaneously with the closing of our IPO on February 29, 2016, we completed the private sale of 8,000,000 warrants (the "Private Placement Warrants") to our Sponsor at a purchase price of $1.50 per Private Placement Warrant, generating gross proceeds to us of $12,000,000. The Private Placement Warrants are identical to the Public Warrants, except that our Sponsor agreed not to transfer, assign or sell any of the Private Placement Warrants (except to certain permitted transferees) until 30 days after the closing of the initial business combination. The Private Placement Warrants are also not redeemable by us so long as they are held by our Sponsor or its permitted transferees.

        A total of $500,000,000, comprised of $490,000,000 of the proceeds from our IPO, including approximately $17,500,000 in deferred underwriting commissions to the underwriters of our IPO, and the proceeds of the sale of the Private Placement Warrants were placed in a trust account maintained by Continental Stock Transfer & Trust Company, acting as trustee.

        On April 14, 2016, we announced that the holders of our Units could elect to separately trade the Class A Common Stock and Public Warrants included in the Units commencing on April 15, 2016. The Units not separated continued to trade on NASDAQ under the symbol "SRAQU" until October 11, 2016, when the Units were separated into their component securities in connection with the consummation of the Business Combination (as defined below).

        From the consummation of our IPO through the end of June 2016, we were searching for a suitable target business to effect an initial business combination. On July 6, 2016, New Centennial, LLC, a Delaware limited liability company and affiliate of our Sponsor ("NewCo"), entered into a Contribution Agreement (as amended by Amendment No. 1 thereto, dated as of July 29, 2016, the "Contribution Agreement"), with Centennial Resource Development, LLC, a Delaware limited liability company ("CRD"), NGP Centennial Follow-On LLC, a Delaware limited liability company ("NGP Follow-On"), Celero Energy Company, LP, a Delaware limited partnership ("Celero" and, together with CRD and NGP Follow-On, the "Centennial Contributors"), Centennial Resource Production, LLC, a Delaware limited liability company ("CRP"), to acquire approximately 89% of the outstanding membership interests in CRP, and on October 7, 2016, NewCo assigned its rights to acquire such membership interests to us (the acquisition and the other transactions contemplated by the Contribution Agreement, the "Business Combination").

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        Upon the terms and conditions contained in the Contribution Agreement, at the closing of the Business Combination, we contributed to CRP approximately $1.49 billion in cash and CRP then distributed to the Centennial Contributors cash in the amount of approximately $1.19 billion in partial redemption of the Centennial Contributors' membership interests in CRP. We and the Centennial Contributors effected a recapitalization of CRP (the "Recapitalization"), pursuant to which (1) all of the remaining outstanding membership interests of the Centennial Contributors were converted into 20,000,000 units representing common membership interests in CRP (the "CRP Common Units") and (2) we were admitted as a member of CRP and issued the remaining 163,505,000 CRP Common Units. We also issued 20,000,000 shares of our Class C Common Stock, par value $0.0001 per share (the "Class C Common Stock"), to the Centennial Contributors. Pursuant to the terms of the limited liability company agreement of CRP, the Centennial Contributors and their permitted transferees generally have the right to cause CRP to redeem all or a portion of their CRP Common Units in exchange for shares of our Class A Common Stock or, at CRP's option, an equivalent amount of cash; provided that we may, at our option, effect a direct exchange of such cash or Class A Common Stock for such CRP Common Units in lieu of a redemption by CRP. Upon the future redemption or exchange of CRP Common Units held by a Centennial Contributor, a corresponding number of shares of Class C Common Stock will be canceled.

        In connection with the closing of the Business Combination, we also issued one share of our Series A Preferred Stock, par value $0.0001 per share (the "Series A Preferred Stock"), to CRD. CRD, as the holder of the Series A Preferred Stock, is not entitled to any dividends from us, but will be entitled to preferred distributions in liquidation in the amount of $0.0001 per share of Series A Preferred Stock. In addition, for so long as the Series A Preferred Stock remains outstanding, CRD will be entitled to nominate one director for election to our board of directors in connection with any vote of our stockholders for the election of directors, and the vote of CRD will be the only vote required to elect such nominee to our board. The Series A Preferred Stock is redeemable by us (a) at such time as CRD and its affiliates cease to own, in the aggregate, at least 5,000,000 CRP Common Units and/or shares of Class A Common Stock (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions), (b) at any time at CRD's option or (c) upon a breach of the transfer restrictions relating to the Series A Preferred Stock.

        Upon the closing of the Business Combination, we changed our name from "Silver Run Acquisition Corporation" to "Centennial Resource Development, Inc.," and continued the listing of our Class A Common Stock and Public Warrants under the symbols "CDEV" and "CDEVW," respectively. The Units automatically separated into their component securities upon closing of the Business Combination and, as a result, no longer trade as a separate security.

CRP History

        CRP was formed in August 2012 by an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds, in connection with the acquisition of all of the oil and natural gas properties and certain other assets of Celero, which was formed in 2006 to focus on the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. Until the closing of the Business Combination, CRP operated as a privately-held independent oil and natural gas company.

        CRP is considered our accounting predecessor and hence the historical financial statements of CRP for the three years ended December 31, 2015 and the interim period ended September 30, 2016 (unaudited) are included elsewhere in this prospectus. The historical financial statements of Silver Run Acquisition Corporation (a development stage company) for the period from November 4, 2015 (inception) to December 31, 2015 and for the nine months ended September 30, 2016 (unaudited) are not included in this prospectus, but were included in our definitive proxy statement filed with the Securities and Exchange Commission on September 23, 2016 and our Quarterly Report on Form 10-Q

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for the quarter ended September 30, 2016, respectively. Unless otherwise specified herein, the information set forth in this prospectus does not reflect the completion of the Silverback Acquisition.

Our Business

        Our only significant asset is our ownership of an approximate 92% membership interest in CRP. We are an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and our properties consist of large, contiguous acreage blocks in Reeves, Ward and Pecos counties in West Texas.

        As of September 30, 2016, our portfolio included 63 operated producing horizontal wells. The horizontal wells span an area approximately 45 miles long by 20 miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling inventory with a focus on maximizing returns to our stockholders. In addition, we believe our acreage may be prospective for the 2nd and 3rd Bone Spring shales and Avalon Shale, where other operators have experienced drilling success near our acreage.

        As of September 30, 2016, we have leased or acquired approximately 42,300 net acres, approximately 80% of which we operate. Our acreage is predominantly located in the southern portion of the Delaware Basin, where production and reserves typically contain a higher percentage of oil and natural gas liquids and a correspondingly lower percentage of natural gas compared to the northern portion of the Delaware Basin. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, we added one horizontal rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. During 2016, we placed 11 horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on reducing drilling times, optimizing completions and reducing costs.

        The Permian Basin is an attractive operating area due to its extensive original oil-in-place, favorable operating environment, multiple horizontal zones, high oil and liquids-rich natural gas content, well-developed network of oilfield service providers, long-lived reserves with relatively consistent reservoir quality and historically high drilling success rates. According to the U.S. Energy Information Administration (the "EIA"), the Permian Basin is the most prolific oil producing area in the United States, accounting for 46% and 36% of total crude oil production from the seven most prolific U.S. producing regions (Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian and Utica) during the month ended December 31, 2016 and December 31, 2015, respectively.

        On December 28, 2016, we completed the acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC for a cash purchase price of approximately $855,000,000, subject to customary purchase price adjustments. The assets acquired from Silverback include 30 operated producing horizontal wells and approximately 35,000 net acres that directly offset our existing acreage in Reeves County, Texas. We operate approximately 95% of, and have an approximate 88% working interest in, this acreage and believe that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations.

        The acreage acquired in the Silverback Acquisition includes 11,694 net acres, with an allocated value of approximately $300 million, subject to the AMI. Pursuant to the AMI, one or more of three separate counterparties may elect to acquire up to an aggregate of 80.75% of the acreage subject to the AMI by paying to us, on or before January 30, 2017, such counterparty's share of the cost and expense of acquiring the acreage. The failure of a counterparty to make such payment on or before January 30, 2017 will be deemed to be an election not to acquire the AMI acreage.

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        Our goal is to build a premier development and acquisition company focused on horizontal drilling in the Delaware Basin. We have assembled a multi-year inventory of horizontal drilling projects. As of September 30, 2016, we had identified 1,388 gross horizontal drilling locations in the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C zones across our Delaware Basin acreage based on spacing of four wells per 640-acre section in the 3rd Bone Spring Sandstone and five to six wells per 640-acre section in the Wolfcamp zones. Our drilling inventory includes 381 extended lateral locations of either 9,500 or 7,500 lateral feet. Our near-term drilling program is focused on both the Upper and Lower Wolfcamp A zones, but we also intend to drill locations in the 3rd Bone Spring Sandstone, Wolfcamp B and Wolfcamp C zones. Based on our and other operators' well results and our analysis of geologic and engineering data, we believe the 2nd and 3rd Bone Spring shales and Avalon Shale may also be prospective across our acreage, and we may integrate these zones into our future drilling program as they become further delineated. The following table provides a summary of our gross horizontal drilling locations by zone as of September 30, 2016.


Gross Identified Horizontal Drilling Locations(1)(2)

 
  Total  

Zones:

       

3rd Bone Spring Sandstone

    64  

Upper Wolfcamp A

    403  

Lower Wolfcamp A

    335  

Wolfcamp B

    311  

Wolfcamp C

    275  

Total Horizontal Locations(3)(4)

    1,388  

(1)
Our total identified horizontal drilling locations include 48 locations associated with proved undeveloped reserves as of September 30, 2016. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, 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 horizontal zones. In addition, to evaluate the prospectivity of our horizontal acreage, we have performed open-hole and mud log evaluations, core analysis and drill cuttings analysis. See "—Our Properties." The drilling locations that 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—Risks Related to Our Business—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." Further, to the extent the drilling locations are associated with acreage that expires, we would lose our right to develop the related locations. See "Risk Factors—Risks Related to Our Business—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 horizontal drilling location count implies 880-foot spacing with five to six wells per 640-acre section in the Wolfcamp zones and 1,320-foot spacing with four wells per

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    640-acre section in the 3rd Bone Spring Sandstone, in each case, consisting primarily of single-section (i.e., approximately 4,500-foot) laterals.

(3)
673 of our 1,388 horizontal drilling locations are on acreage that we operate. We have an approximate 84% average working interest in our operated acreage.

(4)
We have included undeveloped horizontal locations only on our leasehold in Reeves and Ward counties.

        We believe that development drilling of our 1,388 gross horizontal locations, with an increasing focus on drilling extended lateral wells as well as potential downspacing, will allow us to grow our production and reserves. In addition, we believe our large acreage blocks allow us to optimize our horizontal development program to maximize our resource recovery and our returns. We also intend to grow our production and reserves through acquisitions that meet our strategic and financial objectives. Furthermore, we believe our operational efficiency is enhanced by a third-party gas gathering system and cryogenic processing plant, which were built specifically for the area where the majority of our acreage is located, and our operated saltwater disposal system. In addition, a third-party crude gathering system, which became operational in the third quarter of 2016 and will transport the majority of our crude oil to market at a lower cost than we have experienced historically, will provide additional efficiencies.

        We experienced a significant decrease in our drilling and completion costs during 2015, which continued into 2016. This trend has been driven by efficiency improvements in the field, including reduced drilling days, the modification of well designs and reduction or elimination of unnecessary costs. Additionally, overall service costs have declined as a result of reduced industry demand. For the nine months ended September 30, 2016, the spud-to-rig release for our three single-section horizontal wells was approximately 21 days compared to 28 days and 46 days for all single-section horizontal wells we drilled in 2015 and 2014, respectively. We expect that further optimization in the field (including the increased drilling of longer laterals, pad drilling, the use of shared facilities and zipper fracs), reduced rig rates and lower service costs will improve our well economics.

        Our 2016 capital budget for drilling, completion and recompletion activities and facilities costs was approximately $92 million, excluding leasing and other acquisitions. We allocated approximately $80 million of our 2016 capital budget for the drilling and completion of operated wells and $6 million for our participation in the drilling and completion of non-operated wells. For 2016, we budgeted $25 million for leasing. In the nine months ended September 30, 2016, we incurred capital costs of approximately $48.9 million, excluding leasing and acquisition costs.

        Because we operate approximately 80% of our net acreage (as of September 30, 2016), the amount and timing of our capital expenditures are largely subject to our discretion. We believe our approximate 84% average working interest in our operated acreage provides us with flexibility to manage our drilling program and optimize our returns and profitability. We could choose to defer a portion of our planned capital expenditures depending on a variety of factors, including the success of our drilling activities; prevailing and anticipated prices for oil, natural gas and NGLs; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the level of participation by other working interest owners. We have an approximate 17% working interest in our non-operated acreage.

        For the nine months ended September 30, 2016, our average net daily production was 7,982 Boe/d (approximately 69% oil, 20% natural gas and 11% NGLs). The following table provides summary information regarding our proved reserves as of December 31, 2015, based on a reserve report prepared by Netherland, Sewell & Associates, Inc., our independent petroleum engineer ("NSAI"). Of

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our proved reserves, approximately 40% were classified as PDP. PUDs included in this estimate are from 52 horizontal well locations across three zones.

Estimated Total Proved Reserves  
Oil
(MMBbls)
  NGLs
(MMBbls)
  Natural Gas
(Bcf)
  Total
(MMBoe)
  % Oil   % Liquids(1)   % Developed  
  23.2     3.9     32.4     32.5     71     83     40  

(1)
Includes oil and NGLs.

        Based on the reserve estimates of NSAI, the average PUD horizontal EUR as of December 31, 2015 is approximately 610 MBoe (approximately 71% oil, 12% NGLs and 17% natural gas) for our Wolfcamp wells, which have an average lateral length of approximately 4,500 feet.

    Our Properties

        Our properties include working interests in approximately 90,800 gross (42,300 net) surface acres, substantially all of which are located in the oil-rich core of the Southern Delaware Basin, a sub-basin of the Permian Basin, in the Texas counties of Reeves, Ward and Pecos. The following table summarizes our surface acreage by county as of September 30, 2016.

 
  Gross   Net  

County:

             

Reeves

    76,600     36,400  

Ward

    2,400     1,900  

Pecos

    11,800     4,000  

Total

    90,800     42,300  

        In addition to the acreage described in the table above, we acquired approximately 35,000 net acres in Reeves County in the Silverback Acquisition.

        Permian Basin.     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. The Basin is composed of five sub regions: the Delaware Basin, the Central Basin Platform, the Midland Basin, the Northwest Shelf and the Eastern Shelf. The Permian Basin is an attractive operating area due to its multiple horizontal and vertical target zones, favorable operating environment, high oil and liquids-rich natural gas content, mature infrastructure, well-developed network of oilfield service providers, long-lived reserves with consistent reservoir quality and historically high drilling success rates. According to the EIA, the Permian Basin is the most prolific oil producing area in the U.S., accounting for 23% and 20% of total U.S. crude oil production during the twelve-month periods ended April 30, 2016 and April 30, 2015, respectively. Six key producing formations within the Permian Basin (Spraberry, Wolfcamp, Bone Spring, Glorieta, Yeso and Delaware) have provided the bulk of the Basin's 122% increase in oil production since 2007. Approximately 62% of the increase came from the Wolfcamp, Bone Spring and Spraberry formations.

        Delaware Basin.     The present structural form of the Delaware Basin, a sub-basin of the Permian Basin, began to take shape in the early Pennsylvanian period at which time the area slowly downwarped relative to the adjacent Central Basin Platform and Northwest Shelf. This period was characterized by relatively stable marine shale and limestone deposition with periodic influxes of siliciclastics during sea-level lowstands. Stratigraphic records indicate a rapid deepening of the Delaware Basin during early Permian time. High total organic carbon marine shales, carbonate debris flows and turbidite sandstones were the predominant deposits in the Delaware Basin during this period. Subsequent burial and

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thermal maturation of this thick Permian succession of highly organic source and reservoir rock resulted in what we believe is evolving into a prolific oil field.

        The Delaware Basin encompasses an estimated 10,039 square miles and contained over 25,000 producing wells at the end of 2015, with production from certain wells dating back to 1924. Over the past decade, horizontal drilling activity has been more prevalent within the Delaware Basin relative to other areas of the Permian Basin. According to Baker Hughes, three of the top six Permian Basin counties by horizontal rig count are located in the Delaware Basin. Reeves County, where the majority of our acreage is located, had the second most horizontal rigs of any U.S. county in June 17, 2016, with 21 rigs as of such date.

        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." For the nine months ended September 30, 2016, our net daily production averaged 69% oil, 20% natural gas and 11% NGLs and had a greater liquids-content than other areas of the Delaware Basin.

        Oil and gas production was first established in the area of our leasehold from vertical wells in the Wolfbone interval, a blend of stacked pay zones in the Permian (Wolfcampian) Wolfcamp and overlying (Leonardian) Bone Spring formations. Operators were initially drawn to this area for the thick pay section, superior rock quality and oil-rich production. The Barilla Draw field, partially coincident with our leasehold, is the source of substantial petrophysical data acquired during this vertical phase of development. This data, including 17 of our wells with advanced petrophysical logs and two of our wells with whole core, is being utilized to guide our horizontal development of the area. The vertical development has resulted in a better understanding of our leasehold's geology relative to other parts of the Basin and has not caused significant depletion. Depth to the top of the Wolfcamp from a representative well central to our leasehold is approximately 10,600 feet. The gross thickness of the potential pay section from the top of the Bone Spring formation through the base of the Wolfcamp C is approximately 3,500 feet, an attractive thickness for development with multiple horizontal landing zones. We believe that the combination of these conditions will allow us to achieve superior results during the development of our leasehold.

        Our horizontal drilling, including 63 operated wells as of September 30, 2016, has been widespread with locations across the majority of our leasehold. We have established commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C, across an area approximately 45 miles long by 20 miles wide. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones. Also, as of September 30, 2016, approximately 60% of our total net acreage (approximately 79% of our operated net acreage in Reeves and Ward counties) was either held by production or under continuous drilling provisions. This has put us in a position to strategically develop our acreage with a near-term focus on high-return projects. Our previous activity, such as horizontal drilling in the Wolfcamp B and C zones, has been a catalyst for activity from offset operators. We will closely monitor this offset activity and adjust our future development plans with information and best practices learned from our peers.

        As of September 30, 2016, we operated approximately 80% of our net acreage and had an approximate 84% average working interest in our operated acreage. This operational control gives us flexibility in development strategy and pace. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, which suspension had no effect on our proved undeveloped reserves as of December 31, 2015, we added one horizontal drilling rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. During 2016, we placed 11 horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on reducing drilling times, optimizing completions and reducing costs without compromising worker health, safety and environmental protection. For the nine months ended

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September 30, 2016, the spud-to-rig release for our three single-section horizontal wells was approximately 21 days compared to 28 days and 46 days for all single-section horizontal wells we drilled in 2015 and 2014, respectively. We expect that further optimization in the field (including the increased drilling of longer laterals, pad drilling, the use of shared facilities and zipper fracs), reduced rig rates and lower service costs will improve our well economics. In March 2016, we drilled and completed our first 9,500-foot lateral well, which had an initial 90-day oil production rate of approximately 900 barrels of oil per day.

        Completion design and its effective execution are the predominant factors that dictate relative well performance in an area or zone. We have an evolving completion strategy that includes methodical adjustments of parameters, experimentation of different designs on adjacent locations with similar rock characteristics, constant monitoring and re-evaluation of results and ultimately tailoring completions to the conditions specific to an area or zone. Our current base completion design is a slickwater fracture stimulation, targeting 160 feet stage length, approximately 6 clusters per stage and 2,000 pounds or greater of proppant per foot of lateral length. Field-level rate of return is most influenced by incremental improvements in well performance and cost savings. Our philosophy is to focus on both parameters, with an emphasis on performance enhancement.

        Our current drilling program is focused primarily on the Upper and Lower Wolfcamp A intervals. However, based on existing well results and our analysis of geologic and engineering data, we believe the 3rd Bone Spring Sandstone, Wolfcamp B and Wolfcamp C intervals are prospective across our acreage and we plan to target those zones in our future drilling program. As of September 30, 2016, our location count for the Wolfcamp is based on locations spaced approximately 880 feet from each other within a zone and staggered vertically in adjacent zones, and for the 3rd Bone Spring Sandstone, the current location count is based on locations spaced approximately 1,320 feet from each other (as illustrated in the figure below). If future downspacing pilots are successful, we may be able to add additional locations to our multi-year inventory. In addition, we believe our acreage may be prospective for the 2nd and 3rd Bone Spring shales and Avalon Shale, where other operators have experienced drilling success near our acreage. We also anticipate that our recently completed Silverback Acquisition will impact our existing drilling program as we integrate these new assets.

GRAPHIC

        NSAI, our independent petroleum engineer, has estimated that as of December 31, 2015, proved reserves net to our interest in our properties were approximately 32,457 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 nine months ended September 30, 2016, our average net daily production was 7,982 Boe/d (approximately 69% oil, 20% natural gas and 11% NGLs). During 2015, our average net daily production was 7,317 Boe/d (approximately 69% oil, 19% natural gas and 12%

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NGLs). As of September 30, 2016, we produced from 77 horizontal and 70 vertical wells, in each case, operated and non-operated.

        Facilities.     We strive to develop the necessary infrastructure to lower our costs and support our drilling schedule and production growth. We accomplish this goal primarily 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 artificial lift equipment. A crude gathering system, which became operational in the third quarter of 2016 will transport the majority of our crude oil to market at a lower cost than we have experienced historically. For gas gathering and processing, we have infrastructure in place that spans the heart of our leasehold. The majority of our gas is processed at a cryogenic plant that is centrally located in our area of operations. We have a long-term agreement with a third-party gas gatherer and processor and benefit from priority producer status as the anchor tenant.

        Recent and Future Activity.     During the nine months ended September 30, 2016, 8.0 gross (5.1 net) wells were placed on production on our acreage. All of these wells were horizontal wells. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, we added one horizontal rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. During the remainder of 2016, 3 operated horizontal wells were placed on production.

        As of September 30, 2016, we had identified 1,388 gross horizontal drilling locations in the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C horizontal zones across our Delaware Basin acreage based on approximately 880-foot spacing for the Wolfcamp zones and 1,320-foot spacing for the 3rd Bone Spring Sandstone. Our drilling inventory includes 381 horizontal extended lateral locations of either 9,500 or 7,500 feet. Gross drilling locations are defined as locations on operated and non-operated leaseholds specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, 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 horizontal zones. In addition, to evaluate the prospectivity of our horizontal acreage, we have performed open-hole and mud log evaluations, core analysis and drill cuttings analysis. 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 for which we will 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 proved reserve estimates as of December 31, 2015 and 2014 were prepared by NSAI, our independent petroleum engineer. 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. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Copies of our independent petroleum engineer's proved reserve reports as of December 31, 2015 and December 31, 2014 are included as Exhibit 99.2 and Exhibit 99.1, respectively, of the registration statement of which this prospectus forms a part. Our reserve report as of December 31, 2013 was prepared internally by our in-house petroleum engineers in accordance with (i) the same methodology utilized by NSAI in preparing its reports and (ii) the rules and regulations of the SEC.

        We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent petroleum engineer to ensure the integrity, accuracy and timeliness of the data used to calculate the proved reserves relating to our assets in the Permian Basin. Our internal technical team members meet with our independent petroleum engineer periodically during the period covered by NSAI's proved reserve reports to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Terry Sherban, our Vice President, Reservoir Engineering, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Sherban is a petroleum engineer with 37 years of reservoir and operations experience, and our geoscience staff has an average of approximately 24 years of energy industry experience.

        The preparation of our proved reserve estimates was 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;

    review of reserve estimates by Mr. Sherban or under his direct supervision;

    review by our Vice President, Development and Chief Executive Officer of all of our reported proved reserves, including the review of all significant reserve changes and all new PUDs additions;

    direct reporting responsibilities by our Vice President, Reservoir Engineering 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, 2015, 2014 and 2013 were estimated using a deterministic method. The

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estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing ("PDNP") and PUD for our properties, due to the abundance of analog data.

        To estimate economically recoverable proved reserves and related future net cash flows, NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological 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 have been field tested and have 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 Oil and Natural Gas Reserves.     The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2015, 2014 and 2013, based on the proved reserve report as of December 31, 2015 and 2014 by NSAI, our independent petroleum engineer, and based on our internally prepared reserve report as of December 31, 2013, in each case, prepared in accordance with the rules and regulations of the SEC. Copies of the proved reserve reports as of December 31, 2015 and December 31, 2014 prepared by NSAI with respect to our properties are included as

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Exhibit 99.2 and Exhibit 99.1, respectively, to the registration statement of which this prospectus forms a part. All of our proved reserves are located in the United States.

 
  Year Ended December 31,  
 
  2015(1)   2014(2)   2013(3)  

Proved developed reserves:

                   

Oil (MBbls)

    9,347     8,026     6,021  

Natural gas (MMcf)

    12,711     11,959     4,837  

NGLs (MBbls)

    1,603     766     382  

Total (MBoe)

    13,068     10,786     7,210  

Proved undeveloped reserves:

                   

Oil (MBbls)

    13,852     11,823     12,489  

Natural gas (MMcf)

    19,731     15,455     2,131  

NGLs (MBbls)

    2,248     785     143  

Total (MBoe)

    19,389     15,184     12,987  

Total proved reserves:

                   

Oil (MBbls)

    23,199     19,850     18,510  

Natural gas (MMcf)

    32,442     27,414     6,968  

NGLs (MBbls)

    3,851     1,551     525  

Total (MBoe)

    32,457     25,970     20,197  

Oil and Natural Gas Prices:

                   

Oil—WTI posted price per Bbl

  $ 46.79   $ 91.48   $ 95.96  

Natural gas—Henry Hub spot price per MMBtu

  $ 2.59   $ 4.35   $ 3.67  

(1)
Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average West Texas Intermediate posted price of $46.79 per barrel as of December 31, 2015 was adjusted for quality, transportation fees and a regional price differential. For gas volumes, the average Henry Hub spot price of $2.59 per MMBtu as of December 31, 2015 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $41.85 per barrel of oil, $13.94 per barrel of NGL and $1.71 per Mcf of gas as of December 31, 2015.

(2)
Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.48 per barrel as of December 31, 2014 was adjusted for quality, transportation fees and a regional price differential. For gas volumes, the average Henry Hub spot price of $4.35 per MMBtu as of December 31, 2014 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $84.94 per barrel of oil, $22.70 per barrel of NGL and $4.70 per Mcf of gas as of December 31, 2014.

(3)
Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil and NGL volumes, the average West Texas Intermediate posted price of $95.96 per barrel as of December 31, 2013 was adjusted for quality, transportation fees and a regional price differential. For gas volumes, the average Henry Hub spot price of $3.67 per MMBtu as

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    of December 31, 2013 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $92.05 per barrel of oil, $26.05 per barrel of NGL and $3.76 per Mcf of gas as of December 31, 2013.

        The changes from December 31, 2014 estimated proved reserves to December 31, 2015 estimated proved reserves reflect the addition of 12,864 MBoe of proved reserves through extensions and 1,275 MBoe of acquired proved reserves, offset by net negative revisions of 4,981 MBoe primarily due to the decline in commodity prices.

        The changes from December 31, 2013 estimated proved reserves to December 31, 2014 estimated proved reserves reflect production during this period of approximately 2,015 MBoe and additions of approximately 21,012 MBoe attributable to new locations resulting from the strategic drilling of wells to delineate our acreage position and the sale of 13,706 MBoe of reserves in the CO2 Project Disposition and the Marston Disposition.

        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 the section entitled "Risk Factors—Risks Related to Our Business."

        Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in the registration statement of which this prospectus forms a part and the proved reserve reports as of December 31, 2015 and December 31, 2014, which are included as Exhibit 99.2 and Exhibit 99.1, respectively, to the registration statement of which this prospectus forms a part.


PUDs

    Year Ended December 31, 2015

        As of December 31, 2015, our PUDs totaled 13,852 MBbls of oil, 19,731 MMcf of natural gas and 2,248 MBbls of NGLs, for a total of 19,389 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

        Changes in PUDs that occurred during 2015 were primarily due to (i) negative revisions of 4,648 MBoe primarily related to the conversion of PUDs to unproved reserves of approximately 6,794 MBoe due to the decline in commodity prices, partially offset by a positive revision in performance; (ii) an increase of approximately 9,605 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position; (iii) the conversion of approximately 1,020 MBoe attributable to PUDs into proved developed reserves; and (iv) the acquisition of 268 MBoe of PUDs.

        During the twelve months ended December 31, 2015, we spent $17.7 million to convert PUDs 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, 2015, none of our total proved reserves were classified as PDNP

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    Year Ended December 31, 2014

        As of December 31, 2014, our PUDs totaled 11,823 MBbls of oil, 15,455 MMcf of natural gas and 785 MBbls of NGLs, for a total of 15,184 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

        Changes in PUDs that occurred during 2014 were primarily due to (i) a decrease of approximately 10,806 MBoe related to the CO2 Project Disposition in May 2014 and 296 MBoe related to the Marston Disposition in December 2014; (ii) additions of approximately 13,618 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position; and (iii) the conversion of approximately 318 MBoe attributable to PUDs into proved developed reserves.

        During the twelve months ended December 31, 2014, we spent $10.6 million to convert PUDs 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, 2014, 0.2% of our total proved reserves were classified as PDNP.

    Year Ended December 31, 2013

        As of December 31, 2013, our PUDs totaled 12,489 MBbls of oil, 2,131 MMcf of natural gas and 143 MBbls of NGLs, for a total of 12,987 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 (i) additions of approximately 5,430 MBoe attributable to improved recovery resulting from the application of tertiary recovery methods utilizing CO2 injection on properties in Chaves County, New Mexico that we sold in May 2014; (ii) a decrease of approximately 6,707 MBoe related to the Wolfbone Disposition in October 2013, the sale of our interest in 320 gross (187 net) acres in Glasscock and Midland Counties, Texas, including two wells, in June 2013, and the sale of our interest in 1,951 gross (1,617 net) acres in Midland County, Texas, including ten wells, in August 2013; (iii) additions of approximately 4,038 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position and (iv) the conversion of approximately 402 MBoe attributable to PUDs into proved developed reserves.

        During the twelve months ended December 31, 2013, we spent $7.5 million to convert PUDs to proved developed reserves and $144.0 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, 2% of our total proved reserves were classified as PDNP.

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Oil and Natural Gas Production Prices and Costs

Production and Price History

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

 
  Nine Months
Ended
September 30,
  Year Ended December 31,  
 
  2016   2015   2015   2014   2013  
 
  (In thousands)
 

Production data:

                               

Oil (MBbls)

    1,520     1,329     1,830     1,428     713  

Natural gas (MMcf)

    2,551     2,205     3,058     2,112     797  

NGLs (MBbls)

    242     242     331     235     98  

Total (MBoe)(1)

    2,187     1,939     2,671     2,015     944  

Average realized prices before effects of hedges:

                               

Oil (per Bbl)

  $ 37.48   $ 44.45   $ 42.43   $ 80.50   $ 92.37  

Natural gas (per Mcf)

    2.24     2.76     2.60     4.58     3.79  

NGLs (per Bbl)

    12.80     14.83     14.66     30.64     31.50  

Total (per Boe)

  $ 30.08   $ 35.45   $ 33.87   $ 65.42   $ 76.24  

Average realized prices after effects of hedges:

                               

Oil (per Bbl)

  $ 48.42   $ 63.30   $ 61.61   $ 83.73   $ 74.68  

Natural gas (per Mcf)

    2.24     3.18     3.04     4.58     3.79  

NGLs (per Bbl)

    12.80     14.83     14.66     30.64     31.50  

Total (per Boe)

  $ 37.68   $ 48.85   $ 47.51   $ 67.71   $ 62.84  

Average costs (per Boe):

                               

Lease operating expenses

  $ 4.71   $ 8.93   $ 7.93   $ 8.78   $ 20.24  

Severance and ad valorem taxes

    1.61     1.98     1.88     3.41     4.40  

Transportation, processing, gathering and other operating expenses

    2.00     2.24     2.15     2.37     1.37  

Depreciation, depletion, amortization and accretion of asset retirement obligations

    27.86     33.01     33.73     34.30     31.02  

Abandonment expense and impairment of unproved properties

    1.16     1.99     2.85     9.94     9.07  

Exploration

            0.03          

Contract termination and rig stacking

        1.23     0.89          

General and administrative expenses

    4.87     4.40     5.32     15.73     17.84  

Total

  $ 42.21   $ 53.78   $ 54.78   $ 74.53   $ 83.94  

(1)
May not sum or recalculate due to rounding.


Productive Wells

        As of September 30, 2016, we owned an approximate 61% average working interest in 147 gross (89 net) productive wells. Our wells are oil wells that produce associated liquids-rich natural gas. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.

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Developed and Undeveloped Acreage

        The following table sets forth information as of September 30, 2016 relating to our leasehold acreage. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as 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.

Developed Acreage   Undeveloped Acreage   Total Acreage  
Gross(1)
  Net(2)   Gross(1)   Net(2)   Gross(1)   Net(2)  
  8,200     6,500     82,600     35,800     90,800     42,300  

(1)
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.

(2)
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. Substantially all of the leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 60 to 180 days after the completion of the last well drilled on such lease, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 60 to 180 days until the entire lease is held by production. None of our horizontal drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule. The following table sets forth the gross and net undeveloped acreage, as of September 30, 2016, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

Remaining 2016   2017   2018   2019   2020  
Gross
  Net   Gross   Net   Gross   Net   Gross   Net   Gross   Net  
  5,900     2,700     8,200     3,800     15,700     7,300     6,600     3,100          


Drilling Results

        The following table sets forth the results of our drilling activity, as defined by wells having been placed on production, 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

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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 Nine Months
Ended September 30,
  For the Year Ended December 31,  
 
  2016   2015   2015   2014   2013  
 
  Gross   Net   Gross   Net   Gross   Net   Gross   Net   Gross   Net  

Exploratory Wells:

                                                             

Productive(1)

                                         

Dry

                                         

Total Exploratory

                                         

Development Wells:

                                                             

Productive(1)

    8.0     5.1     9.0     8.1     16.0     12.4     36.0     26.8     26.0     10.9  

Dry

                                           

Total Development

    8.0     5.1     9.0     8.1     16.0     12.4     36.0     26.8     26.0     10.9  

Total Wells:

                                                             

Productive(1)

    8.0     5.1     9.0     8.1     16.0     12.4     36.0     26.8     26.0     10.9  

Dry

                                           

Total

    8.0     5.1     9.0     8.1     16.0     12.4     36.0     26.8     26.0     10.9  

(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

        As of September 30, 2016, we were the operator of approximately 80% of our net acreage. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Marketing and Customers

        We market the majority of our production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our oil, natural gas and NGL production to purchasers at market prices. We sell all of our natural gas and NGLs under contracts with terms of greater than twelve months and all of our oil under contracts with terms of twelve months or less.

        We normally sell production to a relatively small number of customers, as is customary in our business. For the years ended December 31, 2015, 2014 and 2013, Plains Marketing, L.P. accounted for 64%, 78% and 72%, respectively, of our total revenue. During such years, no other purchaser accounted for 10% or more of our revenue. In the third quarter of 2016, we started selling the majority of our oil production to Shell Trading (US) Company ("Shell") under a new marketing contract. The loss of Shell as a purchaser could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of Shell as a purchaser would not have a material adverse effect on our

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financial condition and results of operations because 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 options in the areas of our production. With the completion of a third-party crude gathering system in the third quarter of 2016, the majority of our oil production is currently transported by pipe at a lower cost than we have experienced historically with trucking. Our natural gas is generally transported by our gathering lines from the wellhead to a Central Delivery Point ("CDP") and then is gathered by third-party lines from these CDPs to a gas processing facility. At a small number of our wells, we own natural gas pipeline facilities that connect our wells to third-party natural gas gathering systems located in the vicinity of those wells.

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 developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Seasonality of Business

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

Title to Properties

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

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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 we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

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

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


Oil and Natural Gas Leases

        The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties as of September 30, 2016 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 producing oil and natural gas properties have statutory provisions regulating the development 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.

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        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, 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, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

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

Regulation of Sales and Transportation of Oil

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

        Our sales of oil are affected by the availability, terms and conditions and cost of transportation services. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act.

        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. We rely on third-party pipelines systems to transport the majority of crude oil produced by ours wells. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

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        Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies 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 oil producers and marketers with which we compete.

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 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 provided FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. On June 29, 2016, FERC issued an order (Order No. 826) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of $1,193,970 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) 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.

        We are required to observe such 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

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a commodity. Should we violate the anti-market manipulation laws and regulations, it could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

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

        Natural gas 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 companies that provide natural gas gathering services 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 are 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, or vice versa, 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 includes various occupational 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.

        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 or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies 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 and marketers with which we compete.

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Regulation of Environmental and Occupational Safety and Health Matters

        Our oil and natural gas development 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 of 1980 ("CERCLA"), also known as the "Superfund" law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

        The 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 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 development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA's exemption of certain oil and gas wastes from RCRA. 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

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position. In addition, in the course of our operations, we may generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

        We currently own, lease or operate numerous properties that have been used for oil and natural gas development 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 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 (the "Corps"). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA's and the Corps' jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. To the extent the rule expands the scope of the Clean Water Act's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of the Clean Water Act, and implementation of the rule has been stayed pending resolution of the court challenge. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

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

        The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 ("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

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facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of "responsible party" who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Air Emissions

        The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. 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 October 2015, the EPA lowered the National Ambient Air Quality Standard ("NAAQS") for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as "green completions." These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. More recently, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. 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, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

Regulation of GHG Emissions

        In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to 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 are also required to meet "best available control technology" standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements 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. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose

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methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

        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, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which requires member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The agreement was signed in April 2016, and entered into force in November 2016. The United States is one of over 70 nations having ratified or otherwise consented to be bound by the agreement. 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, many 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 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, proppants 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. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming struck down this rule. The BLM has appealed this decision. The appeal remains pending. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require

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disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.

        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 Railroad Commission of Texas 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 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. 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 development activities, and perhaps even be precluded from drilling wells.

ESA 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 further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency's 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development 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.

OSHA

        We are subject to the requirements of the Occupational Safety and Health 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

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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.

        We have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We have not incurred any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2016, nor do we expect to incur any such expenditures in 2017.

Related Insurance

        We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development 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 January 18, 2017, we had 64 full-time employees. We hire independent contractors on an as needed basis, and 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'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

         The following discussion and analysis should be read in conjunction with the accompanying financial statements and related notes of CRP 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, natural gas and NGLs, 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 Note 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. Financial information included in this prospectus does not reflect the properties acquired in the Silverback Acquisition.

Prior Company Operations

        We have no direct operations and no significant assets other than the ownership of an approximate 92% membership interest in CRP. CRP is considered our accounting predecessor and, accordingly, the following financial results and discussion and analysis reflect the results of CRP prior to the closing of the Business Combination.

        For all periods ending on or before October 15, 2014 and for all dates on or before October 15, 2014, the historical financial results contained herein reflect the combined results of (i) CRP and (ii) Celero Energy Company, LP, a Delaware limited partnership ("Celero"), which was formed in 2006 to focus on the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. On October 15, 2014, Celero conveyed substantially all of its oil and natural gas properties and other assets to CRP in exchange for membership interests in CRP, and as a result, subsequent to October 15, 2014, the historical financial results contained herein reflect the results of CRP. Except as the context otherwise requires, references in the following discussion to the "Company," "we," "our" or "us" with respect to periods prior to the closing of the Business Combination are to CRP and its operations prior to the closing of the Business Combination.

Overview

        We are an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Our horizontal wells span an area approximately 45 miles long by 20 miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C.

        On December 28, 2016, we completed the acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC for a cash purchase price of approximately $855,000,000, subject to customary purchase price adjustments. The assets acquired from Silverback include 30 operated producing horizontal wells and approximately 35,000 net acres that directly offset our existing acreage in Reeves County, Texas. We operate approximately 95% of, and have an approximate 88% working interest in, this acreage and believe that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations.

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        The acreage acquired in the Silverback Acquisition includes 11,694 net acres, with an allocated value of approximately $300 million, subject to the AMI. Pursuant to the AMI, one or more of three separate counterparties may elect to acquire up to an aggregate of 80.75% of the acreage subject to the AMI by paying to us, on or before January 30, 2017, such counterparty's share of the cost and expense of acquiring the acreage. The failure of a counterparty to make such payment on or before January 30, 2017 will be deemed to be an election not to acquire the AMI acreage. As of the date of this prospectus, we have not received notice that any party intends to exercise its rights under the AMI.

        The oil and gas industry is cyclical and commodity prices are highly volatile. In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and 2016, the global oil supply has continued to outpace demand, resulting in a sustained decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and 2016. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The duration and magnitude of the commodity price declines cannot be accurately predicted.

        Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production, as well as NGLs that are extracted from our natural gas during processing. Compared to 2014, our realized oil price for 2015 fell 47.3% to $42.43 per barrel, and our realized oil price for the nine months ended September 30, 2016 has further decreased to $37.48 per barrel. Similarly, our realized natural gas price for 2015 dropped 43.2% to $2.60 per Mcf and our realized price for NGLs declined 52.2% to $14.66 per barrel compared to 2014. For the nine months ended September 30, 2016, our realized price for natural gas was $2.24 per Mcf and our realized price for NGLs was $12.80 per barrel. Lower oil, natural gas and NGL prices not only may decrease our revenues, but also may reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially lower our oil, natural gas and NGL reserves. Lower commodity prices in the future could result in impairments of our properties and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned capital expenditures. Lower oil, natural gas and NGL prices may also reduce the borrowing base under CRP's credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil and natural gas prices may result in significant non-cash fair value losses being incurred on our derivatives, which could cause us to experience net losses when oil and natural gas prices rise.

        In addition, other governmental actions, including initiatives by OPEC, may continue to impact oil prices. Decisions by OPEC to reduce production or increased domestic oil and natural gas production in a changing regulatory environment could impact the price of oil.

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

        See "—Sources of Our Revenues," "—Production Results," "—Operating Costs and Expenses" and "—Adjusted EBITDAX" below for a discussion of these metrics.

        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. Oil sales contributed 87% of our total revenues for the nine months ended September 30, 2016. Natural gas sales contributed 8% and NGL sales contributed 5% of our total revenues for the nine months ended September 30, 2016. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

        Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors. See "—Market Conditions" for information regarding the current commodity price environment. A $1.00 per barrel change in our realized oil price would have resulted in a $1.5 million change in oil revenues for the nine months ended September 30, 2016. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.3 million change in our gas revenues for the nine months ended September 30, 2016. A $1.00 per barrel change in our realized NGL price would have changed revenue by $0.2 million for the nine months ended September 30, 2016.

        The following table presents our average realized commodity prices, as well as the effects of derivative settlements.

 
  Nine Months
Ended
September 30,
  Year Ended December 31,  
 
  2016   2015   2015   2014   2013  

Crude Oil (per Bbl):

                               

Average NYMEX price

  $ 41.53   $ 51.02   $ 48.76   $ 92.91   $ 97.98  

Average realized price, before the effects of derivative settlements

    37.48     44.45     42.43     80.50     92.37  

Effects of derivative settlements

    10.94     18.85     19.18     3.23     (17.74 )

Natural Gas:

                               

Average NYMEX price (per MMBtu)

  $ 2.35   $ 2.76   $ 2.63   $ 4.26   $ 3.73  

Average realized price, before the effects of derivative settlements (per Mcf)

    2.24     2.76     2.60     4.58     3.79  

Effects of derivative settlements (per Mcf)

        0.42     0.43          

NGLs (per Bbl):

                               

Average realized price

  $ 12.80   $ 14.83   $ 14.66   $ 30.64   $ 31.50  

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        While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials for these products.

        See "—Results of Operations" below for an analysis of the impact changes in realized prices had on our revenues.

    Production Results

        The following table presents historical production volumes for our properties for the nine months ended September 30, 2016 and 2015 and the years ended December 31, 2015, 2014 and 2013:

 
  Nine Months
Ended
September 30,
  Year Ended December 31,  
 
  2016   2015   2015   2014   2013  

Oil (MBbls)

    1,520     1,329     1,830     1,428     713  

Natural gas (MMcf)

    2,551     2,205     3,058     2,112     797  

NGLs (MBbls)

    242     242     331     235     98  

Total (MBoe)(1)

    2,187     1,939     2,671     2,015     944  

Average net daily production (Boe/d)(1)

    7,982     7,101     7,317     5,521     2,586  

(1)
May not sum or recalculate due to rounding.

        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 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.

    Derivative Activity

        Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. Due to this volatility, we have historically used commodity derivative instruments, such as collars, swaps and basis swaps, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices. See "—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk" for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

        We expect to continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our production. CRP's credit agreement allows us to hedge up to 80% of our reasonably anticipated production from proved reserves for up to 24 months in the future and up to 65% of our reasonably anticipated production from proved reserves for 25 to 60 months in the future, provided that no hedges may have a tenor beyond five years.

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    Operating Costs and Expenses

        Costs associated with producing oil, natural gas and NGLs are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells we own. As of September 30, 2016 and December 31, 2015, we owned interests in 147 and 138 gross wells, respectively.

        Lease Operating Expenses.     Lease operating expenses ("LOE") 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 LOE. 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 LOE 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 LOE at an acceptable level. For example, we monitor our LOE 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 LOE, 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 LOE per Boe. These initiatives would influence our overall operating cost and could cause fluctuations when comparing LOE on a period to period basis.

        Severance and Ad Valorem Taxes.     Severance taxes are paid on produced oil 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 severance taxes we pay correlate to the changes in oil, natural gas and NGLs 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, which also trend with oil and natural gas prices.

        Transportation, Processing, Gathering and Other Operating Expenses.     Transportation, processing, gathering and other operating expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and gas processing costs. These costs will fluctuate with increases or decreases in production volumes, contractual fees and changes in fuel and compression costs.

        Depreciation, Depletion, Amortization, and Accretion of Asset Retirement Obligations.     Depreciation, depletion, amortization, and accretion of asset retirement obligations ("DD&A") is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with our development and acquisition 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

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of their carrying value may have occurred. Please read "—Critical Accounting Policies and Estimates—Impairment of Oil and Natural Gas Properties" for further discussion.

        General and Administrative Expenses.     General and administrative ("G&A") expenses 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.

        Derivative Gain (Loss).     Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. We have not elected to apply cash flow hedge accounting, and consequently, recognize gains and losses in earnings rather than deferring such amounts in other comprehensive income as allowed under cash flow hedge accounting. Fair value gains or losses, as well as cash receipts or payments on settled derivative contracts, are recognized in our results of operations. Cash flows from derivatives are reported as cash flows from operating activities.

        Interest Expense.     A portion of our working capital requirements and capital expenditures are financed with borrowings under CRP's revolving credit facility and term loan. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under CRP's 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 and accretion of asset retirement obligations, abandonment expense and impairment of unproved properties, (gains) losses on derivatives excluding net cash receipts (payments) on settled derivatives, noncash incentive compensation expense (gains) losses on sale of oil and natural gas properties and other non-cash and non-recurring operating items.

        Our management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. For further discussion, please read "Selected Historical Financial Information—Non-GAAP Financial Measure."

Factors Affecting the Comparability of Our Future Financial Data Attributable to CRP to the Historical Financial Results of CRP's Operations

        Our future results of operations attributable to CRP may not be comparable to the historical results of operations of CRP for the periods presented due to the following reasons:

        Marston Disposition.     In December 2014, CRP conveyed approximately 1,845 net acres in Ward County, Texas, including 18 wells that produced 122 net Boe/d for the year ended December 31, 2014, for cash proceeds of approximately $12.5 million (the "Marston Disposition"). The Marston Disposition was accounted for as a transaction between entities under common control.

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        CO2 Project Disposition.     In May 2014, CRP conveyed certain oil and natural gas properties in Chaves County, New Mexico pursuant to which it had pursued a tertiary recovery project utilizing CO2 to increase production on such properties, including wells that produced 378 net Boe/d in the first half of 2014, for net cash proceeds of approximately $59.3 million (the "CO2 Project Disposition").

        Wolfbone Disposition.     In October 2013, CRP conveyed approximately 1,000 net acres in the Delaware Basin, including 187 non-operated wells that produced approximately 200 net Boe/d in the first half of 2013, for net cash proceeds of approximately $28.7 million (the "Wolfbone Disposition").

        Income Taxes.     We are a C-corp under the Code and, as a result, are subject to U.S. federal, state and local income taxes. Although CRP is subject to franchise tax in the State of Texas (at less than 1% of modified pre-tax earnings), as a partnership, it generally passes through its taxable income to its owners for other income tax purposes and is not subject to U.S. federal income taxes or other state or local income taxes. Accordingly, the historical financial data attributable to CRP contains no provision for U.S. federal income taxes or income taxes in any state or locality other than franchise tax in the State of Texas. Following the closing of the Business Combination and going forward, the financial data attributable to CRP may be affected because we are subject to additional tax as a C-Corp. We estimate that we will be subject to U.S. federal, state and local taxes at a blended statutory rate of 36% of pre-tax earnings allocable to us. Subject to certain restrictions, CRP generally will be required to make pro rata distributions to its members, including us, in an amount at least sufficient to allow us to pay our taxes. Such distributions will reduce the cash available to be used in CRP's business.

        Public Company Expenses.     We incur direct, incremental G&A expense as a result of being a publicly traded company, including, but not limited to, 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 G&A expenses are not included in CRP's historical financial results of operations.

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Results of Operations

    Nine Months Ended September 30, 2016 Compared to September 30, 2015

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

 
  Nine Months Ended
September 30,
   
   
 
 
  2016   2015   Change   % Change  

Revenues (in thousands):

                         

Oil sales

  $ 56,975   $ 59,068   $ (2,093 )   (4 )%

Natural gas sales

    5,717     6,082     (365 )   (6 )%

NGL sales

    3,097     3,590     (493 )   (14 )%

Total Revenues

  $ 65,789   $ 68,740   $ (2,951 )   (4 )%

Average sales price:(1)

                         

Oil (per Bbl)

  $ 37.48   $ 44.45   $ (6.97 )   (16 )%

Natural gas (per Mcf)

    2.24     2.76     (0.52 )   (19 )%

NGL (per Bbl)

    12.80     14.83     (2.03 )   (14 )%

Total (per Boe)

  $ 30.08   $ 35.45   $ (5.37 )   (15 )%

Production:

                         

Oil (MBbls)

    1,520     1,329     191     14 %

Natural gas (MMcf)

    2,551     2,205     346     16 %

NGLs (MBbls)

    242     242         %

Total (MBoe)(2)

    2,187     1,939     248     13 %